Good solids-removal equipment operation, including that of shale shakers, helps prevent these problems.
This section contains comments directed specifically toward rig hands who control solids-separation operations. The information was first published in the American Association of Drilling Engineers’ (AADE) Shale Shakers and Drilling Fluid Systems book as a short, succinct guide for rig hands. Appreciation and gratitude is due Wiley Steen and Mike Stefanov for field confirmation of the effectiveness of these suggestions. Effective use of solids-separation equipment is greatly dependent on the treatment the equipment receives on a rig every day and every tour. If some basic principles of solids-separation equipment maintenance and operations are not followed, even the most advanced techniques and high-dollar drilling equipment will be compromised.
All personnel should be thoroughly familiar with the equipment installation, including footprint, wiring pattern, and location of safety equipment. Personnel should always be aware of the potential serious hazards associated with moving equipment and electric currents. Also, to varying degrees, skin, eye, ear, and nose protection is necessary dependent on how much of an irritant the drilling fluid system is.
A carpenter’s drill bit carries wood cuttings out of a drilled hole using spirals located just above on the bit itself. In oil or gas drilling, drill string spirals do not move the cuttings (‘‘dirt,’’ or rock drilled by the bit) out of the hole. Drilling fluid brings cuttings to the surface. Cuttings, also termed drilled solids, left in the mud create or contribute to many problems. Some are:
- Stuck pipe
- Bad cement jobs
- Lost circulation
- Swabbing in kicks
- Slowed drilling rates
- High mud costs
- Wear on pumps and other equipment
- Shorter bit life and more frequent trips to change bits
Benefits of Good Drilled-Solids Separations
- Replacement of pump fluid end parts is reduced, and pumps operate more efficiently.
- Less drill string torque and drag equates to less wear on string and less key-seating (a major potential for stuck pipe).
- Casing is more easily run. Cement jobs are better and require fewer squeeze jobs.
- Bit life is extended due to less abrasion.
- Penetration rates can increase.
- Dilutions to maintain low mud weights are reduced. This manifests not only in reduced drilling-fluid costs, but also in reduced drilling-fluid volumes and thus reduced drilling-fluid waste and waste pit volumes.
- Additions of weighting material are made with little or no difficulty.
- Downhole tools set and release with little or no interference from drilled cuttings.
Tank and Equipment Arrangements
- Solids-removal equipment is arranged so that larger solids are removed before smaller solids.
- Each piece of equipment should discharge into the compartment immediately downstream from its suction compartment.
- Each compartment in the removal section, except for the sand trap, should feature backflow from the downstream compartment into the upstream compartment.
- Except for settling tanks (sand trap), each tank should have adequate agitation.
- Only one compartment should be used as a settling tank.
- No solids-removal equipment of the degasser should have a settling pit for a suction pit.
- All suction pits should be agitated.
Although all of the equipment listed below may not be needed or used, the preferred sequence, with larger-size particles being the first removed, is:
Unweighted Drilling Fluids
- Gumbo removal
- Scalper shakers
- Main shale shakers
- Dewatering system or unit
Weighted Drilling Fluids
- Gumbo removal
- Scalper shakers
- Main shale shakers
- Mud cleaner
- Dewatering system or unit
Gumbo removal devices (‘‘gumbo busters’’) are often fabricated or adapted at rig site.
The purpose of a shale shaker is to remove large drilled solids from the drilling fluid. The shale shaker is the first piece of solids-control equipment to treat or condition the drilling fluid. Good shaker performance is necessary if the entire system is to function at or near design efficiency or capability.
Shakers now come in a dazzling assortment of sizes, shapes, and motions. Their performance is controlled by the size(s) and shape(s) of the openings in the screen(s), the drilling-fluid properties, the amount and type of cuttings arriving at the shaker, and the general mechanical condition of the equipment. The shaker selected for your rig may or may not be the best for the drilling at hand. Unfortunately, if it is not, it must still be kept operational, and with intelligent, conscientious work perhaps can be made to do the job. All commercial shale shakers, however, remove cuttings—and they remove cuttings better when properly maintained and operated.
Obviously cuttings cannot be removed until the drilling fluid first brings them to the surface. Solids coming off the end of shaker screens should have sharp edges. Cuttings that ‘‘roll around’’ in the borehole on the way to the surface have rounded edges. Rounded edges, or round cuttings, indicate that the cuttings are not being transported directly to the surface as fast, or directly, as they should be. The driller and/or mud engineer should be advised as to the shape of the cuttings coming over the shaker in regard to round edges. Rounded-edge cuttings indicate that there are many drilled cuttings stored in the annulus. This increases the mud weight in the annulus and the pressure at the bottom of the hole. The excess pressure significantly decreases the drilling rate and cuttings removal from beneath the drill bit.
Eight general rules to assure shale shakers will work properly and remove cuttings:
1. The shale shaker should be run continuously while circulating. Cuttings cannot be separated if the shaker bed is not in motion.
2. Fluid should cover most of the screen. If only one quarter or one-third of the screen is covered, the screen is too coarse and should be replaced with a finer screen.
3. If fluid flows through a hole or tear, cuttings are not removed. Any screen with a hole or tear should be replaced immediately. With a panel screen, the hole or tear can be plugged.
4. Shaker screen replacements should be made as quickly as possible. Minimize downtime by planning your work. Locate and arrange tools and screens before starting. If possible, get help. This will decrease the amount of cuttings being kept in the mud because the shaker is not running. If possible, change screens during a connection. In critical situations, drilling may be interrupted and the pumps stopped while the screen is replaced.
5. Dilution fluid (water or oil) should not be added in the possum belly or on the shaker screen. Dilution fluid should be added downstream. Dilution-fluid (even water) additions should be metered or otherwise measured.
6. Except for cases of lost circulation (when it is necessary to retain lost circulation material), the shaker should not be bypassed, not even for a short time.
7. Large cuttings should be removed from the possum belly when mud is not being circulated. If the possum belly is dumped into the sand trap just before making a bit or wiper trip, the sand trap should also be cleaned. Otherwise, when fluid circulation starts after a trip, the large cuttings dumped into the sand trap will likely move down the pit system and plug desilters or desanders. Note: The possum belly and/ or sand trap is not always used with synthetic-based mud or some specialized fluid systems.
8. As much as possible, flow from the well (bell nipple) should be evenly distributed among all the shakers.
Things to Check When Going on Tour
- Make sure shale shaker is running properly.
- Listen for bad bearings or motor imbalance. The vibration should be smooth and uniform.
- Are screens installed per manufacturer’s specifications? Is tension correct? Intension continuous cloth screens periodically.
- Check for holes in screens. Wash screens during a connection for the examination. Sometimes a flashlight is needed to examine the entire screening surface. Note: Frequently holes appear where the overflow from the possum belly strikes the screens. It is here that the highest concentration of cuttings strikes the screens.
- Replace screens whenever necessary. Holes in panel screens may be plugged or blanked for possible reuse.
- Check for (sharp) cuttings, not drilling fluid, going off end of screens. If not the case, inform the driller and/or mud engineer.
- Ensure that the fluid flow over shakers is uniform across all, or as close to uniform as possible. This may entail modifying the flowline or possum belly, including adjustment of gates on the shakers themselves.
- Intension screens if particles cake up to form patties. This could also indicate a cracked screen frame that absorbs the acceleration force that moves solids down the screen.
- Review the mud weights and funnel viscosity coming out the hole for the previous tour. These measurements should be made on a regular and consistent basis so that any gradual changes caused especially by downhole conditions can be easily detected. (For consistency, common sense applies. Samples should be taken from the same place every tour, preferably from the possum belly or flowline and from the suction tank. For weighing, the same mud balance should be used. If mud balance is adjusted, adjustment should be noted on a weight-vis chart.)
- Check that the gas and flow sensors are properly positioned in the possum belly but do not move them. Notify the mud logger or driller if they need adjustment.
When API 80 or coarser screens are used, the sand trap performs a valuable function as large sand-sized particles settle in it. Settled cuttings are regularly dumped overboard or to a waste pit.
The sand trap should overflow into the next compartment downstream. This provides an opportunity for solids to settle in the sand trap. Sand traps are very effective when water is used as the drilling-fluid makeup base in a simple system. But when a drilling-fluid system is treated to provide a large value of low-shear-rate viscosity, or high yield points, solids will not settle quickly, and sand traps are much less effective. When the shale shaker screen has large openings, many solids may settle in the sand trap; when very small openings are present on the screen, a sand trap may not be very useful.
Drilling fluids will encounter gas from formations penetrated in petroleum prospective areas. Formation gases are partially dissolved under the influence of the high pressure exerted by the drilling-fluid column at depth. Also at depth, gases not in solution are compressed to occupy very small volumes. Nearing the surface, the pressure in the fluid column reduces, and gases both evolve from solution and expand to larger volumes. At the surface, these gases must be removed; otherwise, centrifugal pump operations become erratic and inefficient. In severe cases, fire hazards exist.
Neither air nor gas is effectively removed from a viscous drilling fluid by flowing through a shale shaker screen. After passing through the shale shaker and sand trap, all drilling fluid should be directed through a degasser. Either one of two types—atmospheric and vacuum—are found on most rigs. A (‘‘poor boy’’) degasser, or mud-gas separator, is also installed on most rigs to remove gas from kicks. Atmospheric degassers usually sit on top of the degasser tank. A submerged pump conveys gascut fluid through a disc valve into a chamber where the spray formed collides at high velocity with the inner wall,driving entrapped gas out of the drilling fluid. Gas is discharged to the atmosphere at pit level, and drilling fluid is discharged into the next tank. Atmospheric degassers should discharge horizontally across the top of the subsequent tank allowing breakout of large bubbles. Their use is somewhat restricted to low-weight, low-yield point fluids.
Vacuum degassers subject thin or shallow streams of drilling fluid to a low pressure, under which the gas expands greatly to be more easily separated. The gas is drawn off by a vacuum pump and the degassed fluid pumped out through an eductor jet, which also draws additional fluid into the chamber. Vacuum degassers should discharge into a downstream tank below the fluid surface. The discharge line should turn so discharge will be directed upward to the fluid surface.
The degasser should process more drilling fluid than enters its suction compartment from the sand trap or shale shaker. This will cause some of the drilling fluid to backflow from the downstream compartment into the degasser suction compartment. The degasser suction compartment tank should equalize overflow from the next compartment downstream. Weigh the drilling fluid into and out of the degasser to determine whether gas is being removed. The mud weight should be compared mud weight, determined with a pressurized mud balance. ‘‘Clean mud’’ should be circulated through the degasser on a routine basis to avoid clogging by settled solids.
Gas exhaust piping should terminate in a nonhazardous area a safe distance from wellhead and surface pits. The exhaust line should be valved and branch in two separate directions so that gas can always be flared downwind of surface pits and wellhead.
Note: Some toxic gases, hydrogen sulfide for example, are heavier than air and will accumulate in low areas. Caution should always be exercised when approaching or working near a gas-line discharge. Also, because it is heavier than air and will settle, simply discharging hydrogen sulfide above a drilling rig (at the top of a derrick, for example) does not provide sufficient degree of safety.
Hydrocyclones are simple, easily maintained mechanical devices without moving parts.
Many of the solids generated while drilling reach the surface too small for separation by shale shakers. Hydrocyclones are relied upon to separate the majority of these finer solids. Hydrocyclone units are designed to separate low-gravity solids larger than about 15 to 20 microns from an unweighted fluid system. Upstream the shale shakers remove larger particles that might cause cone plugging.
Hydrocyclones are arranged with the larger cone size unit upstream of the smaller cone size unit. The desanders function primarily to decrease the solids loading of the smaller, 4-inch desilter cones. Generally a desander size and desilter size are available as part of the rig equipment. A separate tank and centrifugal pump are needed for each size unit. Suction into the hydrocyclone unit is taken from the tank compartment immediately upstream of the tank receiving discharge. The number of cones in use should process 100% of the flow rate of all fluids entering the suction tank of the hydrocyclones plus at least 100 gpm. This ensures adequate fluid processing. The suction and discharge tanks are always equalized at bottom.
A pressure gauge should always be on the inlet manifold to determine feed head (pressure) supplied by the centrifugal pump. Other than cone or manifold plugging, improperly sized or operated centrifugal pumps are by far the greatest source of problems encountered with hydrocyclones.
Most hydrocyclones, regardless of size (inner diameter at inlet), are designed to best operate at 75 feet of fluid head. Some new cones on the market may require a different head. Be certain to check with the manufacturer to determine the centrifugal pump impeller size needed to provide the proper head at the hydrocyclone manifold. A 75-foot head is equivalent to a pressure of 32.5 pounds per square inch for a 1.0 specific gravity fluid (or water). See the following chart, where head = 75 feet.
|Pressure(psig)||Fluid Density or Mud Weight (ppg)|
Remember that a centrifugal pump creates a constant head independent of mud weight. As the mud weight goes up, the centrifugal pump will maintain the same head, but the pressure will automatically increase. All feed lines should be as straight and as short as possible with a minimum of pipe fittings, turns, and elevation changes. Pipe diameters should be 6 or 8 inches for reduced friction losses and less solids settling.
A centrifugal pump should operate only one unit of the solids-removal system; for example, either the mud cleaner or the desilter or the desander, not both desilter and desander.
Cones should exhibit a spray discharge with a central air suction at apex. If cones do not operate in spray discharge,
- too many solids are being presented, and either more efficient upstream separation or additional hydrocyclones are required. As a first step, thoroughly check shaker screens for possible tears;
- solids have plugged the manifold or apex; or
- feed pressure is below 75 feet of head. See the preceding chart.
If desilters are a significant distance above the liquid level in the mud tanks, a vacuum breaker should be installed on top of the discharge line. The vacuum breaker could be a simple 1-inch-diameter pipe about 12 inches or longer welded vertically onto the discharge manifold.
Hydrocyclones discard absorbed liquid with drilled solids. Solids dryness is a function of cone geometry—apex opening relative to diameter of vortex finder. Mud cleaners and/or centrifuges can process cone underflow for increased dryness. The discharge line should be above the fluid surface in the receiving tank to avoid creation of a vacuum.
Guidelines for Effective Hydrocyclone Use
- Check cones regularly to ensure that the apex is not plugged and operation is in spray discharge.
- Ensure that sufficient head (75 feet) is available at hydrocyclone inlet.
- Process the total surface pit volume at least once during any bit trip.
- When the shale shaker will not screen down below 100 microns (API 140), a desander should be used upstream of the desilter.
- Between wells, or when drilling is interrupted, manifolds should be、 flushed with a fluid compatible with the drilling-fluid system, and cone internals examined for wear.
Most hydrocyclones are designed to be balanced. A properly adjusted, balanced hydrocyclone has a spray discharge to the underflow outlet and exhibits a central air suction core. A cone is balanced by pumping water through the cone at the appropriate head and adjusting the bottom opening so only a small amount of water exits the cone.
To set a cone to balance, slowly open (widen) the apex discharge while circulating water through the cone at 75 feet head (32.5 psig). When a small amount of water is discharged, the center air core is almost the same diameter as the opening, and the cone is balanced. When coarse solids are in the feed slurry, wet solids are, by design, discharged at the apex.
The discharge pattern changes from spray to ‘‘rope’’ when too many solids are present in the feed slurry for efficient separations. This is characterized by a slow-moving cylindrical discharge that resembles a rope. Even though rope discharge stream density will be greater than spray discharge stream density, solids separations are actually far less efficient, and spray discharge should be immediately restored.
|Symptom||Probable Cause(s) and /or action|
|Some cones continually plug at apex||Partially plugged feed inlet or discharge; remove cone and clean out lines. Check shaker for torn screens or bypassing. Possibly increase apex size. Stop dumping the possum belly into the sand trap, particularly before a trip.|
|Some cones losing whole mud in a stream
|Plugged cone feed inlet allowing backflow from overflow manifold|
|Low feed head||Check centrifugal pump operation – rpm, voltage, etc. Check for line obstructions, solids settling, partially closed valve. Check shaker for torn screens or bypassing.|
|Cones discharge small amounts of solids, little fluid||Increase apex size and/or install more cones.|
|Vacuum in manifold discharge||Install anti-siphon tube (vacuum breaker), then check for proper feed head.|
|Increasing solids concentration in drilling fluid||Insufficient cone capacity – more cones and/or smaller cones; solids may be too small, use finer shaker screens. Check for holes in shaker screens. Look for shaker bypasses. Check tank plumbing Check suction and discharge line locations.|
|Heavy discharge stream||Overloaded cones; increase apex size and/or install additional cones.|
|High drilling-fluid losses||Cone apex too large, reduce discharge opening size (diameter). Reduce cone sizes.|
|Unsteady cone discharge varying feed head||Air or gas in feed line. Is degasser working?|
|Aerated mud downstream of hydro-cyclone||Route overflow into trough to allow air breakout. Is overflow being discharged too deep in receiving tank?|
Obviously a plugged hydrocyclone cannot process (separate solids) drilling fluid, and maintenance of a low-level drilled-solids concentration is then not possible. On a drilling rig, someone should be assigned the task of unplugging cones. Cones plug when there are too many solids to be separated. This can happen when penetration rate is very fast, over 100 feet per hour, and more or larger hydrocyclones are needed.
Plugging also often exhibits when the shale shaker possum belly is emptied into the sand trap during a bit or wiper trip. Shortly after resumption of circulation, the newly dumped but yet not totally settled concentration of large solids moves down the system. On reaching the apex of the desander and/or desilter, hydrocyclone plugging can occur.
The principle use of mud cleaners has always been the removal of drilled solids larger than barite. The mud cleaner is a combination hydrocyclone and fine shaker screen. Hydrocyclone underflow containing a concentration of solids and drilling fluid is sieved through an API 200 or API 150 screen. Because barite is ground so that the majority is smaller than 74 microns (API 200), most barite should pass through a mud cleaner screen. Most of the weight material passes through the screen and is returned to the active drilling fluid system. Solids—a high concentration of drilled solids—are discarded off the screen. Some barite will be discarded and some drilled solids will be retained in the drilling fluid. Solids removed will decrease mud weight.
Mud cleaners are also used to retain expensive liquid phases, even in unweighted drilling fluids such as synthetic or KCl muds. The mud cleaner concept is also frequently used in microtunneling in that manner. It removes solids from water used in tunneling under roads, etc., when water acquisition or disposal is difficult or expensive. Note: Even when linear motion or balanced elliptical motion shale shakers are properly operated with API 200 screens, mud cleaners have been found to remove significant quantities of drilled solids.
Mud cleaners are normally located on the surface tanks in the same position as desilters. They are frequently the same piece of equipment, with only the hydrocyclones being used while the drilling fluid is unweighted. When weighting material is added, screens are placed on the mud cleaners: ‘‘Barite in, screens on.’’
Newer rigs, especially those found offshore, are outfitted with several linear or elliptical motion shale shakers. After surface and/or intermediate casing strings have been set, fewer shale shakers are needed to handle the correspondingly lower flow rates for smaller hole sizes. Some rigs have been modified with as many as twenty 4-inch hydrocyclones mounted above one of the main shale shakers. A valve is installed on the flowline to convert a main shaker into a mud cleaner. When drilling smaller hole sizes, this shaker is taken out of primary service, and with proper plumbing the arrangement can function as a mud cleaner.
When drilling fluid is initially passed through a mud cleaner, the mud weight decreases, and more barite is needed to maintain density. Remember, the principle use of mud cleaners has always been the removal of drill solids larger than barite. When solids—either barite or drilled solids—are removed, mud weight decreases, and to maintain fluid density, some barite must be added to compensate for the discarded drill solids. Overall, any removal of solids larger than 74 microns is beneficial
to drilling a trouble free hole. ‘‘Bad solids out, barite in.’’
If fluid passes too quickly through the mud cleaner screen and the materials on the screen become too dry, solid particle separations will be inefficient. Barite will clump together with other solids and be carried over to discard. A light spray of drilling fluid (taken from the desilter overflow) onto the mud cleaner screens promotes efficient separations and prevents discard of too much barite.
Direct screen underflow discharge into a well-agitated section of the surface tanks so weight material will not settle.
The mud cleaner is meant to continually process drilling fluid just like the main shale shakers. The mud cleaner screen removes larger drilled-solid particles from the system. When mud cleaners—or hydrocyclones—are operated only part of the time, solids remain in the drilling fluid system. Particularly on passing through drill-bit jet nozzles, particles degrade into smaller size. Smaller-size particles are progressively more difficult to remove and more damaging to the drilling fluid system. A centrifuge (see the following section) can remove some of these smaller particles, but centrifuges do not process all of the rig flow. The mud cleaner is effective in removing solids before they grind to smaller size, and should be used whenever circulating.
A decanting centrifuge is a tool used in viscosity control and it is also solids-removal equipment. It is a machine with an internal cylinder, or bowl, that rotates at high speeds ( 1800 rpm). As drilling fluid is pumped into and conveyed through the rotating bowl, it is subjected to a large centrifugal force that increases the separation or settling rate of the suspended solids. The higher-mass particles separate fastest along the wall of the rotating bowl.
An important distinction is that while screens and hydrocyclones are used to separate and discard larger drilled-solids particles, centrifuges are used to separate and discard smaller, ultra-fine particles, both drilled solids and barite.
Why use a centrifuge? Short answer: To remove drilled solids.
During drilling operations, drilled solids accumulate and degrade in size, which causes viscosities and gel strengths to increase, especially in weighted drilling fluids. These fluids necessarily contain concentrations of weight material solids. A centrifuge will separate ultra-fine (less than 2 microns barite and 3 microns drilled solids) from larger, desirable-size barite particles and drilled solids, which, while undesirable, are not as harmful to fluid flow and wall building properties. Expensive treatment additives are also discarded with the ultra-fines stream. However, most chemical treatment expense is directed to combat actions of ultra-fine drilled solids. While some additions will be necessary, the ultimate result is lessened additive and barite usage, and the removal of drilled solids will be beneficial.
- Before startup, rotate bowl or cylinder by hand to make sure it rotates freely.
- Start centrifuge first, before starting the drilling-fluid feed pump or dilution water.
- Set drilling-fluid mud and dilution rates according to manufacturer’s recommendations, which usually vary according to mud weight.
- Turn off drilling fluid feed
- Turn off dilution water
- Turn off machine.
Reduced viscosity of the fluid within the bowl with dilution enhances separation. Dilution fluid should be added sufficient to maintain an effluent with a funnel viscosity between 35 and 37 seconds.
While centrifuging a water-based system, beneficial bentonite will be discarded along with drilled solids and must be replaced. Usually one or two sacks of bentonite per hour of centrifuge operation over and above normal treatment levels will benefit especially filtration and wall building characteristics. Centrifuge adjustments, other than varying dilution fluid rate, are seldom needed and should be left to a centrifuge mechanic.
Two final notes about solids control and weighted drilling fluids.
- Ultra-fine particles, both barite and drilled solids, that increase viscosities and gel rates are discarded by a centrifuge. The more valuable larger-size weighting material is retained. Without centrifuging, reduction of ultra-fine concentration would require discard of whole mud, which includes valuable weight material.
- Mud cleaners do not compete with centrifuges. The mud cleaner and centrifuge are complementary to each other—not competitive with each other. The mud cleaner removes particles larger than barite, the centrifuge removes ultra-fine particles smaller than most barite. These very small particles with much greater relative surface area can cause dramatic viscosity increases.
Piping to Materials Additions (Mixing) Section
The equalizing line leading from the drilled-solids removal section into the materials additions, or mud makeup pit, compartment should be through an L-shaped pipe that allows the discharge end to be raised and lowered. Normally the discharge end will be raised or lowered so that the removal section maintains a constant fluid level.
Pipe diameter should be 8 to 10 inches to provide sufficient flow rate and retard solids settling in the line. Pipes that are too large will plug with settled solids until the drilling-fluid speed is sufficient to keep the pipe open. Any drilling fluid hauled to the location from another source, or drilling fluid from a reserve pit that is added to the system, should be added through the shale shaker.