Completion Eng Pag425-450ing3

3.7

Completion engineering

3.7.1 3.7 .1 Int Intro roduc ductio tion n Well completion is an upstream petroleum activity whose aim is to furnish the well, once it has been drilled and cased, with all of the equipment needed to bring the hydrocarbons to the surface, both in the case of natural flow ( Fi Fig. g. 1) and artificial lift Fig. g. 2). A completed well is therefore equipped (Fi with the basic components needed for production: production tubing, safety and interceptio i nterception n systems (packer, downhole valve, christmas trees) and

christmas tree composed of manual manual and automatic gate valves

accessories (nipples, circulating valves, artificial lift systems). Completion engineering has the following aims: a) to meet the requested targets of production/injection rates; b) to choose the simplest layou layoutt from the possibilities available available for a given given level level of functionality and results; c) to meet the needs of safety and respect for the environment; d ) to provide enough flexibility for any changes during the working life of the well; e) to meet all of the above needs at the lowest lowest capital and operating costs.

christmas tree composed of manual and automatic valves and penetrators for electrical cables

Surface Controlled Subsurface Safety Valve (SCSSV)

Surface Controlled Subsurface Safety Valves (SCSSV)

packer fluid

packer with penetrators

tubing casing cement

tubing electrical cable

accessories seating nipples

cement electric submersible pump electrical motor

perforated casing

perforated casing

packer

Fig. 1. Single completed well Fig. in natural flowing.

VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT

Fig. 2. Well completed with artif icial lift Fig. with Electric Submersible Pump (ESP).

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DRILLING AND COMPLETION OF WELLS

All of the t he above is not always possible, particularly as far as low cost is concerned. Therefore, even in the presence of high capital costs, it is important to consider the benefits deriving from more complex and costly layouts layouts in terms of greater production (early or increased production) and in terms of their effectiveness over time (less workover, simpler management). The The role of a completion is therefore to link the reservoir to the surface in order to produce hydrocarbons. hydrocar bons. Other equally important aims are to protect the production casing casing from pressure effects effects and from the composition of the produced fluids (corrosion), to monitor the reservoir production data, to prevent the formation of deposits that could obstruct the pipes, to prevent the deposit of salts and the corrosion of the production tubing, and to optimize exploitation of the reservoir reservoir.. Depending on whether the field is onshore or offshore, the development development strategy controls to a varying extent the drilling and well completion operations, with respect to equipment to be used, techniques to be selected and the environmental impact.

Onshore development systems Development with individual wells Onshore development by means of individual wells is the simplest from the point of view of the completion with respect to the interface with the surface facilities since these wells are generally drilled and completed individually, then connected by individual flow lines to the manifold headers and subsequently to the gathering points. This well configuration makes it possible to place the well site in the location defined by the reservoir study and then drill the well ‘vertical’ ‘vertical’ to the top of the reservoir (unless there is a need for multidrain or horizontal wells, or there are logistics problems such as the presence of residential residential areas, parks, etc.). etc.). The advantage of vertical wells is their lower drilling costs and lower lower completion costs in terms of materials (reduced length and volume of wells) and associated services (directional drilling is not used and since the levels are crossed vertically, perforations are less expensive). expens ive). This system is is logistically logisticall y less efficient from the point of view of monitoring and control since a control network network is needed to connect the wells to a central system as well as to local safety systems. Furthermore, this type of system is subject to a greater number of external risks and is therefore a very vulnerable system. It is however the simplest system to manage in the case of simultaneous operations, since each well can host dedicated rigs.

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Development with clusters The development of an onshore field by using clusters of wells leads to some complications regarding both well location and drilling. The cluster (see Chapter 5.1) is usually constituted by a single cellar (a cellar is a ditch dug at the site to accommodate the wellhead wellhead in order to limit the environmental environme ntal impact, leaving only the production christmas tree above ground level) in which the wells evenly evenl y spaced. The drilling and management of a cluster must take different needs into account: the cellar must be deep enough for the highest wellhead, wellhead, in a production/injection configuration, so that a drilling and/or workover rig can be skidded over it without dismantling either the rig and/or the christmas trees. It must also be wide enough to allow safe access during drilling, production and worko workover ver.. The spacing, i.e. the distance between the vertical axes of the wells, must be large enough enough to allow for drilling drilling and completion in sequence, with the possibility of operating simultaneously on adjacent wells with different types of rigs. For example, it must be possible, to use a drilling rig at the same time as a workover workover rig or rigless equipment. Developments using clusters can be compared,, with few compared fewer er space limitations, to offshore platform developments, developments, with respect to the proximity proximity of the flow lines, to the management of the safety system and to the well trajectory, trajectory, which must be deviated to reach targets that are some kilometres away aw ay from the vertical of the cluster. The possibility of concentrating control and protection systems is a distinct advantage since it reduces the environmenta environmentall impact.

Offshore development systems Surface wellhead systems The types of offshore development systems differ depending on water depth (see Chapter 5.2). In order of increasing water depth, the main development schemes are: a) barges or artificial islands (less than 10 m of water); b) monopods (one-leg platforms) or tripods (three-legs) for shallow water (35-40 m at the most); c) multi-leg jacket or g ravity structures where the number of legs generally varies according to the depth of the water (maximum of 150 m) and the payload they have suppor t; d d )) platforms with concrete structures (up to a depth of 350 m); e) Tension Leg Platforms (TLP), i.e. floating platforms that are anchored to the sea floor with metal tendons (350-400 m); f m); f )) floating systems (semisubmersible or ships) connected to various subsea production networks. In the case of surface wellheads, the problem is reduced to the consideration of all surface interfaces,

ENCYCLOPAEDIA OF HYDROCARBONS

COMPLETION ENGINEERING

together with problems due to the limitations of space and safety related to the execution of simultaneous operations in restricted space. The aspects to consider are: a) the selection of rigs and their use; b) the well structural interface with surface facilities (spacing of the wellheads and wells at each platform level depending on the well system size); c) the installation of the conductor pipes (environmental protection tubes connecting subsea wellhead with the platform wellhead) and their centralisation within the platform structure (jacket); d ) the tieback system design, i.e. the connection of the production casings of wells during the pre-drilling phase, from the sea floor (see Section 3.7.2), and the drilling wellhead; e) the well movement in relation to the f ixed structures (design of wellhead installing system; f ) determination of wellhead vertical movements with respect to the conductor pipe due to temperature variations during production and the relevant movements of flow lines with respect to the platform structure); g ) the integration of control and safety systems. Subsea wellhead systems In this case, in addition to normal well problems, there are other needs related to the design and installation of the subsea production system, including: a) the selection of the rigs (either moored or dynamic position rigs); b) the completion running; c) the level perforating phase (opening communication of production levels with the wellbore); d ) the production phase for clean-up; e) the wellhead installation phase; f ) the flow line installation phase; g ) control umbilical installation phase for subsea wellhead control during production; h) the transfer of the control system to a remote station; i) the well workover phases during its productive life performed by means of a rig similar to that used for initial installation or by means of dedicated rigs.

Completion design Studies for completion design are divided into: pre-feasibility, feasibility and detailed studies. Normally, pre-feasibility and feasibility studies are aimed at supplying management with accurate economic data to approve the start of the development project. The detailed study is aimed at preparing specifications for the purchase of materials and the services needed for the development plan. Data needed for the development project This is a summary of the data needed to prepare the document defining the basic prerequisites and goals of f ield development in which the wells are an integral part ( statement of requirement ). These data include: a) the PVT (Pressure, Volume, Temperature)


characteristics of the fluids to be produced, i.e. the density, viscosity (variable according to pressure and temperature) and related phase diagrams; b) reservoir data regarding the number of productive levels; c) the production sequence planned; d ) the volumes of hydrocarbons in-place for each level; e) the type of drive mechanism (water drive, solution-gas or gas-cap drive); f ) the forecast of the well flow rates and the contribution of each level in the case of commingled production; g ) the forecast of the evolution of the flow rate and of the fractions of the fluid produced; h) the pressure behaviour forecast (SBHP, Static BottomHole Pressure) with respect to the original reservoir pressure; and i) the minimum flowing pressure (i.e. abandonment pressure) for each well. In addition, in order to more accurately define the drilling profile, the following must be determined: a) the positioning of the wells on the reservoir top; b) the geological data defining the petrophysical characteristics as well as their spatial distribution; c) the mechanical strength of the rocks penetrated; d ) the reservoir structure map; e) the contacts between the fluids; f ) the depth of production levels and relative pressure gradients; g ) drilling data from exploration/appraisal drilling, that allow the determination of the pressure and temperature gradients; h) any discontinuities; i) overpressures and potential problems.

3.7.2 Completion layout The completion design follows the flow diagram of Fig. 3, which first identifies the logic sequence for the borehole-formation interface, then that related to the interface between the production tubing and casing and, finally, the number of levels to be put into production, the production sequence and/or the possibility of commingled production from two or more levels.

Borehole-formation interface The borehole-formation interface differs according to whether the wells are vertical, deviated (up to an angle of 60°-70°), sub-horizontal or horizontal (angle greater than 70°). Traditionally wells have a telescopic casing profile and involve the use of a greater number of casing sizes the deeper the well while maintaining a fixed production casing size. Horizontal wells generally have a borehole that navigates inside the reservoir itself. Vertical wells The interface options for vertical wells can be divided into three main categories: open hole, open hole with non-cemented liners, and cased hole.

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completion layout

borehole-formation interface

vertical/ deviated wells

horizontal wells

open hole

number of levels

tubing-casing interface

packerless

packer

polished bore receptacle

anchored

shallow set

liner hangers

deep set

casing

open hole with uncemented liner

cased hole

free moving

slotted liner

conventional

tubingless

open hole screens

formation fracturing

open hole gravel pack

cased hole gravel pack

Fig. 3. Completion layout.

In the case of an open hole, the production casing shoe is set to the top of the production reservoir which is later drilled and left as an open hole. Generally, this option is chosen in the presence of a single hydrocarbon bearing reservoir when it is constituted by secondary porosity rock. The principal limitation of this type of completion is that it is impossible to selectively produce more than one level or to exclude the presence of undesired fluids (water or gas). In the case of an open hole with non-cemented liner, there are three possibilities: • Non-cemented slotted liner: this choice is implemented in consolidated formations (carbonate, sandstone) that produce through a network of fractures or formations characterized by thin layers which are difficult to identify by means of the logs. Productive intervals are drilled after having set and cemented the production casing/liner to the reservoir top. Completion can include a slotted liner (tubing with longitudinal slots) when there is a risk of borehole collapse due to mechanical instability of the rock as a consequence of the reduction of the pore pressure. • Sand control with screens in open holes (open hole screens): this option is used in the presence of a non-consolidated formation to mitigate the transport of sand and any interstitial clays by the fluids produced. If such material were to

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accumulate in the wellbore, they would reduce production until ultimately stopping it completely. Sand control can be managed by reducing the flow rates (thus tolerating the production of minimal amounts of sand), or by filtering it with mechanical tools (dual screens) around which the sand sets during production. • Sand control with open hole gravel pack: this system is used when sand movement inside the formation must be avoided. Sand control takes place by pumping sand with a controlled grain size into the well, which acts as a natural filter for the formation sand. This action is coupled to that of simple mechanical filters (gravel pack). In order to ensure an adequate volume of sand between formation and screens, the borehole is generally underreamed below the end of the last casing. Cased holes are the most common because they allow better well management. In this case, for the purposes of level selection and ease of control and safety it is necessary to: a) determine the number of intervals to open to production, using guns and explosive charges to perforate the production casing/cement by following the relevant underbalance or overbalance procedures; b) choose completion fluids suitable for minimising formation damage and therefore to evaluate the need for stimulation; c) define the cementing quality through interpretation



of the logs of specific wells (cementation log); d ) ensure true isolation of the levels. Cased hole completions can be subdivided as follows: • Conventional: this completion scheme is used when the formations are stable. The casing perforation is carried out using suitable explosive charges, which are high-penetration in the event of heavy formation damage induced by drilling fluids, and possibly, with the use of underbalance techniques to remove the effects of damage. • With formation fracturing: in this case, given the very low permeability of the formation, productivity is improved by creation of induced fractures. To do so a high pressure acid solution is injected into the formation and a small part of the level is perforated in order to concentrate the effect of the pressure. High penetration explosive charges are necessary and excellent cementing is required so as to limit the fracture. • Sand control by means of cased hole gravel pack: this scheme is used for sand production control in cased holes. Explosive charges are used that can perforate holes of a certain size (ID, Internal Diameter 0.7'') in the casing in order to facilitate the passage of controlled grain size sand pumped into the formation. The technique of sand pumping is very effective in the presence of fractures (frac-pack). Horizontal wells Completion schemes in horizontal wells are similar to those of vertical wells but, in this case, there are factors that complicate their management. Normally, horizontal wells have very long sections inside the production level (since the well trajectory is intentionally navigated inside the hydrocarbon bearing zone) and are difficult to manage during the injection and production phases in terms of pressure losses. It is also extremely difficult to carry out good cement bonding even in consolidated formations. The borehole’s mechanical stability is therefore more sensitive to geostatic loads in the case of an important drop in the static pressure of the reservoir during the production life. The most common completion schemes are therefore comparable to those used in open hole vertical wells. Still, the length of the horizontal segment and the effect of gravity complicate installation procedures of the equipment (there is, for example, a great deal of friction in the lower part of the borehole, and difficulty in transferring any rotation to the bottom) and the pumping of the sized sand for sand control. To this end, specific sand control techniques have been developed for horizontal wells as well as in situ expandable mechanical screens to avoid the need for fluid pumping with the transport of solids.


Multilevel production With vertical wells that cross reservoirs consisting of more than one production level with different petrophysical characteristics or containing different types of fluids, the number of levels to be completed must be decided. In horizontal wells, there are similar configurations when step-well trajectories are used in multilayer reservoirs. Multilayer horizontal reservoir completion configuration is rare and is carried out by subdividing a horizontal well into step sections, managed more or less individually with valves controlled from the surface, both during production (to guarantee optimum drainage of the reservoir) and injection (to ensure stimulation and/or injectivity in the case of water injection wells). The types of multilevel completion are listed below. Completion for commingled production. In this case, a number of productive levels are put into production at the same time, thus mixing the output. The completions are very simple and used when all of the levels have the same pressure regime, similar production indexes and contain similar hydrocarbons. Otherwise, the most permeable levels would tend to produce more efficiently than the others which may result in cross flow from one level to an adjacent one (when the well is closed and the pressure at the bottom tends to be balanced). Completion for sequential production. Sequential level production is implemented either by intervention on the well by opening the sliding sleeves, or through recompletion, i.e. first opening to production on one level (generally the deepest), pulling out the production string and then recompleting the well in an upper level. Single completions with segregated production. In this case, a single production tubing is used but levels are kept separate by packers. When it is envisaged that the lower levels will be invaded by water before the others and their exclusion is incorporated in the design, plans can be made for initial simultaneous production and later segregated production by means of sliding sleeves or plugs set in the tubing (Fig. 4 A), or a sequential production from bottom to top; or alternating production producing each level separately in sequence ( Fig. 4 B). Sometimes, more productive levels are opened for production first in order to create conditions compatible with the other levels (i.e. to deplete them), after which simultaneous production can be implemented. Multiple completions with segregated production. As in the above case, the levels are separated by packers, however, two or more production tubings are used for simultaneous but segregated production of a number of levels. Parallel tubing ( Fig. 4 C) or

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single completion

Fig. 4. Completions with segregated production: A, initial commingled production; B, sequential or alternating production; C, parallel tubing; D, concentric tubing.

A

concentric tubing (Fig. 4 D) may be used. These completion schemes are generally chosen when it i s not desirable or possible mix the flows of the single production strings. The schemes shown in Fig. 4 A and 4 B allow both simultaneous (commingled) production and segregated production for each individual level but not at the same time. They also make it possible to segregate levels that might produce water or gas in undesired volumes. These types of completions can also be used ‘creatively’, for example by installing flow regulators or exploiting gas levels to lift oil levels. The schemes shown in Fig. 4 C and 4 D are used primarily in offshore reservoirs where single string production would not be economical since it would require a large number of wells.

Tubing-casing interface Except in completions with tubing alone (packerless), which occur less frequently due to their lack of safety, the tubing-casing interface is characterized by the packer system. This system supplies a mechanical tubing anchorage to the walls of the casing and a hydraulic seal to separate the fluids above and below the packer from each other. In essence, the packer consists of slips and counter-slips (with high surface hardness) anchored mechanically to the wall of the production casing by biting into it. In the movement between the two slips, during the packer setting, the elastomeric seal is compressed and expanded against the casing, isolating the area below the packer – which contains the hydrocarbons – from the area above the packer which contains the packer fluid ( Fig. 5). Depending on the working conditions, various types of packers are used: • Permanent packers (retainers), used in hostile environments, i.e. in the presence of high pressure,

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B

dual completion

C

D

high temperature and corrosive environments for long-term completions and in recompletions planned above the packer depth where they can be used as plugs to separate the lower zones. • Retrievable packers, generally used in relatively less hostile environments. They are used in short-term completions, in multilayer completions to separate the various levels and in planned recompletions after workover requiring complete access to the production casing below. • Permanent-retrievable packers, a hybrid of the previous layouts which, as technology has evolved, tend to substitute permanent packers in particularly complex applications. This happens in particular when using special all oy steels (which would require long milling times if permanent packers are used).

annulus with packer fluid

connection tubing/packer

mechanical anchoring slips

packing elements

volume underneath packer

Fig. 5. Packer system.



Fig. 6. Composite wellhead. top adapter for wire line lubricator swab valve n

wing valve oi t c e s n oi t el

working valve p

christmas tree cross master valve

m o c

carrier with metal to metal seal tubing hanger

tie down

secondary packing primary packing

tubing spool n iot

slip c es g ni ll

secondary packing primary packing

BSB slip

Tubing-wellhead interface Onshore or platform wells The drilling wellhead supports and transfers to the ground, through surface casing, the loads on the wells. On the other hand, the tubing spool supports the tubing by means of the tubing hanger and at the surface separates the flow in the tubing from the annulus (the space between the tubing and the casing) of the production casing. The wellhead can be of the composite type ( Fig. 6) with flanges (a less expensive but bulkier solution), generally used for onshore installations, or of the compact type, typical used for platforms or clusters. The construction and types of steels used are regulated by API (American Petroleum Institute) 6A standards (API, 2004). The tubing spool supports the christmas tree whose goal is to avoid the leakage of fluids into the environment and to control their flow. The christmas tree can, in turn, be composite, made of individual fl anged valves, or integral (Fig. 7), with one or a series of monoblocks. The conventional wellhead (see again Fig. 6) can be shaped as a cross or horizontal. It must ensure safe closure of the live well in all the phases of its


ir

casing spool

d

braden head

production life and safe access to the live well for workovers through tubing even during production, for example in the case of installation of bottomhole devices for the measurement of data. Subsea wells In subsea wells, the wellhead and christmas tree are located on the sea floor. During installation, the wellhead is connected to the rig through a subsea BOP (Blow Out Preventer) stack – BOPs are joined in a stack group to facilitate installation operations – and a connecting pipe (riser) to the rig by means of the tensioning and heave compensation (motion compensator) system. Depending on the water depth, the BOP can be run on guide lines ( Fig. 8) connected to the equipment from the guide base. Otherwise, when used without guide lines, they are installed using acoustic transponders and video localizers (ROV, Remote Operated Vehicle) during the running. The drilling wellhead, which is run all at once at the start of drilling, is a monoblock with a constant internal diameter. The casing hangers are located on top of each other or one inside the other. There is a special housing for the tubing hanger. For further details, see Chapter 3.7.

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top adapter

swab gate valve wing gate valve

wing gate valve

master gate valve with actuator master gate valve control line port

Fig. 7. Integral christmas tree.

Offshore tie-back systems with platform wellheads. Pre-drilling phase The exploratory wells drilled with jack-up rigs, where the BOPs are onboard the rig and connected to the well by means of a marine riser, have casings that terminate on a special drilling wellhead placed on the sea floor. After the drilling and testing phase, the well is suspended and completely shutoff on the sea floor. Should the well be recovered, the necessary casings (at least the production casing and the conductor pipe to protect against sea and weather) must be reconnected to the surface, and the structure (jacket) wellhead,

Fig. 8. Wellhead and subsea christmas tree, system with guide lines (courtesy of Cooper Cameron Corporation, Cameron Division).

complete with christmas tree, is placed on the production structure (monopod or platform). This process is known as tie-back . In reservoir development with platforms, this system is generally adopted when the wells are predrilled, and performed with semisub or jack-up rigs, before the j acket and platform are available, even though the platform will be equipped with a drilling rig. This process is less costly since it makes it possible to drill the development wells in parallel to the constr uction of the production structures (jackets and top-sided). This allows production to start in advance in comparison to a sequential development which first requires platform construction and then drilling and completion of the wells. During predrilling the rig is positioned on the vertical of the axis of the slots in the template anchored to the sea floor, which is a protection structure of a series of wellheads, similar to an onshore cluster. The wells are drilled in sequence and the same casings are installed in all of the wells (phases) so as to reduce logistic problems and optimize drilling times. Drilling of each well is suspended when the last casing is cemented to the reservoir top. To do so, the BOP stack is moved from one well slot to another on the template. The wells are thus temporarily abandoned on the sea floor. Once the jacket and topsides are installed, each well is tied-back to the surface by the conductor pipe (for environmental protection of the well), and by the casing (to support the wellhead installed on the platform). The drilling phase of the production interval, the completion and the production start-up are carried out using the drilling rig constructed for the platform.

tubing spool cover plug annulus line with control valves control pod

tubing hanger production line with control valves

housing base frame

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Criteria for wellhead design Wellhead characteristics are defined on the basis of the pressure rating, the Product Specification Level (PSL), i.e. the type of steel used and the Temperature Class (TC), according the 6A standards of the API and ISO 10423:2003 (ISO, 2003). Pressure rating . Working Pressure (WP) is def ined as the highest pressure to which a single component, the wellhead in this case, may be subjected during its working life. API has conventionally divided wellhead operating pressure ratings into six classes: a) 1st class to work up to 2,000 psi (13.8 MPa); b) 2nd class up to 3,000 psi (20.7 MPa); c) 3rd class up to 5,000 psi (34.5 MPa); d ) 4th class up to 10,000 psi (69.0 MPa); e) 5th class up to 15,000 psi (103.5 MPa); f ) 6th class up to 20,000 psi (138.0 MPa). An increase in the rating is reflected in a rise in the costs, this is why an accurate determination of the rating is of the utmost importance. Given the lack of measurements of the maximum wellhead pressure, the Static Bottom Hole Pressure (SBHP) is used as the working pressure, i.e. it is assumed that WP SBHP. This approach is obviously cautionary and leads to system oversizing, critical when approaching the technological limits of construction (today around 20,000 psi, 138 MPa), and with a heavy impact on costs. It is therefore advisable to measure the wellhead pressure during exploratory well tests and to use WPSTHP max  SF, where STHP max is the maximum Static Tubing Head Pressure measured and SF is a Safety Factor - chosen on the basis of the uncertainty of the measurement, defined by the company (for example, SF1.1 for natural gas wells and SF 1.3 for oil wells). This criterion takes into consideration the static tubing head pressure, measured during a test after the well has been shut-in for a certain period of time, which is the equivalent of the static bottomhole pressure minus the hydrostatic pressure generated by the fluid column contained in the tubing (Phyd ), i.e. STHP SBHP – Phyd . If the fluid in the tubing is a dry gas, and therefore not subject to further phase changes during the measuring period (normally 48 hours), it is possible to assume a safety coefficient value (1.1) lower than that assumed in the case of oil (1.3). Oil, which liberates gas in the well and thus develops into a two-phase state, tends to segregate in the tubing when the well is closed (with the heavy components on the bottom and the lighter components on top). Since the dynamics of this phenomenon might not be complete at the moment of measurement, the static pressure measured during a shut-in may be lower than the actual shut-in pressure. For this reason, it is preferable to assume a higher SF to determine the rating and to assume an average estimated density of the two-phase fluid in the tubing.


Product Specification Level (PSL). This consists of a range of values (from 1 to 4) which defines all of the quality controls to which the materials must be subjected during design, construction and testing. The highest value is that applied for the most severe installation conditions. The PSL of the equipment is based on a logical process that evaluates the predicted working pressure and the hydrogen sulphide (H 2S) content, since this compound is highly corrosive for steels and lethal to humans. If H2S is present, the PSL also accounts for environmental conditions in terms of the vicinity of civilian structures and the applicability of the NACE (National Association of Corrosion Engineering) standard specifications for the selection of materials (MR 01-75 standard; NACE, 2001). The aim of this environmental evaluation is to provide the constructor with design and construction criteria (the PSL) suitable for the different installations, according to the actual working conditions, on the basis of risk evaluation. Temperature class. This defines the application limits within a class to which corresponds the choice of steel grades. A wellhead must commonly meet a number of temperature classes simultaneously and therefore the relevant materials must be chosen with great care (for example, in sub-arctic conditions with temperature variations between 40°C and 40°C).

3.7.3 Fluids present in the well Completion fluid The completion fluid is present in the well during completion installation or removal. A good completion fluid must be dense enough to ensure a hydrostatic pressure greater than that of the formation (at least 300 psi), contain a minimum amount of solids and, if it does contain solids, generate a filtrate that will not damage hydrocarbon bearing levels. Furthermore, it must also be viscous enough to ensure the solids transport capacity. Oil-based drilling muds are rarely used. Brine, heavy brine or foams are more common. For more details, see Chapter 3.5. Annulus filling fluid (packer fluid) The packer fluid is the static fluid present in the annulus between the tubing and the production casing throughout completion life. It can be the same as the completion fluid or any appropriate fluid that ensures that its density is maintained over time to balance the static reservoir pressure at the bottom of the hole (kill fluids). In other words, it must be able to kill the well in the case of loss, breakage or release of the barrier created by the packer and tubing. In high pressure and high temperature wells, where the tubing and casing

433


well during completion

well producing

well after killing before BOP installation A BOP B wellhead C plug inside hanger 1 valve 2 safety valve 3 tubing 4 casing 5 cement 6 packer fluid 7 completion fluid 8 packer

static barrier annulus 1(B)456 tubing A456

static barrier B3(2)8(6)45

static barrier C3(2)8(6)45

dynamic barrier A457

Fig. 9. Safety barriers.

sizing criteria are near the acceptability limits of the safety factors, it may be advisable not to use a kill weight fluid. In fact, in such wells, the high hydrostatic load a fluid with the density characteristics defined above (i.e. with a pressure gradient greater than 1.8-2 bar/10 m), together with the accumulation of high pressure at the head of the production annulus caused by a possible leak in the tubing, could lead to casing failure or tubing collapse. The consequences of such an event would be more critical than those to be avoided by means of the counterpressure due to the packer fluid. The latter however is never to be considered a safety barrier.

3.7.4 Impact of safety on the completion scheme Whatever the type of completion to be designed, there are minimum prerequisites that must be respected to ensure the safety of the installation with respect to the surrounding environment and the safety of the personnel working directly on the well site during installation, production and workover as well as to protect the people and objects in the vicinity. There are active and passive safety measures during the various phases. Active safety measures are those actually or potentially manageable during operation (dynamic barrier). Passive safety measures are those intended to ensure that fluids are contained whatever the external event (static barrier; Fig. 9). The criterion normally

434

accepted in order to achieve a safe design, is that of having two independent barriers that can be tested separately.

Static (primary) barrier The static barrier contains the fluid and isolates it from the surrounding environment without the need for outside intervention. The activation of the barrier occurs for example with a fail safe valve when the barrier assumes the safe (i.e. closed) position whenever the control element (the hydraulic control pressure) fails, either by choice or design. The barrier only acts as such in the direction of the flow it is supposed to prevent. For example, the tubing alone is not a bar rier, but becomes one when linked with a bottomhole packer and if check valves are installed at its ends (bottomhole wireline plugs, christmas tree valve). It can be tested both with positive (over pressure) and negative pressures (under pressure). The downhole safety valve installed in the tubing is not normally considered a barrier as it operates as a safety valve only in one direction, while in the other direction it allows the passage of fluid which is to be pumped into the well. It does however act as a supplementary emergency safety device required by the company’s safety policy since it is designed to act in the case of accidental leaks from the wellhead and therefore when there is the possibility of escape of hydrocarbons into the environment. It is therefore not taken into consideration as one of the two independent barriers.



Table 1. Selection of safety valves: applications

Type of valve

Application

Tubing retrievable flapper valve

Wells in offshore platforms Subsea wells Wells with presence of H2S or CO2 Wells with surface flowing temperature greater than 130°C

Wireline Retrievable Surface controlled flapper Valve (WRSV)

As on insert valve for tubing retrievable SCSSVs

Storm chokes

As a backup to the WRSV when there is a control line failure. Set in the lower wireline nipple

Annular safety system

Gas lift wells ESP wells with gas discharge Jet pump wells (under the pumps)

Wireline retrievable injection valves

All injection wells (water, waste water, cuttings)

Dynamic (secondary) barrier The dynamic barrier contains the fluid and isolates it from the sur rounding environment in a controlled environment. It is not a classic barrier since the open/closed concept cannot be applied to it and testing its effectiveness is difficult. For example, the denser completion fluid is a ‘dynamic’ barrier since it stops the reservoir fluid from flowing thanks to the differential pressure generated by the different densities of the fluids. In an interval open to production, it only guarantees this containment when the two fluids are in static equilibrium. In the opposite case, i.e. when the formation absorbs the completion fluid, the weight balance becomes unstable and, if not controlled by reintegrating absorbed fluids, the well may start to flow. This is because the level in the tubing is lowered following absorption. If not compensated, it in turn causes a drop of hydrostatic pressure on the formation, thus allowing hydrocarbons to enter the well. The completion fluid can be considered a dynamic barrier since, for short periods and under close control and observation, its effects can be exploited during tubing substitution operations, in the presence of the static barrier supplied by the BOP. On the other hand, the packer fluid remains static during the well’s production life from the time when it is installed until the first workover. Nonetheless, it cannot be considered a barrier because, even if its density is high enough to control the well, its rheological characteristics may deteriorate with time and its density thus be altered.


Selection of safety systems The above considerations related to barrier definitions aside, a well’s safety configuration depends on the policy of the country where the well is operated and of the company operating it. Generalization is therefore absolutely impossible. For example, Table 1 and 2 show the minimum criteria that the designer should respect independently of the geographic area of

Table 2. Selection criteria for safety valves

Type of well

Criteria

Oil production

All new offshore developments All onshore naturally flowing wells All wells to be recompleted All isolated wells

Gas production

All new offshore developments All wells to be recompleted

Gas storage

All wells

Gas injection

All wells

Water injection

All wells

Artificial lift

All gas lift wells in, tubing annulus ESP wells with tubing, including annulus in the case of gas discharge

H2S in produced fluids

All wells

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the world where operations take place. These minimum criteria require the use of downhole safety valves to form an emergency barrier in the case of uncontrolled production from the well. Such valves must be of the fail safe type, they must be controlled from the surface and are normally installed in the production tubing. They must also have the same pressure rating as that defined for the tubing and the christmas tree.

3.7.5 Selection of materials Once the fluid corrosivity characteristics are known, the types of steel must be selected. This activity has to be started very early because, if it is thought to be necessary to perform control tests on the existing materials and qualification tests for new materials, long times are required. Material selection is fundamental for the life of the well because, aside from hydrocarbons, H2S and/or CO2, chlorides (Cl – ), oxygen (O2), aerobic or anaerobic bacteria flora may also be present. Therefore, the tubing, liner and christmas tree, as well as production casing and the wellhead must be resistant to corrosion. A careful choice of steels must take into account the predicted duration of completion, whether there will be workover during its production life and relative capital and operating costs.

Methods to control well corrosion Methods for controlling corrosion include one or more of the following options, depending on their impact on the project cost and development strategies: a) use of tubulars with extra thickness (corrosion allowance) and carefully planned substitutions; b) choice of appropriate corrosion resistant alloys; c) reduction of tensions; d ) elimination of sharp bends; e) elimination of impulsive loads and/or vibrations; f ) chemical inhibition through use of a scavengers for O 2 and/or H2S, control of the pH and use of inhibitors; g ) application of an internal coating; h) use of carbon steel with non-metallic inserts. The strategy of using corrosion allowance is applied where there is generalized corrosion in the carbon steels, and thicker tubing is chosen. In that case, substitution of the tubing at set times is planned, for example when workover on the well due to reservoir problems is already planned. Options c, d and e are aimed at eliminating stress in situations of Sulphide Stress Cracking (SSC). They are related to the well profile and are not always attainable. They can however lead to the adoption of mixed sections or sections of tubing in Corrosion Resistant Alloys (CRA) in the zones under g reatest stress, limiting

436

carbon steel to the zones under less stress. The use of these methods requires an adequate evaluation of the states of stress throughout the length of the tubing. Chemical inhibition with sequestering agents is typical of processes limited in time, for example during drilling, or is applied to fluids in a static conditions – the packer fluids for instance – in order to avoid damage over time due to action of oxygen and bacterial flora. On the other hand, corrosion inhibitors are used for production/injection fluids. These are generally amine-based substances (see Chapter 5.4) that limit or slow corrosion, coating the tubing wall with a thin f ilm and are generally complementary to the use of corrosion allowance. Inhibitors are normally added in small quantities (ppm) to the produced fluids, and in different concentrations in all injected fluids. There are various methods for using inhibitors in the production well: injected into the well in cushions (batch treatment), injected into the formation (squeeze treatment), left at bottomhole so that they can transported by the fluid produced over time, or by continuous injection. In the last case, their transport to the bottomhole requires the installation of small diameter chemical injection lines banded to the production tubing. The injection of inhibitors must be combined with a detection system on the surface to evaluate their effectiveness during the well’s production life, for example, by means of tests to evaluate the weight loss. The cost of inhibitors and their management must be carefully evaluated during design because on a long-term basis they may be comparable with apparently more expensive systems such as the use of corrosion resistant alloys. The internal coating method consists of covering the internal walls of the production tubing with an in situ cured epoxy bicomponent resin. To this end, there are resins that are resistant to aggressive well chemicals as well as to high temperatures (130°C) which offer adequate protection to cor rosion as long as there is not excessive wear due to wireline and coiled tubing trips (see below) in the wells. In fact, such trips damage the surface of the walls by friction, thus uncovering metallic areas that are then subjected to a preferential corrosive attack. The resins used are sensitive to permeation of gas and, in the case of extremely violent decompression, can blister, swell and lose adhesion. For this reason, their application must be carefully analysed. They involve a cost roughly 20% higher with respect to carbon steel and the bonus is a reduction of the flow friction coefficient. Furthermore, they require special connections (CB rings, Corrosion Barrier rings) to isolate metal to metal seals and avoid damage during make-up. The tubing with non-metallic liners is



manufactured with tubular material in carbon steel, with internal liners of composite materials (f ibre glass). They have the same function as the internal coating described above, however they reduce the internal diameter by at least 5 mm instead of a few tenths of a millimetre in the case of coatings. Various compositions and types of f illing between the tubing and liner (cement, resins) have been identified, and have various applications both in water injection wells and natural gas wells. For aramidic resins that are resistant to high temperatures, the cost is comparable to that of martensitic steel.

Tubular materials The tubular materials for wells is collectively indicated as OCTG (Oil Country Tubular Goods) and classified according to API standards based on: the Outside Diameter (OD) of the tubing (OD 1.05''-4.5'') and of the casing (OD >4.5''); the range of the length of each element e.g. for the tubing in terms of range 1 (20-24 ft), range 2 (24-32 ft), and range 3 (32-48 ft) and for the casing in terms of range 1 (16-25 ft), range 2 (25-34 ft) and range 3 (34-48 ft); the linear weight (lbs/ft or kg/m) for which, once the outer diameters are set, both the thickness and the inner diameters of the tubing (the diameter used for fluidodynamic calculations) can be determined. Another parameter to be considered is the drift, a conventional measurement that defines the maximum diameter of any piece of equipment that can run inside the pipes (tubing or casing) without it getting stuck. OD-connection is the outer diameter of the collar or of the upset of the threaded pipe end, i.e. the maximum tubing diameter. Finally, the grade indicates the steel’s characteristics. Premium or gas tight connections are used at most for production tubing. It is recommended that these connections also be used for the casing and production liners, particularly when the annulus is used for gas lifts or when the packer fluid gradient is lower than that of the reservoir (underbalanced). Connections can also be of the collared or integral type. The substantial difference between upset or integral connections and collar connections lies in the fact t hat the latter require cutting of an extra thread on each tubing and therefore introduce an additional potential point of leakage. For this reason, upset connections are preferred in exploration wells. The fact remains that the use of upset connections is limited in time, if they are used repeatedly and then tested, because the number of recuts is limited due to exhaustion of the upset part. Tubing made from cor rosion resistant alloy cannot be upset. They are cold worked and upsetting would impair their resistance and require after forging at temperature and heat treatment that would render the pipe inhomogeneous at its extremities.


Seal elements These normally consist of elastomers (components with high elastic properties) for the gas seal and non-elastomers for anti-extrusion. Elastomers that are used as seal units can be distinguished into the following conf igurations according to the function which they must fulfil. O-rings are designed to bear pressure under static conditions and can also support variations in pressure for a limited number of cycles; in any case, they tend to be extruded out of their grooves, and therefore they need rigid support. They are generally used either statically as internal seals for completion equipment or in components that are subject to a single cycle (pressure equalization systems). The T-seals/moulded seals are designed as dynamic seals and are harder than the O-rings. They work with higher interference and can incorporate antiextrusion metallic reinforcing elements during hot moulding. In the form of T-seals, they are often used in tubing hanger seals, while in the form of moulded seals, they are used as dynamic seal packs inside Seal Bore Extensions (SBEs) of the packer or Polished Bore Receptacles (PBRs). The PBRs are used if large tubing elongations are foreseen. V-packings are obtained by moulding and mounted as seal units that perform their task inside the packer seal bore. They withstand pressure rises inside the V-shape, while they collapse when pressure is applied in the opposite direction. The packing units thus consists of two packs of single V elements facing in opposite directions. This characteristic renders them suitable to bear some dynamic pressure, or sudden pressure reversals. Given the fragility of each unit, the V-shaped elements are always installed in pack (seal units) and never individually. Given the reduced thickness of the rubber lip, they withstand poorly, extended and repeated movements inside the seal surfaces in which they are installed. The packing elements of packers are large in comparison to the other seals. They work, not by diametral interference, but by compression transmitted during the packer setting movement directly from the anti-extrusion elements of the packer itself. In order to meet the compression setting criteria, the elastomer needs a certain elasticity; for that reason, only rubbers with these characteristics – NBR (Nitrile Butadiene Rubber), HNBR (Hydrogenated Nitrile Butadiene Rubber), Aflas – are suitable, while harder rubbers (Kalrez, Chemraz) are not appropriate for this type of application (packer elements) despite their g reater resistance to aggressive chemicals. Metal To Metal (MTM) seals are used when well conditions are so extreme due to pressure, temperatures and aggressive chemicals that the use of elastomer materials is

437


Table 3 Flow rate range as a function of the tubing diameter .

Tubing size (inches)

Tubing weight (lb/ft)

2.375 2.875 3.5 4.5 5.5 7.0

4.6 6.4 9.2 12.6 17.0 29.0

Tubing ID (inches) 1.995 2.441 2.992 3.958 4.892 6.184

impossible. The seal is usually supplied by elastoplastic deformation and interference of a soft metal element on the structural component made of alloy steel (Incoloy 825 on Inconel 718). In these cases, it is important to carefully evaluate the design of the seal – which requires accurate machining – and the installation conditions and procedures – which require extremely clean conditions in the sealing area. The change from elastomers to metal to metal seals means a considerable increase of equipment cost and therefore must not be extensively used if not strictly required.

3.7.6 Determining the size of the tubing The determination of the size of production tubing requires both an analysis of fluid flow, in order to choose the optimal diameter to attain production at the desired flow rate, and a mechanical analysis, to determine steel grade and thickness. All of this is needed to ensure an installation which is in line with the safety criteria that each company adopts. There is software for the first type of analysis that calculates the tubing diameter (nodal analysis) and the friction losses along the tubing, using fluidodynamic data as input. For the second type of analysis, stress analysis software is used to simulate all of the possible loads on the tubing during the different phases of the well’s production life. The resistance criteria determine the design acceptability via the verification of the design factors.

Nodal analysis A broad estimate of the oil and gas tubing flow rate range is provided in Table 3. These are average values that do not take into account the real length of the well and the fluid composition and are therefore only indicative. The actual determination of the size requires more precise estimates. The process followed, summarised below, is called nodal analysis because it

438

Range of oil flow rate (m3/d ) <150 150-500 300-1,000 500-1,600 800-2,700 >1,200

Range of dry gas flow rate (km3/d ) <50 50-250 80-400 180-1,000 250-1,500 400-4,000

calculates and supplies the fluidodynamic characteristics in every node in the system ( Fig. 10). From a comparison of the energy available from the reservoir and the energy required by the well system up to the surface, the optimum diameter of the production tubing over time can be determined; it will be a compromise between the requirement of the initial hydrocarbon flow rate and its variation over time, both as flow rate and as composition (ratios between the gas/oil, water/oil and gas/water phases). The objectives of nodal analysis are to examine the system to predict the flow rate, and to optimize the diameters of the system components. In order to do so, the following key operations are necessary: • Selection of the most appropriate equation describing the resistance to the flow movement inside the reservoir and the wellbore (IPR, Inflow Performance Relationship) as a function of the flow rate and selection of the deliverability curve (VLP, Vertical Lift Performance) which describes (again as a function of the flow rate) the energy required to lift the hydrocarbons to the surface. • Analysis and definition of reservoir performance in proximity to the well, based either on geometric or induced damage to the formation, caused by different operations and/or by the natural reduction of reservoir pressure over time. • Analysis of the multi-phase flow in the tubing. • Calculation of the working limit for natural flow and assessment of the possible need for artificial lifting. Curve of available bottomhole energy The simplest curve of available energy (IPR, Inflow Performance Relationship) is linear, in which the Productivity Index (PI) is proportional to the difference in pressure between the reservoir and the well (i.e. the more the flowing pressure is reduced with respect to the static pressure of the reservoir, the higher the quantity of fluid that is produced). This is true for non-compressible, single-phase fluids that flow above the bubble-point pressure. The equation



that supplies a linear IPR in the p-Q diagram is the following: PIQ/( pr  pwf ) where pr is the average reservoir static pressure in the area surrounding the well (SBHP), pwf is the flowing pressure at the same depth to which pr is referred, and Q is the total flow rate of the fluids produced at the surface at standard conditions (101 kPa, 15°C). The linear IPR curve is not valid when dealing with two-phase reservoir fluids. When the flowing pressure drops below the bubble point pressure ( pb), the gas saturation around the well rises causing a reduction of relative permeability to liquids and therefore a reduction of the flow rate. In this case, the real IPR is curved downwards in the p-Q diagram. For this section of the curve, Vogel (Vogel, 1968) found a numeric model for this part of the curve defined by the equation Q/Qmax10.2·( pwf / pr ) 2 0.8·( p / p ) where p is less than p , Q is the liquid wf r r b flow rate, and Qmax is the maximum liquid flow rate when pwf  0. The complete curve of the IPR which includes the bubble-point pressure consists of a straight line for p pb and of a non-linear section which acts according to Vogel’s equation for p pb. This curve is modified to take into account the residual damage around the well after removal.

Energy curve to lift the fluid to the surface The curve expressing the energy needed to lift the fluid to the surface (VLP, Vertical Lift Performance) takes into account all of the pressure losses in the tubing for a certain diameter and requires numerical integration of the fluid gradient curve in steady state flow along the entire length of the tubing. This curve is determined by three factors: pressure loss due to a change in the potential energy ( D p PE ), pressure loss due to variations of kinetic energy ( D p KE ), and pressure loss due to friction (D p F ), thus D pD p PE D p KE D p F . Each term is determined by means of empirical correlations validated by laboratory tests carried out by varying the flow parameters. The point of intersection between the IPR (curve of available energy) and the VLP (curve of energy needed for the diameter considered) gives the naturally flowing well flow rate at the given conditions. Varying the different system parameters (WHFP, Well Head Flowing Pressure) and the tubing diameter, it is possible to determine the various production flow rates. The best choice of tubing diameter is that which produces the requested flow rate with minimal completion costs. Given parity of

D p(pwh psep)

Fig. 10. Pressure losses scheme to calculate tubing diameter.

gas pwh

D p6(pDSC psep)

psep liquid stock tank

choke-regulator pDSC Inside Diameter reduction safety valve D p4(pUSV pDSV)

separator D p5(pwh pDSC)

pDSV (pr pwfs) (pwf s pwf ) D p3(pUR  pDR ) D p4(pUSV pDSV) D p5(pwh pDSC) D p6(pDSC psep) D p7 (pwf pwh) D p8(pwh psep) D p1



pUSV )

h w

p

 f 







w

p (



D p2



f riction losses in reservoir friction losses at wellbore friction losses in Inside Diameter restriction friction losses at safety valve friction losses at surface choke friction losses in surface lines total friction losses insid e tu bing total friction losses in surface lines

7

p

D

Inside Diameter reduction bottom hole D p3(pUR  pDR )

pDR pUR

pwfs

D p2

(pwfs pwf )






pwfs

D p1

pr

pe

(pr pwfs)





439


the flow rate, when the tubing diameter is increased, the pressure losses diminish or given an equal bottomhole D p, the well produces at higher flow rates. If the IPR and the VLP never meet, for the flow rate and pressure requested, the reservoir will not have sufficient energy for natural flow and thus an artif icial lift system must be installed in order to produce at economically viable flow rates. All of the correlations used in calculations for both the fluids’ PVT characteristics and the equations used to determine pressure losses give valid estimates for different types of fluids. For this reason, proper adjustment have to be made, although too many attempts to make the correlations coincide with the actual data can be detrimental. To avoid this, the data must correspond to the measured conditions at the extremities of the system, i.e. at the wellhead and bottomhole.

Tubing stress analysis Once the optimum diameter for production tubing has been defined and the type of steel to use has been chosen on the basis of the environment conditions, it is necessary to verify whether the tubing can be installed in the type of well to be drilled. In other words, the compatibility with the production casing diameter must be verified. Then, the thickness and grade (mechanical characteristics) must be defined so that they can meet the stress conditions calculated in the various load hypotheses, and the Safety Factor (SF) set by the oil company. The Tubing Stress Analysis (TSA) is carried out both for safety in design, i.e. by defining the minimum strength needed for well equipment (breakage of part of the completion can be harmful to people and objects, not to mention the loss of the well production itself), and to optimise capital costs. In fact, a sizeable percentage of the well capital costs, up to 2030% in the case of special alloys, is due to the tubular material. Therefore, by calculating the real loads, it is possible to optimize safety factors, thicknesses and therefore costs. The TSA must be applied to all tubular material in the well and to the interaction between tubing and casing. Generally, the tubing has the minimum critical cross section and is therefore the element most subjected to limit loads. In reality, given the complexity of the downhole equipment, there may be weakness in other completion components. In order to take this possibility into account, once the nominal diameter, grade and thickness of the tubing are set, the specifications of the Down Hole Equipment (DHE) require that this equipment supports at least the same limit loads as the tubing itself. Material properties It is presumed that metals follow an elastic behaviour and that their yield and tensile strengths are

440

indicated by the symbols Y s and T s, respectively. It should be remembered that, aside from causing expansion and contraction of the metal, variations in temperature determine the variation of the Y s of the material, which decreases as the temperature increases (in particular for CRAs and cold worked steels) and this decrease becomes larger as the number of elements in the alloy increases. The value of the thermal expansion coefficient generally used for steel tubes is: 12·106 m/(m·°C) for carbon steel, 16·106 m/(m·°C) per austenitic steel, 13·106 m/(m·°C) for ferritic-austenitic steel (coefficients valid from ambient temperature up to approximately 150°C). The mechanical properties of Premium connections are normally higher than the characteristics of the associated pipe body. They are generally not a problem for the overall resistance of the system if – for that given load situation – only the tubing strength is considered. There are however some limitations, such as for example compression strength. While the tube behaves in an axially symmetric manner to tension and compression, the connections often have less resistance to compression than to tension and therefore leaks can develop at the metal to metal seals in the case of heavy compression on the tubing. Verification of stress is independent of the completion scheme, since the well, whose predominant dimension is length, requires that only the stress along the axis of the tube be taken into consideration. The sections under stress are those included from the wellhead to the packer, which at setting fixes the length on which stress variations occur. Sections of tubing below the packer are subjected to stress due only to their own weight, unless they are bound between two packers. In dual completions, the tubing sections are to be sized individually and then, according to the principle of the superposition of effects, the congruency of the movements at the dual packer is imposed. There are four possible ways that tubing in the well can break: by axial load, by internal pressure or bursting, by collapse due to external (outer) pressure or by a combination of loads (triaxial stress). In order to verify whether the completion string can support the stresses, it is necessary to: identify and determine the loads to which the string will be subjected; compare the loads with the pipe strength (defined by API standards); and compare the real loads with the certified metal strength values in combination with an adequate safety factor. This comparison is made by first defining the design factors for the types of breakage outlined above: a) a design coefficient for axial load (ratio between the yield stress and total calculated axial load); b) a design coefficient for bursting (ratio between maximum burst pressure leading to yielding and the difference between internal and external pressure); c) a design factor for



collapse (ratio between the maximum collapse pressure and the difference between external and inner pressure); d ) a design factor for triaxial load (ratio between the yield strength of the materials and triaxial stress).

Load models The completion scheme of a well is subject to various loads during the working life of the well, i.e. during installation, production and pull-out. Thus, for every case, a ‘ basic case’ is defined which is generally the situation created – in terms of pressure, temperature, associated loads and related deformations – when the completion is run down hole. Then, the various cases of load as variations of the basic case have to be examined in sequence. It may be necessary to take into account particular situations that may arise over time (i.e. stimulation with acid solutions, formation fracturing, wellhead shut-in, etc.). The logical sequence of calculation requires starting with a completion with the tubing anchored to the packer and that this layout, the absolute safest, is progressively modified only if the calculation fails, eventually arriving to a solution in which the tubing is partially or totally free to move with respect to the packer. Definition of loads Once the system geometry (depth, deviations, diameters) has been determined, it is not only necessary to define the pressure and temperature of the initial case – for which direct measurements are generally available – but also to generate load cases for the entire well production life. It is therefore important to list the operations that will be carried out in the well, to generate pressure and temperatures profiles along the entire length of the production string (by nodal analysis) and to use these profiles to calculate the stress induced on the tubing. The main load situation that may arise are: Completion installation. The loads exerted in this phase are due to pressure tests and tubing’s own weight. The basic case predicts the condition of the tubing run in hole with the packer at its lower end. During completion installation, the tubing is heated to the ambient well temperature according to the well temperature profile. As such the tubing is not affected by temperature but only by pressure. The first variation during the running is thus pressurization at the packer setting; the packer, once set to the casing wall, stops any further lengthening of the tubing. Acid stimulation, fracturing . Stimulations are carried out to remove damage or improve formation permeability. Acid stimulation consists of the injection of a known quantity of liquid (acid solutions) with high flow rate and high pressure (with variations of


friction and cooling of the string). Hydraulic fracturing leads to the exasperation of stress due to the stimulation: the volumes injected, the injection rates, the times and pressure reached during fracturing, in particular before fracture formation, are thus increased. Wellhead shut-in. This operation involves a rise in wellhead pressure, since bottomhole pressure tends to return to the values of reservoir static pressure and – since the fluid pressure gradient is certainly lower than one (presence of two phases or only gas) – a residual increase in shut-in pressure is generated at the wellhead. This load condition must be considered since the temperature reached at the wellhead during production does not fall immediately, as a consequence of the thermal inertia in the well, and therefore the load condition relevant to the temperature is similar to that during production, but with greater wellhead pressure. Completion pull-out . This is the condition that expresses the pull tension that must be applied to the tubing to release it from the packer itself or to release the packer during the pulling out for workover and which depend on the type of packer installed. Considering installation of the completion and packer setting as the basic case, the other typical load situations to production wells are: a) opening of the well for production (test and stimulation); b) long-term production; c) shut-in; d ) completion pull-out (releasing tubing from the packer or releasing the packer); e) other planned operations (artificial lift, successive stimulations, etc.); f ) stress on the production casing due to temperature variations (if not completely cemented). For injection wells, in addition to completion installation and packer setting, the other load situations are: a) beginning of injection (test and stimulations); b) long-term injection; c) reopening of the well to injection after a shut-in; d ) stress on the production casing due to temperature variations (if not completely cemented); e) completion pull-out. As stated above, stress must be verified in axial, radial and tangential directions (API standards only give indications on the individual loads applied and do not consider combinations of loads). The typical approach is thus both to determine the stresses in the three directions (axial, radial and tangential) and to compare them with the values indicated by API, as well as to verify the composite stress (triaxial stress). While the formulae used in determining stress are not given here, it is worth highlighting the effect of axial loads. If the tube is free to move, pressure and temperature variations only give rise to variations in length. If, instead, the tube is f ixed, the axial force is the sum of the forces that would exist if the tube were free and the forces generated by the resistance of the

441


anchorage to deformation. Generally, the movement is first calculated as though the tube were free and then the forces to bring it back to the initial position are determined (or at least to the position of anchorage), also taking any instability due to buckling into account. This method makes it possible to evaluate the movement of a mobile seal within the packer when the tubing-packer connection is free and thus to determine the length of the seal elements to install or, in the case of an anchored tubing-packer connection, to establish the pull that the contracting/elongating tubing exerts on the packer and therefore on the casing. At this point, it is worth mentioning the curving of the tubing into a helix due to buckling load, because of the fact that in this case the deformation is limited by the presence of the casing. This makes it possible to reach a higher grade of instability (Fig. 11). The buckling of the production string can be tolerated in many cases from a static point of view if the tensions are acceptable. Still, it should be verified that this does not lead to other problems, such as those related to: blockage of the passage of equipment lowered

F

neutral point

a

Mf Mt

F Fig. 11. Helical buckling of the tubing. M f , moment of flexion; M t , moment of torsion; a, angle of the helix of deformation.

442

downhole by wireline; or metal to metal connection seal loss if the bending is excessive. There are specific formulae to determine the maximum diameters of the instruments and the length of the equipment that can go through a section of tubing under buckling conditions. It is however possible to mitigate or eliminate the effects of buckling by increasing the pressure in the production annulus, since this tends to straighten the tubes.

Design tensions and maximum admissible tensions The so-called Design Factor (DF) is the ratio between yield tension and real tension (calculated) in one section of the structure, while the Safety Factor (SF) is the ratio between yield tension and maximum admissible tension (normally set by the oil company). The result of the TSA of a tubing string is the evaluation of the design factors in all of the completion sections for all load conditions predicted throughout the life of the well (including abandonment or workover). The process may require repeated calculations in the event of unsatisfactory results (the DF must be greater than or equal to the SF) or when various alternatives are analysed in order to establish the most advantageous configuration in terms of cost/benefits. From a comparison of the DF, the SF and the acceptance of the values calculated for all tubing sections, it is possible to determine: the forces exchanged between the tubing and the packer; the forces exchanged between the packer and the casing; and the packer strength, verifying the loads calculated on its characteristic curve that indicates the maximum load supported by the packer (this characteristic curve is supplied by the manufacturers and/or determined experimentally). The SFs normally acceptable are fixed by the oil company. Should the calculation result in a DF less than the minimum required SF, modifications of the configuration must be introduced and the calculations repeated. Modifications may involve: a) a higher grade of steel (verifying the limitations of use in the presence of H2S when grades of over 80,000 psi or 655 MPa (L80) are required); b) an increase in the pipe thickness (section increase, noting however that in this case, the pipe weight and pressure also increase and the temperatures of the fluid produced/injected changes, thus making it necessary to repeat the fluidodynamical calculations); c) use a pull or a stack off of the tubing on the packer or change the packer (or the packer setting mechanism); d ) the use of a smaller production casing in the case of large buckling of the tubing. On the other hand, should the problems of the system only be caused by particular operations like stimulation or fracturing, which



cause high contraction due to cooling, action can be taken by heating the injected fluid or increasing the pressure in the production annulus.

3.7.7 Choosing packer type, setting method and tubing-packer connection The integral type tubing-packer connection provides the greatest structural and seal guarantees. However, the selection of the type of packer, having taken into account tension analysis results, is the result of several compromise solutions. In order to select the type of packer to be used, the type of well where it is to be installed is evaluated. A distinction is made between; a) very critical wells, those with True Vertical Depths (TVDs) of over 4,500 m, with high temperatures (SBHT, Static Bottom Hole Temperature, of over 130°C) and high pressure (SBHP, Static Bottom Hole Pressure, greater than 700 atm), subsea wells, those with platforms on shipping lines (transit lines of commercial maritime traffic) and high-pressure gasinjection wells (over 210 atm); b) very critical and corrosive wells, those with the characteristics defined in point a but producing highly corrosive fluids; c) critical wells, those with a SBHT of between 100°C and 130°C and a depth between 3,000 and 4,000 m (TVD); d ) non-critical wells, those with a SBHT of below 100°C and a depth lower than 3,000 m (TVD). The general approach is to use simple completion schemes in the more complex and critical situations, and then, in very corrosive and critical wells, to use tested equipment of guaranteed reliability without alternative daring operating solutions that may fail during the working life of the well. The selection criteria also take into consideration a series of parameters for each well category. Such parameters can be related to: the procedure (for example, the use of perforation systems, by means of guns run downhole and activated once production packers are set, provoke mechanical shock); the type of completion fluid used (if a completion fluid containing solids in suspension is used, the use of retrieval packers is critical since their release mechanisms can be blocked over time by the deposit of solids); or the life of the completion because of frequent pulling out of the tubing and the production string with the packer. The design scheme followed in very critical wells is as follows: first, choice of the packer, then the choice of the tubing-packer connection and finally of the method of packer setting. The criterion is similar to that for other well categories where the installation operations and the type of fluid used are different.


Single completions In very critical wells, a permanent packer is chosen because it supplies the best mechanical and seal performance. In very corrosive wells, a permanentretrievable packer is used because the corrosivity of the system may require its removal during the production life. If a permanent-retrievable packer made of the adequate CRA steels is chosen, the retrieval can be planned without milling, considering that the milling for permanent packers is time consuming when they are made of chrome-nickel steel alloys. For critical and very critical wells, the hydraulic packer setting method is the best solution. The reason for this choice lies in the fact that the packer is generally run downhole with the production tubing and therefore, in order to avoid problems related to deposit in the annulus, a filtered fluid not containing solids in suspension and of adequate density is circulated in the annulus before setting. At this point, the system is ready for hydraulic setting which is carried out after the installation of a wireline plug below the packer. The two aspects that need to be taken into consideration for the tubing-packer connection are the choice of the tubing-packer connection and the predicted tensions. In very critical or corrosive wells, first the anchored tubing is chosen: the choice is made between an anchored system and a snap latch system capable of separating at a predetermined load. If the TSA shows that DF SF, i.e. if the connection holds in all load situations, a completely anchored system is chosen. If, instead, the analysis indicates that DFSF and the connection tends to release, for example during stimulation, a snap latch system is used with a mobile seal element (PBR) that only starts functioning in critical cases (for example, cooling and contraction due to stimulation). The entire process must be re-verified and should the production still indicate DFSF, a totally mobile system with mobile seals must be chosen. In this last case, since there is a free connection, the packer running and setting methods must also been reconsidered. If this choice is made, there are no other verification problems since a free connection is always verified. The analysis is also used to determine the tubing elongation/contraction and therefore the length of the seals to be chosen. Other well categories require similar considerations – ranging from packer setting methods to methods for level perforation – to take into account how the guns are run downhole and the loads they employ, as well as the composition of fluids and their solids content. Selective completions The considerations outlined below can be applied to selective completions with two or more productive

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levels and give an indication of the various possibilities in selecting the packers and their setting methods, based on the critical elements described in the well classification. The case of a dual completion has been illustrated, but it is clear that in the presence of multiple levels, the lower packer is the f irst starting from the bottom while the upper packers are all the same. When conditions of criticality are not applied, selection is based on the predicted setting depth. In fact, the greater the depth, the less suitable the use of mechanical packer setting methods that require manipulation of the tubing string as well as multiple runs for multiple completions. The setting method depends mainly on the distance between packers. Wireline set mechanical packers (with explosive charges) are generally placed very precisely since the depth is controlled by the depth recordings while running. They are only used as bottom packers because they require a dedicated run, followed subsequently by the tubing running with all upper packers. If permanent packers are used, hydraulic setting for all the packers is preferable. When the lower packer is permanent, the upper packers are retrievable and brine is the completion fluid, the safest method is hydraulic setting for all the upper packers, while the lower packer is set by means of a wireline. When all of the packers are retrievable, hydraulic setting is advisable and, in this case, the distance between the packers must be at least 50 m. This distance takes into account the elasticity required by the relative movements between the packer components that generally tend to scrape the section of tubing above the packer during setting

(with shorter distances, the mechanical anchoring and the sealing can be compromised because of an incomplete setting stroke). As regards the tubing packer connection scheme, the choice of the upper connection is based on calculation of the tensions applied to the single completion, while the subsequent connections are chosen on the basis of different criteria. In general, anchored connections are used when all of multiple packers are run-in hole together, while mobile connections are used when each packer is run individually, and then reintegrates the packer already in the well.

3.7.8 Tubing hanger selection Together with the tubing spool , the tubing hanger is the element that joins the drilling wellhead and the christmas tree (Fig. 12). The vertical crossrun of the christmas tree has the same dimensions as the production tubing since the connection size of the tubing and the tubing hanger Inside Diameter must be compatible. In particular, the inside of the tubing hanger must be larger than the production tubing Inside Diameter because it contains the first nipple for wireline equipment, generally dedicated to the back pressure valve. This valve is installed as a primary safety barrier during the BOP installation and removal phases when the well is completed. The choice of steel for the tubing hanger is consistent with that of the tubing, in particular, since it is made from a forged bar, it is normally of nobler material than the

Fig. 12. Tubing hanger. gate valve

metal seal

tubing hanger vent port

test port control line metal seal

back pressure valve tubing head adapter tubing head spool tie down gate valve

autoclave valve 15,000 psi

swagelock new vam test port

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corresponding tubing. The tubing hanger is located in the tubing spool, which has special shoulders of sufficient size to support the maximum weight and pressure loads of the tubing string. Here, it is blocked mechanically inside the tubing spool by radial means (tie-down) or, more recently, with elastic snap rings. The connection to the production tubing involves the premium thread of the production tubing itself with metal to metal seals, while the link with the christmas tree requires metal to metal seals that can be a transition type carrier (Laurent carrier). Tubing hanger to tubing spool seals are nor mally elastomeric, while only in the case of high pressure and temperature wells (15,000-20,000 psi, T 100°C) metal to metal seals are used. The tubing hanger is also used to support and provide outside links to the hydraulic control lines of the Surface Controlled Subsurface Safety Valve (SCSSV). In the case of horizontal wellheads, the tubing hanger has a different layout with the flow outlets in a horizontal configuration, while on the vertical run, above the side exit, there are wireline profiles which support the metal-to-metal seal wireline plugs that act as primary barriers. In the case of wells which are pumped by Electric Submersible Pumps (ESPs), the tubing hanger must also support the electric mandrel that interrupts the electric cable to facilitate assembly during completion installation and which works as a safety barrier during production. As far as the choice of accessories is concerned, see Chapter 3.5.

3.7.9 Subsea completions Subsea completions use downhole equipment that is similar to that used on land/offshore wells, but differ with respect to the equipment placed on the sea floor. The hydrocarbons produced by isolated and/or grouped wells are conveyed to a manifold system, designed to handle different flows from production wells or destined to injection wells. In a production system with a riser (see Chapter 5.2), the latter is used to transport hydrocarbons from the manifold system to a surface structure that may be a fixed platform, a semi-submersible platform or an anchored ship, modified to receive fluids on board and possibly serve as a loading terminal for oil tankers. As mentioned elsewhere (see Chapters 5.2 and 5.4), the hydrocarbons undergo treatment at the surface in order to achieve the transport specifications (degassing, water removal, desulphurisation, etc.). Subsequently, they are transferred into tankers, in the case of oil, or sent back to the sea floor, being pumped into subsea pipelines.


The conventional subsea wellhead system (Fig. 13) involves the use of a christmas tree with a valve configuration similar to that of a surface christmas tree for dual completion. The vertical penetration with larger diameter (production bore) is dedicated to the tubing, while the other vertical penetration is used to control the production annulus. During the completion phase, the well is linked to the surface rig by means of an environmental production tube that isolates it from the sea (marine riser). The riser is tensioned between the rig and the subsea Blow Out Preventer group (BOP stack) which is used to guarantee the continuity of the well from the sea floor to the surface. When the tubing hanger – containing two vertical holes – is installed at the end of completion, it is run downhole with the tubing hanger running tool and the production riser and placed inside the drilling wellhead, in its dedicated recess. The production riser consists of sections joined to each other with rapid connectors and each section includes two lines of tubes: the actual tubing and the annulus line. This allows control of the circulation between the annulus and the tubing from the surface, even with the hanger landed in its resting position. A flexible, umbilical line is banded to the production riser during running and contains a series of lines for passage of the fluid for hydraulic control, fluid allowing remote control of the setting and testing functions of the tubing hanger and of the release of the production riser from the tubing hanger. After running, setting and testing of the tubing hanger, the next step is the installation and setting of the wireline plugs placed inside the tubing hanger inside each line of tubing of the production riser. These wireline plugs, together with the well safety system, act as the safety barrier during removal of the BOP and drilling riser system until the installation of the subsea christmas tree is completed. One of the functions of the umbilical is the release of the tubing hanger running tool from the tubing hanger when at the surface and this will allow the subsequent pull out of the production riser, which is retrieved section by section. The BOP stack is then disconnected from the wellhead and pulled out together with the drilling riser. At the surface, the subsea christmas tree and workover control package are assembled and tested, and the entire group is again run using the production riser and the umbilical. Once the equipment has reached the sea floor and is aligned with the christmas tree, it is landed and connected to the drilling wellhead, the hydraulic connectors are closed and all the pressure and functionality tests are performed. At this point, the christmas tree is ready for working. The wireline plugs are extracted from the two prof iles in the

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Fig. 13. Subsea completions (courtesy of Cooper Cameron Corporation, Cameron Division).

gas lift configuration with choke

master valve blocks production chokes for commingling flow from multiple trees pre-engineered valve assemblies for every application mechanical tree connector uses hydraulic power from tree running tool

flowbase with both production and annulus connections

tubing hanger and the vertical swab valves of the christmas tree are closed; the workover control package is released and everything is retrieved with the production riser. The last component to be installed is the tree cap which, in the case of conventional subsea christmas trees, links all of the tree’s hydraulic controls to the production control pod, so that the tree can be controlled by the production system when the production flow lines have been linked to the christmas tree. A different, less costly system is the horizontal subsea wellhead, which allows the use of the drilling riser both for completion and workover, thus reducing capital costs for service material. A simpler control system for a subsea wellhead is that based on direct hydraulic control operated with a remote station from the surface. The reaction time of such a control system is however unacceptable for lengths of over a few hundred metres. For greater lengths, the most common systems are piloted hydraulic systems (sensitive to variations in feeding pressure) and electro-hydraulic systems. The control systems are divided into: workover control systems and production control systems. During the running phase and christmas tree testing, the workover control system operates the hydraulic function of the tubing hanger running tool and the valves, activates all of the closing and opening systems of the hydraulic connectors, allows hydraulic testing of the system seals, and provides continuity to the hydraulic control lines from the bottomhole safety electric lines of the valves, pressure and temperatures transducers and any operated bottomhole valves (smart completions). It is a safety system that ensures

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closure of the Emergency Shut Down (ESD) valves and controls rapid disconnection from the bottom should the rig move off the well vertical by a distance greater than that allowed, due to adverse weather conditions. The production control system controls the subsea wellhead from the production unit and thus has all the valve control functions. It also transfers the monitoring signals of the wellhead and bottomhole tools.

3.7.10 Notes on artificial lift As highlighted in the discussion on the determination of the size of the production tubing diameter, when the inflow performance relationship (IPR) and vertical lift performance (VLP) curves for the fluid in question do not intersect and there are therefore no operating conditions for natural flow, in order to produce the oil, it is necessary to install an artificial lift system that gives the fluid the energy it needs to reach the surface. In the following, the various systems of artificial lift, the concepts on which they are based and the limits of their application that must be examined before selection will be illustrated. This is partly based on the environment where operations will take place (onshore, offshore), the energy systems available (electricity, gas, hydraulic fluids), and relevant costs. For further details on artificial lift systems, see Chapter 6.2. There are about a million oil wells in production in the world today, 90% of which use artif icial lift. The most common systems are: sucker rod or beam pumping, gas lifts, and electric submersible pumps.



Other systems include: hydraulic piston pumping, hydraulic jet pumping and Moineau pumps (PCP, Progressive Cavity Pumping; Fig. 14). The selection criteria include the following factors: production conditions, reservoir data, fluid properties, and economic parameters, e.g. capital costs and operating costs. Moreover, the type of well (single or multiple completion) must be considered in order to determine the possibility of commingled production and any geometric interference of either the tubing or other equipment. Other considerations are whether the wells are onshore or offshore and what type of profile they involve (vertical or deviated). Additional factors to consider are the energy systems available, the logistics of transport, storage and treatment facilities for the fluids, and the environmental impact. Other important elements are the climatic conditions, fluid corrosivity, any production of solids (sand, clay), the presence of paraffins, the type of reser voir drive mechanism and the variation of pressure and percentage of water and gas produced over time.

3.7.11 Final design The final well completion design is therefore the result of an interactive process which may or may not coincide with the original scheme. Whatever the case may be, the final scheme must be crosschecked with the operating procedures of equipment running and retrieval and with potential emergency situations at various levels to ensure overall safety. Clearly, the designer must work to meet the well productivity and safety objectives set at the beginning of the project. When this is impossible, even after modifying the system parameters where possible and acceptable, the designer must inform the oil company of possible limitations in production or operations. As mentioned earlier, the design must include technical drawings, sizing calculations, a list of components and product specifications to prepare the call to tender for materials purchasing. Moreover, the design must include estimates of the cost of materials, plants and services and installation and management timing (including forecasts for workover timetable), to allow the project managers to draw up the budget (CAPEX, CAPital EXpenditure, and OPEX, OPerating EXpenditure) and to obtain approval for purchasing.

3.7.12 Workovers Workover is def ined as any intervention carried out in the well after completion, for any reason, whether this


Progressive Cavity Pump, PCP centrifugal pump

gas lift

others

hydraulic pump rod pump Fig. 14. Artificial lift: world wide distribution.

includes use of a drilling rig or other systems such as service rigs, snubbing units, coiled tubing or wireline units. Workover makes it possible to act on formation (washing, stimulation, cement squeezing, etc.) or on the well itself (bottomhole cleaning, level change, substitution of packer or tubing, substitution of the christmas tree, etc.). The main operations carried out during workover concern: • Mechanical problems, including tubing and packer repairs, elimination of obstructions caused by sand, paraffin, asphaltenes and scales (salt deposits), repairs of the gravel pack damaged by sand, cement squeezing, cement plugs and sand plugs, fishing out of equipment lost in the well, milling of packers and damaged equipment that cannot be fished out, and complete well shutoff. • Reservoir problems, including level change, perforation extension, elimination of undesired gas or water production, opening of obstructed holes, reduction of productivity due to emulsion or water blocking, level partialization, acidizing, fracturing, etc. • Conversion of the well, including installation of an artificial lift system, injection of gas and water, and the conversion to a gas storage well.

Equipment used Workover rigs The main difference between a drilling rig and a workover or service rig lies in the smaller size of the latter due to different operating purposes. As a result they entail lower daily costs, greater rapidity of rigging-up/rigging-down/transport and less bulk. On the other hand, a workover rig has less hoisting power, less installed hydraulic power and less stowage capacity of tubular material on the der rick. In particular situations, the use of a drilling rig may be required to carry out workovers. This may occur in the case of deep wells, a first completion at the end of the

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Fig. 15. Coiled tubing unit. goose neck

injector head hydraulic hose stripper/stuffing box quad BOPs

lubricator/riser

control cabin coiled tubing reel

power skid BOP christmas tree

drilling phase, subsea wells, isolated offshore wells, and offshore wells (even on platforms) where it is impossible to operate with a workover rig or if none is available. Snubbing unit Snubbing is the technique of lowering tubings of conventional length and diameter that are connected one to the other and pushed (stripped) into the well under pressure by means of a system of hydraulic pistons with the use of two BOPs to guarantee safety. The technique allows rotation of the string and injection of fluids for possible mechanical repairs of the well or for reservoir pressure support. The unit is mounted directly on the christmas tree and allows the tubing string to be pulled out by use of a hydraulic piston. It has the advantage of being able to operate when the well is under pressure and allows heavy workover (for example, dismantling of the completion) without having to shut-in the well. On the other hand, it has the disadvantage of a low pull-out speed due to the reduced hydraulic piston stroke. To avoid this problem, in countries where it is most commonly used (Canada, USA), the unit is combined with a service rig, i.e. a unit equipped with a rotary table, and thus with rotating capacity. It can normally be used for light workovers and is often employed for the purposes of well control for blowout remedial. ETU operating unit The Endless Tubing Unit (ETU) or coiled tubing is a technique that uses a continuous tube of small diameter coiled around a drum and run/pushed into the well through the injection head, thus making it possible to pump treatment/circulation fluids without

448

rotating the tube itself ( Fig. 15). The ETU is essentially composed of coiled tubing, a gooseneck injection head, a control house, a power pack and pressure control equipment. It is equipment typically used without a workover rig (rigless) and can be moved rapidly (by lorry on land, or barge at sea), with significantly reduced operating costs with respect to a conventional rig. Since it consists of a continuous tube (diameter 1''-3.5'') unwrapped from a drum kept under pressure, it avoids the possibility of rotation of the equipment in the well or to slack off weights or pull heavy loads. For that reason, it is mainly used to circulate fluids and/or clean the bottomhole. However, by means of fluid pumping it can operate bottomhole motors and turbines. Recently, this type of equipment has been used for directional drilling where the deviation of the bottomhole equipment is achieved using hydraulic control lines run inside the coil. Wireline unit The wireline unit is a system that allows intervention inside the production tubing using a harmonic steel cable that transports, essentially using the payload force of gravity, equipment to the bottomhole. It allows numerous well operations (e.g. setting plugs, opening/closing of valves, and opening/closing of sliding sleeves) to be performed from the surface using a slick line or a wire rope with an electrical wireline that activates instruments, guns or allows data collection. The advantages of this unit are that it works even on a live well, the unit is small, it requires little maintenance and is cost effective. The limitations are essentially related to the wire resistance.



Bibliography API (American Petroleum Institute) (1994) Bulletin on formulas and calculation for casing, tubing, drill pipe & line pipe properties, API Bul 5C3. API (American Petroleum Institute) (2000) Specification for subsurface safety valve equipment , API Spec 14A. API (American Petroleum Institute) (2001) Specification for casing & tubing , API Spec 5CT. ASTM (American Society for Testing and Materials) (2002) Specification for mechanical testings of steel products, ASTM A 370. Harper C.A. (2002) Handbook of plastics, elastomers and composites, New York, McGraw-Hill. ISO (International Organization for Standardization) (2000) Petroleum and natural gas industries. Corrosion resistant alloys seamless tubes for use as casing, tubing and coupling stock , ISO 13680. ISO (International Organization for Standardization) (2001) Petroleum and natural gas industries. Downhole equipment. Packers and bridge plugs, ISO 14310. ISO (International Organization for Standardization) (2002) Petroleum and natural gas industries. Procedures for testing casing and tubing connections, ISO 13679. ISO (International Organization for Standardization) (2004) Petroleum and natural gas industries. Subsurface safety valve systems. Design, installation, operation and repair , ISO 10417.


Magarini P.A. et al. (2000) Best practi ces & mini mum requirements. Sec 1, Eni-STAP. NACE (National Association of Corrosion Engineering) (1996) Laboratory testing of metals for resistance to sulfide stress cracking in H 2 S environments, NACE TM 0177 96. SINTEF (Scientific and Industrial Research at the Norvegian Institute of Technology) (2002) Reliability of well completion equipment. Phase IV , SINTEF-Eni.

References API (American Petroleum Institute) (2004) Specification for wellheads and Christmas tree equipment , API 6A. ISO (International Organization for Standardization) (2003) Petroleum and natu ral gas indu stri es. Drilling and produc tion equi pment. Wellh ead and Chri stma s tree equipment , ISO 10423. NACE (National Association of Corrosion Engineering) (2001) Sulfide stress cracking resistant metallic material for oilfield equipment , NACE MR 01 75. Vogel J.V. (1968) Inflow performance relationships for solution gas drive wells, «Journal of Petroleum Technology», January, 83-92.

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