A packer is a tool used in oil and gas production wells, which when set, seals the annular space between 2 strings of pipe or a string of pipe and the open hole. They also must have the capability of permitting production flow through them and onto the surface. As its major functions, a packer should :
- Protect casing from bursting under conditions of high production or injection pressures
- Protect casing from corrosive fluids
- Provide better well control
- Prevent fluid movement between productive zones
Components Of Wells Production Packers
Even though a great number of types of packers exist, there are a few basic parts common to all packers. A permanent packer is shown in Figure 2, and in Figure 3, a retrievable compression packer. They all have the following components in common :
- seal assembly – usually of rubber, some with metal back-up rings
- slips to engage the casing wall and hold the oil and gas packer against applied forces
- cone assembly to force the slips out to engage the casing
- friction element to allow motion of the inner mandrel relative to the packer body (not on hydraulic or permanent production packers)
- setting and releasing mechanism
- mandrel assembly to hold parts together
In addition, some offer the option of a hydraulic hold-town assembly (Figure 4) to facilitate high-pressure work below the production packer. In the following paragraphs, some of these basic components are discussed in greater detail.
The elements’ sole function is to form a seal between the wells packer’s flow mandrel and the casing in which the packer is set. Elements are made of various depending upon downhole conditions. They are also available in various durometers (hardness) again depending on downhole conditions or pipe weight availability.
Seal Extrusion Prevention
Many techniques are used to lessen the unwanted extrusion. In some wells packers, back-up rings are used to reduce the unsupported cross-section of the rubber seal. In others, multiple sealing elements of varying hardness are used to reduce the deformation of the rubber itself. For example, in a three-element oil and gas packer (Figure 5), the upper and lower elements are usually harder than the middle one.
All three are compressed when the packer is set. The lower hardness center elements seals off against imperfections in the casing wall. The higher hardness end elements, on the other hand, aid in restricting extrusion and affecting a seal when high temperature and pressure differentials are encountered. This degree of hardness is related to the seal element’s ability to withstand deformation, and thus bears a general relationship to its ability to hold pressure without failing.
Flow or Packer Mandrel
The flow mandrel (sometimes called the packer mandrel) is the “tube” part of the packer which allows production to enter the tubing and, in turn, onto the surface. It can be generally stated that a packer consists of external components built around the flow mandrel. In many instances, the strength of the flow mandrel affects greatly the pressure differential rating of the oil and gas packer. Downhole conditions will dictate the type of alloy used to make the flow mandrel.
Wedge or Cone
The wedge is simply that part of the wells packer which forces the slips to move outward during the setting sequence. The wedge is known by several other names such as the cone, expander, or expander cone.
The cone is simply that part of the packer which forces the slips to move outward and bite into the casing during the setting of the oil and gas packer. The cone is known by several other names such as the wedge, expander, or expander cone.
Setting And Releasing Elements
The simplest packer’s setting mechanism is the J-slot and pin arrangement (Figure 6), which requires, for setting, only a slight rotation of the tubing at the packer, and can usually be released by simply pulling on the packer. This rotational requirement is often difficult to achieve in high holes. A typical choice for deviated wellbores is therefore a hydraulically set packer with straight pickup release mechanisms. The changes in tubing length with pressure and temperature changes – must always be evaluated in order to make the proper selection for a setting or releasing mechanism.
Production Packer Slips
Slips can be of any of a variety of shapes, provided that they are sharp and have an adequate surface for holding the production packer in position under the anticipated pressure differentials and tension/compression due to tubing movement.
They are serrated or “tooth-like” parts of the packer. Once forced outward by the setting action, the slips “bite” into the casing wall preventing the packer from moving when pressure differentials exist across the packer. Some wells packers have two sets of opposing mechanical slips. The bottom slips prevent downward motion & the top set of slips controls the upward motion of the packer. Some packers incorporate bi-directional slips, that is, one set of slips that prevent movement in either direction. There are a few wells packer techniques with a set of hydraulically activated hold-down button slips & sets of lower slips. Other designs include packers with only one set of slips and therefore can hold pressure from one direction only. Certain types of isolation packers have no slips at all.
Theoretically, a packer can be seated and unseated a number of times without requiring the replacement of slip elements. The cost, however, of slip replacement in comparison with rig cost very insignificant. Complete service and repair of a oil and gas packer should therefore be performed whenever the packer is removed from the wellbore.
Friction elements are an essential part of mechanically set packers, as seen on the packer in Figure 7. Ordinarily, friction devices are either bow springs or friction blocks. If properly designed, either one will provide the holding force needed to allow independent rotation of the inner mandrel. Friction blocks are quite popular today, but wells packers with bow springs are also prominent on the market. The preference for friction blocks is not strong enough to bring about a redesign of the old packers in order to accommodate them.
Why Do We Need To Run a Packer?
By no means are all wells completed with production packers. A packer is used only when there is a need for it. The principle reasons for running a packer could be arbitrarily grouped as:
- The production control.
- Production testing.
- The protection of equipment.
- Well repair and well stimulation.
Examples are given in the following list.
In a gas lift well:
- Firstly, to keep casing pressure off the formation (intermittent or chamber lift)
- Secondly, to facilitate kick-off (and, incidentally, to prevent passing well liquids, which might be abrasive, through the gas lift valves)
In a dual, or multiple, completion well:
To segregate the producing layers for one of the following reasons:
- incompatibility of pressures of producing intervals
- separate production, and gathering of two crudes of distinctly different qualities
- control of an individual layer for high G.O.R., or for water cut
In a steam injection/steam soak well –
- to maintain an empty annulus and thus prevent loss of heat from the tubing (and, incidentally, reduce the expansion of the casing)
- the production test of an exploration well, i.e. producing a discovery well, where the performance and the properties of the formation are as yet unknown
- testing a producing well to locate point of gas or water entry (where production logging services are not readily available)
Protection of Equipment
- Wells packers used to keep undesirable high oil or gas pressure off the casing or the wellhead
- Protect the casing from the effects of corrosive fluids
- In an injection well, to keep high water or gas injection pressure off the casing or the wellhead.
Wells Repair/Simulation & Packers
- Pressure testing the production casing
- Location of casing leak (Check also: Casing Repair)
- Isolation (temporary?) or a casing leak
- Cement squeeze repair of casing leak
- Temporary shut-off of undesirable gas or water entry (particularly on a low producing or depleted well)
- During fracturing, to keep high “frac” pressure off the casing
- During acidizing, to ensure acid enters formation
- To avoid formation damage by work-over fluid during well repair (the oil and gas packer would probably be in the well already, for some other purpose)
- In a marine well, to protect against the effect of collision, or other surface hazards
- Packers are used also to reduce the risk of well head leaks on a high-pressure wells
- Environmental protection of prolific or high pressure wells in a housing area
The Main Functions of a Production Packer are:
- To keep formation pressure off of the casing. This is necessary in order to prevent casing failure.
- To keep formation gases or fluids off of the casing. It is desirable to keep formation gases and fluids away from the casing, as many corrosive agents may be present in them. If the casing is exposed to corrosive agents, premature failure might result.
- To isolate zones or bad casing. Most often, it is necessary to keep zones separated within a well bore. A production packer must be used to do this. One of the most economical methods for isolating old perforations or casing failures is by placing a packer on either side of the area.
- To hold kill fluids in the annulus. It is very desirable, in many cases, to leave weighted kill fluids (Kill sheet calculations) in the casing annulus. Kill fluids in the annulus reduce the differential pressure across the tubing from the inside in high-pressure wells. Kill fluids also reduce the pressure differential on the casing from the outside. Many times, inhibitors are incorporated in the fluids to reduce corrosive action on the tubing and casing.
- To keep gas list pressure off the formation. Gas lift wells usually produce more efficiently where a packer is used to keep gas lift pressure off of the oil-producing formation. Also, it is usually better to prevent gas from passing around the end of the tubing during gas lifting.
- Safety. Formation pressure is more easily controlled through the packer-tubing system than if the formation is working on the entire casing.
- Test formations. wells Packers are commonly used to test the productivity of a formation before the well is completed, thus avoiding the completion expense of the well proves to be a “dry hole”.
- Gravel pack. There are several methods that may be used to gravel pack a well. Some methods require the use of a packer and some do not. However, it is generally agreed that those methods using a packer provide a better pack than those methods which do not use a packer.
Wells Packers Types
From the customer’s and service company’s point of view, oil and gas packers can be classified into 2 major categories:
- Production packers: Production packers are those packers that are typically purchased by the customer from the service company. Production packers typically remain in the well bore during normal well production.
- Service packers: Service packers are those packers that are used temporarily and then retrieved from or milled out of the well. Well testing, cement squeezing, acidizing, and fracturing are common procedures in which service packers are used in. Since a retrievable service packer is normally used for only a short period of time, the customer rents the packer instead of purchasing it.
The Production Packers can be further divided into major types depending on certain mechanical criteria. The following is one possible categorization scheme:
- Permanent packers
- The seal bore retrievable packers
- Mechanical retrievable oil and gas packers
- Hydraulic retrievable packers
- Hydrostatic set packers
Classification According to Applications
Production packer application with regard to completion design is addressed in this section as there are some basic features that affect the completion architecture. Although there are many varieties of wells packers available, there are three basic types used in completion designs:
- Permanent Retrievable.
Packers Selection In Oil & Gas
The decision about what kind of production packer to run can be very complex and the list of packer features available today is almost endless. Examining packer features, in general, is not the way to begin. The best approach of packers’ design selection is to first examine well conditions and desired operational capabilities and then determine which packer features meet those well conditions and best fulfill those operational requirements.
Packer selection has three stages:
- Selection of type of wells packers
- Selection of the setting mechanism
- Selection of main oil and gas packer accessories including the tubing-packer connection
In stage 3, stress analysis is carried out to check the completion string (packer and tubing) under the stress to which they are exposed.
Packers Retrieving Considerations.
1. Release packer with minimum tubing manipulation, straight pull, or 1/3 turn release.
Many times well conditions or other downhole equipment in the string make it desirable to have the packer release with little or no tubing manipulation. Deviated holes are examples of the former, while the presence of eccentric gas lift side pocket mandrels or lengths of 1/4″ control line in the hole would be examples of the latter. A straight pull release mechanism is the most desirable option in most cases. These packers are usually shear pinned in the set position (exception –some tension set types). Another option is a minimum rotation type release (1/3 turn at the packer) that some retrievables have. Many seal bore type retrievables are released by straight tension but only after the production seal unit has been pulled. These packers require an additional trip with a releasing tool in order to pull the packer. However, no tubing rotation is required. A few special packers have also been designed and run that are straight pull release after a wireline sleeve has been shifted. This option is somewhat unpopular because the ability to pull the packer is dependent on wireline access to the packer. Lack of tubing access may very well be the reason for needing to pull the production packer in the first place.
2. Back up release capability, safety shear release or rotating release.
Undesirable well conditions, unplanned production problems and incompatibility with other downhole tools are all reasons that may make a back-up release capability a needed feature. If the primary release mechanism cannot or does not function for some reason, such a feature becomes very important. At times, these possibilities can be anticipated and such a feature should hold a high priority in packer selection. The most common type of secondary release is by shearing shear pins or screws with straight pull. However, rotation-type secondary releases have also been incorporated on some packers.
3. Tubing or packer retrievable with some fill, packer bypass or flush seal unit.
Some production operations may result in moderate fill in the casing above the packer. An example would be production of a second zone above a single packer in the tubing/casing annulus. Produced fines from the upper zone may settle out on the packer top. In such cases, the packer should be placed as close as possible to the bottom of the upper zone or a sliding sleeve should be placed as close as possible to the packer top. However, even then some fines will remain and a bypass or pressure unloader is very useful to allow tubing to casing circulation above the elements to remove the fines or debris. In permanent or seal bore type retrievables, a seal assembly can provide the same ability. This functions best when the seal assembly is equal to or smaller in OD than the tubing.
4. Equalize pressure on packer release, pressure unloader or separate seal unit.
When packers are run past moderate depths, it becomes possible or probable that considerable pressure differentials may exist across the packer upon release. If the operator does not load the tubing before release, the casing fluid pressure maybe substantially higher than the pressure of the partially depleted reservoir being isolated. A differential from below may exist under other conditions if the isolated reservoir is charged by injection or is naturally over-pressured.
In either case, if a pressure-equalizing device of some type is not available, then there is a good possibility that packer release may be difficult and/or the element package will be damaged in the releasing process. This is an especially important feature if the packer needs to be reset on the same trip. An option to the internal-pressure-unloader design feature is that the same equalization may be done by pulling the seal assembly out of a seal bore type retrievable packer.
5. Release packer with no tubing trip, tubing connect directly to packer.
As mentioned previously, some packers require a round-trip of the tubing in order to retrieve the seal assembly and re-run the pulling tool. This is not acceptable in certain instances. In some filed operations where regular workover is common, the economics of such pulling procedures could not be justified. In order to be able to pull the packer without making a tubing trip, it must be of the type that is designed to be threaded directly to the tubing and not the seal bore type retrievable that is attached to the tubing via a latch on seal assembly. The exception is the wireline release version previously discussed. Many of these thread-to- packer types may be modified with accessories so the tubing may be pulled separately from the packer and still retain the retrievability without a tubing round trip.
6. Easily milled packer, minimum mill distance and non-rotating.
The needs for an easily and quickly millable permanent packer are obvious. Packer designs that make this possible include millable metal components, designs for minimum mill distances, designs for minimum milled OD’s and anti-rotation locking features.