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Well preparation for gravel packing
Well preparation includes many activities to ensure that the well is completed properly. Some of these items and activities include appropriate drilling practices, cleanliness, completion fluids, perforating, perforation cleaning, acidizing, and/or specifications for rig and service company personnel.
The productivity of a cased- or openhole gravel-packed completion is determined in part by the condition of the reservoir behind the filter cake, the quality of the filter cake, and the stability of the wellbore. Given this, it can be said that the completion begins when the bit enters the pay. Thus, it follows that the goal of drilling is to maintain wellbore stability while minimizing formation damage.
Maintaining wellbore stability
Wellbore stability in the form of washouts, hole collapse, and fracturing is an effect of:
- Large drilling fluid loss
- Inadequate overbalance
- Reaction between filtrate and the formation
But, for whatever reason, instability affects both cased- and openhole completions because it can cause loss of the wellbore. Thick cement sheaths in washed-out sections result in poor to no perforation penetration and the lack of cement can make sand placement difficult. Hole collapse can prevent running screens to the bottom of the hole. Failure, in the form of fracturing or collapse, can stop an openhole gravel pack, should failure occur while the pack is in process.
Because stability is an effect of the reaction between the drill-in fluid and the formation, the following factors become key parameters in building a drill-in fluid:
- Filter cake
These variables usually can be addressed by using polymers and fluid-loss agents in a brine-based fluid containing a properly-sized bridging agent like that contained in special drill-in fluids.
Formation damage, expressed quantitatively in the form of skin, depends on:
- Filtrate used
- Particle damage
- Filter cake quality (for openhole gravel packs)
Skin, in turn, is a reflection of poor productivity; it is expensive to remove or bypass. Preservation of reservoir pore throats requires:
- Keeping particles out of pores
- Minimizing filtrate loss
- Employing a filtrate that is compatible with rock and reservoir fluids
With openhole completions, filtrate must be nondamaging, but it is generally overlooked in cased-hole completions. Frequently, it is assumed that any damage caused by filtrate will be bypassed with perforating. Looking at the occasions when reservoirs are exposed to moderate to high fluid losses, often expressed as a “thirsty mud,” it is possible to have filtrate invade 1 to 3 ft from the wellbore. If the filtrate is incompatible with reservoir rock and fluid, there will be a damaged ring beyond which it may be impossible for perforations to penetrate. For openhole completions, the quality of the filter cake is also as important as the other requirements. Because the cake must be gravel packed into place, it is necessary that the cake be thin and friable and have a low breakout pressure.
Again, as with the wellbore stability issue, filtrate and filter cake become key parameters. Proper selection of a filtrate brine base, along with polymers and fluid loss agents containing a properly-sized bridging agent, usually meets these needs.
Cleaning the casing, openhole, and work string
Cleanliness may be one of the most important considerations for gravel packing. Because a gravel pack represents the installation of a downhole filter, any action that promotes plugging the gravel pack is detrimental to well productivity. Many advances have been made in improving the cleanliness of gravel-pack operations, particularly in completion fluids. However, in spite of the fact that clean completion fluids are used, the lack of cleanliness in the casing, work string, lines, pits, and other equipment is a source of potential formation damage. While cleaning the well and rig equipment can be expensive, it is not as expensive as lost productivity or having to rework the entire completion because proper cleaning was neglected in the beginning.
Reverse circulation is the preferred method of circulation for cleaning the casing. The recommended annular velocity is a minimum of 130 ft/min for casing shoe deviations less than 60° and 300 ft/min for wellbore deviations greater than 60°. Reverse circulation is more effective than conventional circulating, as material is moved downhole with the gravity where it is more efficiently circulated to the surface because of higher velocities in the work string than in the annulus. For an openhole completion, reverse circulation permits cleaning the casing to specifications before addressing the open hole. Planning for a work string that will permit reverse circulation at reasonable bottomhole pressures is required.
To clean the casing, the following cleaning agents should be employed:
Mechanical agents are usually in the form of casing scrapers; most hydraulic agents are push pills and filtered brine. Casing sweeps provide a chemical wash to address polymers, oil, and/or solids adhering to the casing wall.
As a mechanical agent, scrapers remove cement and scale, which will not hinder a bit but will impede a packer. It is prudent to run casing scrapers to the bottom or at least through the interval to be perforated. For openhole completions, the scraper should be run to within 100 ft of the shoe or at least past the proposed packer seat. In displacing the drilling/drill-in fluid, a push pill is pumped first, followed by a casing sweep that is followed by filtered brine. (See Fig. 1.) Push pills serve as a hydraulic piston by creating a sharp interface between mud and casing sweep. The casing sweep removes polymers and solids adhering to the casing wall. The filtered brine provides turbulence to help remove and wash material from the casing.
Push pill volumes should at least be equal to a volume of 300 ft of work string-casing annulus and have the same density as the drill-in fluid and a yield point that is 1.5 to 2.0 times that of the drill-in fluid. Thus, they are easily made from a portion of the drill-in mud by the addition of a viscosifier to raise the yield point. Casing sweeps depend on the chemical employed to remove solids and polymer and, to be effective, will require some contact time at turbulent rates. Calcium hypochlorite (65% active) at 1.5 lbm/bbl and a 5-min contact time effectively removes polymers and fluid-loss agents.
As with the casing, reverse circulation is the preferred method of circulation for an open hole. With the casing cleaned and displaced as previously discussed, all attention can be focused on cleaning the open hole. Wellbore losses and instability can easily be detected and repaired if necessary, and any unrecovered material will be pushed to the bottom out of the way. Recommended annular velocity is 300 ft/min at any deviation to scour the filter cake in preparation for gravel packing and to clean the hole.
Push pills should be used to displace the drill-in fluid from the open hole. The pill should be spotted in the casing and work string annulus above the open hole using forward circulation; then, the work string is run to the bottom and the push pill and drill-in fluid displaced from the open hole with filtered brine using reverse circulation. (See Fig. 2.) Push pills are sized, as discussed above.
The work string should be sized to permit reverse circulation. It should always be run open ended to minimize backpressure on the formation. The work string contains the same types of debris associated with the casing; however, unlike casing, both the inner and outer surfaces of the work string must be clean because completion fluid is circulated along both surfaces. The work string is usually not a major problem if it has been in use before the completion. Work strings just delivered from storage should be carefully inspected for the following:
- Mill varnish
- Other debris
Scraping the work string is usually not as good an option as for the casing, but visual inspections, before it is run into the well, are encouraged to ensure that the string is in good mechanical condition and clean. As a minimum, a “rabbit or drift” with a diameter slightly less than the drift diameter of the work string helps to loosen scale and other debris, as well as providing assurance of the internal diameter of the work string. Once the work string is clean, every effort must be made to keep it clean.
A common source of contamination of the gravel pack is thread dope lubricant. One should use thread dope lubricant sparingly and only on the pin ends during the completion phase. Eliminate the use of thread dope completely on the final run in the hole just before gravel packing the well. Pickling the work string with a pipe dope solvent and a 10% HCl solution before starting a gravel pack is a must. As with any solvent, there is a required contact time and wash rate to dissolve lubricant and carry material out of the work string. Consider the use of a dedicated clean work string strictly for gravel packing, if a number of wells are to be completed.
Although they are sometimes ignored, tanks and lines are a common cause of damaging materials, particularly when the rig that drilled the well is used for completing the well. Tanks must be thoroughly scraped and jetted to ensure that any residual solids from the drilling fluids are removed. When possible, tanks should be dedicated to completion fluids when a drilling program involves drilling numerous wells requiring gravel packs. Casing sweep chemicals and seawater are recommended for removing debris from rig lines.
If properly filtered brine is used as per the following discussion on filtration, the hole is displaced as recommended, and surface facilities are cleaned, it is easy to obtain returned brine that has less than 20 NTU (nephelometric turbidity units) throughout the entire gravel-pack operation. Again, this is only possible if all of the steps are followed. NTU are measured with turbidity meters that should be carefully calibrated.
Gravel-pack completion fluids must be sufficiently clean in order that suspended particles do not plug or reduce the permeability of the formation, perforations, or gravel-pack sand. To achieve a clean fluid requires filtration. Completion fluids are typically filtered to 2 or 10 microns, but in some cases, they are filtered to 1 micron. The fluid can be filtered by either a diatomaceous earth (DE) filter upstream in combination with a cartridge filter unit downstream or with a cartridge filter unit alone. A schematic of the filtration system is shown in Fig. 3. The DE filter unit does a majority of the filtering before the fluid arrives at the cartridge filter unit. Because DE is less expensive than cartridge filters, the use of a DE filter with a cartridge filter downstream is more economical than a cartridge filter unit alone. This is especially true if the completion fluid is dirty, which is usually true at some point during the completion or if large volumes of fluid are required, as in the case of gravel packing.
DE filters are not absolute filters, so a wide variety of particle sizes are capable of “bleeding through” the filter. The DE filter packing itself also will bleed through the filter. DE is capable of plugging the formation and is not acid soluble; therefore, a DE filter should always be used with a downstream cartridge filter to stop the DE and provide additional fluid filtration.
Cartridge filter units can use either nominal or absolute filter cartridges. The nominal filters are typically wound elements designed for bulk solids removal using deep bed filtration. The absolute filters have pleated elements that rely on surface filtration to retain specific size particles. Absolute filters are rated on their efficiencies by their beta rating. The beta rating is defined as the ratio of the concentration of a given particle size entering the filter to the concentration of the same size particle exiting the filter. Commonly used filters have beta ratings from 100 to 5,000. The beta rating depends on flow rate.
As an example, a filter that will stop a 2-micron particle at 1 gal/min (gpm) might not stop the same particle at 10 gpm. Also, beta ratio depends on the particle size considered. A cartridge will have a high beta ratio (removal efficiency) for large particles, but a lower beta ratio for smaller particles. For most oilfield operations, filters with beta ratings of 1,000 are all that are required because these remove 99.9% of the particulate material from the fluid passed through it. The equation for calculating removal efficiency from the beta ratio is written as
- Rex = removal efficiency for particle size “x” (percent)
- β = beta ratio for particle size “x.”
Most completion fluids used for gravel packing are filtered to 2 microns with a removal efficiency of 99.9% or better. Care should be taken while filtering to ensure that the pressure differential through the cartridges does not exceed the cartridge manufacturer’s recommendation (typically 30 psi); otherwise, collapse of the cartridge and fluid bypass may occur, destroying the filter’s efficiency. Filtration of naturally viscous fluids is difficult because of increased pressure drop required to flow a viscous fluid through the cartridge. If polymers are used, they must be thoroughly sheared to remove unhydrated clusters or “fish eyes.” These fluids should be filtered after shearing. Occasionally, you may have to deal with extremely dirty fluids. If time permits, it is advisable to allow the dirty fluid to stand undisturbed overnight to allow solids to settle to the bottom of the holding tank. The clean fluid can then be decanted from the top of the tank and filtered without having to deal with the large volume of settled particles. Oil entrained in the completion fluid also can present filtration problems.
Completion and gravel-pack fluids
The normal sources of completion fluids are:
- Produced brine
- Commercially mixed clear brines
In addition to being clean, the fluids used in the well completion must be compatible with the formation and formation fluids. Of particular concern is clay swelling. Additionally, the fluid should be compatible (that is, not cause precipitation on mixing) with formation water. The candidate completion fluids should be tested in the laboratory to ensure their compatibility with the formation and formation fluids because an incompatible completion fluid can cause permanent formation damage.
The overriding design criterion for a good completion fluid is the hydrostatic requirements to maintain well control. Fluid density can be controlled by adding several water-soluble salts such as:
- Sodium chloride
- Sodium bromide
- Potassium chloride
- Ammonium chloride
- Calcium chloride
- Calcium bromide
- Zinc bromide
- Lithium bromide
The densities of these fluids range from 8.33 to as high as about 20 lbm/gal, values that are comparable with the densities of drilling muds. All fluids have their advantages and disadvantages, which depend on the density of the fluid required. High density fluids are expensive.
The fluids used for gravel packing can be water or oil based. The water-based fluids are usually the most desirable, have a higher density, and are more flexible to use than the oil-based systems. Because of this, the water-based fluids are more commonly used. The simplest water-based fluid used for gravel packing is the completion brine itself. Crude oil has been used in the past in preference to water because it was cheaper; however, with the increase in the cost of oil, its use has been largely discontinued in preference to the water-based systems. Crude oil is still a valid alternative in extremely water sensitive formations and when small densities are needed; however, oil is inflammable, and extra precautions are needed to prevent spills.
Perforating for gravel packing
Perforating consideration for gravel packing is primarily an exercise in selecting the perforating gun and charge configuration that will provide adequate inflow from the reservoir. Remember that the gravel must be placed in the perforation tunnels. If the gravel porosity is about 35%, this equates to filling 65% of the cross-sectional area of the perforations with gravel. Large-diameter perforations, greater than 0.75 in., fired in high-shot density guns, 12 shots/ft or higher, are the desired configuration to provide a high inflow area. The gravel-pack charges have typical penetrations of 8 to 10 in., which is all that is required for these completions. Deep penetration charge designs are ineffective because they produce an insufficient perforation area for gravel packs. They should be avoided except in special situations, such as having to penetrate two strings of casing, etc. Whether the perforating is performed with wireline or tubing-conveyed guns depends on interval length and other factors. Short, one-gun run completions favor the wireline guns. Intervals with completion lengths greater than 30 ft favor tubing conveyed guns because the entire interval can be perforation underbalanced with a single run of the perforating assembly. Other than these broad guidelines, one should use standard perforating procedures.
With an impingement pressure approaching 15,000,000 psi, the perforation jet pushes through the casing and cement and into the formation, where it compacts the materials immediately surrounding the perforation. Because the cement and the formation are crystalline, they are compacted. This creates a zone of reduced permeability at the boundary of the perforation that is caused by the high impingement pressure. It is often referred to as the compacted zone. The compacted zone can be up to ½ in. thick and can have a permeability that is substantially less than that of the bulk formation, which can significantly restrict well productivity.
Additionally, the shaped charge creates debris that is deposited in the perforation. The metal from the housing is typically steel and not readily soluble in acid. The liner is usually made of compressed copper that may form a copper slug called a “carrot” after the perforation is created. The carrot may remain inside the hollow carrier and be retrieved, or it could remain in the perforation tunnel or become lodged in the perforation entrance hole in the casing, which is the worst case.
The perforating debris and the compacted zone must be removed to maximize well productivity. Failure to remove the debris and compacted zone can reduce the potential production rate. The methods available for perforation cleaning include:
- Underbalanced perforating
Some recently developed techniques are also available to assist in the operation of cleaning the perforations such as “debris-free” charges. Such charges are not actually debris-free but result in fine-grained material that is acid soluble and easily flowed from the well.
Acidizing perforations involves injecting a predetermined type and volume of acid into the perforations after they have been created to dissolve any acid-soluble material. In most cases, perforating debris is not highly soluble in acid; therefore, acidizing is more effective and better applied when used with other cleaning techniques. Some considerations critical to acidizing are the compatibility of the acid with the formation, the volume of acid being pumped, and the need for uniform placement of the acid into the perforations.
Acid solubility tests should be performed on a formation sample to select the most effective acid. This is important because the acid may actually damage the formation instead stimulating it. The volume of acid to pump is typically determined by the number of perforations and the length of the perforated interval.
Poor placement of acid produces variable and inconsistent results, possibly leading to a decrease in productivity. Ideally, each perforation would receive an equal volume of acid. In reality, the acid tends to flow into the perforations that are unrestricted and do not especially need cleaning. Meanwhile, other perforations that do need cleaning take in little or no acid. To achieve uniform placement of acid into the perforations, use an acid “diverter” to attempt to divert acid from the permeable perforations to the damaged perforations. The usual technique involves pumping several stages of acid separated by diverter slurries consisting of viscous gel and gravel-pack sand. The diverter will flow into the most permeable perforations and fill them with gravel-pack sand. The combination of gravel-pack sand and the high viscosity of the gel reduce the ability of the perforation to accept fluid. The next acid stage should then flow into the other, more resistive perforations, allowing for a more uniform treatment. This technique is referred to as a “staged acid treatment” or an “acid prepack.” It can be performed immediately after underbalanced tubing-conveyed perforating (for best results) or just before performing the gravel pack. This will be reviewed further in the discussion on prepacking perforations.
The goal of washing is to establish communication between several sets of perforations to effectively remove the perforation debris and compacted zone from the well. Unfortunately, perforation washing is commonly performed incorrectly because rig crews may not take time to follow correct procedures. Washing perforations involves running an opposing cup-type tool or pinpoint packers into the well after perforating. The cup tool seals on the inside of the casing and allows a circulation path through the tool and out ports located between the opposing cups. The tool’s cup spacing is usually about 1 ft to focus the washing operation over a short interval. The washing consists of pumping filtered, unviscosified completion fluid at the largest rate possible without breaking down the perforations, as Fig. 4 illustrates. Washing should be conducted at the smallest acceptable fluid overbalance.
Fig. 4—Washing perforations with wash tool.
Backsurging is the running of a surge tool in the well after perforating. The tool has a chamber that contains air at atmospheric pressure. A packer is set, and the lower valve to the chamber is opened to expose the formation to atmospheric pressure, thereby surging the perforation to expel damage. Unfortunately, the technique does not open all plugged perforations and may require several runs in the well to achieve results. Each run is a special trip.
Underbalanced tubing-conveyed perforating
Underbalanced-tubing-conveyed perforating is popular for cleaning perforations. It is similar to backsurging but only requires a single trip in that the desired underbalance is set by the amount of fluid in the work string. Upon gun detonation, the formation is immediately surged in proportion to the amount of underbalance. General guidelines for underbalance in unconsolidated sandstone reservoirs are to use 500 psi for oil wells and 1,000 psi for gas wells. In a given field, trial-and-error testing can establish the best underbalance for site-specific conditions.
A relatively new technique is to bypass perforating damage instead of using a cleaning or removal technique. Extreme overbalance perforating is used to perforate and then fracture the formation. The process has been used primarily on consolidated formations with relatively large compressive strengths.
Frac packing and water fracs also have been successfully used in unconsolidated formations to bypass perforating, drilling, and cementing damage. This procedure is discussed later.
Fluid loss control
Fluid loss control is a common consideration when completing unconsolidated formations with a gravel pack, especially in high-permeability formations. In addition to the potential formation damage caused by fluid loss, there is particular anxiety when expensive fluids are involved or when completion fluid reserves are low. The amount of fluid loss that can be tolerated tends to be site-specific, but when losses exceed about 30 bbl/hr, there is concern. Loss rates of 20 to 40 bbl/hr on an offshore rig that has only 100 bbl of reserve fluid is serious. In the latter situation, the rig has about 3 to 4 hours before it either runs out of fluid or has to replenish its supply. Another problematic situation is when fluid losses are high and the completion brine is costly. Hence, managing and minimizing fluid losses can be a major problem.
The normal methods for controlling fluid loss include:
- Reduced hydrostatic pressure
- Viscous polymer gels
- Graded solid particles
- Mechanical means
The type of fluid-loss control that is recommended often depends on what phase of the completion process is being executed. Because completion begins as soon as the bit enters the pay and continues through the running of production tubing, excessive fluid loss may become an issue while drilling the reservoir, during openhole gravel packing (especially for a highly deviated hole), immediately after perforating, after prepacking, and after gravel packing.
When selecting a fluid-loss control technique, the current condition of the well, operations still needing completion, and available remedial techniques for elimination of the deleterious effects of fluid loss control must all be considered. These considerations may lead to different fluid-loss control techniques being used throughout the completion and must not be taken lightly.
- Penberthy, W.L. Jr. and Shaughnessy, C.M. 1992. Sand Control, 1, 11-17. Richardson, Texas: Monograph Series, SPE.
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