3.5 Well completion - · PDF fileform the closing point of the reservoir, ... Well completion. ... pup joint packer wireline entry guide tubing

3.5.1 Introduction

The term completion, when applied to oil wells, isused to define all post-drilling operations that arenecessary to hydrocarbon production. Completion has,on the whole, a permanent nature, which means thatplanning parameters must be carefully evaluated, andpossible solutions must undergo technical andeconomical optimisation.

Completion planning involves choosing andorganizing the equipment to be used, selectingmaterials, establishing production line tubingdimensions, stipulating production intervals, andfinally defining the mode of formation fluidproduction. This evaluation must take into account theevolution of the productive characteristics of the well,according to the production forecast.

In fact, the production characteristics of each welldepend on the interaction between the reservoir, the completion, and the surface equipment.These macro-elements, in their interaction, set theconditions for production in relation to the flowingpressure and the flowing rate at the wellhead.

One very important element that influences thefluid mechanics during production is the type ofproduced fluid. This fluid can be a liquid, a gas, or amixture of liquids and gases. Therefore, the chemicaland physical characteristics of the produced fluid andits evolution over time must be known when planningthe completion. An understanding of the producedfluid’s characteristics is the basic element needed todefine the pressure at the first separator, which willform the closing point of the reservoir, well andsurface plant’s fluid mechanic system, and which is thestarting point when planning a production plant.

The production capacity of a well is determined onthe basis of reservoir data such as reservoir pressure,

permeability and the thickness of the pay rock aroundthe well, and according to the results of previousproduction tests, which are used to determine theProductivity Index (PI). Using the productivecapacity, defined as a function that combines the flowrate and the acting pressure regime, which is known asthe Inflow Performance Relationship (IPR), theservice conditions of the well are determined. On thebasis of these, the diameter and thickness of the tubingare chosen. It is also important to consider theefficiency of the completion in the light of thedecrease in reservoir pressure over time, and toevaluate a possible substitution of the originalcompletion with one of a bigger diameter, to reducepressure loss, and guarantee the produced flow. If thereservoir pressure is insufficient for natural flow, itmay be necessary to consider an artificial lift system.

The presence of non-hydrocarbon components inthe produced fluid conditions the choice of thematerials. In fact, the frequent presence of carbondioxide and/or hydrogen sulphide in the hydrocarbon-water mixtures leads to the formation of acid solutionsthat attack the materials the completions are made of.This is why the materials generally used, such asspecial stainless steels, elastomers, and compositematerials, have a good resistance to corrosive agents,and good retention of mechanical properties.

Another fundamental element to be taken intoaccount when planning the choice of materials and thecompletion’s structural design is the temperature. Aswe know, the subsoil temperature increases by 3°C forevery 100 m of depth. The metallic structure istherefore subjected to mechanical stress due to thermaldilatation. The temperature also influences in differentways the acidic components’ effect on the materials,and the mechanical behaviour and stability of theplastic and elastomeric materials.

385VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT

3.5

Well completion

The type of completion adopted will depend onthe structural/geological characteristics of thereservoir, and on the type of mineralization. Thereare two categories of completions: conventionalcompletions and so-called smart completions. Thelatter were introduced in the early 1990s with the aimof allowing production management to take placedirectly in the well, thus avoiding maintenance workleading to interrupted production and additionalworking costs.

In the course of a well’s producing life, whichlasts several decades, interventions may be necessaryto restore the optimal flow conditions. Theseconditions may be reduced because of clogging,scale, hydrate or asphaltene deposits or otherproblems in the hole or the formation. The operationsto be undertaken to remove possible obstructions, orto restore the production capacities of the formationmust be planned when designing the completion, inorder to reduce the costs and simplify theinterventions.

Some completion jobs aim to prevent problemsthat may arise during the productive phase. Forexample, the completion could get clogged up bysolids dragged up through the production plant,causing erosion to the plant in general, or to specificparts of it, such as valves or bends. It is thereforenecessary to separate the solid particles from thefluids, by installing filters and sand-catchingdevices. The solid particles must then be properlydisposed of.

3.5.2 Types of completion

OverviewOil and gas well completions can be divided into

two main categories: open hole well completions, andthe case-hole completions.

In open hole completions the pay rock is kept as itis, and no cemented casing columns are needed. Thistype of completion is realized when the formation isself-supporting or when, on the contrary, it is tooseverely fractured to guarantee successfulcementation. It is the optimal solution since the entiredrainage surface is available for production, andpressure drops are limited. Moreover, the absence ofcasing columns makes it easier to proceed to wellstimulation. On the other hand, in open holecompletions it is impossible to control the entrance ofsand and water in the hole, and it is therefore verydifficult to isolate the levels and proceed to theirstabilization.

Case-hole completions are more widely used due totechnical reasons relating to the stability of the hole. In

this case the well to be completed is one that has beenlined and cemented throughout its entire development.In order to make production possible, it is necessary tore-establish hydraulic communication between the payrock and the hole. This operation involves drilling thelining, the cementation and the pay rock.

There are four possible solutions to establishcommunication between the productive formation andthe surface: a) tubingless completion; b) packerlesscompletion (with a tubing string and without isolationbetween casing and tubing); c) single string withhydraulic isolation completion; d) multiple stringcompletion.

The tubingless completion method is used inwells where the pay rock pressure is low and highflow rates are required. In this case production musttake place directly through the final lining of thewell, with no support from production strings orisolation systems.

386 ENCYCLOPAEDIA OF HYDROCARBONS

DRILLING AND COMPLETION OF WELLS

tubing hanger

tubing joint

seating nipple

pup joint

pup joint

packer

wirelineentry guide

tubing

seating nipple

seating nipple

pup joint

wirelineentry guide

Fig. 1. Packerlesscompletion (© 2004 Baker Hughes,Incorporated).

Fig. 2. Single string packercompletion (© 2004 Baker Hughes,Incorporated).

Packerless completion is a more financiallyadvantageous system. Here, only the production tubingis placed in the well, and it is possible to produce boththrough it and through the annulus (Fig. 1). Theproduction tubing can be used for injecting inhibitorsor killing fluid. This method is somewhat limited interms of flow conditions and the protection of thetubing materials. Moreover, it is difficult to detectleaks in the tubing or the casing, and to gatherbottomhole pressure data.

The single stringe completion using hydraulicisolation and just one string is convenient when theproduction layer appears to be homogeneous and aselective-zone production is not necessary. It consistsin the use of a single tubing string that is lowered intothe well together with an isolation device for theformation section to be produced, called the packer(Fig. 2).

Where there are several production layers for onefluid, a single selective completion is used. Thissystem has only one tubing string and severalpackers that isolate the various production levels.By using wire-line operations it is possible to open

and close the valves so as to allow production onsingle layers (Fig. 3).

The multiple tubing string completion uses, at themost, two or three tubings, isolated by packers andproducing on different levels at the same time (Fig. 4).This solution is useful when the reservoir presentsdifferent layers of mineralization, for example gas andoil, or different types of oil, because it allows us toproduce selectively according to necessity, whilekeeping production active on various levels at thesame time. For the single tubing strings, it is alwayspossible to adopt a solution similar to the singleselective completion, thus obtaining a multipleselective completion. This system’s drawback is thelimited diameter of the tubing which in turn reducesthe flow capacity of each tubing string.

Multilateral completionsThe introduction of deviated well drilling, and in

particular the adoption of multilateral schemes has ledto the necessity to develop devices for ad hoccompletions. In general, completion technology for


WELL COMPLETION

locator seal assembly


production packer

production packer

production packer

sliding sleeve

sliding sleeve

seal bore extension

seal bore extension

seal bore extension

seating nipple

seating nipple

wireline entry guide

blast joint


blast joint

safety valve

safety valve

scoophead

seating nipple

seating nipple

blast joint

sliding sleeve

single string retrievablehydraulic set packer

hydraulic set dual packer

hydro-trip pressure sub

wireline entry guide

Fig. 3. Selective single stringcompletion (© 2004 Baker Hughes,Incorporated).

Fig. 4. Dual string completion(© 2004 Baker Hughes,Incorporated).

3 4

multilateral wells combines selective and multiplefunctions, and also has the particular characteristic ofusing several holes, which converge into a ‘father’well. In fact, the multilateral system is based onseveral wells, all derived from one initial well. Thenumber of wells, their orientation, disposition andinclination to the vertical, as well as the chosen type ofcompletion and isolation, have led to the developmentof a number of systems. Below is a brief description ofthe systems currently available, based on theclassification provided by the TechnologyAdvancement of Multilateral (TAML), a group ofexperts operating in the field (Fig. 5).

Level 1 is known as the Openhole Sidetrack. Thismethod is the simplest completion system. Both themain well and the secondary wells are openhole. Thesecondary wells are not isolated. Level 2 has a casedand cemented main well, while the secondary wellshave an openhole completion. It is possible to installliners, or filters, in the lateral branches. The keyelement of this type of completion is the connectionfitting for lateral inflow that is assembled togetherwith a permanent packer. Level 3 is similar to level 2.The difference lies in anchoring the lateral liner to theinside of the main well, thus giving the completionbetter mechanical strength. This type of completionalso includes a hook hanger, which is a connectingdevice installed between the completions of the mainwell and that of the secondary branch, allowing forselective entry in both holes. In level 4 the lateral wellis cemented. This guarantees the mechanical resistanceof the derivation section of the lateral branch, but doesnot grant it hydraulic sealing.

In level 5 the hydraulic seal is obtained by isolatingthe junction between the lateral branch and the fatherwell from the injected fluids and the produced ones.The hydraulic seal is achieved by means of threeconventional packers: one in the lateral branch, onelowermost in the main well, and the last one above thejunction. A scoophead diverter tool is also added todivert the tubing into the lateral branch. This methodoffers selective access to the single branches, and thepossibility to manage independent production. Level 6aims to guarantee mechanical and hydraulic continuityby using casing to ensure hydraulic sealing in thebranching section. To this end, ad hoc elements areused to make sure that it is perfectly continuous. Forthe completion, standard configurations, such as dualcompletion, are used, with the difference that the twotubing strings are set in two distinct holes. Once more,a scoophead diverter tool may be used.

Multilateral technology can potentially increasewell productivity by exposing a limited number ofwells, generally horizontal or severely deflected.Technological improvements in drilling and completion

have made it possible to drill, cement, and completeseveral lateral wells starting from a single main well.This technology gives enhances the benefits ofhorizontal completion. Under certain conditions, suchas production from very deep reservoirs, multilateraltechnology saves time and money, compared totraditional drilling of many single wells.

Multilateral wells expose the reservoir to theproductive system more than others, thus increasingthe productivity from a single slot. As some reservoirsdepend exclusively on the natural fracturing system foroil and gas production, the planning of lateral wellsincreases the probability of finding and producing oiland gas from various fracture systems.

The use of multilateral completion in a singlereservoir can increase the drainage efficiency. In fact,the lateral wells can be drilled in several directions toincrease the area in contact with the reservoir,enhancing well productivity and reducing the numberof wells needed for the development of the productionfield.

When an impervious barrier blocks the verticalflow of the hydrocarbons between two productionareas, stacked systems can be used to produce in bothareas, and overcome the obstacle in the formation.

According to the length, number, angle anddistance of the secondary wells, this kind of systemcan increase productivity, in comparison withconventional horizontal wells. The development costsfor single wells can be reduced because a smallnumber of wells is necessary.



level 1 level 2 level 3

level 4 level 5 level 6

Fig. 5. Multilateral well completion:TAML classification (© 2004 Baker Hughes, Incorporated).

The decision to drill and complete a multilateralwell requires the planning of an appropriatecombination of drilling, casing and completioncomponents in order to minimize problems. Thechoice of an appropriate completion system, as statedabove, depends on the interventions required in thewell, and on the expected life cycle of the well.

Intelligent Completion Systems (ICS)The term Intelligent Completion System indicates

the direct control of well processes. This system aimsto control the flow and emission, both on a productivelevel and on an environmental level, operating as closeas possible to the source in order to adopt the bestproduction strategies to control well behaviour.Proximity to the source, and in particular to theproduction area, is one way of facilitating operationssuch as pressure, temperature, and flow measurement,as well as making operations such as separation andre-injection of produced water more economical.

The main reason for adopting an ICS lies in theproduction flexibility, the reduction of future workoverjobs, and the consequent improvement in wellperformance. The fundamental benefit is the reductionof routine operations and occasional interventions dueto the use of remote instrumentation and motorizeddevices in the well, such as control and/or productionvalves.

The most interesting aspects of ICS include: a)flow control of different production levels; b) selectiveclosing of the levels where production is conditionedby water or gas rates greater than the established ones;c) selective water injection for assisted production ondifferent levels; d) instrumentation for precisemeasurements of pressure, temperature and flowdynamics; e) devices for the separation of water, oiland gas downhole; f ) remote control of production;g) instrumentation for selective testing of theproduction capacity of the various levels.

The archetypal ICS is geared towards wellscontaining areas isolated by multiple or single packers.Each packer contains well-logging devices formeasuring pressure and temperature, and monitoringthe flow, as well as powered choke valves allowing theregulation of production. All monitored and controlledlevels are connected to the control centre on thesurface by cable. This cable transmits the datagathered by the sensors in each production level, andcarries the command signals to the devices locatedalong the tubing string (Fig. 6).

The systems for data transmission, both bi-directional and not, from or towards the bottom ofthe well, usually make use of fibre-optic technology.Fibre optics present many advantages comparedto traditional cable-data transmission systems, for

example the ability to transmit a greater quantity ofinformation than conventional systems with a bettersignal-noise relationship. Fibre-optic systems do notinterfere with other systems present in the well sincethey do not use electric current for data transmission.They also save a lot of space, occupying from onequarter to half of the space normally required forconventional systems. This rational use of spaceallows for the installation of other technicalinstrumentation. Fibre optics are intrinsically saferthan conventional systems since they are notdependent on an electrical signal to function, and areable to withstand temperatures as high as 300°C.Safety is, in fact, an important aspect of electricitysupply both for fibre-optic transmission systems andfor the engines needed by the actuators linked with theregulation devices in the well.

One highly interesting aspect of intelligentcompletion is the use of separating devices inside thewell. The idea of separating oil from water downhole,and re-injecting that same water into the formationduring oil production is very convenient. Thistechnique avoids the expense of hoisting the fluids tothe surface, reduces the size, weight, and cost of the


WELL COMPLETION

safety valve

gauge carrier

lateral entry nipple


torquemaster packer

control lines

multiple feed through packers

hydraulic sliding sleeve or electric valve

gravel packscreen

gravelpack packer

Fig. 6. Intelligent completion: completion with production control in well (© 2004 Baker Hughes, Incorporated).

equipment needed on surface, and reduces theprocessing costs in specific areas, such as offshoreplatforms.

The general tendency is to remove water as closeas possible to the pay rock, thus creating morefavourable conditions for production. Indeed, atrelatively high temperatures, such as reservoirtemperatures, the fluid viscosity is inferior to that onthe surface, and both gas, and, if present, asphaltene,are still in a state of solution. Moreover, the oil fromthe reservoir has still not been subjected to intensestirring therefore emulsion is less likely to form.Finally, water removal on this level helps to limitpressure-loss along the production tubing, andtherefore increases production.

3.5.3 Completion equipment

The equipment that is used to assemble completionstrings in a well is numerous and varied; therefore,only the main elements will be described here.

Tubular equipmentThe main element in completion is the tubing,

that is the network of pipes which connect the area ofthe reservoir selected for production to the surface.The pipes are made of non-welded stainless steel, andare classified according to length, diameter, type ofsteel, weight, thickness, and according to the type ofthread and joint. An alternative to the use of stringsof pipes connected by joints is the use of so-calledcoiled tubing, which consists in a steel pipe coilaround a drum that is introduced into the well bymeans of a special tool. This method is economicallyconvenient because it allows us to get a completionworking in very little time, and to dismantle it veryrapidly. Coiled tubing can also be re-used in othercompletion plants. It is generally used in temporarycompletions to carry out long-term well tests, orwhere the use of a jointed tubing system wouldpresent serious problems.

Special elements are added to the tubular units thatmake up the production string. These are needed tocarry out specific local functions, and include flowcouplings, blast joints, landing nipples, circulationdevices and travel joints.

Flow couplings are short pipes which are thickerthan the tubing. They are used near devices that areliable to produce high turbulence within the tubing, inorder to delay possible damage due to erosion. Theflow couplings are generally twice as thick as thetubing, for an equal internal diameter, and are usuallyused with the landing nipples or the circulationdevices.

The blast joints also serve to prolong thecompletion’s life span by protecting it from the erosiveflow which comes into the well via the productionstring. They have a similar internal diameter to thetubing, but their external diameter is larger.

The landing nipples are thick stub pipes, turned onthe inside to create blocking profiles and landing seats.These joints serve to provide landing seats for flowcontrol devices. Other joints are used to landremovable safety valves. In this case the landingnipples can differ from the standard joints bypresenting a hydraulic control line.

Circulation devices are used to put the inside of theproduction string in communication with the annulustubing-casing. This communication is required tocirculate a fluid in the well, to treat the well withchemical products or to inject fluids into the tubingthrough the annulus. There are two different devicesfor doing this: sliding sleeves and side pocketmandrels.

A sliding sleeve is a cylindrical device with aninternal sliding mechanism, or sleeve. Both the sleeveand the outer cylinder are perforated so as to providecoupled openings, and the sleeve is moved up anddown by a wire-line tool. When the sleeve is broughtinto the open position, the relative opening is in linewith the opening in the outer cylinder, and allowscommunication between the tubing and the casing.The sliding sleeves are usually positioned either abovethe uppermost packer in order to carry out circulationand pressure-balancing operations in the well, orbetween two packers to allow for selective productionon multilevel reservoirs.

The side pocket mandrels are special devices thatpresent a chamber parallel to the flow chamber, inwhich it is possible to fix devices and connect theannulus to the inside of the string without occupyingthe flow diameter. Their main utility is that ofproviding seats for gas-lift valves, but they can also beput to a different use: as a means for circulating fluids,and as an emergency device for well killing. In thiscase, a valve is installed, which will only open if thereis major external pressure on the tubing, thus allowingthe entrance of a fluid.

One very important element is the expansion joint,usually referred to as the travel joint. These jointsabsorb the motion of the production tubing which isdue to variations in pressure and temperature. A traveljoint is composed of two concentric tubes fitting intoone another, and hydraulic seal units, that are placed inthe internal tube to isolate the annulus between the twoelements during the joint excursion. Travel joints areusually installed above the uppermost packer, tocontain the tubing motion which is otherwise difficultto compensate.



Wellhead completion The production string is connected to the wellhead

by means of a series of elements that form thewellhead completion. These are the tubing spool, thetubing hanger, and the Christmas tree (Fig. 7).

The tubing spool serves to hold up the productionstring and to connect, at the bottom, the casing headsand, at the top, the Christmas tree. The tubing spoolincludes two lateral openings that allow annuluscontrol between production tubing and productioncasing.

The tubing hanger is needed to support the tubingand to establish the annulus seal. The annulus ispositioned in the tubing spool, and the productiontubing is screwed on to it. An external gasketguarantees the seal between the production casing andthe tubing.

The Christmas tree is located above the tubingspool. Its function is to consent productionregulation, and to create safe conditions for workoveroperations inside the well. The Christmas tree iscomposed of two main gate valves, called the mastervalves, which enable the well to be closed. Abovethese a crossover connection is installed. Wingvalves, which are fixed to the lateral flanges, are usedboth for production and for possible workover jobs inthe well. On the upper flange there is yet anothervalve, similar to a master valve, and a crowningflange that is used to install the workover equipmentwithout having to stop the flow. The absolutepressure gauge is installed on the crowning flange incorrespondence with the wellhead.

The production packerIn most cases, the production string has not only

one anchoring point in the wellhead, but also a secondone located in the lower part, near the level to beproduced. The latter is achieved by means of a packer,which also serves as a hydraulic separator between theproduction area and the remaining part of the well.Packers also have a number of other functions. Theyare used to protect the casing from formation pressureand from the fluids produced, to isolate leaks in thecasing or in damaged perforations, to isolate multipleproduction horizons, to keep production fluids withinthe annulus, and to enable the use of certain artificialhauling methods.

Once the need to install a packer has beenidentified, it is necessary to choose the type,dimension, hole number, as well as the instalment andremoval modalities. Although a wide range of packermodels exist, all packers have similar characteristics:every packer is equipped with a flow mandrel, packingunits, a cone seat, and slips. The mandrel provides theflow conduct for production. The production tubing is

installed on the mandrel, along with any other devicethat needs to go through the packer. The packing unitsenable the maintenance of different pressures betweenthe tubing and the annulus. The cone seat sets in placethe guy rings, which then grip the casing wall andprevent up and down motion on the part of the packer.The cone seat also permits the expansion of thepacking units.

A primary distinction of the various packersincludes a classification according to the removalpossibilities they offer, and separates the permanentpackers from the removable ones.

Permanent packers cannot be completely removedor reinstalled in the well; they are usually installedseparately from the completion string, which issubsequently inserted under pressure on the flowmandrel of the packer. Appropriate equipment isnecessary for this particular job. It is possible to installthis type of packer using the production string, but todo so it must be possible to disconnect the tubing fromthe packer, in order to later remove the packer. Theremoval of this type of packer involves milling,making it impossible to reuse the packer elsewhere.

Removable packers, on the other hand, aredesigned to be removed and reinstalled elsewhere inthe well. This characteristic means that they are


WELL COMPLETION

wing valve

tubing pressure

surface choke

tubing

master valve

productioncasing

intermediate casing

surfacecasing

lowermostcasing head

uppermostcasing head

tubinghead

casingvalve

casingpressure

the

Chr

istm

as tr

eeth

e w

ellh

ead

Fig. 7. Wellhead and Christmas tree scheme (Agip, 1996).

usually installed together with the production string,and are activated both mechanically and hydraulically.These packers can be removed either by exertingtension on the string, or by implementing a series ofrotations that lead to the disengagement of thegripping device. The uncoupled guy rings retract totheir seats, the packing units relax, and the device isready for removal.

Another characteristic according to which packersmay be classified is the presence of crossing holes.These enable communication through the packer, andcan both host the completion string, and permit accessand connection to any type of electronic device, ormeasurement equipment located beneath the packeritself. There are packers with one, two or three holes,and they are known as single, double, or triple packers.The double packers are usually used, for example, indouble-string completions. In the case of single-stringcompletions, the use of a double packer allows thetransmission of electrical power from a submersedpump.

The installation of packers involves pushing theslips towards the packing units in order for them toexpand. To exert this compression force between theslips and the rubber units, several techniques can beput into practice. These different modalities includestring rotation, weight release, string tension,pressurizing from the inside of the string and gasexpansion produced by means of explosion.

In general, the installation methods are divided intomechanical, hydraulic and electrical ones. Mechanicalmethods make use of techniques that involveinterventions on the completion string, such as rotationor tension of the tubing, or weight release. Thehydraulic method consists in pressurizing the inside ofthe string to activate the piston that is located withinthe packer, while the electrical method consists insending an impulse to the setting device through theelectric wire. The electrical impulse activates anexplosive charge within the setting device in order toexpand the combustion gas: the increase in pressuredue to its expansion provides the necessary force forthe setting of the packer.

Certain packers require the setting force to beapplied continually in order to keep the packer inplace. These packers are called compression-set andtension-set packers. They are both of the mechanicaltype, and require the setting force to be applieddirectly to the production string. Compression-setpackers need a compressive load to be constantlyapplied from above. This load is usually applied byreleasing the tubing weight, but can also be applied bymeans of a pressure differential, using the increasedpressure exerted on the upper face of the packer. Thisis why compression-set packers are used in injection

wells. In fact, if the compressive load happens to bereduced, the setting device slackens, and the packerbecomes uncoupled. It is therefore important toevaluate the forces exerted on the tubing to establishwhether these may lead to the uncoupling of thedevice.

As tension packers can be set and held in placeonly under tension, a tension load must be exerted bymeans of tubing pulling. This means that the extrapressure in the lower part of the packer increases itstightness. This type of packer is used in cases wherethe formation pressure of the production levels issuperior to the pressure exerted on the annulus.Neutral stress or compression conditions lead to theuncoupling of the packer. Operative conditions whichproduce tubing expansion, for example a temperatureincrease that induces thermal dilatation, also producethe uncoupling of the packer.

Hydraulic, electrical or mechanical packers that areset by means of string rotation are defined as neutral,since they remain in place whether the string is undertension, in compression, or neutral.

The methods employed to bring the packer into thedesired position may involve the use of cable, drillpipes or work pipes, or the production string itself. Themethod used for setting must be compatible with thechosen type of packer and the connection systembetween the packer and the tubing, and the relevantcost evaluations must be taken into account whenconsidering alternative solutions.

There are four different methods to connect thepacker to the tubing: threaded connection, anchorassembly, J-latch setting and locator setting. Ananchor assembly system requires the use of short pipeswith seal gaskets, and a series of grip teeth to keep thetubing locked to the packer. A J-latch setting consistsin a J-shaped gripping and locking latch set on top of aseries of seals, which is fixed to the packer head bymeans of internal or external pins. These types ofconnection, together with the threaded connection,promote the development of an integral packer-tubingsystem. The locator assembly consists in a stack ofannular seals topped by a positioner. This system doesnot promote mechanical continuity between the tubingand the packer, which is why it allows for tubingmotion, both in expansion and in contraction, againstthe packer.

Subsurface Safety Valves (SSV)SSV are control devices that are used to interrupt

well production when there is an emergency. Theopening and closing of a safety valve can either beoperated from the surface by means of a hydrauliccontrol line, or directly activated by the wellconditions.



SSV that are controlled from the surface arecomprised of a piston on which pressure is exertedfrom the surface by means of the hydraulic line. Thispressure causes the locking device to remain open.A spring is positioned to act in the oppositedirection, thus closing the valve, should an absenceof pressure occur. In most types of SSV controlledfrom the surface, well pressure is made to act inaccord with the spring, in order to close the valveitself.

SSV controlled within the well are directlycommanded by well pressure, and do not require asurface control line. In this case, the valves are armedon the surface before installation. They stay open aslong as the flow conditions remain in keeping with thenormal production pressure regime, otherwise theyclose. Given that the absence of control from thesurface makes it impossible to re-arm, and therefore tore-open them, the use of these valves is limited tospecific applications.

There are two types of SSV: Tubing Safety Valves(TSV), that are installed along the production tubingand used to control the tubing flow, and AnnularSafety Valves (ASV), that are used to control the flowin the annular space between the tubing and thecasing.

Security valves may be classified according totheir shutting system, and according to how they arereused or dismantled. To be dismantled, some TSVrequire the removal of the tubing, while others can bedismantled without any work on the tubing, butthrough a wireline intervention which removes thevalve from its seat using an appropriate tool. Theshutting devices most commonly adopted for SSVs areballs or hinged disks; both mechanisms can be usedwith removable safety valves or with a wirelineintervention.

An essential element that characterizes thedifferent types of valves is the pressure-equalizingdevice. In fact, a difference in pressure across thevalves occurs during the closing process. This must beeliminated before re-opening the valve. Thanks to thepressure-equalizing device this opening operation canbe carried out by working directly on the valve. If this device is not in use, it is necessary to equalizepressure by pressurizing the tubing above with a pumpor a compressor before opening the valve. Pressure-equalizing devices are extremely useful but,since they are exposed to high stress and speed levels,they can themselves become problematical during valve opening and closing operations. This is why equalized valves are usually used for SSVwhich are installed and removed using wireline, whilst non-equalized valves are highly recommendedfor tubing retrievable safety valves.

Annular Safety Valves (ASV) are used in theproximity of the wellhead to prevent gas fromgetting in from the casing-tubing annular spaceshould a wellhead failure occur. This situation mayarise, for example, in a completion using gas-liftsystems, or Electrical Submergible Pumps (ESP). Inboth cases the annulus between tubing and casing isused to either inject (in the case of a gas-lift) or toevacuate gas (in case the case of an ESP). After this,an ASV is installed, together with a productionpacker, a TSV, and an optional travel joint. Thevalves are controlled from the surface by means ofcontrol lines, to enable re-arming if necessary.

Future use of ASV depends on the development ofhole-separation systems and formation-fluid re-injection for single completions.

3.5.4 Equipment

In choosing the equipment for a well completion it isnecessary to specify which materials are adequate forthe use foreseen.

Metallic tubular elements are produced in low(0.3%) carbon steel with low quantities ofmanganese. The increase in mechanical resistance isobtained by hardening or tempering the steel. Specialsteels that do not come under the API categories areused in hostile environments that require highmechanical resistance or resistance to hydrogensulphide. The API standards that regulate the metallicmaterials used for completion equipment also applyto the well casing.

The equipment for standard use usually complieswith the mechanical requirements laid down by theAPI L-80 regulation. The API L-80 also applies tocorrosive or acidic environments, but does not taketemperature into account. Temperature has a greatinfluence on the behaviour of non-metallic materialssuch as, for example, elastomers. These deteriorateover time at temperatures above 275°C, and lose allsealing capacity. High-efficiency elastomericcompounds have higher operating temperatures, but,when used under strong pressure, require supportdevices to avoid elastomeric extrusions.

Interesting results arise when considering theworking conditions and the type of environment inwhich completion equipment must function. Theprobability of corrosion occurring is strongly linkedto the presence of both reservoir and condensationwater. The water present in the production stringassumes a corrosive character in the presence ofcarbon dioxide (CO2), hydrogen sulphide (H2S), andacidification fluids; it is therefore important toestablish corrosiveness a priori, in correspondence


WELL COMPLETION

with the temperatures in the hole when CO2 andH2S are present, before choosing which metallicmaterials to install. It should be noted that thecorrosion speed increases with the water productionand the decrease in the water’s pH. When the tubingbecomes wettable to oil, or when water-in-oilemulsions are produced, the possibility of corrosionis strongly mitigated.

Corrosion due to CO2 proves to be dependent onits concentration and temperature; in particular, fortemperatures below 60°C, the main corrosive factor isthe concentration of carbon dioxide. As theconcentration of CO2 increases, so does the corrosiveeffect, whereas corrosion diminishes with the increaseof water salinity. At temperatures above 60°C, thedeposition of iron carbonate (FeCO3) and iron oxidecauses a decrease in corrosion. In this case the rise insalinity produces an increase in the corrosive potentialof the water-carbon dioxide mixtures.

Another important aspect relative to corrosion isthe use of different metallic materials together. In thiscase potential differentials develop between the twometals that are in contact, creating a galvanic flux thatconsumes the metals as though they were sacrificialelectrodes. It is also important to evaluate the effect ofstimulation operations using acidic solutions, orinjections of water is not completely de-aired, andtherefore rich in oxygen.

Induced embrittlement due to the presence of freehydrogen is of crucial importance in hostileenvironments. In this case, exposure to hydrogensulphide causes a non-brittle material to take on brittlemechanical behaviour, due to the penetration ofhydrogen atoms within the metallic structure. Thisphenomenon is most common in high-pressureenvironments, and is accentuated when theconcentration of hydrogen sulphide increases. Otherenvironmental factors that favour the development offractures in embrittled metals are tension stress,temperatures below 65°C and the presence of acidicwaters. Conditions for embrittlement can also becaused by the chlorine ions found in hot andparticularly saline waters.

In addition to metallic materials, plastic materialshold a very important place. These materials aremainly used for the realization of packing units,which are not only exposed to mechanical strain, butalso to other types of stress when exposed to hightemperatures and pressures, and when in the presenceof both hydrocarbon and non-hydrocarboncompounds. Plastic materials are divided into twogroups: elastomeric or non-elastomeric. The firstgroup includes the well-known nitrile compoundsthat have proved to be particularly appropriate for therealization of gaskets and packing elements.

However, elastomeric nitrile compounds have alimited field of application, since their quality isdegraded in the presence of hydrogen sulphide,aromatic solvents (xilene and toluene), and heavycompletion fluids, such as zinc bromides, and acids.The same quality abasement occurs at temperaturesexceeding 135°C. To operate in conditions which arehostile to nitrile, fluorocarbon elastomers can beused. However, it should be noted that corrosioninhibitors made with amines, methanol,glutaraldeide, and steam will degrade the qualities ofthis material. Another possible solution is offered byperfluor elastomers, which present a wide field ofapplication without showing any particular limits inperformance.

The non-elastomeric plastics, on the other hand,are generally used for seal gaskets, particularly thethermoplastic materials. These present good chemicalresistance, but tend to lose some of their mechanicalproperties when subjected to high temperatures. Theyare usually used in packing units, and are sometimesused together with elastomers. Thermoplasticmaterials are considered high performance, and aretherefore used in particularly severe conditions.

3.5.5 Completion fluids

The definition of completion fluids is a recentoccurrence in oil industry history. In the past, nodistinction was made between drilling fluids andcompletion fluids. According to the definition,completion fluids come somewhere between drillingfluids and stimulation fluids. A strict definition ofcompletion fluids considers them to be saline solutionsor brines, which are used in completion operationssuch as casing perforation or gravel-pack setting. In abroader sense, completion fluids are all those fluidsthat come into contact with the reservoir; in fact, thisdefinition does not refer to the type of fluid, but to thefunction it serves. Perforation fluids used in thedrilling of the mineralised formation can beconsidered completion fluids. This perspective led tothe development of the so-called drill-in-fluid, whichcan be used both as perforation fluid and completionfluid. As such, a completion fluid comes into contactwith the mineralised formation, and its main functionis to avoid damaging the producing capacity of thereservoir. In this light, the fluids used for the acidicwashing of the wells to remove calcium carbonate andmud walls formed by drill-in fluids can be consideredto belong to this category.

The brines used in completion operations are theprincipal fluids to be put to such use. One can also usedrilling mud and degassed oils. The brines are formed



by a watery base with a salt content that is establishedaccording to the required density, and chemical andphysical compatibility regarding the formation withwhich they come into contact.

The density of the fluid is established so as to havecontrol over the pressures in formation. Havingdefined the depth and the overbalance pressure,generally 15-20 bar, the density of the fluid isdetermined. This will have to be modified according tothe temperature, to take into account the expansionthat these fluids experience undergo whentemperatures increase. Their expansion factor dependson the total saline concentration and on the saltsdissolved in them. Another factor to be considered inpreventing overbalance pressure is the compressibilityof the fluid, although this has a less importantinfluence.

The salts most commonly used are the chlorides ofsodium (NaCl), ammonium (NH4Cl), potassium(KCl), and calcium (CaCl2), as well as the bromides ofpotassium (KBr), sodium (NaBr), calcium (CaBr2),and zinc (ZnBr2). Some of them are used inassociation, for example: calcium bromides andchlorides, and zinc bromide with calcium bromide.The densities can reach a maximum of 1,100 to around2,500 kg�m3 at 20°C. In terms of costs, the mosteconomical brines are the chlorides and the calciumbromide and chloride mixtures.

The brines must satisfy compatibilityrequirements applying to both clay formations and tothe formation waters, as well as to the gases and oilsthat are present. The objective regarding the variousclays is to avoid swelling and/or deflocculation,which in turn cause the detachment of particles fromthe walls. To reach this objective, minimum salinityrequirements must be fulfilled, in other words, atleast 3% of NH4Cl or 2% of KCl must be present.In the case of formations that present a strongproportion of clay components, it is generallypreferred to replace brines with oily fluids that havehigh inhibiting capacities. When using salinesolutions with high densities particular attentionmust be paid to any damage caused to the formationby solute precipitation. In fact, it has been observedthat in the presence of calcium salts, precipitationoccurs when density exceeds 1,700 kg/m3. In thesecases it is advisable to use at least 8% of ZnBr2. Ithas also been noted that temperatures above 150°Cinfluence the growth of crystals, thus favouringdamage.

The compatibility of completion fluids withformation waters has a great influence on theformation of scales. Scales form when incompatiblewaters are mixed, when temperature or pressurevariations cause solubility to vary or when water

evaporates. The most common types of scales areformed by calcium and iron carbonates, calcium,barium and strontium sulphates, sodium chloride, ironsulphide and silicates. In order to prevent soluteprecipitation it is useful to carry out compatibility testsbefore choosing the completion fluid. If severaldifferent brines are used, it is recommended to verifytheir compatibility beforehand.

Verifying the compatibility with natural oils andgases in formation involves testing for any formationof water-oil emulsions and slime deposit, which couldclog the pores and damage the formation. It istherefore considered important to test in the laboratoryfor emulsion formation under reservoir conditions.Should incompatibility be ascertained it can becounteracted by reformulating the completion fluid.These phenomena mainly arise where thick brineswith a high degree of salinity are used. In the case ofnatural gas, the risk of CaCO3 precipitation whenusing calcium-based brines depends on the contents ofthe CO2.

3.5.6 Casing perforation

In cased hole well completions, it is necessary to drillthe casing in order to restore hydraulic connectionbetween the inside of the hole and the pay rock. Thisoperation is carried out with the help of devicescalled guns, a denomination due to the originalperforation method that involved the use ofperforating bullets shot by short guns. The guns havethe function of guiding the bullet towards the casedhole so as to perforate it and reach the pay rock,penetrating it in part. The speed reached by thebullets, about 1,000 m/s, is sufficient to perforate thetubing, the cement and the pay rock. This method isnot very efficient when used in resilient formations,or when particularly strong casing materials are used.Nowadays, this method is only used when dealingwith soft formations, or when it is important toobtain perfectly round holes.

Another perforation method consists in usinghigh-pressure fluid jets containing either liquids orwater-sand mixtures. The devices used make itpossible to create holes or gashes in the casing, and,if necessary, to produce a cut in the casing. The mainadvantage of this method is the possibility of creatingvery clean cuts without damaging the formation. Themain disadvantage is the slowness of the process, andthe elevated costs it involves; it can realistically beused only for carrying out perforations on shortintervals.

The third perforation method is currently themost widely used, and is called jet perforating. This


WELL COMPLETION

method consists in using explosive charges oftenknown as jet charges, which are collocated withina support system called gun. The charges have aconcave shape which, in the moment of expulsion,promotes the formation of a primary expansionchamber for the gases produced and helps to aimin the chosen direction. Jet perforation systems arecomposed of a series of elements that form the so-called explosive train. These elements are: adetonator that is used to activate the charges, adetonating fuse to connect the detonator to thecharges and the charges to each other, and thecharges themselves. The explosive train can bebrought into the hole in different ways. A wirelinesystem can be used before lowering thecompletion. Alternatively, coiled tubing or theproduction string itself can be used, in order tocarry out successive operations directly in thewell.

The explosives used in this perforation systemare of the detonating type, that is to say materialsin which combustion proceeds at a faster speedthan sound propagation. Detonating explosives canbe divided into primary and secondary types.Primary explosives are used exclusively indetonators because of their extreme sensitivity toignition, and must therefore be handled withextreme care. In the oil industry they areincreasingly being replaced by secondaryexplosives, which are used in all three componentsof the explosive train. They are much less sensitiveto ignition, and are therefore an intrinsically safermaterial. In the oil industry the most utilizedsecondary explosives are RDX, HMX, HNS andPYX (Table 1).

The two types of detonators that are used arethe electrical and the percussion detonators. Whena wireline method is employed for the positioningand the execution of the perforation, the detonatorsused are of the electrical type. Among these adistinction is made between detonators usingprimary explosives, and those using secondaryones. The detonators that make use of secondaryexplosives are: exploding foils, explodingbridgewires, and deflagration-detonation transitiondetonators. The choice of the appropriatedetonator depends on the energy necessary for itsignition. In fact, these detonators present a self-ignition risk due to stray currents that can occurwithin the electrical elements. Adopting detonatorsthat require a lot of energy for ignition reducesthis risk.

If the positioning system adopted uses theproduction tubing, it is preferable to carry outperforation operations using a percussion detonator.

In this case, a percussion device hits a capsulecontaining a small quantity of explosive thatprovokes the ignition of the primary and thesecondary explosives. The intrinsic security of thissystem is greater than that of electrical detonatorssince there are no metallic elements within thedetonator. However, there is still the risk ofexplosion due to impact that may occur duringpositioning operations in the well.

To transmit detonation to the charges locatedalong the gun the detonating fuse is used. The fuseconsists of secondary explosive contained in a liningmade of either metallic materials (aluminium orlead), or plastic materials extended across a wovencloth. The detonation speeds depend on thesecondary explosive in use. The slower ones areachieved with HNS and PYX explosives (between6,000 and 6,100 m�s) whilst higher detonationspeeds are obtained with RDX and HMX (about7,900 m�s).

A further way to perforate casing column is byusing the jet charge method. Jet charges functionin a very complex manner, but the system itself isparticularly simple, consisting in explosive mattercontained within a unit which is adequatelyprotected by a special lining. The jet chargefunctions as follows: the ignition of the explosiveproduces detonation, the pressure wave generated,together with the expansion of the gases, producethe rupture of the liner following a symmetricalaxis.

The shape and penetration length of theperforation depend on the geometry of the chargeand the material of the liner. A cone-shaped chargeproduces a long thin jet that results in a deepperforation with a thin diameter. Parabolic shapesand semi-spheres produce shallow holes with largediameters. The distinction between Deep-Penetrating (DP) and Big-Hole (BH) jet perforatorsis based on these results. DP charges typically createholes with diameters varying between 5 and 12 mmwith a penetration depth of 30-50 cm. BH chargescreate holes with a diameter between 15 and 40 mm,and a depth that does not exceed 20 cm.

The explosive train is kept in place by the so-called gun. There are two different types of guns:guns with a charge holder set inside a tube, andcapsule systems. The first consist in a pipe sealedat both ends, containing the explosive train. Thissystem protects the explosives from the outerenvironment and prevents every type ofdeterioration. The two existing types are: portedguns, with holes milled into the pipe and closed byspecial capsules, and scalloped guns, which haveno holes, and a thinner pipe wall in proximity of



the explosive charges. The first can be reusedseveral times, while the second must be abandonedin the hole. The tightness of the guns isfundamental in avoiding contact between thecharges and the fluids, which would lead todamage. The ignition systems used with portedguns are electrical, with detonation fromunderneath. The type of ignition used for scallopedguns can be electrical, hydraulic or percussion-based, with ignition from above.

Capsule guns are formed by charges which areindividually equipped with single protectivecapsules, and are installed on a set of cables or on aflexible plastic support. With this system, largercharges for equal tubing diameter can be used, sincethe space otherwise taken up by the metallic liner isavailable. Using this system it is possible to obtainperforations of double depth, and a 20% increase indiameter. On the other hand, the explosive train isexposed to the fluids in the well, presenting a greaterrisk of failure. In this situation, it is necessary to payspecial attention to the tightness between thedetonator and the fuse to avoid any possible contactwith the fluids.

Choosing the best perforation system involvesunderstanding which operations will be carried outin the future, in order to enhance productionefficiency. For wells with a sufficient flow capacitythat do not require successive stimulation, the mainobjective is to restore continuity between the holeand the undamaged formation. Consequently, theperforation objectives are: maximum perforationdepth; phase displacement between the charges; shotdensity; the percentage of perforated level; and thepresence of underbalance conditions duringperforation, with the pressure in the hole lower thanthe formation pressure.

Phase displacement or phase angle is obtained byplacing the charges themselves on different levels soas to avoid excessive weakening of the casing shouldthe phase displacement be unsuccessful, and in orderto be able to reach the most productive areas of theformation. Phase displacements can be of 45°, 60°,90°, 120°, or 180°.

Shot density is an important parameter used fordefining production efficiency according to thenumber of shots reaching the formation. Every singlecase must be considered when evaluating the situation.It is also important to bear in mind that the successrate for these complex perforation operations rangesfrom 50% to 70%.

Limiting the formation length to be produced causesa reduction in efficiency due to the necessity of forcingthe flow to converge towards the perforated area.

Carrying out perforation operations inunderbalance conditions helps avoid potential damageinduced by explosion debris. In fact, in this situation,after the explosion, a counter-flow coming from theformation towards the hole makes it possible to purgethe perforations.

3.5.7 Filters and drains for solidtransport control

Solid transport induced in hydrocarbon productionfrom pay rocks generally occurs in the case of non-consolidated formations and causes dangerousevents with costly consequences. Most of theseevents are due to the accumulation of solids in thewell that can lead, as an extreme consequence, tokilling the well, i.e. making it impossible to produce.Another high-risk factor is the erosion of elementsof the completion string, from the wellhead to the


WELL COMPLETION

Table 1. Secondary explosives used for perforation

Explosive Chemical Density Detonation Speed Detonation PressureFormula [kg/m3] [m/s] [MPa]

RDX C3H6N6O6 1,800 8,750 34,500Cyclotrimethylenetrinitramine

HMX C4H8N8O8 1,900 9,150 39,300Cyclotetramethylenetetranitramine

HNS C14H6N6O12 1,740 7,400 24,100Hexanitrostilbene

PYX C17H7N11O16 1,770 7,600 25,500Bis(picrylamino)-3,5-dinitropyridin

(Economides et al., 1998)

surface plant, as is the accumulation of ‘sand’ in theseparators, which must be removed. Problemsinduced by solid transport, also known as sandproduction, do not occur only in the well, but alsoinside the formation, where empty spaces may formbehind the casing leading to its instability and/orcollapse.

There are four methods to prevent sand fromentering the well: a) reducing fluid production; b)mechanical methods; c) in situ consolidation methods;d) combined methods.

The first method is based on the removal of theprimary cause of solid transport: the speed of theflow around the well is reduced to values that do notallow solid transport to occur. It is obviously themost economical method since it does not requireany investment, but it has strong repercussions onthe production. Horizontal wells are a particularlyinteresting case. In this type of well the greaterexposure of the formation to well draining leads to alower speed in the formation, for an equivalent flowrate. The transport capacity of the fluid current isconsequently reduced along with sand production.High-speed flowing is not, however, to beconsidered the only cause for solid transport. Theformation grains can potentially be predisposed tobeing transported. Clearly, in non-consolidatedformations this method for containing solidtransport may prove to be quite ineffectual, if notdamaging.

Mechanical methods are the most commontype used to limit the production of sand. Thereare several methods, all of which use devices thatare installed downhole to withhold sand andprevent it from entering the well. Thesemechanical devices can be filters and/or slottedliners, and serve the following purposes: filteringthe formation, withholding solid particlesartificially introduced, and avoiding natural solidgranulate dispersion. These devices are normallyused in association with a drain, which consists ofgranular material (with an appropriately chosengranulometry) that is placed to fill the emptyspaces behind the casing and the perforation, andthe filter. The purpose of the drain is to withholdsolid particles both mechanically and through areduction in the flow speed due to the increase inpermeability induced in the hole.

In situ consolidation systems consist in providinga non-consolidated formation with an artificialcementation while maintaining the highest possiblepermeability. These operations are carried out usingplastic materials or synthetic resins.

Combined methods consist in using mechanicalmethods together with consolidation methods. A

drain made of resin-coated sand is used to obtain thecementation of the grains after they have been set inplace.

The setting operations for mechanical sand-control systems are very articulate and complex, andrequire an accurate description of the single devicesas well as of the operative methods. Below is adetailed overview of the single items.

To obtain an effective and efficient drain it isfundamental to choose the right filling materials. Infact, the majority of oil and service companies haveadopted the API RP-58 (1995) regulation whichgives recommendations for the choice andconstitution of the drain. One of the most importantrecommendations regards choosing the correctrelation between the dimension of the formationgrains and the dimension of the material used for thedrain. Saucier’s technique recommends choosing arelation between the average diameter of the draingrains and the diameter of the formation grains(between 4 and 8), to ensure filtering withoutinducing an excessive reduction in the permeabilityrate. This technique does not take into accountgranulometric distribution but only considersaverage dimension.

The sands used for draining are characterizedby a high level of quartz and by consistent graindimensions. The grains must be as round aspossible to avoid the formation of bridges and theconsequent halting of installation. Other materialscan be used instead of silicate sands. These are:resin-coated sands, granites, glass beads, andaluminium oxides. These alternatives presenthighly spherical grains.

There are various types of filters. The simplestinvolve the creation of longitudinal slots withopenings in proportion with the dimension of thegranular material used for the drain. These filters arenot very expensive and have a small filtering area.They are used in wells with long productionintervals and low productivity rates. In highlyproductive wells wire-wrapped filters are used (Fig. 8 A). In these filters a triangular wire is wrappedaround a tubular element with openings in it. Thefilter presents an elevated filtering surface, and thespace between one spiral and the next corresponds toan opening in the filter. The dimension of theopenings depends on the characteristic size of thedrain. There are also prepacked filters in which thechamber between the spiral filter and the tubularelement is filled with granular material that may ormay not be artificially cemented. Prepacked filterscome in three varieties: dual wrapped prepacked(Fig. 8 B), casing external prepacked (Fig. 8 C) andwith a double filter and a thin gravel pack.



The fluids used to place the drain are an equallyimportant element in draining operations. These fluidsmust be able to: transport the filling materials to theirplace, separate from the solid fraction in order to allowthe drain to form, and leave the formation withoutaltering its permeability. These functions can beincompatible, and the selection of the ideal fluidrequires special attention. Completion brines andderivates can be successfully used with the addition ofpolymers to increase viscosity and therefore transportcapacity. The most common gel-forming agents areHydroxyethyl-cellulose (HEC), succinoglycan (SCG),Xanthan, and Surfactant gel.

There are various methods for placing drains: a)circulation pack; b) reverse-circulation pack; c) waterpack; d) frac-pack. The frac-pack owes its origin to thenecessity of filling the fractures produced artificiallyby pressurization. Filling the fracture with granularmaterial not only reinforces the formation, but alsomakes it possible to place the drain in fractures thatwould otherwise probably close when overpressureceased.

3.5.8 Artificial lift systems

The need to use an artificial lift is an important aspectto be considered when designing a completion plant. Itmust be evaluated in the light of the operative life spanand working conditions of the well.

There are numerous artificial lift systems, each ofwhich has an optimal application field. The main typesof lifts are: a) sucker rod pumps; b) hydraulic lifts; c)Electrical Submersible Pumps (ESP); d) gas lifts; e)Progressive Cavity Pumps (PCP). See Fig. 9.

The main purpose of artificial lift systems is toprovide the fluid with the necessary energy to reachthe surface and continue flowing to the primarytreatment plants. The efficiency of lift systems can bedefined by calculation, more specifically by dividingthe power provided to the fluid by the power used byexternal sources such as engines or compressors. Gaslifts are the least efficient method, while PCPs presentthe maximum productivity, ranging from 5 to 70%.

The artificial lift system to be adopted cannot bechosen merely upon technical grounds, but mustalways be accompanied by an evaluation based onlong-term economic convenience. This is the reasonwhy low efficiency methods are still widely used.

Artificial lift plants with plunger pumps or sucker-rod pumps are made up of a cylinder, a piston,an aspiration valve and a release valve. The piston is connected to the surface by a string of pipes, and isactivated by an eccentric system or a crank and slottedlink that transforms the engine’s rotary movement intoan up and down motion. During the descending phase,the valve in the piston opens and the one in thecylinder shuts. This ensures the passage of the oil fromthe cylinder towards the delivery pipe above thepiston. During the ascending phase, the valve in thepiston shuts and the one in the cylinder opens. In thismanner, the piston pushes the liquid in the deliverypipe up to the surface enabling more oil to be suckedin to fill the cylinder. The pump is generally poweredby an electrical or diesel engine that is connected tothe surface unit by a speed reducer. This type of lift isvery reliable and resilient, and is capable of lifting oilcontaining high percentages of sand. It presents lowinstallation and maintenance costs and is characterizedby high head, but it can only be used on reduced flows(about 6 m3�h), and presents problems when used indeviated wells.

Centrifugal pumps are composed of a rotor and astator; the motion of the liquid is speeded up by therotation, and then slowed down by the vanes in thestator. This operation transforms the liquid’s kineticenergy, obtaining an increase in pressure. Thispressure then lifts the hydrocarbons to the surface.Generally, centrifugal pumps are installed within the


WELL COMPLETION

Fig. 8. Examples of structured filters: wire wrapped (A),dual wrapped prepacked (B), and casing external prepacked (C) (Economides et al., 1998).

A

B

C

well and are formed of several stages connected tothe same rotation mast, so as to avoid suction lift.The vanes in each stage are configured so as to havepeak efficiency for the flow rate concerned. As thenumber of stages increases so does the pump headand the quantity of power required by the engine.Given that the well diameter limits the dimensions ofthe vanes, the pumping rates can only be increased byincreasing the rotation speed. Electric power can beprovided by surface generators or through connectionto the public network, and then distributed to theengines after having been brought to the adequatetension by means of a transformer. On the surface,there are electronic controllers with automaticswitches or fuses for high-tension protection, manualswitches, measurement equipment, and temporisersfor intermittent pumping. Artificial lift systems withESP present low installation costs and allow highdelivery pumping (20 m3�h at 1,000 m); however,they are also characterised by high operating andmaintenance costs, and their use is limited to depthsabove 3,000 m due to the increase in operatingtemperature and in power required.

Ejection pumps exploit the pressure riseobtained when slowing down a fluid by passing itthrough a diverger. A surface centrifugal pumpinjects motor fluid into the well through a pipe thatis fitted with an ejector at its lower extremity. Anozzle that accelerates the motor fluid andconsequently diminishes pressure forms the firstpart of the ejector. Down stream from the nozzle ashort pipe is fixed transversally, immersed in theformation fluid. The depression createddownstream from the nozzle enables formation-fluid suction. The motor fluid and the aspiratedfluid pass through a diverger where they undergo akinetic energy reduction and a rise in pressure,which lifts them to the surface. A portion of the

fluid that reaches the surface is then pumped backinto the well. Artificial lift systems with ejectionpumps present low installation and maintenancecosts, but elevated operating costs. They have anexcellent operating performance when used indeep and deviated wells (6,000 m) and promotehigh delivery production (80 m3�h).

A gas lift completion allows hydrocarbons toreach the surface by means of the reduction of thehydrostatic load downhole. The gas is compressedon the surface using compressors and successivelyblown into the well, usually through the annulus.The gas then enters the delivery pipe throughholes distributed along the pipeline, making itpossible to reduce the density of the fluid andbring the well to deliver. The gas lift may becontinuous or intermittent. The first case is used inwells that present good downhole pressure, andallows for stronger flows. The second system isused in depleted or low-pressure wells that requirea high gas cushion volume to lift thehydrocarbons. If the available quantity of gas isinsufficient, the gas can be recuperated at theseparator, recompressed, and sent down the wellagain. The valves that allow the passage of the gascan be controlled in two ways: by means of thedischarge pipe, or by means of the cable. Theformer type have the advantage of presentinglarger passages for the gas and therefore allowhigher delivery, while the latter have limitedpassages, but can be replaced without pulling thetubing. They can be concentric, requiring theremoval of all uppermost valves to enableoperation on the lowermost ones, or eccentric,presenting greater external obstruction. Gas liftcompletions present very low installation andoperating costs that can be further reduced byusing a centralized compressor to feed several



tubinganchor

controlequipment

armoredcable

pump

electricmotor

drivehead

suckerrod

floater/stator

progressivecavity pump

gas liftsubmersible

electricpumphydraulic

pump

rod pump

pump

rodpump

gas liftvalve

packer

standingvalve(optional)

Fig. 9. Artificial lift systems (Economides et al., 1998).

wells at the same time. They are reliable and ofeasy maintenance, but allow a limited productionflow (2 m3�h at 3,000 m).

Bibliography

Angel J. (2000) Intelligent oilfields. Managing the interfaces,«Offshore», 60, 184.

Baroid (1994) Completion and workover fluid technology,Houston (TX), Baroid.

Brown K.E. (1977-1984) Technology of artificial lift methods,Tulsa (OK), PPC Books, 4v.

Coull C. (2001) Intelligent completion provides savings forSnorre TLP, «Oil & Gas Journal», 99, 78-79.

Furlow W. (2001) Expandables market changing the waywells are drilled and completed, «Offshore», 61, 42.

Furlow W. (2003) Service companies goes it alone,«Offshore», 63, 62-64.

Hogg C. (2002) Level 6 multilateral numbers increase, «Oil& Gas Journal», 100, 63-67.

References

Agip (1996) Well completion and workover course, Agip, 2v.Economides M.J. et al. (edited by) (1998) Petroleum well

construction, Chichester-New York, John Wiley.

Claudio AlimontiDipartimento di Ingegneria Chimica,

dei Materiali, delle Materie Prime e MetallurgiaUniversità degli Studi di Roma ‘La Sapienza’

Roma, Italy


WELL COMPLETION

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