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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume IV - Production Operations Engineering

Joe Dunn Clegg, Editor

Chapter 6 – Formation Damage

Mukul M. Sharma, SPE, U. of Texas at Austin

Pgs. 241-274

ISBN 978-1-55563-118-5
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Any unintended impedance to the flow of fluids into or out of a wellbore is referred to as formation damage. This broad definition of formation damage 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.

Over the last five decades, a great deal of attention has been paid to formation damage issues for two primary reasons: (1) the ability to recover fluids from the reservoir is affected very strongly by the hydrocarbon permeability in the near-wellbore region, and (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.

On this page, we discuss methods to measure and to quantify the extent of formation damage and provide criteria that can be used to identify various types of formation damage. The goal is to define the mechanisms involved better so that an operator can recommend and design the correct remedial action and/or make changes to drilling, completion, and production operations to minimize damage in the future. It is generally true that, whenever possible, preventing formation damage is more effective than remedial treatments such as acidizing and fracturing. We do not discuss such treatments in this chapter. However, for each type of damage mechanism, potential remedial treatments are suggested.

Quantifying Formation Damage

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


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):


Fig. 6.1 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). In 1970, Standing[1] introduced the important concept of well flow efficiency, F, which he defined as


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, pR, and skin factor, S. Methods to measure these quantities are discussed in Sec. 6.3.

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, [3] Fetkovich, [4] and Standing. [1] These IPRs can be summarized as follows[5]:




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. 6.2 for different flow efficiencies. It is evident that, as flow efficiency decreases, smaller and smaller hydrocarbon rates are obtained for the same drawdown RTENOTITLE.

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 Brown[6].

Determination of Flow Efficiency and Skin

It is evident that, to quantify formation damage and to study its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells. The most common methods are multirate tests, isochronal gas-well tests, and transient well tests (pressure-buildup analysis).

Multirate Tests

Multirate tests can be conducted on both oil and gas wells. In these tests, several stabilized flow rates, qi , are achieved at corresponding stabilized flowing bottomhole pressures, pwf. The simplest analysis considers two different stabilized rates and pressures. The IPR can be written as


Simplifying and solving for the flow efficiency, F, we obtain


where x ≠ 0.

The above equation clearly shows that it is possible to obtain flow efficiency rather simply with two stabilized bottomhole pressures and two stabilized flow rates. A similar analysis can be performed to obtain an expression for a linear IPR (x = 0).

Multirate Tests in Gas Wells: Inertial Effects

For many gas wells and some oil wells, flow rates are sufficiently high that turbulent or inertial pressure drops near the wellbore can be significant. In such cases, the additional pressure drop measured by the skin can be confused with the pressure drop because of non-Darcy or inertial flow. It is very important to separate out the pressure drop caused by turbulent flow from that caused by physical skin because it has a significant impact on the stimulation recommendations made on the well. To analyze high-rate gas or oil wells, the following equation is needed. [7]

Darcy's law for high-rate gas wells can be written as




This equation can be rearranged to obtain


Here, Aqsc represents a laminar pressure drop and Bqsc2 represents an inertial or non-Darcy pressure drop (sometimes referred to as a turbulent pressure drop). Note that A contains the physical skin, S, and B is directly proportional to the non-Darcy coefficient, D. By plotting multirate test data as a plot of RTENOTITLE, we obtain A and B as an intercept and slope, respectively. It is then possible to compare the magnitude of the pressure drop caused by S with that caused by inertial effects, Dqsc.

If S>Dqsc, a stimulation treatment would be recommended. However, if Dqsc > S, the well may need to be reperforated or fractured to increase the inflow area and to reduce inertial effects.

Isochronal Test in Gas Wells

In gas wells in which it takes a long time to achieve stabilized rates, wells are shut in and produced for a fixed time interval (Δt) at several different rates. These isochronal tests are then interpreted by the following "deliverability" relation,


where the exponent n lies between 0.5 and 1. An exponent closer to 0.5 indicates that non-Darcy effects are important; an exponent close to 1 indicates that they are not. [2]

It should be noted that the "deliverability" equation is a variation of the equation derived in the previous section.

Pressure-Buildup Analysis

The most common method for determining skin is a pressure-buildup test. [2][8] In this test, a well that has been producing for a time, tp, is shut in for time Δt. The pressure buildup is recorded as a function of time. By constructing a Horner plot[2][8] like the one shown in Fig. 6.3, we can compute the skin and the product of the permeability and formation thickness, kh, of the reservoir (in field units).




Here, m is the slope of the straight-line portion of the Horner plot, and pws,1hr is the extrapolated shut-in pressure at a shut-in time of 1 hour.

It is also possible to obtain the average reservoir pressure with the Matthew, Brons, and Hazelbrook method from the pressure-buildup data. [9] Knowing both the average reservoir pressure and skin, we can calculate the flow efficiency of the well. This method provides a direct and quantitative measure of the extent of formation damage in a well.

Methods following the same principle have been developed for deviated and horizontal wells. Equations for analysis are more complex and are not discussed in this chapter. The same methods can also be used to analyze data from gas wells and from wells on artificial lift.

The short discussion presented above shows how near-wellbore formation damage can be quantified by measurements made on oil and gas wells. Such measurements are essential for determining the extent and magnitude of the formation damage and its impact on hydrocarbon production. However, these measures do not provide us with any clues on the reasons for the formation damage. In subsequent sections in this chapter, reasons and mechanisms for formation damage and strategies to minimize the impact of drilling and completion operations on well productivity are discussed.

Formation Damage vs. Pseudodamage

Formation damage mechanisms can be broken down into two broad classes: near-wellbore permeability reduction and near-wellbore relative permeability changes. These changes can occur under a variety of different circumstances. The following sections deal with different ways in which permeability and relative permeability in the near-wellbore region are altered by drilling, completion, and production operations.

Before we discuss formation damage mechanisms, 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) [10][11][12][13] and permeability loss as a result of depletion. [14] Reservoir engineering models for limited-entry flow in partially penetrating wells are presented in several reservoir engineering texts such as Dake. [10]

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; and 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.

In this chapter, flow restrictions in the completion itself such as the compacted zone around perforation tunnels and plugged gravel packs are included in the discussion of formation damage because they typically are measured as a well skin (Section 6.3).

Drilling-Induced Formation Damage

Drilling fluids serve to balance formation pressures while drilling to ensure wellbore stability. They also carry cuttings to the surface and cool the bit. The drilling engineer traditionally designs drilling fluids with two primary goals in mind: to ensure safe, stable boreholes, which is accomplished by operating within an acceptable mud-weight window, and to achieve high rates of penetration so that rig time and well cost can be minimized. Note that these primary considerations do not include well productivity concerns. Over the past decade, a growing recognition of the importance of drilling-induced formation damage has led operators to mesh the objectives of the drilling engineer with those of the production and reservoir engineers. This can be achieved only if the design of the drilling program is a coordinated effort between drilling and production engineers. The use of drill-in fluids (fluids used to drill through the pay zone) that minimize formation damage has become widespread.

Drilling and well productivity concerns are addressed in the design of drill-in fluids. To meet well productivity objectives (i.e., to minimize formation damage), the drill-in fluid must meet the following additional objectives: minimize the extent of solids invasion into the formation by bridging across the pores and forming a thin, low-permeability, filter cake; minimize the extent of filtrate and polymer invasion into the formation through the formation of an external filter cake; and ensure ease of removal of the external filter cake during flowback to maximize the inflow area during production and to avoid plugging gravel packs. To achieve these goals, various strategies have been adopted. In this section, we address these strategies in terms of the basic mud formulations being used. Traditional water-based muds, oil-based muds, and some special formulations of drill-in fluids for fractured formations and unconsolidated sands are discussed. This is followed by a discussion of formation damage caused by drilling in deviated and horizontal wells and the use of drill-in fluids for such applications.

Formation Damage Caused by Water-Based Muds

The vast majority of drilling fluids consist of bentonite mixed with polymers to enhance the rheology (or, more specifically, the cuttings-carrying capacity of the fluid), starches to control fluid loss, dissolved salts such as potassium chloride or sodium chloride, and perhaps a pH buffer to maintain the pH of the mud to the desired level. A great deal of work has been done in the last three decades on evaluating the formation damage potential of water-based drilling fluids. [15][16][17][18][19] The following factors have been observed to have an impact on the depth of invasion of solids and filtrate and therefore on the extent and depth of formation damage or permeability impairment: the state of dispersion of solids in the mud, the size and concentration of solids and polymers in the mud, the pore throat size or permeability of the formation, the pH and salinity of the filtrate, and the water sensitivity of the formation.

In most instances, the invasion of solids into the formation is limited to 2 or 3 in. from the wellbore wall, which implies that the productivity of perforated wells with relatively shallow depth of damage will not be significantly affected. Fig. 6.4 shows the productivity index (PI) of a well for different depths of damage assuming an 8-in.-long perforation. It is evident that as long as the depth of damage is smaller than the perforation length, the well PI is not significantly affected. Wells that are completed openhole without stimulation are particularly susceptible to this kind of damage.

In some instances, deep penetration of drill solids can occur. Fig. 6.5 shows the depth of invasion of formation damage when a 300-md Berea sandstone core is subjected to dynamic circulation of different water-based drilling fluids across its face. [21] It is evident that, in overtreated muds (containing too much thinner or dispersant), dispersed bentonite particles can penetrate through > 8 in. of rock and cause severe and irreversible damage. The other extreme, flocculated muds (too little thinner or too much salt), will limit solids invasion but will result in thick, high-permeability filter cakes. Filter cakes can result in such problems as stuck pipe and large filtrate loss. The use of salts and thinners is, therefore, a critical part of the design of drilling fluids for a given application. Appropriately conditioned muds must be used to eliminate the possibility of solids invasion and to minimize filtrate invasion. As discussed later, using sized bridging solids is a powerful tool for reducing solids and polymer invasion.

Although solids invasion clearly is detrimental to well productivity, filtrate invasion can also lead to substantial formation damage and to greater depths in some instances. It has been shown, for example, [21][22] that the use of freshwater muds can result in filtrates that can be damaging to water-sensitive sandstones. In such instances, the simple process of increasing the salinity of the filtrate can prevent fines migration induced by filtrate leakoff. The loss of aqueous filtrates also results in a reduction in the relative permeability to the hydrocarbon phases. [22] Such relative permeability effects are referred to as water-blocks and are discussed in the section on formation damage resulting from emulsion and sludge formation.

Similarly, the use of polymers is widespread but can, in some instances, lead to formation damage. Its been shown that the use of improper mixing producers in dissolving polymers into brines can result in the formation of "fish eyes," or unhydrated aggregates of polymer that can be several microns in diameter. These particulate gels are very effective as plugging agents and can lead to irreversible damage if not broken up and completely hydrated in the mud. Proper conditioning and dispersal of polymers is of critical importance in the field. [23][24][25][26]

There is a limited database on the formation damage caused by starches and other polymers such as xanthan or carboxymethylcellulose. These data indicate that the flow of such polymers can induce a substantial reduction in permeability as a result of constriction of pore throats, particularly in low-permeability formations.

Formation Damage Caused by Oil-Based Muds

Oil-based muds consist of water droplets dispersed in a continuous oil phase. The water droplets are stabilized by emulsifiers and organophilic clays. Standard API fluid loss tests show that the fluid leakoff rate in oil-based muds is substantially lower than for water-based muds. However, as shown elsewhere, [27] when tests are conducted on oil-saturated cores (not filter paper), leak-off rates for oil-based muds can be combrble to those for water-based muds. One important conclusion of this study is that API fluid leakoff tests should not be used to determine filtration rates in oil-based muds. Instead, dynamic filtration tests conducted on oil-saturated cores are much more representative. The relative permeability to oil in oil-saturated zones is high, leading to large leakoff rates in the productive zone. [27]

The invasion of solids and oil droplets into the formation is determined largely by the effectiveness of the external filter cake formed by organophilic bentonite and water droplets. The structure of the filter cake formed is substantially different from that of water-based muds. Water droplets bridge across the pore throats to form the external filter cake. Because the droplets are deformable, they can form very impermeable filter cakes, leading to good leakoff control. However, if the overbalance pressure exceeds the capillary pressure needed to squeeze the water droplets into the pores, a significant loss in productivity can result. To prevent this from happening, large overbalance pressures should be avoided.

Experimental studies have shown that the accumulation of drill solids in the mud results in the introduction of fines that can be much more damaging than clean mud. Drill-solids control, therefore, is an important issue in oil-based muds. In general, however, oil-based muds prove to be excellent (albeit expensive) candidates for drilling gauge hole and providing high-productivity wells. [27][28]

It is important to recognize and identify damage caused by oil-based muds because the recommended treatment procedures for stimulating wells damaged by oil-based muds can be quite different from those for wells damaged with water-based muds. Acidizing wells with conventional acid formulations may not be successful and in fact may result in additional damage as a result of the presence of emulsifiers in the filtrate. Solvent preflushes may need to be designed on the basis of compatibility tests between the mud, crude oil, and acid formulation.

The Concept of Minimum Underbalance Pressure

It is clear from the preceding discussion that the formation of an external mud cake is important in protecting the formation from solids and filtrate invasion. Are there conditions under which an external mud cake will not form across the face of the formation? Yes, there are at least two situations in which an external filter cake does not form across of the face of the formation: (1) lost circulation and (2) drilling overbalanced below the minimum overbalance pressure.

When drilling through very-high-permeability rocks or fractured formations, solids present in the drilling fluid may not be able to bridge across the face of the pores or fractures, resulting in leakoff of whole mud into the formation. [13] This leakoff can result in very severe, irreversible damage to the fracture or matrix. In general, bridging solids are added to the drilling fluid to bridge across the pores or fractures. Sizing of these solids is discussed in more detail in Suri and Sharma[18].

The second case in which filter cakes do not form is less intuitively obvious. To form a mud cake, solids in the mud are pushed against the formation by a hydrodynamic force that is proportional to the leakoff velocity. In addition, because of mud circulation, particles are constantly being sheared away from the face of the external cake. This balance between the hydrodynamic shearing action resulting from mud circulation and the fluid leakoff into the formation results in an equilibrium cake thickness. [29][30] Because the leakoff is proportional to the overbalance pressure, smaller overbalance pressures will lead to smaller leakoff rates and thinner external filter cakes, resulting in a minimum overbalance pressure below which no external filter cake is formed at all. Alternatively stated, there is a minimum permeability for a fixed overbalance pressure below which no external filter cake will form. This suggests that we must always drill either underbalanced or above the minimum overbalance pressure to ensure that an external cake is formed and available to protect the formation when drilling through the productive zone. Additional details for calculating the minimum overbalance pressure are provided in Di and Sharma[30].

Mud-Induced Damage in Fractured Reservoirs

When drilling through fractured formations, large quantities of whole mud can be lost to the fracture network, resulting in fracture plugging. Because fractures contribute almost all the productivity of such wells, it is important to keep these fractures open as much as possible. In such cases, underbalanced drilling is recommended and frequently used. Underbalanced drilling allows fluids from the fracture to flow into the wellbore, keeping the fractures relatively undamaged. If, however, because of safety and regulatory constraints, underbalanced drilling is not possible, bridging additives need to be added to the mud system to ensure that large-enough particles are available to bridge across the fracture face. The bridging additives most commonly used to ensure the formation of a bridge across the fracture face are calcium carbonate and fibrous additives such as cellulosic fibers and acid-soluble fibers. [31][32] Sizing of these granular or fibrous additives has been discussed in detail in Di and Sharma[31] and Singh and Sharma.[32]

Formation Damage in Horizontal Wells

Horizontal wells are more susceptible to formation damage than vertical wells for the following reasons. [33][34]

  1. The pay zone in a horizontal wellbore comes into contract with a drilling fluid for a much longer period than a vertical pay zone (days compared with hours).
  2. Most horizontal wells are openhole completions, which means that even shallow damage that in a cased perforated completion would be bypassed by the perforations becomes significant.
  3. Because the fluid velocity and pressure gradient during flowback are usually small, cleanup of internal and external cakes is not as effective as in vertical wellbores. Thus, only a fraction of the wellbore contributes to flow when the well is returned to production.
  4. Removing mud-induced formation damage by acidizing horizontal wells is often very difficult and expensive because of the large volumes of acid required and the difficulty in placing the acid in the appropriate wellbore locations.

Studies conducted on a simulated horizontal wellbore indicated that the heel is more damaged than the toe and that the upper part of the well is less damaged than the bottom of the wellbore where the drillpipe rests. [33] The damage zone around the horizontal wellbore can therefore be modeled as an eccentric cone around the wellbore with a significantly larger depth of penetration at the heel and a shallower depth of penetration at the toe. [34]

Because the drilling fluid is in contact with the producing zone for an extended period of time, drill-in fluids have been devised to minimize the potential formation damage. Sized calcium carbonate and sized salt fluids are the drill-in fluids used most often in such applications. Oil-based muds have also been evaluated for this purpose. A more detailed discussion of their formation damage potential is provided in several sources[35][36][37][38][39][40][41][42].

Formation Damage Caused by Completion Workover Fluids

When completion or workover operations are conducted on a well (perforating, gravel packing, etc.), the fluid present in the wellbore must minimize the impact on the near-wellbore permeability. Several decades ago, engineers realized that the use of drilling fluids during completions was inappropriate because fluids caused severe damage to the productive zone. A wide variety of fluids are now available as completion or workover fluids. A list of these fluids is provided in Table 6.1. Our discussion here focuses on formation damage issues related to these different types of completion and workover fluids.

Water-based fluids usually consist primarily of clear brines. The only problem with clear brines is that they are not ever really clear. [43][44][45] They always contain some solids, including corrosion products, bacteria, and debris from the wellbore and surface tanks. The density of the brine is maintained large enough so that the bottomhole pressure exceeds the reservoir pressure by a safe margin (typically 300 to 600 psi). Substantial amounts of solids can be pushed into the formation, resulting in a loss of permeability in the near-wellbore region. Fig. 6.6 shows the loss in permeability observed when brines with differing quantities of solids are injected into a core. Rapid reductions in permeability are observed even with relatively clean fluids. Surface filtration facilities are often used to clarify and filter completion brines, which can help to reduce the permeability impairment substantially. Most of the high-density brines used can be quite expensive. Large volumes of fluid loss can add substantially to the cost of a completion operation. An important fact to keep in mind with completion and workover fluids is that, unlike drilling fluids, they do not contain drill solids. This means that there is no effective bridging material available to reduce fluid leakoff.

When fluid-leakoff rates are very high, fluid-leakoff-control additives may be used to minimize leakoff and formation damage. Use of acid-soluble granular additives such as calcium carbonate is the most common strategy. [47][48][49][46][50][51][52] If this method proves to be ineffective, viscosifying polymers are used to reduce the amount of fluid loss. Hydroxyethylcellulose (HEC) is commonly used because it is soluble in hydrochloric acid. HEC is a poor viscosifier at higher (> 250°F) temperatures, and unbroken and unhydrated HEC in the form of fisheyes can be damaging.

Polymer fluids suffer from similar drawbacks. Severe formation damage can occur if large amounts of polymer are lost to the formation. This problem is particularly acute if the polymer is not completely hydrolyzed in the brine.

If the density requirements of the completion fluid are relatively modest, emulsions can be used as completion fluids. In these instances, the droplets that form the dispersed phase act as a filtration-control agent. Both water and oil-external emulsions have been used when reservoir pressures are low.

Oil-based fluids such as crude oil and invert-emulsion muds can be used as completion fluids. It is important to ensure that the crude oil does not contain asphaltenes or paraffins that might precipitate under changes in pressure and temperature as the fluid is circulated into the well. Several sources[47][48][49][46][50][51][52][53] provide a more detailed discussion of some of the issues summarized in this section. In addition, crude oil is flammable and messy to handle.

Damage During Perforating and Cementing

When cement is bullheaded into the annulus to displace mud, the differential pressure between the cement and the formation fluid can lead to a significant loss of cement filtrate into the formation. If, however, large volumes of cement filtrate invade the rock, the possibility of formation damage exists.

The major constituents in the aqueous phase in contact with hydrating cement are calcium silicates, calcium aluminates, calcium sulfates, calcium carbonates or bicarbonates, and alkali sulfates. Depending on the specific composition of the cement and its pH, the filtrate may be supersaturated with calcium carbonate and calcium sulfate. As the cement filtrate invades the formation and reacts with the formation minerals, its pH is reduced from > 12 to a pH buffered by the formation minerals. This rapid change in pH can result in the formation of inorganic precipitates such calcium carbonate and calcium sulfate.

Evidence of formation damage induced by cement filtrates has been clearly demonstrated in experimental studies presented in a couple of sources.[54][55] Cunningham and Smith[54] investigated the influence of cement filtrates on formation permeability and concluded that there was little evidence of fines migration or clay swelling induced by the cement filtrate. They observed severe permeability reductions of 60% to 90% in cores invaded by cement filtrate. Yang and Sharma[56] investigated the impact of cement additives such as lignin derivatives, cellulose derivatives, organic acids, and synthetic polymers on the extent of permeability reduction in cores exposed to cement filtrate. In that study, cement filtrate was injected immediately after filtration into a sandstone core. Reductions in permeability of 40% to 80% were observed up to 6 in. into the core. Most of the damage observed was attributed to the precipitation of insoluble material such as calcium carbonate and calcium sulfate in the core. The quantity of precipitate and rate of precipitation relative to fluid convection were important factors that controlled the extent and depth of permeability damage. Cement filtrates that showed fast rates of precipitation tended to damage the upstream end of the core, whereas filtrates with slow precipitation rates tended to plug the downstream end of the core or not plug the core at all. The composition of the cement played an important role in determining both the quantity and the rates of precipitation. For example, the addition of lignin derivatives or polymer reduced the quantity of precipitate and resulted in less damage to the rock. The addition of cellulose derivatives, on the other hand, increased the rate and quantity of precipitation by an order of magnitude and resulted in more damage. [56]

If the depth of invasion of the cement filtrate can be restricted to ≈ 4 in., cement-filtrate-induced damage should not be a major concern because the perforation tunnels will bypass the damage. However, in some situations in which large volumes of cement filtrate may be lost, this form of damage should be seriously considered. In such cases, the use of fluid-loss-control additives and polymers in the cement slurry needs to be evaluated carefully so that the cement is properly designed to minimize both the leakoff rate and the amount of insoluble precipitates formed in the formation.

The process of perforating is critical to well productivity because the perforation is the only channel of communication between the wellbore and the formation. During underbalanced perforating, the surge flow of fluid into the wellbore should clean the perforation tunnel of all disaggregated rock and liner debris. Any remaining debris in the tunnel could plug gravel packs during production. Even clean perforation tunnels show a narrow region of reduced permeability around them. The nature of this crushed or compacted zone around perforation tunnels created during perforating has been widely studied. [20][57][58][59][60][61][62][63][64][65][66][67][68][69][70][71][72][73][74][75][76][77][78][79] It is now well recognized that it consists of shattered grains and fines generated by the perforation charge and perhaps fines that flow in from the formation during underbalanced surge flow. The reduction in permeability in the compacted region is typically of the order of 20 to 50% but can be larger in some cases. [79] Using an optimal underbalance pressure results in better perforation performance. [58] The reasons for this are not completely understood. It is likely that too low an underbalance results in insufficient perforation cleaning and too large an underbalance results in the generation and migration of additional fines. This explanation is consistent with the observation that the optimum underbalance pressure is higher for lower-permeability formations.

Formation Damage Caused by Fines Migration

Fines migration is a recognized source of formation damage in some production wells, particularly in sandstones. [80][81] Direct evidence of fines-induced formation damage in production wells is often difficult to come by. Although most other forms of formation damage have obvious indicators of the problem, the field symptoms of fines migration are much more subtle. Indirect evidence such as declining productivity over a period of several weeks or months is the most common symptom. This reduction in productivity can usually be reversed by mud-acid treatments. A large number of wells around the world follow these patterns of reduction of productivity followed by significant improvements when subjected to a mud-acid treatment. This behavior most often suggests a buildup of fines in the near-wellbore region over a period of time. Field studies and laboratory experiments have indicated that the fines causing the permeability reduction include clays, feldspars, micas, and plagioclase. Because the mobile fines are made up of a wide variety of minerals, the clay content of the reservoir may not always be a good indicator of the water sensitivity of the formation.

Core flow tests conducted in the laboratory clearly show that if low-salinity (< 2%) brines are injected into water-sensitive rocks, large reductions in permeability (up to a factor 500) are obtained (Fig. 6.7). [82][83][84][85] It is now well established that this dramatic reduction in permeability is almost entirely a result of fines migration. Evidence is shown clearly in Fig. 6.7. Reversal of flow results in a temporary increase in permeability as the fines plug pores in the reverse flow direction.

Fine-grained minerals are present in most sandstones and some carbonates. They are not held in place by the confining pressure and are free to move with the fluid phase that wets them (usually water). They remain attached to pore surfaces by electrostatic and van der Waals forces. At "high" (> 2%) salt concentrations, the van der Waals forces are sufficiently large to keep the fines attached to the pore surfaces. As the salinity is decreased, the repulsive electrostatic forces increase because the negative charge on the surfaces of the pores and fines is no longer shielded by the ions. When the repulsive electrostatic forces exceed the attractive van der Waals forces, the fines are released from pore surfaces. [86] There is a critical salt concentration below which fines are released. [82][86] The typical magnitude of the critical salt concentration is in the range of 5,000 to 15,000 ppm (1.5%) sodium chloride. For divalent ions, this concentration is significantly lower. If a water-sensitive sandstone is exposed to brine with a salinity below the critical salt concentration, fines are released, and significant reductions in permeability are observed (Fig. 6.7).

Fines migration can also be induced by mechanical entrainment of fines, which can occur when the fluid velocity is increased above a critical velocity. [85][86][87][88][89][90] Gruesbeck and Collins, [85] among others, have measured the critical velocity for sandstones. Typical reported values of critical velocities are in the range of 0.02 m/s. This translates into modest well flow rates for most oil and gas wells.

It has been experimentally observed that critical flow velocities for fines migration are lower when the brine phase is mobile. Critical velocities are an order of magnitude higher when the brine is at a residual saturation. This implies that fines migration will be more important with the onset of water production in a well, which is indeed the case. It is often observed that well productivities decline much more rapidly after the onset of water production. In such instances, more frequent acid treatments are needed to maintain production after water breakthrough.

The extent of permeability reduction observed is also a function of the wettability of the rock. More oil-wet rocks tend to show less water sensitivity, maybe because the fines are partially coated with oil and are not as readily accessible to the brine. Significantly smaller reductions in permeability are observed when the rock is made less water-wet. [84][90]

The above observations imply that fines migration can be induced by any operation that introduces "low" (< 2%) -salinity or "high" (> 9%) -pH fluids into a water-sensitive formation. Fines migration can also be induced by "high" flow rates in the near-wellbore region, particularly in wells producing water. Examples of such operations include loss of freshwater-mud filtrate or completion fluid to the formation, steam injection in a huff 'n' puff operation for recovering heavy oil, water injection from a freshwater source, high well production rates (flow velocities above the critical velocity), and water breakthrough in production wells.

Formation Damage Caused by Swelling Clays

Swelling clays, although relatively abundant in shales, do not occur as commonly in producing intervals. Thus, problems with swelling clays are not nearly as common as those associated with fines migration. The most common swelling clays found in reservoir rock are smectites and mixed-layer illites. It was earlier thought that much of the water and rate sensitivity observed in sandstones was caused by swelling clays. However, it is now well accepted that the water-sensitive and rate-sensitive behavior in sandstones is more commonly the result of fines migration and only rarely of swelling clays. [91][92] Swelling clays reduce formation permeability by peeling off the pore surfaces and plugging pore throats, not by reducing porosity alone. Should this happen to any extent, large reductions in permeability are observed.

The presence of swelling clays is generally associated with drilling problems (i.e., hole quality and stuck pipe). This can result in poor cement jobs and sensitivity to completion fluids. Poor hole quality in the producing interval can result in significant migration of fluids behind pipe, resulting in reduced fluids control in the wellbore. These problems are encountered if either the producing formation or the intervening shales contain substantial quantities of swelling clays. When swelling clays are present in the producing interval, formation damage problems can occur because of rate sensitivity or water sensitivity. Care must be exercised to ensure that production rates and drawdowns in such wells are maintained so that the critical velocity is not exceeded in the near-wellbore region.

Clay minerals, such as smectites and mixed-layer illites, can expand in volume up to 20 times their original volume through adsorption of layers of water between their unit cells. Such 2:1 clay minerals are particularly prone to swelling because there is no hydrogen bonding between the octahedral layers of the unit cells.

Swelling is known to occur in three steps. In the first step, referred to as crystalline swelling, layers of water enter the interlayer space in the clay mineral, resulting in an increase in the C spacing of the clay mineral in steps. The size of these steps is observed to be approximately equal to the diameter of the water molecule. Extremely large swelling pressures can be generated through such an expansion of the clay lattice. The next stage in swelling is referred to as hydration swelling. This is thought to occur through the hydration and dehydration of ions entering the interlayer region. Several theories have been proposed to explain the observed repulsive hydration force observed in the presence of different cations. [93] Finally, when the interlayer spacing is ≈ 50 Å or so, free swelling occurs. This is driven primarily by the balance between electrostatic and van der Waals forces between the layers of clay. In this stage of swelling, the clay layers are sufficiently far apart that very little mechanical integrity exists in the clay. Such clay minerals are liable to be dispersed in the flowing fluid and to plug pore throats.

To prevent fines migration and clay swelling, various chemical treatments have been designed. These include polymers containing quaternary ammonium salts, [94] hydrolyzable metal ions such as zirconium oxychloride, [95] hydroxy-aluminum, [96] and polymerizable ultrathin films. [97]

Each of these methods relies on coating the fines (which are usually negatively charged) with large polyvalent cations that can attach irreversibly to the mineral surfaces. When the electrostatic charges on the fines are neutralized, the likelihood of fines migration is reduced significantly. Fines-stabilizing chemicals have been used in treatments such as acidizing, gravel packing, and fracturing. The effectiveness of such treatments is discussed extensively in Borchardt.[98]

Formation Damage in Injection Wells

Water is commonly injected into formations for three primary reasons: pressure maintenance, water disposal, or waterflooding. In such projects, the cost of piping and pumping the water is determined primarily by reservoir depth and the source of the water. However, water treatment costs can vary substantially, depending on the water quality required. In most cases, the well injectivity is a crucial factor in determining the cost of water injection. Maintaining high injectivities over long periods of time is extremely important for all water injection projects.

Historically, a great deal of expense and effort have been expended in treating water to ensure that very-high-quality water is being injected so that the injectivity of the well can be maintained over a long period of time.

There are two main properties of injection water that determine the formation damage or the injectivity of water injection wells: the total dissolved solids in the injection water and the total suspended solids (solids and oil droplets) in the injection water. [99][100][101][102][103][104]

The salinity and ion content in the injection water control two types of formation damage in an injection well: freshwater sensitivity of the formation and precipitation of inorganic scale.

In water-sensitive formations, if fresh water is being injected from a nearby lake or river, caution must be exercised to ensure that fines migration is not a major factor. This can be achieved by ensuring that the salinity is above the critical salt concentration for the rock. Injection wells are usually less susceptible to fines-migration problems than production wells because the fines being generated are pushed away from the wellbore, leading to less severe impairment in the near-wellbore region and therefore relatively small losses in injectivity. In some instances in which the reservoir contains large proportions of clays and fines, severe injectivity losses may be experienced when injecting below the critical salt concentration.

The precipitation of inorganic scale is a major concern when injecting brines with a high concentration of divalent ions. The hardness of the injection water is a good indicator of its scaling tendency. Should the water analysis indicate large concentrations of calcium, magnesium, iron, or barium, a water treatment facility that softens the water may be required. This is also an issue when injecting seawater into formations that contain brines with high salinity.

Large persistent drops in injectivity are expected when inorganic scales are formed in injection wells. Most field experience, however, indicates that the injection fluid quickly displaces the native brines away from the near-wellbore region with very little mixing. Inorganic scale precipitation resulting from incompatibility between the injection and reservoir brine is therefore not usually an issue for most injection wells. Geochemical interactions between injected fluids and the reservoir minerals can sometimes result in the formation of insoluble precipitates. Scale precipitation can also be induced by changes in pH, temperature, and state of oxidation of the brine. The formation of insoluble iron precipitates as a result of corrosion is a common source of damage in injection wells. These precipitates, mixed with other organic material, can result in severe and irreversible reductions in well injectivity. Careful analysis of both the formation brines and injected fluids and a check of the reservoir mineralogy are necessary. Checking for compatibility and ensuring that inorganic scale precipitation does not occur at reservoir temperature and pressure conditions are important when any water injection program is planned.

The presence of solids and oil droplets in the injection fluid can result in severe and rapid declines in injectivity. [99][100][101][102][103][104] If the injection pressure is below the fracture gradient and if fracturing is undesirable from a reservoir engineering or environmental point of view, small concentrations of solids can result in rapid reductions in well injectivity. As an example, 5 ppm of solids being injected into a well at 10,000 B/D computes to 45 kg of solids being injected every day. This large volume of solids can result in severe and rapid plugging of the injection well in a relatively short duration. Field experience in many parts of the world suggests that matrix injection of clean brines containing 3 to 5 ppm of suspended solids results in injection well half-lives (time it takes for injectivity to decline to half its value) of 3 to 6 months. Fig. 6.8 shows the injectivity of a well in the offshore Gulf of Mexico. Seawater was being injected into this well at the rates indicated. 101 As the figure shows, despite the relativity good quality of the water, a rapid reduction in injectivity was observed in this and other wells in this field. This reduction led to costly stimulation and workover operations in these subsea wells.

In other field experiences, water has been injected into injection wells with minimal impact on injectivity. A good example of this type of injection well behavior is the injection of produced water in Prudhoe Bay field in Alaska, where 2,000 ppm oil plus solids in the injection water has been routinely injected with relatively little impact on well injectivity. The apparent lack of formation damage is a consequence of thermally induced injection well fractures that propagate hundreds of meters into the formation. [105][106][107][108][109][110][111] A great deal of work has been done to study the impact of water quality on the growth of fractures in water injection wells and the impact of injection well fractures on reservoir sweep and oil recovery. [112][113] This discussion is outside the scope of this chapter.

When fracturing injection wells is undesirable or unacceptable, the quality of the injection water plays an important role in determining well injectivity or formation damage in injection wells. Various water clarification devices such as sedimentation tanks, sand filters, cartridge filters, flotation devices, and hydrocyclones are available. These facilities significantly prolong the life of water injection wells and significantly reduce the formation damage. An economic analysis is thus necessary to ensure that the benefits are greater than the costs.

Formation Damage Resulting From Paraffins and Asphaltenes

Perhaps the most common formation damage problem reported in the mature oil-producing regions of the world is organic deposits forming both in and around the wellbore. These organic deposits fall into two broad categories, paraffins and asphaltenes.

Crude oils contain three main groups of compounds: saturated hydrocarbons or paraffins, aromatic hydrocarbons, and resins and asphaltenes. Table 6.2 shows the gross composition of crude oils, tars, and bitumens obtained from various sources. It is evident that crude oils contain substantial proportions of saturated and aromatic hydrocarbons with relatively small percentages of resins and asphaltenes. More degraded crudes, including tars and bitumens, contain substantially larger proportions of resins and asphaltenes.

Paraffin Deposition

Paraffins are high-molecular-weight alkanes (C20+) that can build up as deposits in the wellbore, in feed lines, etc. These organic deposits can act as chokes within the wellbore, resulting in a gradual decrease in production with time as the deposits increase in thickness. This can result in producing problems unless some remedial action is taken on a systematic and periodic basis. Deposits vary in consistency from soft accumulations to hard, brittle deposits. Usually the deposits are firmer and harder as the molecular weight of the paraffin deposits increases. Sometimes paraffins and asphaltenes occur together in organic deposits.

The primary cause of wax or paraffin deposition is simply a loss in solubility in the crude oil. [114][115] This loss of solubility is usually a result of changes in temperature, pressure, or composition of the crude oil as a result of loss of dissolved gases. paraffins that have the highest melting point and molecular weight are usually the first to separate from solution, with lower-molecular-weight paraffins separating as the temperature decreases further. For example, a C60 alkane with a melting point of about 215°F will deposit at a much higher temperature than a C20 alkane with a melting point of 98°F.

The ability of the crude oil to hold the paraffin in solution is generally quantified with two indicators: a pour point and a cloud point. The procedure for measuring the pour point and cloud point may be found in ASTM manuals (D2500-66 for cloud points and D97-66 for pour points). The cloud point is defined as the temperature at which paraffins begin to come out of solution and a clear solution of hydrocarbons turns cloudy. Obviously, it is difficult to measure the cloud point for dark crude oil because cloudiness is not visible. In such cases, the presence of paraffin crystals may have to be detected with a polarizing light microscope. The pour point is defined as the temperature at which the crude oil no longer flows from its container. As the temperature is lowered, wax crystals form an interlocking network that supports the hydrocarbon liquid within it. This network of paraffin crystals is quite shear sensitive and loose when first formed but can harden and become extremely rigid as fluid is lost from it. Pour points are relatively easy to measure in the field and provide a good indication of conditions under which large quantities of paraffin will fall out of solution in crude oils.

The most common cause of loss of solubility of the paraffin in the crude oil is a decrease in temperature, which may occur for a variety of reasons[116]: cooling produced by the crude oil and associated gas expanding through the perforations, gas expansion while lifting fluids to the surface, radiation of heat from the tubing to the surrounding formation induced by intrusion of water into or around the wellbore, and loss of lighter constituents in the crude oil because of vaporization. Several other possible reasons for a decrease in temperature can be envisioned. In offshore installations, for example, paraffin problems are usually associated with the rapid change in temperature as the crude oil from the wellbore enters subsea pipelines that are immersed in seawater at 4°C. Large volumes of paraffins can be deposited on the surfaces of the pipelines, which requires periodic pigging.

Pressure itself has little or no influence on the solubility of paraffin in crude oil. However, it does have a significant impact on the composition of the crude oil. Reductions in pressure usually lead to loss of volatiles from the crude oil and can induce the precipitation of paraffins. This is the primary reason why paraffin problems are more common in the more mature regions of the world. As the reservoir pressure is depleted and the lighter components of the crude oil are produced in preference to the heavier fractions, the likelihood of paraffin precipitation is significantly increased.

For paraffin deposition to be a significant problem, the paraffin must deposit on the pore walls or the tubing surface. If the paraffin remains entrained in the crude oil, it usually offers few production problems. Several factors influence the ability of paraffin to deposit on the pipe walls:

  1. The presence of water wetting the surfaces of the pipe tends to inhibit paraffin deposition. In addition, water has a higher specific heat than oil, which increases flowing temperatures.
  2. Pipe quality plays an important role. Rusty pipes with large surface area and numerous sites for paraffin crystal formation offer an ideal location for paraffin deposition. Paraffin adheres to rough surfaces better than smooth surfaces.
  3. The temperature profile in the near-wellbore region or within the pipe plays an important role in determining whether the paraffin will deposit on the walls or will continue to be entrained with the fluid.

The injection of fluids such as stimulation fluids or injection water into the wellbore can often induce paraffin deposition problems. This is particularly true if the surface temperature is significantly colder than the reservoir temperature. Field cases documenting paraffin precipitation during fracture stimulation are provided in McClaflin and Whitfill.[114]

Removal of Paraffin Deposits

Paraffin accumulations are removed by methods that can be broadly placed into three categories: (1) mechanical removal of paraffin deposits, (2) the use of solvents to remove paraffin deposits, and (3) the use of heat to melt and remove the wax. Mechanical methods such as scrapers, knives, and other tools are most commonly used to remove paraffin deposits in the wellbore. They can be very effective and are relatively inexpensive.

The most common solvent used to remove paraffin from tubulars and the near-wellbore region is crude oil. Hot oiling is the least expensive method, commonly used on stripper wells to remove paraffin deposits. Lease crude taken from stock-tank bottoms is heated to temperatures of 300°F or more. This heated oil is then injected or gravity fed into the tubing or annulus (more common). The high temperature induces solubilization of the paraffin deposits in the injected crude, which is then produced back to the surface. Hot oiling has been used successfully to remove paraffin deposition but can result in formation damage. The use of hot salt water to melt the paraffin may be a safer approach.

Solvents, both organic and inorganic, have been used in the past. These include crude oil, kerosene, diesel, and surfactant formulations that can solubilize the paraffin. Organic solvents that consist of a blend of aromatics are usually used to remove mixtures of paraffin and asphaltene deposits. However, the cost of such treatments can be significantly higher than that of hot oil or water treatments.

Steam has been used in a number of cases in which severe paraffin problems have resulted in plugged tubulars. The lack of solubility of paraffin in hot water necessitates the use of surfactants with steam or hot water so that the melted paraffin can be removed.

Methods for Preventing Paraffin Deposition

Several mechanical adjustments can be made in the production string that can minimize the likelihood of paraffin deposition. In general, these steps are designed to minimize the cooling of the crude oil as it is produced to the surface. This can be accomplished by designing pumping wells or tubing sizes and gas lift systems that maximize the flow of oil to the surface and minimize the heat lost to the surrounding formations. Use of more expensive methods such as plastic coatings on tubulars and electrical heaters is severely limited by economics.

Paraffin inhibitors are a class of compounds that consist of crystal modifiers that prevent the deposition of paraffin onto pipe surfaces. These surface-active materials retard paraffin deposition by inhibiting the adhesion of paraffin to sites on the tubing walls. Surfactants used in these applications include wetting agents, dispersants, and crystal modifiers. [116][117] Each of these chemicals needs to be tested for a specific crude oil to evaluate its effectiveness.

Asphaltene Precipitation

High-molecular-weight constituents of crude oil containing nitrogen, sulfur, and oxygen (N, S, and O) compounds are referred to as asphaltenes. This broad class of compounds is clearly not hydrocarbon because these compounds contain a large portion of heteroatoms in their structure. Lower-molecular-weight NSO compounds are referred to as resins. The separation of crude oil into resins and asphaltenes and other constituents is based primarily on solubility. Asphaltenes and resins are generally defined as the pentane-insoluble fraction of the crude oil. [118]

The average molecular structure of an example asphaltene fraction from a crude oil from Venezuela is shown in Fig. 6.9. [118] It consists primarily of condensed aromatic rings associated with aliphatic tails. The polynuclear aromatic rings associate with each other through their π electron systems to form clusters of stacked rings, as shown in the figure. In crude oils, these asphaltene structures are dispersed and maintained in suspension by the action of resins. If sufficient quantities of resin molecules are present in the crude oil, the asphaltenes remain dispersed and in solution. However, the addition of large quantities of alkanes or removal of the resin fraction can result in a loss of solubility because the asphaltene molecules associate with each other, forming large aggregates or micelles, and precipitate out. These micelles or aggregates are visible under optical microscopes as dark, solid aggregates. Precipitation of asphaltenes occurs through the formation of such aggregates. The solubility of asphaltenes is therefore a function of temperature, pressure, and the composition of the crude oil. Any action that affects the compositional balance of the crude oil can affect the ability of the oil to maintain the asphaltenes in solution.

A very common example of the change in composition of a crude oil is what occurs during pressure depletion in a reservoir. As shown in Fig. 6.10, the solubility of asphaltene is a minimum at the bubblepoint pressure. [119] This has important consequences for predicting where asphaltene precipitation will occur in a reservoir. As the reservoir is depleted and the bubblepoint pressure is achieved lower in the tubing or even in the formation itself, the possibility of asphaltene deposition occurs at these locations. Indeed, in studies published in the literature, the location of asphaltene deposition is observed to move from the top of the tubing to the bottom and into the reservoir over a period of time as the reservoir pressure is depleted and the location where the bubblepoint pressure is reached moves further out toward the reservoir.

Asphaltene deposition can also be induced by changes in composition of the crude oil through injection of fluids such as CO2 or lean gas. [120][121] Several studies have documented the possibility of asphaltene precipitation during lean gas and CO2 injection (Browne et al.[39] and Zain and Sharma[40]). Large changes in temperature can also induce asphaltene deposition. [122][123] In such cases, deposits of paraffin and asphaltene are commonly observed together. The asphaltene particles frequently act as nucleation sites for paraffin crystals.

Removal of Asphaltene Deposits

Removal of asphaltene deposits also requires the use of solvents or mechanical devices. However, the solvents used for asphaltene removal are quite different from those used for paraffins. Because asphaltenes are soluble in aromatic solvents, mixtures of aromatic solvents such as xylene have been used to remove asphaltene deposits. [124] It should be noted that solvents such as diesel and kerosene that are primarily straight-chain alkanes should not be used because they may induce asphaltene precipitation.

Formation Damage Resulting From Emulsion and Sludge Formation

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. [125] 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.

Formation Damage Resulting From Condensate Banking

As shown in Fig. 6.11, gas/condensate reservoirs are defined as reservoirs that contain hydrocarbon mixtures that on pressure depletion cross the dewpoint line. In such instances as when the bottomhole pressure is reduced during production, the dewpoint pressure of the gas is reached in the near-wellbore region. This results in the formation of liquid hydrocarbons near the wellbore and in the reservoir. As the liquid hydrocarbon saturation in the near-wellbore region increases, the gas relative permeability is decreased, resulting in significant declines in well productivity. [126][127] An example of this is shown by the data in Fig. 6.12. Here, a substantial reduction in well productivity is obtained as the average reservoir pressure declines below the dewpoint for a well in the Arun gas field. This mechanism of formation damage is related primarily to changes in fluid saturation in the near-wellbore region, resulting in decreases in gas relative permeability.

The buildup of the condensate bank and its consequences on well productivity have been well studied in the literature.[129][130][131][132][133][128][134][135][136][137][138] Early predictions of productivity loss because of condensate dropout indicated that a loss in PI by a factor of 5 to 8 would be expected because of liquid buildup. [131][132][133] However, the decline in PI observed in many of the fields is much smaller (a factor of 2 to 4). Further investigation of this problem indicated that the high gas flow rates in the near-wellbore region can result in stripping out of the liquid hydrocarbon phase in regions around the wellbore. This stripping-out effect has been quantified through capillary-number-dependent models for relative permeability of the gas phase. [130][138] With this phenomenon properly accounted for, good agreement with field observations is obtained (Fig. 6.12).

In addition to liquid dropout, several other important phenomena can play an important role in determining well productivity and need to be carefully evaluated. Because of the high flow rates of gas in the near-wellbore region, non-Darcy effects may be significant and may need to be accounted for. [128][134][135][136] The combination of non-Darcy flow, capillary-number-dependent relative permeability, and phase behavior makes the problem rather complex, and numerical simulations are needed to fully capture all the physics of the problem. Clearly distinguishing the effects of liquid dropout from non-Darcy effects from production performance and pressure-transient tests can be challenging and may require compositional numerical models. Such models are widely available and have been used in estimating gas-well productivity, including condensate dropout.

The most direct method of reducing condensate buildup is to reduce the drawdown so that the bottomhole pressure remains above the dewpoint. In cases when this is not desirable, the impact of condensate formation can be reduced by increasing the inflow area and achieving linear flow rather than radial flow into the wellbore. This minimizes the impact of the reduced gas permeability in the near-wellbore region. Both of these benefits can be achieved by hydraulic fracturing.

Hydraulic fracture stimulation is the most common method used to remedy condensate buildup problems. The creation of a fracture results in a significant decrease in the drawdown needed to produce the well. In addition, buildup of a liquid hydrocarbon phase on the faces of the fracture does not affect well productivity as significantly as in radial flow around the wellbore. Additional details of this are available elsewhere. [137]

Recently, the use of solvents and surfactants such as methanol has been suggested as a way to stimulate gas/condensate wells in which hydraulic fracturing is not the preferred option. [139][140] The use of methanol results in removal of the condensate and water banks around a wellbore. This allows gas flow to be unimpeded through the near-wellbore region, resulting in smaller drawdown and slower accumulation of condensate. Within certain ranges of temperature and pressure, the presence of a residual methanol phase in the near-wellbore region can also result in the inhibition of condensate formation for a period of time.

Formation Damage Resulting From 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, however, 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.

Formation Damage Resulting From 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. [141][142]

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. [143] Water blocks will generally be more troublesome for low-permeability, depleted gas wells in which the capillary number is significantly less than 1. [144][145]

There are three primary methods used to remove water blocks: (1) surging or swabbing the wells to increase the capillary number temporarily; (2) 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, and (3) the use of solvents or mutual solvents such as alcohols to solubilize the water and remove it through a change in phase behavior. [146][147] 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.

Formation Damage Resulting From 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. 6.12). Wettability alteration to less water-wet conditions is therefore clearly undesirable.

The loss of surfactants in drilling and completion fluids, [148][149][150] 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. [151] 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. [152] 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.


This chapter has presented methods to measure and quantify formation damage in oil and gas wells. Several different mechanisms responsible for causing formation damage were discussed. A better understanding of these mechanisms allows us to make recommendations for drilling, completion, and production operations that will reduce the extent of formation damage and maximize well productivity.


A = contains the physical skin, S
Aqsc = laminar pressure drop
B = proportional to the non-Darcy coefficient, D
Bqsc2 = inertial or non-Darcy pressure drop
c = compressibility
Dqsc = inertial effects
F = well flow efficiency
J = productivity index
k = overall permeability, md
kI = initial permeability, md
kh = permeability and formation thickness
m = slope
n = exponent
p = pressure
pb = bubblepoint pressure
pR = average reservoir pressure
pwf = flowing bottomhole pressure
pws,1hr = extrapolated shut-in pressure at a shut-in time of 1 hour
ΔPskin = additional pressure drop caused by formation damage
q = flow rate
qi = flow rates
qo = oil flow rate
qsc = volumetric flow rate, surface conditions
re = external boundary radius
rw = well radius
S = skin factor
T = temperature
t = time
tp = well that has been producing for a time
Δt = fixed time interval
z = real gas compressibility factor
μ = viscosity
μg = gas viscosity


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  47. 47.0 47.1 _
  48. 48.0 48.1 _
  49. 49.0 49.1 _
  50. 50.0 50.1 _
  51. 51.0 51.1 _
  52. 52.0 52.1 _
  53. _
  54. 54.0 54.1 _
  55. _
  56. 56.0 56.1 _
  57. _
  58. 58.0 58.1 _
  59. _
  60. _
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  79. 79.0 79.1 _
  80. _
  81. _
  82. 82.0 82.1 82.2 _
  83. _
  84. 84.0 84.1 _
  85. 85.0 85.1 85.2 _
  86. 86.0 86.1 86.2 _
  87. _
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  89. _
  90. 90.0 90.1 _
  91. _
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  96. _
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  98. _
  99. 99.0 99.1 _
  100. 100.0 100.1 _
  101. 101.0 101.1 101.2 _
  102. 102.0 102.1 _
  103. 103.0 103.1 _
  104. 104.0 104.1 _
  105. _
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  107. _
  108. _
  109. _
  110. _
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  113. _
  114. 114.0 114.1 _
  115. _
  116. 116.0 116.1 _
  117. _
  118. 118.0 118.1 118.2 _
  119. 119.0 119.1 _
  120. _
  121. _
  122. _
  123. _
  124. _
  125. _
  126. _
  127. _
  128. 128.0 128.1 128.2 128.3 _
  129. _
  130. 130.0 130.1 _
  131. 131.0 131.1 _
  132. 132.0 132.1 _
  133. 133.0 133.1 _
  134. 134.0 134.1 _
  135. 135.0 135.1 _
  136. 136.0 136.1 _
  137. 137.0 137.1 _
  138. 138.0 138.1 _
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  148. _
  149. _
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  151. _
  152. _

SI Metric Conversion Factor

Å × 1.0* E–01 = nm
bbl × 1.589 873 E–01 = m3
ft × 3.048* E–01 = m
°F (°F – 32)/1.8 = °C
gal × 3.785 412 E–03 = m3
in × 2.54* E + 00 = cm
lbm × 4.535 924 E–01 = kg
psi × 6.894 757 E + 00 = kPa


Conversion factor is exact.