1 Feb, 2018
How to Prevent Formation Damage
The term "formation damage" was first used in the literature in the early 1950's and since that time a large number of technical papers have been written addressing the subject. The early concerns with formation damage, based upon published literature, appear to have been with damage from swelling clays and then evolved more into concern for fines migration problems. Maly, 1976, pointed out that close attention to the smallest job detail is vital to minimizing formation damage. Today, the industry recognizes formation damage can be from many sources or well activities, such as drilling, running and cementing pipe, perforating, stimulation fluids, production methods, paraffin, asphaltenes, scales, workover fluids and operations, etc. The effect of these activities can be summed as damage associated with either the movement and bridging of fine solids or chemical reactions resulting in precipitates and changes in wettability. As more interval is exposed the problems can become more dramatic. This is particularly true in horizontal and multilateral wells. A 1994 JPT Distinguished Author Series paper (Experts Share Views on Formation Damage Solutions) provides some interesting thoughts about formation damage, primarily related to horizontal wells. Other issues reducing productivity from wells can be water coning, condensate buildup, wellbore configuration, etc.
Formation damage is important in both production and injection wells. Damage in producing wells will reduce the oil and gas production rates and may leave some intervals inadequately drained. In injection wells, formation damage adversely affects sweep efficiency and recovery factors.
A summary of many of the sources of damage is shown in Figure 1-1 below.
Figure 1-1. Sources of Damage
The effect of damage on production rates can be calculated using Darcy’s equation in its simplest form. By determining the average permeability, which would include a damaged or stimulated near wellbore area, and using the undamaged formation permeability, the production rate influenced by the damage or stimulation can be calculated (Craft and Hawkins,1959).
Figure 1-2. Sources of Damage
Figure 1-3. Damage Area Around Wellbore
As an example, the equations assume a well is located in a reservoir with a drainage radius, re, of 660 feet (201 meters) with a wellbore radius, rw, of 0.33 feet (0.1 meters), a permeability in the damaged zone, ks, of 1 millidarcy and a permeability in the undamaged formation, ke, of 100 millidarcies with the damaged zone radius, rs, being 2 feet (0.61 meters). With this damage around the wellbore the average permeability, Kavg, would be:
Kavg = Average permeability through reservoir and near wellbore damage
ks = Permeability in the near wellbore area, damaged (skin) or stimulated
ke , ko = Permeability away from wellbore, in the undamaged or non-stimulated area
re = Drainage radius for the reservoir feeding the wellbore
rw = Radius of the wellbore
Js = Production rate through the damaged or stimulated well
Je = Production rate without any damage or stimulation
Using Darcy's equation for an oil flowing which has a viscosity of 1.0 cp with a pressure drop, (Pe – Pw) of 100 psi the production rate, Q, would be:
If the well were undamaged or damage removed by acidizing, the production rate would be:
Also, if the damage around the wellbore was removed and the original, undamaged permeability was increased to 200 md (for the 2 feet radius) in the process the production rate could be calculated as follows:
and for the same drawdown,
These examples all relate to actual formation damage often referred to as skin damage. When a skin value is determined, a positive value indicates damage and the higher the value, the more damage we have. A negative value indicates stimulation, i.e., the area around the wellbore has a permeability greater than the formation. This could result from acidizing as well as hydraulic fracturing. The skin effect, S, was introduced by Van Everdingen, 1953, and refined by Hawkins, 1956, and is defined by the equation shown in the following figure. The equation does point out that the degree of permeability reduction is more significant than the depth (radius) of the damage.
The total skin would include any flow impairment from mechanical, well configuration effects. This can be an additional pressure drop, sometimes referred to as pseudo skin effects, and can be caused by inadequate perforations, tubing I.D. too small, surface equipment, etc. Only attributing the total skin to damage outside the wellbore (formation) is a common mistake. The pseudo skin, if present, must be subtracted from the total skin to estimate the true skin associated with real formation damage. Pseudo skin is also referred to as rate sensitive skin. Where pseudo skin exists, as the production rate is reduced, the pseudo-skin is reduced. Acidizing or other stimulation attempts would not be expected to reduce this type of ‘damage’. Another rate sensitive skin is that from turbulent flow caused by producing wells at high flow rates resulting in turbulent flow in the perforations and/or in the near wellbore area. Additionally, producing oil wells at a high drawdown can cause the pressure at the wellbore to drop below bubble point resulting in gas evolution, an additional phase (gas) and a reduced relative permeability (to oil) near the wellbore. Producing wet gas wells at high drawdown can also cause an additional phase (condensate) to come out of solution resulting in a relative permeability effect.
To remediate damage effectively, it is important to accurately diagnose the damage type. Too often we use trial and error treatments hoping to get results rather than doing the proper analysis of the situation first.
To help in this analysis, an understanding of the types of formations with which we deal is necessary. To better understand the formations, a look into the geology and depositional environments, as well as a microscopic look at the pore space which will be invaded, is also necessary. Understanding damage mechanisms are key to prevention of formation damage. Even with the best of knowledge and methods, formations are still going to be damaged to some degree and an evaluation of the degree and type of damage existing is important prior to deciding on remediation. There are those situations where it is less expensive to accept some formation damage while drilling a well and using an inexpensive acid treatment to remove the damage after the well is cased and perforated. Of course, there are those situations where this initial damage is so severe that it cannot be removed with a matrix treatment and perhaps a more expensive hydraulic fracturing treatment will be required to bypass the damage. Also, with many horizontal wells being completed open hole or with very little zone isolation, the ability to remove formation damage can be more difficult. Thus, damage prevention becomes critical. Although these evaluation methods are somewhat secondary to the objectives in this text, they are presented to give an overview of the methods available. A discussion of hydraulic fracturing is included since in some cases this technology is used to bypass damage as well as to truly stimulate reservoirs. The approach taken for this tip is to present the basics in damage removal such that the reader will be able to safely navigate through the many options he/she has in selecting the best approach for the well(s) in question.
By paying close attention to all aspects of well work, formation damage can be kept to a minimum. Also, by keeping good records of materials and practices used, identification and detection of problems can be more accurate. Improved knowledge of the problems will result in improved efficiency in remedial treatments.
The first opportunity we have to damage the formation is during the drilling of the well. This damage can be caused by invasion of the mud filtrate and particulate material in the mud. The particulate material comes from that added for weighting, for fluid loss control and other additives as well as drill solids. Earlier work reported by Abrams from other's investigations of the effects of drilling mud particulate invasion on rock permeability can be summarized as follows:
1. Invasion and formation damage occur with all muds
2. The depth of invasion and level of impairment can be controlled, to a certain degree, by designing the mud to include bridging material
3. The effectiveness of the bridging material in reducing invasion is a function of the concentration and particle size of the material and of the pore sizes of the formation rock
4. Damage is most likely to occur in higher permeability formations; most muds contain sufficient quantities of particles, including cuttings, in the size range required to bridge lower permeability rocks
5. Where invasion occurs, backflushing does not always remove the impairment
These results were based primarily on tests performed on linear, consolidated cores using fluids that in many instances were not designed to minimize invasion. Although depths of invasion as great as 12 inches, 30.48 cm, have been reported, impairment with competent muds has been found to occur within several inches of the wellbore. Abrams extended this reported work to include analysis of particle size that would effectively bridge the pores at or near the wellbore wall. Additionally, his work was based upon laboratory experiments where the tests were conducted with radial flow through simulated as well as formation core samples.
The results of his study concluded:
Muds containing bridging material that meets the one-third rule for bridging impair rock to depths less than 1 inch, 2.54 cm. The rule requires that the mud must contain bridging material with diameters greater than or equal to one-third the formation median pore size at concentration levels of at least 5% by volume of the mud solids.
Matching procedures based on the calculation of the rock pore sizes from capillary pressure or permeability data, which are generally available for important fields, can be used for selecting additives. Silica, calcium carbonate, wax and asphalt solids are available in different size ranges and can be used for this application.
Although this work was published in 1977 it is still valuable information to us today. There are many additives available for control of mud fluid loss as well as loss circulation materials. The particle sizes of these materials may be sized such that they do not allow much mud filtrate loss to the formation nor will the particulates themselves enter into the formation pores assuming the Abrams criteria above is met.
Other factors that affect drilling fluid invasion include:
High permeability mud cake. Even though the particulate solids may be too large to enter the pores they may not be sufficiently sealed to give a low permeability. It is thought a particle size distribution, some small and some large particles are needed to give a low permeability wall cake.
High degree of overbalanced pressure. When possible this should be kept to a minimum. However, as has been discussed, a certain mud weight will be required to maintain hole integrity and well control. This may be especially true with horizontal wells. We are seeing an increasing interest in underbalanced drilling[2,3] primarily for horizontal wells and this is a method which should greatly reduce formation damage. As always, concerns for well control should take priority when selecting mud weight. With the interest in underbalanced drilling we are now hearing about underbalanced completions. This appears to be a normal extension to underbalanced drilling with advantages being reduced fluid loss and improved productivity (less damage).
Extended formation drilling fluid contact time can obviously cause more fluid invasion and, therefore, damage. Again this would be of concern primarily in horizontal wells. It can be an issue in non-horizontal wells when leaving an upper zone open while drilling deeper. So, when long exposure times are expected extra care should be taken to assure the mud is compatible with the formation or at least the damage zone is shallow.
Since most horizontal wells are not cased and perforated, damage prevention is of utmost importance. This can be best accomplished by providing an easily removed filter cake that has prevented excessive filtrate loss. Halliday and Ryan, et al discuss drill-in fluids for controlling formation damage and mud clean-up in horizontal wells.
To gain insight into how damaging a drilling or completion fluid may be, laboratory tests are always recommended. These tests evaluate the detrimental effects of filtrate as well as any particulate material in the mud.
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Formation damage during actual cementing (placement of the cement) is not thought to be a significant problem. However, peripheral to the actual cementing, there can be several problems resulting in formation damage or a poor completion. The intent of the cement is to isolate the productive zones from unwanted fluids. If the cementing is not carried out correctly, a poor cement job may result and unwanted fluid invasion into the productive intervals may occur. The result from this can be lost production. Where this is the case, often a cement squeeze treatment is carried out and if not done properly the formation can be broken down and cement invasion can cause further damage. Prior to conducting the primary cementing operation, the hole should be conditioned. This is the first step to getting better cement jobs and less potential for formation damage.
Drilling mud should be circulated to condition and clean the hole prior to running casing. Mud circulation should continue for sufficient time to help clean the hole of drilled solids that may bridge during cement placement. The well should be circulated at a pump rate equal to or higher than the drilling circulation rate, if allowed by the fracture gradient. This will aid in the cleanup of the hole. Additionally, the hole should be circulated long enough to bring any gas entrained in the drilling mud to the surface. When running casing it should be run in a manner that will allow for drilling fluids to be displaced from the hole to the pits. Excessive running speed could force whole mud into the formation. Casing centralizers and scratchers can help improve the cement job. Centralizers improve the position of the pipe in the hole for better mud displacement and centralization for cementing. Scratchers will help loosen excessive wall cake and high yield point, stagnant drilling mud. While running the casing, excessive filter cake can accumulate on scratchers, centralizers and collars. This could prevent circulation after the casing is on bottom. Circulating approximately every 1000 to 3000 feet, 305 to 915 meters while running in the hole will assist in removing any filter cake that has collected.
As mentioned, the potential formation damage problem with the actual cementing of the casing is the filtrate loss from the cement and preflush fluids to sensitive formations and formation fluids. A preflush or spacer fluid is designed to separate the drilling fluid and the cement slurry. The spacer must be compatible with both fluids while controlling both formation pressures and lost circulation zones. These fluids are usually high fluid loss and/or abrasive fluids. This high fluid loss is expected to occur into the permeable zones and can cause damage. Spacer fluids are designed to thin the muds or to displace some of the mud and filter cake. Fresh water, brine, chemically treated water, emulsions or an oil are used as spacer fluids.
The base fluid chosen will depend upon the drilling fluid in the hole, the cement being used and the formation. Fresh water may cause formation damage from water blocks, emulsions and the hydration and/or migration of clays and silts in the formation. Brines may or may not be compatible with the cement slurry. Calcium chloride brines are not compatible with a neat cement slurry. The brines generally cause less formation damage, however, they may form emulsions and can be incompatible with drilling fluids. A chemical spacer can prevent these problems if properly selected. Oil based muds will normally require an oil based spacer. This helps in protecting formation clays. Many oil based muds leave the casing and hole in an oil wet condition. For good cement bonding and hydrocarbon production it is preferred to have the system water wet. If possible, a water wetting surfactant should always be added to the spacer fluids. Mud displacement prior to cementing is usually conducted in turbulent flow. Where low viscosity fluids are used they are circulated in turbulent flow and contain mud thinners and dispersants that penetrate the mud and reduces its viscosity. Often the fluid will contain low concentrations of abrasive solids to scour the hole in order to help remove mud cake. The solids are especially useful when turbulent flow conditions cannot be obtained. Where higher viscosity fluids are used the objective is to remove the mud by viscous displacement. The higher the viscosity the more difficult it is to obtain turbulent flow.
We normally do not expect whole cement particles to invade the formation. Most cement particles range in size from 20 to 100 microns which are too large to invade most formation pores. However, the water in the cement slurry could be a source of formation damage due to its high pH. Properly designed and mixed cements should lose only a small fraction of their mix water. Even when a cement slurry contains too much water, the volume of cement filtrate invading the formation is minor in comparison to fluid loss from preflushes and the drilling mud. In many cases the cement is designed for fluid loss control so this does not happen.
Where holes are cased and cemented the next operation is perforating the pipe and formation. The objective is to obtain adequate communication with the formation and hopefully penetrate any formation damage existing. The proper perforating job can reach these objectives. However, a poor perforating job could actually create more problems than it overcomes. It has been reported in the industry that in some cases only one out of four shots are effective. Effective perforating, in order to reduce formation damage and to optimize contact beyond formation damage, includes several factors such as
a) perforating fluid
b) perforating gun selection
c) depth of penetration
d) rock stress
e) wellbore pressure in relation to formation pressure and stresses
f) perforation diameter
g) shot density
h) perforation debris
i) perforation compacted zone
j) partial zone perforation
k) perforation phasing
The perforating fluid is potentially damaging to reservoir permeability. This is especially true in overbalanced perforating where the fluid being used is not compatible with the formation, for example, where the drilling mud is the fluid in the hole when perforating. There is considerable overbalanced perforating now being conducted but it is with selected fluids and extreme overbalanced conditions. Clean, non-damaging fluids should be used during perforating. Common perforating fluids are hydrochloric acid, organic acids, non-acid water based fluids (e.g., 2% KCI water) and oils. The concern with hydrochloric acid is its corrosiveness, particularly at high temperatures. This would require high concentrations of corrosion inhibitors which will oil wet sandstones and be damaging. The more common acids used for perforating fluids are formic and acetic acids. These are less corrosive and usually adequate for reaction with the perforation tunnel and the formation to prevent formation damage. Oil based perforating fluids can contain water wetting surfactants such that they will leave the formation water wet and may be a good choice when perforating very dirty sands.
The API has a large data base available from standard tests that indicates the amount of permeability reduction caused by various perforating guns and charges. The amount of formation damage or permeability reduction from gun debris is difficult to estimate. Powdered metal charge liners were introduced to reduce damage from liner debris. The damage is finite and should be considered along with other factors. The perforation compacted zone is caused by the perforating charge firing and penetrating the casing, cement sheath and formation. The material in the path of the jet is broken up and pushed out of the way. Thus, the formation around the perforation tunnel is crushed and some reports show a permeability reduction of as much as 90%.
Formation damage can occur during subsequent well completion work, following perforating as well as during workovers. Workover operations after perforating may also require non-damaging fluids. These workovers may require the killing of the well, so, well control is obviously important. To stop loss of fluid during these operations viscous pills are often used, particularly in high permeability formations. These fluids should be chosen such that they are easily removed when the well control situation is taken care of, e.g., tubing has been run, etc.
The type of initial completion will play a major role in the amount of damage that can be tolerated. The success of a natural completion is dependent upon minimizing formation damage. Much of the initial damage in a high pressure, high permeability reservoir may be overcome just by producing the well. However, this approach should not be relied upon. Well completions involving sand control using gravel packing can be very sensitive to formation damage. These are usually high permeability reservoirs and it is in these types of completions that the completion fluids need to be extremely clean and filtered. All completion fluids should be clean and the degree of filtration would depend upon the completion type and formation characteristics. There are several types of filtration units available. Cartridge filters are made of a permeable matrix of material or filament wrapped around a perforated plastic or metal tube. Solid particles are blocked or filtered out as the fluid flows through the permeable material into the center tube. The permeable matrix is made from a variety of materials such as cotton, paper, polyester, polypropylene or fiberglass. The filters are rated by pore sizes such as 1, 2, 5, 10 and 25 microns. This rating is either nominal or absolute to the size of the particles they will remove. A nominal rated filter can be expected to remove about 90% of the particles larger than their nominal rating. The wound, wrapped, cartridges have a broad range of pore sizes and a relatively small surface area. Large particles are trapped in the outer layers and progressively smaller particles lodge nearer the center. High flow rates and pressures cause inefficiency. They should be constantly monitored and replaced when they begin to plug or when fluid bypass begins to occur. Pleated cartridge filters have greater effective surface area, a narrow range of pore sizes, are only a few layers thick and tend to last longer than conventional cartridge filters. They are given an absolute rating based on the diameter of the smallest hard spherical particle that will be retained under specific test conditions. Absolute rated cartridge filters will achieve a sharp cutoff at their rated size. Most of the particles larger than their rating will be removed. The absolute filters will usually become plugged with particulate material much faster than nominally rated filters. Filter cartridge performance can be compared by using a Beta ratio. Beta ratio is defined as:
Beta ratio is converted to Removal Efficiency as:
Acidizing or Hydraulic Fracturing
Where the initial completion will include acidizing or hydraulic fracturing the formation damage from sources presented earlier are less important. A major concern with these types of completions is the damage which may occur on subsequent well work, i.e., loss of fluids which are dirty or otherwise incompatible with the formation. When pumping fluids down tubulars for whatever purpose we should always be concerned about the material in the tubulars and it going to the formation creating damage. Of concern is scale from produced water, iron from millscale and corrosion, pipe dope, paint, etc. By cleaning the pipe prior to pumping acids and other fluids to the formation some of this type of damage can be prevented.
Initial completions with horizontal wells in unconsolidated formations often includes a sand exclusion device (screen) without gravel packing. In these cases the formation sand is allowed to collapse around the screen and sand control is accomplished with the screen. A potential problem with this completion is the filter cake material, formation fines, drill solids, etc plugging of the screens. The removal of the filter cake and other solids prior to allowing production through the screen is important to prevent screen plugging.
Quality control in well work is important to prevent damage. It is not uncommon for formations to be further damaged when stimulation treatments are attempted. This can be caused by poor quality control at the well site as well as from the wrong chemicals being used for the formation being treated.
Formation damage can adversely affect production rates, efficiency and recovery factors of a well. Research has shown that there are many causes of formation damage, and the effect of these sources and well activities can be summed as damage associated with either the movement and bridging of fine solids or chemical reactions resulting in precipitates and changes in wettability. It is important to be knowledgeable about what you can do to prevent formation damage at various stages in well activities. Here are the ones discussed in this tip of the month:
To learn more about this topic, we recommend attending an upcoming session of Formation Damage: Causes, Prevention, and Remediation (FD) or related courses such as Well Stimulation: Practical & Applied(WS), Sand Control (SNDC), Downhole Remediation Practices for Mature Oil and Gas Wells (DRP) and Production Chemistry (OGPC).
This post contains material from Formation Damage: Causes, Prevention and Remediation (FD).