7 7 C O N T E N T S 1 DEFINITION 2 MULTIPLE ZONE DEPLETION CONCEPTS 2.1 Co-mingled Flow 2.1.1 Advantages 2.1.2 Disadvantages 2.2 Segregated - Multiple Zone Depletion 2.2.1 Advantages 2.2.2 Disadvantages 2.3 Alternate Zone Well Completion Strategy 2.3.1 Advantages 2.3.2 Disadvantages 2.4 Selection of Development Strategy 3 MULTIPLE ZONE COMPLETION CONFIGURATIONS 3.1 Dual Zone Completion 3.2 Completions for 3 or More Zones 4 MULTIPLE COMPLETION EQUIPMENT 4.1 Tubing Hanger Systems 4.2 Multiple Tubing Packer Systems. 5 AUXILIARY EQUIPMENT FOR MULTIPLE COMPLETIONS SUMMARY Multiple Zone Completions
Transcript
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C O N T E N T S
1 DEFINITION
2 MULTIPLE ZONE DEPLETION CONCEPTS2.1 Co-mingled Flow2.1.1 Advantages2.1.2 Disadvantages2.2 Segregated - Multiple Zone Depletion2.2.1 Advantages2.2.2 Disadvantages2.3 Alternate Zone Well Completion Strategy2.3.1 Advantages2.3.2 Disadvantages2.4 Selection of Development Strategy
3 MULTIPLE ZONE COMPLETIONCONFIGURATIONS3.1 Dual Zone Completion3.2 Completions for 3 or More Zones
Having worked through this chapter the Student will be able to:
• Describe the options, and their inherent constraints / advantages, for producingmultiple reservoir units.
• Propose general completion schematic options for producing two, threeor more zones simultaneously.
• Define the equipment requirements in terms of packers, tubing hangers and Xmastrees for multiple completion strings.
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Multiple Zone Completions
1 DEFINITION
Multiple zone completions are employed on reservoirs where more than one distinctreservoir layer is to be intersected by a single well and for which the intention orrequirement is to produce/induce these layers separately. Normally the reservoirs aresequentially encountered as the depth increases. The concept of a homogeneousreservoir rarely, if ever, exists in reality. However, producing formations can oftenbe considered stratified, and their producability depends upon the extent to whichvertical flow occurs. Stratified reservoirs are created by changes in depositionalconditions but the layers have different rock properties and hence flow characteristicse.g. permeability. The layers can have a variable degree of vertical communication.Alternatively, if the layers deposited by changes in depositional conditions areseparated by deposited layers having very low or non-existent vertical permeability,each of the producing layers is a non-communicating reservoir layer.
2 MULTIPLE-ZONE DEPLETION CONCEPTS
The depletion of multiple zone reservoirs can be accomplished by one of thefollowing:-
(a) Comingling the Flow from Various Zones:
In this approach, more than one zone flows into the tubing string, e.g. two zonesproducing up a single tubing string.
(b) Segregated Multi Zone Depletion:
With this approach the concept is to use multiple production conduits withinthe same wellbore, where each tubing is utilised for the production of one zone.
(c) Alternate Zone Well Completion Strategy:
Here the idea is to complete each well on one specific reservoir.
The advantages and disadvantages of each of the above techniques is discussed below.
2.1 Co-mingled Flow
2.1.1 Advantages
(1) Since each well provides a drainage point in each reservoir unit, the totalnumber of wells is a and the capital investment, is therefore minimised.
(2) Since the amount of drilling is minimised, the production plateaux for all thereservoirs should be reached as quickly as possible. i.e. production should beaccelerated compared to the other optional strategies
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2.1.2 Disadvantages
(1) The mixing of produced fluids in the wellbore can be disadvantageous if oneor more fluids have any of the following characteristics:
(a) Corrosive or potentially corrosive materials e.g. acids, H2S, CO
2.
(b) Produced sand and a potential erosive effect. The implementation ofsand control procedures may be more complicated.
(c) Fluids having different Hydrocarbon compositions and hence economicvalue.
(d) Different WOR and GOR as this would influence the vertical liftperformance of the total well system.
(2) Variation in individual zone pressures and permeability can lead to a backpressure effect on the less productive or lower pressure reservoirs.
(3) The use of co-mingling removes the capability for continuous control of theproduction process, i.e. closure of one individual zone cannot necessarily beeffected unless a relative configuration is used.
(4) Injection of fluids, e.g. stimulation fluids cannot easily be diverted intoindividual layers without temporary isolation using sealants (diverters) orbridge plugs.
(5) A change in the production characteristics of one zone e.g. water coning and aconsequent increase in WOR, will influence the total production from the wellbut may be difficult to remedy without closing in the well.
2.2 Segregated - Multiple Zone Depletion
2.2.1 Advantages
(1) The production rate and duration of flow on each zone can be independentlycontrolled.
(2) Changes in the production characteristics of one zone will not influence theothers.
(3) Some remedial work on individual zones can be accomplished without alwaysaffecting production on other zones, e.g. cement squeeze, reperforating,perforation washes.
(4) Stimulation on each zone can be applied.
(5) Continuous monitoring of the depletion of each zone can be achieved, whichassists in material balance or reservoir simulation studies for reservoirmanagement.
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Multiple Zone Completions
2.2.2 Disadvantages
(1) Since each zone has a tubing string the amount of production tubing and othercompletion equipment required is considerable. This requires additional capital andinstallation time.
(2) The mechanical complexity of the completion is increased and hence thepossibility of equipment malfunction is also increased.
(3) The amount of completion equipment is increased and hence the statisticalpossibility of component failure is also increased.
(4) The retention of tubing sizes may reduce the total flow capacity of the well
2.3 Alternate Zone Well Completion Strategy
2.3.1 Advantages
(1) Effective control of all aspects of reservoir depletion and well control isprovided.
(2) Changes are easily introduced to adapt to variations in the depletion strategy,e.g. changing a well from production to injection.
(3) Problems encountered on one well does not necessarily influence the continuityof the production of fluid from other zones/wells.
(4) Each well is relatively simple mechanically and the risk of failure due tocomplexity is minimised.
2.3.2 Disadvantages
(1) To achieve the same degree of depletion control by having good reservoirdrainage, the number of wells to be drilled and completed must increase in total.Thus, the total cost of such a development will be substantially increased to achievethe same drainage effiency in the reservoir.
(2) Unless the number of wells is increased, the difference of production on somezones will defer, reduce and extend the field of life thus increasing unit productioncosts.
2.4 Selection of Development StrategyThe chosen strategy for the completion and development of a reservoir drainagesystem, will depend very largely on the following:
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(1) Offshore or Onshore DevelopmentIn an offshore development, the cost per well is so large that the planned number ofwells is usually minimised. This limitation will not be as significant in an onshoredevelopment.
(2) Areal Size and Number of Reservoir ZonesThe drilling of a large number of wells can be more easily accomplished with orwithout directional drilling on land. Offshore, however, if the structure covers a verylarge area, the use of very high angle wells will be necessary. To run very complexmultiple completions in high angle wells can lead to significant difficulties beingencountered.
(3) Variation in the Reservoir Rock and Fluid CharacteristicsThe degree to which corrosion or erosion is likely to occur will influence the type ofcompletion. In addition the degree to which drawdown on one zone might suppressproduction from other zones may be important.
The flow potential of each zone might be impaired if too small a tubing size is used,because of the lack of space within the wellbore for a multiple tubing completion.
3 MULTIPLE ZONE COMPLETION CONFIGURATIONS
Wells can be completed on any number of zones within the same well by simplyincreasing the amount of completion equipment installed to provide isolation and flowcontrol capability. The benefits of using the same wellbore for multizone productionare significant, but as the number of zones increases, the complexity and potential formalfunction can negate the inherent advantage of the single wellbore completion. Theoptimum number of zones to be produced into any wellbore will depend on thereservoir, e.g. in high rate, highly deviated completions, perhaps even two tubingstrings might not be desirable. In other cases three tubing strings in each wellboremight be used to deplete a number of zones.
3.1 Dual Zone CompletionThere are a number of ways in which completions can be designed to produce twozones. Besides co-mingled flow and individual well/zone completion there are:
(1) Casing/Tubing FlowIn this case a single tubing string is run with a single packer installed to provideisolation between zones. One zone will produce up the tubing, whilst the other willproduce up the casing-tubing annulus.
The difficulty with this type of completion is that under natural flow conditions it willhave a live annulus perhaps necessitating an annular safety valve. Also the producedfluid is in contact with the casing and it may thus cause damage by corrosion orabrasion. In addition, pressure limitations on the annulus with respect to casing burstmay preclude stimulation of the zone which produces via the annulus.
Two alternative completion types exist:
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(a) Upper zone annular flow - applied where the upper zone fluid is non-corrosive,non-abrasive and where pressure limitations of the casing would not precludestimulation.
(b) In situations where the upper zone would not be suitable for annular flow, thena lower zone annular flow system could be used requiring one tubing string, twopackers and a crossover tool. This design however, severely precludes mechanicalareas to both zones for logging, perforating etc..
Single String Selective 2 Zone 2 String
Upper Zone/ Annular Flow Lower Zone / Annular Flow
(2) Dual Tubing FlowIn this type of completion a separate tubing string for each zone is provided with twopackers, one to isolate between zones and the other to isolate the upper zone from theupper casing annulus. Here the depletion of each zone can be accurately monitoredand controlled. In addition, the injection of fluids into each zone is limited only bythe tubing design criteria. Also, the completion is more suited to the effectiveproduction of problem well fluids.
Figure 1
Options for 2 Zone Flow
without Comingling
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(3) Single String Selective ProducerIn this completion, the well is completed over two zones, utilising one tubing stringdesigned to selectively allow the production of either or both of the zones. Thecompletion requires two packers, one to isolate between zones and the other to isolatethe annulus. In addition, an entry point for fluid from the upper zone to enter the stringmust be provided which can be opened and closed as desired, e.g. a sliding side door.Finally, when producing the upper zone into the tubing, closure of the lower zone maybe accomplished by setting a plug in a nipple at the base of the tailpipe.
3.2 Completions for 3 or More ZonesThe available options discussed in section 3.1 for dual completions can be extendedfor wells to be completed on three or more zones with or without some degree of zonalco-mingling.
(1) Triple Zone CompletionsThis can be accomplished with either:
(i) A completion utilising separate zonal flow into one of three tubing strings andhaving three packers for isolation.
(ii) A two string completion, whereby flow from two zones is co-mingled into oneof the tubing strings.
(iii) Single zone annular flow and two tubing strings producing separately from twozones.
(iv) Two string completion where either or both of the strings are completed toallow selectively production from two of the zones. This requires two tubingstrings and three packers.
(v) Single string, triple zone selective completion.
(2) Four or More Producing ZonesNormally no more than three strings are run into the wellbore, but a large number ofoptions exist.
(1) Single string selective producer.
(2) Dual string selective producer.
(3) Dual string/selective with annular production.
(4) Triple string with annular production.
(5) Triple string with selective production.
It is clear that when four or more zones exist, the completion strings can becomecomplex, costly, difficult to run and retrieve, and more likely to produce mechanicalfailure. The considerations can severely impact on the life of the well.
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Multiple Zone Completions
4 MULTIPLE COMPLETION EQUIPMENT
In general terms, equipment requirements for multiple completions are largely basedupon the equipment available for single string completions with the following exceptions:
Obviously the number of tubing strings will affect the completion procedure.However, since the sizes of the tubing and hence ancillary equipment are dictated bythe limitations imposed by the casing inside diameter, tensile load and torquecapabilities will not normally be a significant problem for a completion rig.
4.1 Tubing Hanger SystemsHere the difficulty is one of landing off the tubing in the landing seat in the tubing headspool. The simplest way of achieving this is to use a segmented hanger. For eachtubing string a hanger segment is produced. Upon landing off all the tubing strings,the hangers should form a composite circular hanger which also seals the annularspace in the landing seat within the tubing head spool. Normally each hanger segmentis made up with a tubing pup joint above and below which is attached to the rest of thestring. The tubing strings are either run independently or simultaneously.
When using a surface controlled sub-surface safety valve, provision must be made forthe control lines for each tubing string and valve system.
4.2 Multiple Tubing Packer Systems.In a multiple tubing systems, the number of packers will normally equal the numberof zones to be produced. For a dual zone, dual tubing completion, two packers willbe required, the lower being a single packer whilst the upper will be a dual packer.Similarly for a three zone, triple tubing completion, three packers will be required,comprising a single, dual and a triple packer.
Multiple string packers are available to similar specifications as single string packers,i.e. they can be either permanent or retrievable. In addition, they can be set using ahydraulic or a mechanical setting procedure. The wireline setting procedure, althoughfrequently used to set the lower single string packer, would find little application forthe upper packer(s) because of the cable weight limitations.
All multiple string packers must offer a means of connecting tubing above and belowthe packer for each string. In some cases mechanical attachment exists e.g. tubingscrewed onto the base of the packer whilst, in other cases, the packer offers a seal bore.
In any completion involving multiple strings, the tubing strings will have differentlengths and are denoted as the long string, intermediate string and short string. Thisterminology is crucial to the running procedures for the completion, e.g. a packer maybe run into the well on the long string which is landed off, and may be set usinghydraulic pressure either by the long string or by the short string after it has been run,located into the packer seal bore and landed off in the THS.
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Although in most cases it is preferable to run retrievable multi-string packers since itleads to easier retrieval in an already more complex workover operation, permanentpackers are available and may be required in high pressure wells, or where significanttubing movement and stress is anticipated. One example of such a packer in the Bakermodel DE available for either hydraulic setting DEH, or for setting on tubing orwireline the model DE-1. This packer is based on the model D packer having the samedesign principle of full circular slips and metallic back up rings. The packer offers twoseal bores whose length can be extended up to 20 ft. If the packer is set on wireline,then the long string would be run through the upper seal bore and down into the sealbore or latched into the lower packer. The long string can then be pressure tested priorto running the short string. With the hydraulic version, the packer with the long stringtailpipe is made up and run on both the long and short tubing strings. After landingoff, a ball is dropped down onto an expendable seat in the base of the packers andpressure of for example, 3000 psi seats the packer and 4000 psi shears out the ball andseat.
A dual version of the A-5 packer is available from Baker, which is set by pressurecreated in the short string. A modified version termed the AL-5 is the same packer,but can be set by pressure in the long string. To allow pressure testing of the tubingwithout premature setting of the packer, a modified ALS-5 packer is available fromBaker.
Halliburton have a range of hydraulically set, retrievable packers, termed the RHrange. The RH packer has been discussed previously, but Halliburton also offer theRDH and RTH for dual and triple completions respectively. The packers can be setby hydraulic pressure in either the long or short string
Figures 2
Dual Completion-split
hanger
Figure 3
Dual tubing hanger -
integral
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Multiple Zone Completions
Figure 4
Hydraulic Set Packers; dual
and triple configuration
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Primary-ThreadedSecondary-Collet
Primary-ThreadedSecondary-J-Slot
Primary-J-SlotSecondary-Collet
Primary-ThreadedSecondary-J-Slot
Primary-J-SlotSecondary-Collet/
Sleeve Latch
Primary-ThreadedSecondary-Threaded
J-Slot Latch Collet Latch Collet/Sleeve Latch
Since the packer is normally run on the long string, it is possible to set the packerwith the long string in tension, but the short string can be set in either tension orcompression.
Once the packer has been run to the desired depth and the long string landed off,the short string is run and landed off within the second seal bore of the packer. Aball dropped down the desired setting string, lands in an expendable seat (1).Internal hydraulic pressure from the tubing shears the pins (2) by the downwardsmovement of the setting piston. The downwards movement of the setting mandrelexpands the lower element and sets the slips. Upon releasing the tubing pressure,the packer is held in the set position by internal slips (3). Differential pressurefrom below the packer sets the hydraulic hold down buttons. To retrieve thepacker, the short string is first retrieved, and upwards tension will shear the pins(5) and allow retrieval.
Figure 5
Seal Assemblies for
Hydraulic Set Packers
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Multiple Zone Completions
Shear Pins Shear Pins
ReleasingPins
Catcher Sub
Internal Slips
Catcher Sub
Hold DownButtons
Schematic 1Running In
Schematic 2Setting
Schematic 3Retrieving
(1)
(3)
(2) (2)
(4)
Mechanical set dual or triple packers are also available. The packer utilises a weightset concept (3000 - 5000 lbs) and can be set by either the long or short string. Inaddition, if a J latch system is used for both strings, each string can be retrievedindependently for workover without unseating the packer. The packer is available aseither short string or long string, set with or without hydraulic holdown, e.g. SH/SAand LH/LA. The setting concept is useful since no tubing rotation is required.
Four different connecting systems are available for engaging the short and long stringinto the packer:
(1) Threaded connection - this could be used for two strings if both strings were tobe run and pulled together. Normally, it is simpler to pull the strings individually.
(2) J-slot connector - requires 1/3 right hand turn at the packer for release.
(3) Collet connector - requires no rotation.
(4) Collet-sliding sleeve latch - this is an adaption of the collet connector wherean inner sleeve is fitted and this has to be shifted to lock and unlock the collet.
Figure 6
Running, Setting and
Retrieval Operations for
typical dual hydraulic set
packer
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5 AUXILIARY EQUIPMENT FOR MULTIPLE COMPLETIONS
(1) Circulation sleevesA useful item for dual completions in a pressure operated sliding sleeve which allowseasy circulation of fluids between long and short strings or between the long string andthe annulus. This facility removes the necessity to remove the tree in order todisconnect the string latches prior to circulating the well to kill or initiate production.The tubing can, in fact, be landed off and the well circulated prior to setting the packer.The opening of the sleeve requires about 600 - 800 psi differential pressure in the longstring. It may be necessary to have a ball and expendable seat below the packer in thelong string to protect the lower formation against the pressure generated in the tubing.After circulation, a ball dropped down the short string lands in the expendable seat,and pressure applied to set the packer also closes the circulation sleeve.
An alternative pressure operated circulation sleeve uses internal pressure to open thesleeve but after use, a ball is dropped down the tubing and lands in a recess. With theapplication of tubing pressure the inner sleeve is moved downwards and the devicecloses. In operation it requires about 650 psi internal pressure to shear the screws onthe lower sleeve and this allows the spring to push the lower sleeve down and exposesthe ports. After circulation, the ball is dropped down and once in position a pressureof 2900 psi will be required to shift the upper sleeve down and close off the ports.
(2) Blast JointsThe long string in a multiple completion is located in the casing opposite the perforatedsections of upper producing zones and as such they are present in the section of thewellbore where fluid entry occurs. The direction of fluid low through the perforationsinto the wellbore is normally perpendicular to the well axis and the fluid flowstreammust quickly change through 90° to flow up the tubing. The fluid entering the wellboremay have a significant impact force on the tubing wall of the long string and will leadto hydraulic erosion. If sand or solid fines are being produced, they will drasticallyincrease the erosion rate.
Accordingly, to compensate for the increased erosion, a thick walled tubing sectionknown as a blast point is normally included in the string opposite the perforatedintervals of the upper production zones.
SUMMARY
In this section we have discussed the options and equipment requirements forcompleting multiple zone reservoirs. In most cases we must balance the reservoirmanagement requirements in terms of flow control, regulation and isolation as againthe additional complexity and its inherent costs - both capital and intervention, as wellas operational constituents.
In some situations the complexity can also limit production rates due to the numberof tubings within a fixed size of casing and the consequent need to use smaller tubingdiameters.
