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
• To achieve high rates of penetration so that rig time and well cost can be minimized

These primary considerations do not include well productivity concerns. A growing recognition of the importance of drilling-induced formation damage has led to the use of drill-in fluids (fluids used to drill through the pay zone) that minimize formation damage. This page discusses the formation damage that may be associated with various types of drilling fluids.

Drill-in fluids to reduce formation damage

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
• 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. Traditional water-based muds, oil-based muds, and some special formulations of drill-in fluids for fractured formations and unconsolidated sands are discussed below.

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
• 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.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:

• State of dispersion of solids in the mud
• Size and concentration of solids and polymers in the mud
• Pore throat size or permeability of the formation
• pH and salinity of the filtrate
• 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. 1 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.

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  Fig. 1—(a) Schematic of a gun perforation showing zone of crushed rock around tunnel. (b) Effect of damage by mud while drilling on well productivity when perforated with a nondamaging fluid is permeability of crushed zone around perforated tunnel as a percent of initial permeability.

In some instances, deep penetration of drill solids can occur. Fig. 2 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. 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.

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  Fig. 2—Depth of permeability damage cause by mud invasion for muds with different degrees of bentonite dispersion. All muds contain 4% bentonite by weight.

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, 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. Such relative permeability effects are referred to as water-blocks and are discussed in 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.

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.

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, 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.

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.

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.

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. There are at least two situations in which an external filter cake does not form across of the face of the formation:

• Lost circulation
• 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. 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.

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. 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.

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. Sizing of these granular or fibrous additives has been discussed in detail in Di and Sharmaand Singh and Sharma.

Horizontal wells

Horizontal wells are more susceptible to formation damage than vertical wells for the following reasons.

• Pay zone in a horizontal wellbore comes into contact with a drilling fluid for a much longer period than a vertical pay zone (days compared with hours)
• 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
• 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
• 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. 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.

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 by several sources.

Noteworthy papers in OnePetro

1. P.A. Francis; M.R.P. Eigner; I.T.M. Patey. 1995. Visualisation of Drilling-Induced Formation Damage Mechanisms using Reservoir Conditions Core Flood Testing. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, May 1995. SPE-30088-MS. https://doi.org/10.2118/30088-MS

2. Karl Ronny Klungtvedt; Mahmoud Khalifeh; Arild Saasen; Bjørn Berglind; Jan Kristian Vasshus. 2021. Preventing Drilling Fluid Induced Reservoir Formation Damage. Presented at the SPE/IADC Middle East Drilling Technology Conference and Exhibition, Abu Dhabi, UAE, May 2021. SPE-202187-MS. https://doi.org/10.2118/202187-MS

3. Y. Ding; G. Renard; B. Herzhaft. 2008. Quantification of Uncertainties for Drilling-Induced Formation Damage. SPE Prod & Oper 23 (02): 221–231. SPE-100959-PA. https://doi.org/10.2118/100959-PA

4. Deepankar Biswas; P. V. Suryanarayana. 2004. Estimating Drilling-Induced Formation Damage Using Reservoir Simulation to Screen Underbalanced Drilling Candidates. Presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, February 2004. https://doi.org/10.2118/86465-MS

External links

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See also

Formation damage

Drilling problems

PEH:Formation_Damage