Completion 5a6s1k

(1)

COMPLETION

COMPLETION TYPES This Part is an introduction to well completions. When a well has been drilled it is not in a state in which it will produce hydrocarbons. The well, like the job, has to be "completed". The word "completion" may at first seem a little confusing, because it is used within the industry to mean two different (but closely related) things. When referring to a given well the completion can mean:  the (geometrical) concept of how the well should be configured for production.  the actual hardware which is run into the well in order to produce it, In practice the context will always make it clear what is meant. The first will give the answer to the question "How are we going to complete the well ?" and the answer will be of the type "as a twin string dual completion". The second will give the answer to the question "What are we going to use to complete the well ?" and the answer will be of the type "the completion will consist of a wireline set permanent packer, a dual retrievable packer run on a 31/2 " long string and a 27/8" short string" plus the other necessary details such as connection types etc. They can be classified in three ways - by reservoir/wellbore interface, by mode of production and by completion geometry - as shown in Figure 2.7.1, and further subdivided as shown in the lower levels of Figure 2.7.1 and in Figure 2.7.2.

7.1.1 CLASSIFICATION BY RESERVOIR/WELLBORE INTERFACE OPEN HOLE COMPLETIONS Open hole completions are also termed 'barefoot' completions. In this type of completion the casing is set in place and cemented above the productive interval(s). Further drilling extends the well bore into and/or through the reservoir(s) which is left uncased, hence the term 'Open Hole'; See Figure 2.7.3.

Figure 2.7.3 : Schematic of open hole completion

This completion method is used where it is desirable to expose the whole of the productive interval(s) to the well bore. The rock of the producing formations must be strong or 'consolidated' to prevent breakdown and collapse when in production. It has many advantages over other completion methods as there is no formation damage from cement and the well can be easily deepened or converted to a liner type completion. The downside of an open hole completion is that excessive water or gas production cannot be controlled. Similarly, zonal stimulation is more difficult.

8:39 PM

6/7/2007

M A-Mohsen

(2)

COMPLETION

LINER COMPLETIONS

UNCEMENTED LINER COMPLETIONS In some formations hydrocarbons exist in regions where the rock particles are not bonded together and sand will move towards the well bore as well fluids are produced. The use of an uncemented liner (slotted or screened) acts as a strainer stopping the flow of sand. Liners are hung off from the bottom of the production casing and are usually sealed by a liner packer to direct well flow through the liner bore. The advantages and disadvantages of uncemented liner completions over other completion methods is the same as for the open hole completion. Various types of uncemented liner are as follows:

Slotted Pipe Slot widths depend on the size of the sand grains in the formation and are typically 0·01" - 0·04" (0·25 - 1 mm) wide; see Figure 2.7.4a. Figure 2.7.4a : Uncemented slotted pipe as liner

Wire Wrapped Screens A liner is drilled with holes along its length, typically 3/8 "-1/2 " (10-12 mm), and then lightly wrapped with a special V-shaped wire - see Figure 2.7.4b.

Figures 2.7.4b, c & d : Other completions using uncemented liners

Wire-wrapped screen liner completions are not used very often since sand movement into the well bore causes permeability (flow rate) impairment and screen erosion can occur at high production rates. These problems may be overcome by filling the annulus between the open hole and screen with graded coarse sand which acts to the open hole section as well as prevent formation sand movement. This completion method is termed an 'external gravel pack' (to differentiate it from an 'internal gravel pack' used in cased hole completions). An alternative to a gravel pack is to consolidate the formation with a resin. Both methods are described below:

8:39 PM

6/7/2007

M A-Mohsen

(3)

COMPLETION

External Gravel Pack The open hole is enlarged to about twice its drilled diameter with a hole opener (under-reamer) and a wire wrapped screen is installed. Gravel, graded to a size calculated to prevent the formation sand from ing through it, is placed outside the screen with special gravel pack running equipment. The pack is then sealed behind the screen; See Figure 2.7.4c.

Resin Injection Placement of plastic resin can be performed through tubing and activated chemically by flushing with chemicals to harden and consolidate sand particles; this technique is also known as artificial cementation or on site consolidation. Accurate placement of the pumped resin may best be achieved using modern coiled tubing methods. The resins most extensively used are phenol-formaldehyde, epoxy, and furan. The attractiveness of this method is that it can be done through the tubing after completing if unforeseen sand problems develop. Plastic resin injection techniques are useful in thin (<10 ft., 3m) high porosity zones.

PERFORATED CEMENTED LINER COMPLETIONS In perforated cemented liner completions, the casing is set above the intended productive interval, and the latter then drilled. A liner is cemented in place which is subsequently punctured (perforated) by shaped explosive charges at the depths it is desired to produce from. These perforations are designed to penetrate any impaired regions around the original well bore and provide an unobstructed channel to the undamaged formation. By using various depth measuring devices, i.e. a casing collar locator (CCL), specific zones within the productive interval can be perforated selectively, thus avoiding unproductive zones, the production of undesirable fluids (gas or water), or production from unconsolidated sections that might produce sand. Perforated cemented liners are used for single (as shown in Figure 2.7.5) Figure 2.7.5 : Schematic of a perforated cemented liner or multiple zone completions

PERFORATED CEMENTED CASING COMPLETIONS In a perforated cemented casing completion, the hole is drilled through the target formation(s) and production casing is run and cemented in the hole. Like the perforated liner completion method, the casing and cement are perforated to reach the reservoir(s), allowing communication of the well fluids to the well bore. Another term for a perforated casing completion is the 'set through' completion. Perforated cemented casing completion methods are:

Standard perforated cemented casing: The use of a perforated casing completion for Multiple productive intervals is shown in Figure 2.7.6a. Figure 2.7.6 : Schematics of perforated cemented casing completions

8:39 PM

6/7/2007

M A-Mohsen

(4)

COMPLETION

Internal gravel packs: In this method the production casing is cemented to TD. Perforating of the producing interval(s) is performed and the perforations cleaned. A screen is then run inside the casing and gravel is placed into the casing/screen annulus and the perforating tunnels; see Figure 2.7.6b. Cased and perforated completions are the most common types of completions performed today since they offer selective pay zone perforation and also allow selective stimulation, which is more difficult in open hole or uncemented liner completions.

7.1.2 CLASSIFICATION BY MODE OF PRODUCTION NATURAL FLOW When a hydrocarbon reservoir can sustain flow due to its natural pressure, flow may be either, up the tubing string, the production casing, or both

Tubingless completions Casing flow completions are a particularly low-cost method in marginal flow conditions such as low rate gas wells. See Figure 2.7.7a. Figure 2.7.7 : Schematics of flowing wells (single string)

Casing flow completions are normally not used in Shell operations primarily because the production casing is exposed to well pressure and/or corrosive fluids. Tubingless completions are potentially hazardous especially in offshore installlations as there is an increased risk of collision damage offshore and no facility to install sub-surface safety valves (SSSVs). The use of casing flow production methods has been discouraged both offshore and onshore, but is under review again due to potential cost savings and the availability of new equipment.

Tubing flow completions Tubing flow completions as shown in Figures 2.7.7 b & c utilise tubing to convey the well fluids to surface. Given that the resistance to flow of a conduit is inversely related to its diameter, the potential of prolific wells will depend on the tubing size and will always be lower than if it were produced through the casing. You should note, however, that it may be more effective to use a smaller conduit in wells whose production is limited by the inflow performance of the reservoir. Under these circumstances the flow velocity is inversely related to the tubing diameter and the

8:39 PM

6/7/2007

M A-Mohsen

(5)

COMPLETION

velocity resulting in the most efficient flow regime, at which the rate is a maximum, may well be achieved at less than the maximum available diameter. As well as for production, the tubing string can be utilised as a 'kill string' or for the injection of chemicals. Tubing strings may also accommodate gas lift valves which essentially 'gas assist' well liquids to surface; these valves would be installed if formation pressure decreased to a level where natural flow could no longer be sustained. The most common method of completing a well that flows naturally is to use a single tubing string/packer system. The packer is installed in the production casing to offer casing protection, sub-surface well control and an anchor for the tubing. Two examples of such a completion are shown in Figure 2.7.7b & c. The former shows a simple low cost completion which may be installed in a low pressure well, the latter shows a more sophisticated completion which would be used in a higher pressure well Other equipment commonly installed in the tubing string to facilitate safer production operations includes: 

Wireline No-Go Nipple if installed above the highest opening in the tubing permits the installation of a bottom hole check or safety valve, or a plug.  Safety Valve Landing permits the installation of a surface controlled sub-surface safety valve Nipple (SCSSSV).  Flow Couplings absorb erosion caused by turbulence and abrasion.  Circulating Sleeve fitted above the packer to enable the displacement of tubing contents with either a lower density liquid to kick off well or a higher density fluid to kill it. All of these standard completion tools are described in later Topics. In general, the type of tubing and packer installation is dependent upon the completion requirements in conjunction with economic considerations. The completion engineer must consider many aspects of tubing/packer completions such as chemical injection, well servicing accessibility, perforating method and future artificial lift methods etc.

High rate liner In a liner completion the liner hanger can take the place of a packer, with large diameter tubing stabbed into the polished bore receptacle of the liner hanger. A polished bore receptacle in a liner hanger can be used in place of a packer, i.e. a high rate liner, as shown in Figure 2.7.7d. This method is used in deep wells where tubing and casing clearances are small and for high productivity wells where the use of a packer would restrict

ARTIFICIAL LIFT Artificial lift methods are necessary when a reservoir's natural pressure is insufficient to deliver liquids to surface production facilities. Various artificial lift methods, and their key completion considerations are described below and illustrated in Figure 2.7.8. More details are given in Topic 7.5.

Rod pump lift These pumps consist of a cylinder and piston, each fitted with a check valve, known as the standing and travelling valves respectively. Reciprocation of the piston via "sucker rods" by a surface unit pumps the well fluid up the tubing. They are utilised in low to moderate rate wells which can deliver less than 2,000 bpd (300 m3/day). The key feature of a rod pump completion is that it normally has an open annulus, although a tubing anchor device such as a packer sometimes has to be used if the stretch of the tubing, as it is alternately loaded and unloaded by the piston, approaches the stroke of the piston. A completion using the latter device is shown in Figure 2.7.8a.

8:39 PM

6/7/2007

M A-Mohsen

(6)

COMPLETION

Figure 2.7.8 : Artificial lift methods

Hydraulic pump lift Hydraulic pump lift is utilised in crooked holes, when the produced fluid has a high viscosity and in variable production conditions, all of which cause problems for conventional rod pumping. Three types of hydraulic pump are available to lift liquid: consists of a set of coupled pistons, one driven by a power fluid and the other pumping the well fluid; systems exist for production up the annulus, as shown in Figure 2.7.8b, or up the  Piston: tubing. delivers power fluid to the tubing as a low pressure high velocity jet which entrains the  Jet: produced fluid and has its velocity converted into sufficient head to produce to surface. power fluid rotates a shaft on which a centrifugal or axial pump is mounted; see Figure  Turbine: 2.7.8c. The main feature of these types of completions is the use of both the annulus and tubing as a flow path for the power fluid. The most common power fluid is recycled "stabilised" crude oil, which removes the necessity to separate produced fluid from power fluid at the surface. Stabilised crude is crude which has had virtually all the gas removed so that it can be circulated in a low pressure system prior to re-injection. If the produced fluid itself is not suitable, if for example the viscosity is too high, crude with different characteristics may be available either from different reservoirs in the same field or from other fields in the area.

8:39 PM

6/7/2007

M A-Mohsen

(7)

COMPLETION

Plunger Lift The plunger lift system, as illustrated in Figure 2.7.8d, is a low rate lift system in which annulus gas energy is used to drive a plunger carrying a small slug of liquid up the tubing when the well is opened at surface. Subsequent closing of the well allows the plunger to fall back to the bottom. Plunger lift is useful for dewatering low rate gas wells as it prevents the water falling back through the gas. In this type of completion the open annulus is used to store lift gas and a tubing stop is installed as a bumper for the plunger.

Electric submersible pumps (ESP) ESPs are used to move large volumes of low gas/liquid ratio fluids from reservoirs with temperatures below 250o F, e.g. water supply wells, high water cut producers, and high deliverability undersaturated oil wells See Figure 2.7.8e. The main features of an ESP completion is the special wellhead and downhole equipment used for installation and protection of the electric cable. Usually the larger tubing sizes are used to handle the greater volumes the ESP can deliver.

Gas Lift Gas lift supplements the flow process by the injection of compressed gas into the flow stream which lightens the liquid column, reduces the liquid viscosity, reduces friction and supplies potential energy in the form of gas expansion; see Figure 2.7.9. Continuous gas lift is used to lift liquid from reservoirs that have a high productivity index (PI) and a high bottom hole pressure (BHP). Intermittent lift is used in reservoirs that exhibit low PI/low BHP, low PI/high BHP, or high PI/low BHP. Liquid production can range up to 4,000 bbls/day (650 m3/day) through normal size tubing strings; casing flow can lift up to 25,000 bbls/day (4,000 m3/day). The gas lift completion requires a packer and gas lift valves for Figure 2.7.9 : Gas Lifting unloading and production. The gas lift valve setting depths and tubing size are determined from computer packages which optimise production according to PI, GLR, etc.

7.1.3 CLASSIFICATION BY COMPLETION GEOMETRY SINGLE ZONE COMPLETIONS Flowing wells that are equipped with a single tubing string are usually completed with a packer. Single zone completions may involve the downhole commingling of production from several intervals within that zone. Examples of single zone completions are shown in Figure 2.7.10:

8:39 PM

6/7/2007

M A-Mohsen

(8)

COMPLETION

Figure 2.7.10 : Single zone completions

At the design stage, optimum tubing size for maximum long term flow rate, future artificial lift needs, and future workover operations should be considered.

MULTIPLE ZONE COMPLETIONS When a well encounters multiple pay zones it has to be decided which of the following completion methods will be used:  Produce the zones individually in sequence through a single tubing string and the annulus.  Complete the well with multiple tubing strings and produce several zones simultaneously.  Commingle several zones in a single completion.  Produce only one zone from that well and drill additional wells to produce from the other pay zones. Examples of multiple zone completions are shown in Figure 2.7.11.

Figure 2.7.11 : Schematics of multiple zone completions

8:39 PM

6/7/2007

M A-Mohsen

(9)

COMPLETION

The main disadvantages of multiple zone completions are that the requirements for well servicing/workover operations become more frequent and at the same time they are more complex and time consuming. In theory it is a very elegant solution to complete a well with multiple packers and have the ability to produce from different intervals by simply manipulating wireline tools In practice operating companies have discovered time and time again that with more than two packers in a well the lifetime cost of repairs and recompletions is far higher than it would have been by using simple completions and accepting the fact that a drilling unit would have to re-enter the well from time to time. Very often the costs are higher than the cost of drilling a second well would have been. The problems encountered are:  that there are many more potential leak paths than in a simple completion, including communication between perforated intervals behind the casing  that wire line operations are more difficult (see Topic 7.6), and  that packers can become stuck due to fall out from higher producing zones.

Single string dual completion This is the most basic type dual completion where production of the lower zone is up through the tubing and production of the upper zone is up through the casing/tubing annulus; see Figure 2.7.11a.

Twin string dual completion In a twin string dual completion, separate flow from two zones (more if commingled) can be maintained through two tubing strings and two packers, as shown in Figure 2.7.11b.

Multiple string completions In this design, separate flow from three zones can be achieved using three packers - Figure 2.7.11c. Such completions yield high total production per well and generally reduces costs. However, these type of completions are difficult to install and are usually restrictive to production, due to the small tubing sizes, to be economically attractive. Further, as mentioned above, the difficulty of future remedial workover of such wells prevents their widespread use.

Concentric string completions Concentric strings require less clearance than multiple string completions and can often achieve a higher overall flow capability, see Figure 2.7.11d.  that there are many more potential leak paths than in a simple completion, including communication between perforated intervals behind the casing  that wire line operations are more difficult (see Topic 6), and  that packers can become stuck due to fall out from higher producing zones.

Single string dual completion This is the most basic type dual completion where production of the lower zone is up through the tubing and production of the upper zone is up through the casing/tubing annulus; see Figure 2.7.11a.

Twin string dual completion In a twin string dual completion, separate flow from two zones (more if commingled) can be maintained through two tubing strings and two packers, as shown in Figure 2.7.11b.

Multiple string completions In this design, separate flow from three zones can be achieved using three packers - Figure 2.7.11c. Such completions yield high total production per well and generally reduces costs. However, these type of completions are difficult to install and are usually restrictive to production, due to the small tubing sizes, to be economically attractive. Further, as mentioned above, the difficulty of future remedial workover of such wells prevents their widespread use.

8:39 PM

6/7/2007

M A-Mohsen

(10)

COMPLETION

Concentric string completions Concentric strings require less clearance than multiple string completions and can often achieve a higher overall flow capability, see Figure 2.7.11d. * that there are many more potential leak paths than in a simple completion, including communication between perforated intervals behind the casing  that wire line operations are more difficult (see Topic 6), and  that packers can become stuck due to fall out from higher producing zones.

Single string dual completion This is the most basic type dual completion where production of the lower zone is up through the tubing and production of the upper zone is up through the casing/tubing annulus; see Figure 2.7.11a.

Twin string dual completion In a twin string dual completion, separate flow from two zones (more if commingled) can be maintained through two tubing strings and two packers, as shown in Figure 2.7.11b.

Multiple string completions In this design, separate flow from three zones can be achieved using three packers - Figure 2.7.11c. Such completions yield high total production per well and generally reduces costs. However, these type of completions are difficult to install and are usually restrictive to production, due to the small tubing sizes, to be economically attractive. Further, as mentioned above, the difficulty of future remedial workover of such wells prevents their widespread use.

Concentric string completions Concentric strings require less clearance than multiple string completions and can often achieve a higher overall flow capability, see Figure 2.7.11d. Annulus configurations It is standard company practice to identify an annulus configuration by an alphabetic progression from internal to external casing strings. The 'A' annulus is defined as the annulus within the production/liner casing. An active annulus refers to any annulus being used for circulation purposes. An inactive annulus refers to an annulus that cannot be circulated, e.g. any annulus formed between two strings of cemented casings. In the case of a well having an extra annulus between the production casing and the tubing, is identified separately, e.g. a well on artificial lift using hydraulic pumping will have a 'drive' annulus.

SUBSEA COMPLETIONS Originally subsea wells were drilled for drainage or injection of parts of a field which were outside the range of deviated wells drilled from production platforms. However, today's subsea technology and the development of floating production and storage systems has reduced costs to where it is now economic to develop fields completely with subsea wells. From a completion point of view, the main difficulties lie in installation and well servicing or workover costs, mainly due to capital equipment and vessel costs. To counter this, it is necessary to design completions with tubing and equipment which has long service life. Lower cost wireline servicing methods from diving vessels have been developed to further improve economics. Indeed it is now even possible to obtain workover riser systems on a rental basis, hence avoiding some capital outlay. The concept of life cycle costs, which is applicable to the drilling and completion of all wells, is especially significant in offshore wells because of the high unit costs and daily rates encountered in the offshore environment. Subsea systems have further been developed for deep water fields in such areas as the North Atlantic, east of the Shetlands. A typical subsea completion is shown in Figure 2.7.12. Sub-sea christmas trees are Figure 2.7.12 : Typical dealt with in Topic 7.4. subsea completion

8:39 PM

6/7/2007

M A-Mohsen

(11)

COMPLETION

HORIZONTAL COMPLETIONS General In a vertical well bore, with current technology it is possible to successfully case and cement the hole, complete the well, perforate the producing zone or zones, clean up the perforations, produce the well and, if the level of production is not economical, use various means of stimulation (hydraulic fracturing, acidisation) of the formation to increase productivity. However the drilling of horizontal wells and their subsequent study has indicated substantial increases in production rates and, potentially, additional ultimate recovery compared to similarly treated vertical wells. As a result, there is now great incentive to drill, complete, test, stimulate and properly produce horizontal wells which, due to the possible increased production rate and recovery, must lead to significant increases in revenue per well. From the drilling point of view, horizontal wells can be classified by the length of the radius between the vertical and horizontal sections - ultrashort, short, medium or long. The geometrical characteristics of such horizontal wells are given in Table 2.7.1

Figure 2.7.13 : Naturally fractured formations

Formations which have naturally fractured networks are prime candidates for horizontal wells with multi-zonal completions where large production increases can be expected, as shown in Figure 2.7.13. The methods used to complete horizontal wells are described below and illustrated in Figure 2.7.14.

Figure 2.7.14 : Horizontal well completions

8:39 PM

6/7/2007

M A-Mohsen

(12)

COMPLETION

Open hole This is the most economical completion where removal of drilling fluid and debris from the horizontal section is the primary stimulation performed. If additional stimulation is required, tubing is run to TD and stimulation fluid spotted into the horizontal section and then pumped into the formation.

Slotted liner or wire-wrapped screen This type of completion is used if there is a risk of hole collapse and/or sand production. It is used in reservoirs that will flow naturally where no stimulation treatments are required.

External casing packers Used in combination with closeable ported subs for selective production from one or more intervals in the horizontal section of a well which penetrates a reservoir that has different zones. In general, packers of this type are commonly used to separate productive zones, either with or without cement. Similarly, because of the difficulty in cementing horizontal liners, many horizontal production strings are run without cementing. With the installation of ported collars or SSDs in such a horizontal completion string design, individual zones can be selectively produced and treated. For uncemented liner completions, the application of rotation may be utilised to deflate certain packers for retrieval.

Cemented casing or liner In this type of completion, production casing or liner is cemented into the horizontal section. After perforating, controlled stimulation treatments (matrix and fracture) can be performed efficiently.

Completion Tools/Practices In a horizontal hole, the completion problems are more complex than in vertical wells. For example, any debris in the horizontal well bore will remain where it is and create an obstacle for moving tools or instruments. Similarly, gravity will have a profound effect on various tools in the horizontal section of the well bore and effective centralisation is necessary. Completion equipment currently available is capable of working satisfactorily in a horizontal well with little or no modification. The main area requiring development is coiled tubing conveyed tools equivalent to wireline tools. Some advance has been made in the development of SSDs, mounted in the horizontal section of wells, which can be opened and closed using a coiled tubing conveyed shifting tool. Similarly, coiled tubing manipulation tools exist for packer setting in horizontal sections.

COMPLETION EQUIPMENT Completion equipment comprises  packer systems  seals and seal stacks  sliding side doors  side pocket mandrels  landing nipples  flow couplings  blast ts  gravel packs.

8:39 PM

6/7/2007

M A-Mohsen

(13)

COMPLETION

7.2.1 PACKER SYSTEMS INTRODUCTION A packer is a device used to provide a seal between the tubing and the casing. In conjunction with a properly designed completion string, this seal directs the flow of reservoir fluids from the producing formation up through tubing to the surface. The packer seal keeps well pressure and corrosive fluids from entering the annular space between the casing and the tubing, hence providing a higher degree of safety throughout the life of the well. A packer is tubular in construction and basically consists of three main elements:  Body to contain the packing elements and slips, through bore to provide the flow conduit through the assembly and connections for the tailpipe and tubing string.  Case hardened slips designed to bite into and grip the casing wall, holding the packer body parallel with the casing axis.  Rubber sealing elements to provide the seal between the packer body and casing. The principal reasons for running a packer are to isolate producing zones or the annulus from formation fluids. They are also used in well servicing to enable well repairs or stimulation operations to be performed.

CLASSIFICATION OF PACKERS In general, packers may be classified roughly by their status when set in a well, i.e.:  Retrievable (able to be retrieved by pulling the tubing as part of the design).  Permanent (not intended to be retrieved but can be removed by destructive milling process). A second generation of the permanent type packers are:  Permanent-Retrievable (although seemingly a contradictory term, this is a retrievable packer having the characteristics of a permanent packer.

Retrievable packers These are generally lowered into the well bore attached to and as an integral part of the production tubing string. As the name implies, retrievable packers can be recovered from the well, usually be applying pull to the tubing.

Permanent packers These can be lowered into the well bore and set on an electric wireline or on tubing after which the wireline or tubing is released from the packer mechanically. and when set. When set, permanent packers may be considered as an integral part of the casing and can only be removed from a well by milling through the slips, thus releasing the grip on the casing.

Permanent/retrievable packers These packers have the same characteristics as permanent packers but can be released and recovered from the well without milling. They utilise a self releasing mechanism activated by a recovery tool. Packers may be further sub-classified according to the number of bores required for production i.e.  Single - one concentric bore through the packer for use with a single completion string.  Dual - two parallel bores through the packer for use with two tubing strings. This can be extended for multiple completions as mentioned in Topic 1.

SETTING PROCEDURES Packers, both retrievable and permanent, are set in the production casing by one of the following methods:

8:39 PM

6/7/2007

M A-Mohsen

(14)

COMPLETION

Mechanically set By running on a tubing string and manipulating the tubing, i.e. by applying compression or tension in combination with rotation depending on the particular setting mechanism of the packer. Packers having rotation set/release mechanisms should be avoided in highly deviated wells since any torque applied to the top end of the tubing may not be able to be transmitted to the packer downhole.

Hydraulically set By running on a tubing string, setting a wireline plug in the tubing below the packer and applying a differential pressure. The packer is then tested for correct setting by applying tension to the tubing and/or by applying pressure to the annulus. Disconnecting from the packer is generally by rotation or further increased pull on the tubing string. More details are given under Permanent Packers

Electric Wireline set By running the packer attached to a wireline setting adapter kit connected to an electrically activated setting device on the end of an electric conducting wireline. On reaching the desired setting depth, usually confirmed by correlating to a previous base log, an electrical signal is transmitted from surface which fires an explosive charge in the top of the device. This drives down a piston which sets the packer via the adapter. The speed of the setting action is controlled by the metering of hydraulic fluid out of the other side of the piston. More details are given under Permanent Packers

RETRIEVABLE PACKER SYSTEMS Retrievable packers may be sub-classified as compression, tension, or compression/tension packers.

Compression packers Compression packers are designed to be set by downward forces from applied tubing weight (compression) or by the application of annulus pressure above the packer. They are utilised in shallow to medium depth oil and gas wells with moderate to low pressures. They are released by a straight pull on the tubing.

Tension packers Tension packers are designed to be set by upward forces from tubing tension or by the application of pressure below the packer. Tension set packers are utilised in waterflood injection wells and in wells where high density completion fluids will not be placed in the casing annulus. They are released by a combination of downward movement and right hand turning of the tubing before pulling.

Tension/compression packers Tension/compression packers are designed for either compressive or tensile forces or application of pressure from above or below. They are usually released by right hand rotation of the tubing string. Figure 2.7.16 :Typical mechanically set retrievable packers

8:39 PM

6/7/2007

M A-Mohsen

(15)

COMPLETION

Retrievable packers are generally used for short term applications or low pressure/temperature production conditions. The main advantages of using a retrievable packer is that no drilling (milling) is necessary to remove the packer and it saves tripping to retrieve as it is pulled with the tubing. The disadvantages of retrievable packers are that:  they can be accidentally released  they may be difficult to retrieve  they have smaller bores than permanent packers in the same diameter casing The following pre-checks are required prior to running retrievable packers:  Ensure that the ID of the packer will accommodate any wireline tools to be run through the packer.  Ensure that all the inside and outside dimensions relevant to the packer are measured and recorded.  Ensure that all lengths relevant to the packer are measured and recorded.  Ensure that all external slips and the packer elements are in good condition before running the packer.

RETRIEVABLE PACKER ACCESSORIES Wireline lockable collets Wireline lockable collet/sleeve latches may be used in dual completions to provide a means of independently running or retrieving the short string. The collet is locked or unlocked by a wireline tool. When locked the short string can be pressure tested or have tension applied. The collet is run on the bottom of the short string and the latch is in the head of dual packer. Figure 2.7.17 shows a hydraulically set dual packer and a collet latch (not to the same scale). In dual string completions, the tubing strings may be run independently or simultaneously. They are usually run simultaneously as it is sometimes difficult to get the second string past the primary string, especially in wells where there are doglegs or when clearances are small such as in gas lift wells with SPMs in the tubing strings. When they are run simultaneously, the short string collet is locked into the dual packer. Once landed and the string pressure tested, the collet is unlocked to ensure that the short string can be retrieved independently of the long string in the event that wireline access to the collet is impossible due to an obstruction. Unlocking of the collet should only be carried out with the string in compression. As an alternative procedure to the above for simultaneously running the tubing strings, the short strings is run two ts above the packer and when at setting depth, the short string is Figure 2.7.17: Typical lowered, latched and locked into the packer before spacing out and pressure testing. hydraulically set dual Conventional wireline methods combined with special locating and shifting tools are used string retrievable packer, plus collet latch to shift the inner sleeve in the collet seal assembly to lock and unlock it in the packer.

Telescoping swivel t In dual or multiple completions the strings must be of equal lengths for connection between packers or to the tubing hanger. There must also be a means to be able to rotate all but one of the connections to allow thread make up. These features are provided by use of a telescoping swivel t (or adjustable union). The telescoping swivel t is a device which is stroked in or out to adjust lengths and allows rotation. They are then locked after connection to the hanger.

8:39 PM

6/7/2007

M A-Mohsen

(16)

COMPLETION

PERMANENT PACKER SYSTEM Permanent packer systems are generally used for more demanding well conditions such as high temperature/pressures, long term high production rates and where excessive tubing movement is anticipated. They also find applications as temporary bridge plugs and are often used in place of retrievable packers which have an inadequate bore size. Permanent packers are sometimes also known as production packers or retainer production packers. They can be installed on electric wireline or hydraulically on tubing for which an adaptor kit is normally required.

PERMANENT PACKER ACCESSORIES Locator tubing seal assemblies Locator tubing seal assemblies, see Figure 2.7.23a, are tubular in construction fitted with a series of external seals providing an effective seal between tubing and packer bore. They are designed to limit the downward movement of seals in the polished bore of the packer by means of a no-go shoulder at the top end of the seal assembly. Locator seal assemblies are normally landed in sufficient compression to prevent upward seal movement due to pressure below the packer.

Seal bore extensions A seal bore extension is used to provide an additional sealing bore when a longer seal assembly is run to accommodate large tubing movements induced by changes in Figure 2.7.18 : permanent packer temperature and pressure during pressure testing or production conditions. The seal bore extension is run below the packer and has the same ID as the packer. Tubing seal assemblies can be assembled in various lengths, for installation in a seal bore assembly, depending on the amount of tubing movement anticipated; See Figure 2.7.23b.

Typical

Anchor tubing seal assemblies Anchor tubing seal assemblies as shown in Figures 2.7.23 c & d are used where it is necessary to anchor the tubing to a permanent packer while retaining the option to unlatch when required. Anchor latches are normally used where well conditions require the tubing to be placed in a state of tension or where insufficient weight is available to prevent seal movement. The anchor seal assembly has a latch sleeve or collet, threaded to match the left hand thread on the packer. The latch has vertical slots cut in it and the lower flank of the thread is chamfered. On entry into the packer the latch sleeve collapses inwards until it butts against the packer shoulder. The latch sleeve is now free to spring out and engage in the thread on the packer. The anchor latch can be released from the packer by placing the tubing in slight tension at the packer and rotating the tubing a prescribed number of turns to the right at surface.

8:39 PM

6/7/2007

M A-Mohsen

(17)

COMPLETION

Wireline setting method The initial action required to set a permanent packer is by a downward thrust on the outside of the packer while holding the inside stationery on the cable. This action continues until the friction of upper slips and expanding elements ing the casing wall overcomes the weight of the packer and packer tailpipe whereafter the piston pulls the inside upwards to complete the setting process. Generally, the completion engineer assumes the packer setting depth is the middle of the elements prior to running whereas in fact the actual depth may be some few inches different but this is of little consequence. The electric wireline setting tool consists of a piston and piston rod inside a cylinder - see Figure 2.7.19. At the appropriate depth an electrical signal is sent down the electric wireline to detonate the explosive charge. The forces generated by the explosion drives the piston/piston rod downwards through a metering device to produce a slower controlled action. Explosive compounds used in electric setting tools can generate up to 90,000 lbs. setting force. Setting times can be adjusted from almost instantaneously to times of about 1 hour. NOTE: Care must be exercised when working with explosives. To achieve the proper direction of forces to set a packer, a blade or key (cross link) is fixed to the piston rod and extends through a slot in a lower housing and engages in an outer sleeve (cross link sleeve). Thus, the downward thrust of the central piston rod is transferred to a downward thrust on the cross link sleeve. After the upper slips bite, the upward force on the cylinder is transferred to an upward pull on the inner mandrel. The actual forces are transmitted to the packer via the adapter kit which also incorporates the mechanism of freeing the setting assembly from the set packer. This mechanism is a collapsible collet which is activated by a release stud which is broken after the packer is fully set. The breaking Figure 2.7.19 : Schematic of an electric force of the stud is selected for the particular packer plus a suitable wireline setting tool margin of error. If the position of a packer is critical, the wireline method is preferred since the depth can be correlated with the formation evaluation tool depths by utilising a casing collar locator (CCL) and/or gamma ray logging tool in the electric wireline tool string. Prior to setting a permanent packer on electric wireline, it is essential that a junk catcher/gauge ring be run to ensure that the well is free of any material that may foul the packer assembly and cause a premature set.

Hydraulic setting method There are two methods of hydraulically setting a permanent packer, these are to run a regular packer on a hydraulic setting tool or, more commonly nowadays, to use a hydraulic permanent packer which incorporates the hydraulic setting mechanism. The latter has an advantage over the former in that it can be installed on the completion string whereas the former requires a work string to set the packer before running the completion string. A typical hydraulic type permanent packer is shown schematically in Figure 2.7.20.

8:39 PM

6/7/2007

M A-Mohsen

(18)

COMPLETION

Hydraulic set packers have an application in being able to be set where wireline or mechanical set methods are difficult, e.g. in highly deviated wells. Figure 2.7.21 shows the principle of operation of a hydraulic setting tool. The packer is run to depth on tubing or drill pipe attached to the adapter kit and hydraulic setting tool. While running in the well bore the tubing is flushed through with annulus fluid via the upper ports (a) and through the sleeve.

Figure 2.7.21 : Schematic of a hydraulic setting tool

Figure 2.7.20 : Schematic of typical hydraulic permanent packer

Hydrostatic pressure in the annulus has access to the underside of the two setting pistons via the lower ports but is excluded from the top of the pistons by the control plug. The resultant upward differential on the pistons protects the tool from premature setting while running. The control plug is held in its closed position by a collet lock and the control latch. The collets are held out by the enlarged lower end of the sleeve, which is shear-pinned to the collets. When the setting depth is reached, a ball is dropped down the tubing and seats in the top of the sleeve. Tubing pressure is increased at surface, the shear screws holding the sleeve break at an appropriate pressure, and the sleeve moves down to shoulder on the control plug. The collets are now free to collapse and further downward movement carries the control plug down giving hydraulic access to the upper piston. The lower seals on the sleeve close off the upper ports and tubing pressure can now work on the upper piston via the hollow piston rod to the lower piston. The pistons are forced down and their movement is transferred via the cross link to the cross link sleeve, to the adapter kit and finally to the setting sleeve on the packer. The packer body is held against this downward thrust by the setting mandrel. The application of further pressure will pull apart a release stud in the adapter kit. The hydraulic setting tool can be then returned to surface; tubing fluid can unload via the exposed lower ports (b).

8:39 PM

6/7/2007

M A-Mohsen

(19)

COMPLETION

Adapter kit The adapter kit transmits the forces generated by setting tools in order to set packers and provides a means of releasing the setting equipment from the packer. The adapter kit is installed between the packer and the setting device. Figure 2.7.22 shows an adapter kit assembly for top-setting a packer. The bottom of the release sleeve carries a left-hand thread, matching the thread in the top of the packer body. The lower half of the release sleeve, including the left-hand thread, is slotted vertically to form a series of resilient fingers. The threaded portion is forced into engagement with the thread on the packer by upward pressure of the mandrel guide. By this means the upward force of the setting device is transmitted to the packer body, while the downward thrust of the adapter sleeve drives down the packer setting sleeve. When setting is complete, forces which are still increasing will shear the release stud (weak link). The fingers of the release sleeve collapse since upward forces no longer exist, and the threaded portion disengages from the packer. The setting tool and adapter can be pulled from the well. Figure 2.7.22 : Adapter kit releasing mechanism

7.2.2 SEALS AND SEAL STACKS GENERAL The materials selected for downhole equipment not only include metallic components but also the seals, e.g. the seal assemblies shown in Figure 2.7.23. Seal materials used are selected for their resilience and resistance to thermal and chemical environments. Unfortunately there is no single seal material that offers adequate levels of these characteristics for all downhole applications. Effective sealing in downhole conditions may be achieved by single seals such as O-rings, T-seals or similar but other applications may require several seals to be used in conjunction such as V-packing stacks on wireline tools, SSDs and packer seal assemblies. Some types of seals are designed for dynamic applications and others static. Often several different materials are required in combination to provide resilience to the downhole conditions. When these seals are used in combination they are termed 'seal systems' by some manufacturers.

SEAL MATERIALS Equipment suppliers have developed seal materials and designed seal stacks to cater for all downhole environments for their product ranges and a completion design engineer making equipment selections must determine which product has the most suitable seals for resistance to the expected well environment.

PACKER SEALS/SEAL STACKS These paragraphs are intended to concentrate on packer and liner hanger systems especially seals which are stacked together in seal assemblies and other packer tools. A typical packer seal stack configuration is shown in Figure 2.7.24. The main packer seal which packs off within the well bore is the 'sealing element'. It is a rugged large piece of elastomeric material which is deformed and forced outwards against the wall of the casing or hole. Various designs are available from single piece elements to three piece with extrusion rings etc. As it is so large, it is usually made of Nitrile as only the very ends of the element is in with the well fluids and, therefore degradation even in harsh environments is limited. A range of element hardnesses are used for various temperature and pressure conditions. In general, harder durometer elements are used in high temperatures or

8:39 PM

6/7/2007

M A-Mohsen

(20)

COMPLETION

pressures to prevent extrusion; however they are more prone to leak as they do not mould as easily to the casing or formation. With regard to packer seal assemblies, an important factor to be considered in seal selection, is the mechanical strength for stinging into and withdrawal of the seals from packer seal bores under differential pressures; this is termed 'unloading'. This is necessary during the installation procedure of the completion and thereafter under pressure cycling and/or temperature changes during the production phase. Tubing movement calculations must be carried out to determine this tubing movement or ensure that both the packer and tubing can cater for the stresses applied when the seal assembly is latched to the packer. The most robust type of seal for packer applications is the bonded seal as shown in Figure 2.7.24. The design of this type of seal is ideal and uses high strength elastomers such as Nitrile or Viton bonded to metal carriers. However, these materials have limited chemical resistance properties.

Figure 2.7.24 : Seal units for permanent/permanent retrievable packers

Seals for performance beyond that of bonded seals require the use of more inert materials and are termed '' seals but, in consequence, they have a lower extrusion resistance and are prone to damage or breakage under unloading conditions. They are, however, effective if confined within seal bores. To help reduce seal damage, it is recommended they only be used in containment systems such as a Chevron or Vring stacks.

7.2.3 SLIDING SIDE DOORS A Sliding Side Door (SSD) or Sliding Sleeve is installed in the tubing during well completion to provide a communication path between the tubing and the annulus when it is opened. It is used to:  bring a well onto production after drilling or workover by unloading, (i.e. circulating the completion fluid in the tubing out with a lighter fluid),  kill a well prior to pulling the tubing during a workover operation (reverse of the previous) and  allow selective zone production in a multiple zone well completion. SSDs and other tubing string wireline operated completion components should be spaced out at least 10m (30 ft) apart to prevent accidental operation of the wrong component. The use of an SSD above a production packer carries a risk as, historically, they have been a source of 'A' annulus leaks. Within some Shell OUs, the use of an SSD as a circulation device has been largely superseded by the side pocket mandrel as shown in Figure 2.7.26. New generation SSDs with non-elastomeric seal technology have greatly reduced the risk of leakage and should now be more seriously considered for some applications.

8:39 PM

6/7/2007

M A-Mohsen

(21)

COMPLETION

Should an SSD leak, it can be straddled by a wireline set straddle but this reduces full bore access for wireline operations below this depth unless the straddle is retrieved. Other alternatives to SSDs are ported nipples with retrievable straddles.

CONSTRUCTION SSDs generally consist of a top sub, bottom sub, outer housing and a sliding sleeve, hence, the title. Two sets of packing are positioned at each side of the circulation holes in the outer housing which seal off the flow path when the sleeve is in the closed position. When the sleeve is moved to the open position by wireline or coiled tubing, a set of slots in the sleeve move across between the packings opposite the holes in the outer housing, hence providing a flow path. The sleeve must be fully open before circulating otherwise the packing opposite the slots will be damaged. Usually the SSD will have an equalising port which is used to equalise differential pressure before the slots are moved past the packing. There are a variety of models available which open either with upward or downward sleeve movement. A number of SSDs can be installed in the completion string and selectively opened or closed by the use of the appropriate selective wireline shifting tool. Tubing and annulus pressures must be equalised before an SSD sleeve is opened to prevent wireline tools being blown up or down the tubing.

APPLICATIONS Oil/gas and water injection wells

Figure 2.7.25 :A sliding side door

The use of SSDs in single/dual completions are detailed below. Above packer for:  Circulation purposes.  Equalising tubing/annulus prior to changing gas lift valves. Between packers for:  Production purposes.  Killing and stimulation purposes. In tailpipes below the bottom packer for:  Equalising pressure should a plug get stuck in the bottom no-go nipple.  Production of a bottom interval if the no-go nipple is obstructed. Use in this application is rare.

Horizontal or high angle wells The SSD has had widespread use for zonal isolation between packers in horizontal or high angle wells. This was an application of a standard completion tool operated by wireline methods converted into operation by coiled tubing so as to be able to work in high well angles where wireline could not operate. One of the largest s of this technology is Maersk Oil and Gas in Denmark.

8:39 PM

6/7/2007

M A-Mohsen

(22)

COMPLETION

7.2.4 SIDE POCKET MANDRELS A Side Pocket Mandrel (SPM) is a receptacle for wireline installed devices which can be used for circulation purposes. An SPM is installed in the tubing string critically positioned for its intended application. The devices which can be installed in an SPM are:  Gas lift valves.  Chemical injection valves.  Circulation valves.  Differential dump kill valves.  Equalising valves.  Dummy valves. The dummy valve is essentially a plug which is installed in the SPM when circulation is not desired, e.g. when pressure testing or when idle. SPMs were originally designed for application in gas lift, which is still their main use, but in modern completions they are also tending to replace Sliding Side Doors (SSDs) for circulation operations; the reason being that the seals are carried on the valve and can be replaced when damaged unlike the SSD which has permanently installed seals and can only be repaired by a workover. They are also versatile in that they may be used for other purposes such as chemical injection and annulus over-pressure protection. A feature of the SPM which has made its use so widespread in gas lift applications is that it provides a full bore through the tubing due to the installed valves/devices being offset to one side in a pocket. This was a vital improvement over previous systems where the valves were set in receptacles, stacked above Figure 2.7.26 : Typical side pocket mandrel (SPM) each other. These were known as 'concentric' systems and to change out a faulty valve meant that all valves above the target valve had to be retrieved before it could in turn be pulled, and vice versa for re-installation.

CONSTRUCTION An SPM consists of an oval or round body shell with an integral forged pocket offset to one side of the longitudinal axis. The SPM pocket has seal bores and a lock profile to accommodate the communication or flow control device - see Figure 2.7.26. Located in the upper part of the body is an orientation sleeve which aligns a wireline setting tool, or kick-over tool, with the side pocket aperture, regardless of well deviation or the orientation of the pocket. Side pocket mandrels are available in two sizes of pocket receptacles, 1" or 11/2 " ID. NOTE: Circulation should only be carried through an SPM with a circulation valve installed, otherwise the pocket itself will be flow cut and permanently damaged, resulting in a workover.

APPLICATIONS SPMs in oil completions are used for gas lifting, circulation, chemical injection for (wax, corrosion inhibitor, etc.) and well kick-off. Used for gas lifting, a number of SPMs are be positioned in the tubing at depths required to give optimum gas lift performance according to the well specific gas lift design. The valves installed in all but the lowest mandrel are usually be unloading type valves, with a metering injection valve installed in the lowermost mandrel which is the injection depth.

8:39 PM

6/7/2007

M A-Mohsen

(23)

COMPLETION

Some completions may incorporate SPMs as contingency for future gas lift use. These SPMs will be plugged with dummy valves until the gas lift system is commissioned. Some wells may have SPMs installed solely for well kick-off purposes. In gas wells they are used for emergency well killing, circulation and chemical injection (methanol, glycol, corrosion inhibitor, etc.). When used for emergency well killing they are installed immediately above the top packer with a shear type kill valve. In water injection wells they are used for circulation purposes only.

SPECIAL APPLICATIONS Models have been developed for special applications such as for the attachment of an injection line run from surface. This can be done as an alternative to using the annulus as a flow path with the advantages of:  reducing the volume of the injection system  keeping injection pressures off the annulus  preventing any potential erosion/corrosion of tubulars or completion equipment. Other SPM features have also been incorporated into sub-surface safety valve technology where one manufacturer developed a valve where the operating mechanism, termed the 'brain', is set in a side pocket and is, therefore, retrievable for repair/replacement. The brain is basically an operating piston which opens a flapper valve contained in the bottom of the tool. A control line is run and connects the port in the SPM type housing to the controls system through the tubing hanger in the normal fashion.

7.2.5 WIRELINE LANDING NIPPLES Landing nipples are tubing string components designed to accommodate the installation of various wireline retrievable flow control devices. The most common flow controls are plugs, standing valves, chokes, pressure and temperature gauges and storm chokes. Nipples are strategically placed in a completion string to enable pressure testing during installation and to locate other flow controls or gauges at their appropriate positions. These could be, for example (from top down): For pressure testing christmas tree and plugging for barrier protection when  Tubing hanger working on the wellhead.  SCSSSV top sub For installation of an insert valve, leak finding and back up plugging position for barrier protection.  At SSSV depth For installation of a storm choke.  Bottom of tubing For pressure testing tubing string string or in SSD top sub during installation, leak finding, deep set storm chokes.  Below packer in packer tailpipe For setting and/or pressure testing packer and string during installation, leak finding and plugging for barrier protection.  Below perforated tubing t To catch any dropped tools and for installation of BHP gauges. Nipples are also commonly used for checking wireline counter depths by tagging them with a tool string. There are two types of wireline landing nipples, no-go and selective. These are described in the following pages.

CONSTRUCTION The main features of a landing nipple, as shown in Figure 2.7.27, are the locking groove or profile, polished seal bore and no-go shoulder. Figure 2.7.27 : Typical wireline landing nipples

8:39 PM

6/7/2007

M A-Mohsen

(24)

COMPLETION

Landing nipples are available in two basic types, made to fit most tubing sizes and weights with API or connections:

No-go or non-selective The non-selective nipple receives a locking device which uses a no-go principle for the purposes of location. This requires that the OD of the locking device is slightly larger than the no-go diameter of the nipple. The nogo diameter is usually a small shoulder located below the packing bore (bottom no-go) or, in some designs, the top of the packing bore itself is used as the no-go. Only one no-go landing nipple of a particular size can be used in a completion tubing string.

Selective There are two selective nipple systems:  One where the locking device or mandrel has a special profile which will only locate the nipple with exactly the same profile (each nipple must have a different profile).  The other where the locking devices are designed with the same external key profile and the method of nipple selection is determined by manipulation of the running tool. This selective design is full bore and allows the installation of several nipples of the same size and type. Figure 2.7.28 : Sur-set lock mandrel

POSITION OF WIRELINE LANDING NIPPLES The industry norm has been to use selective landing nipples in the tubing string with one no-go nipple installed at the bottom of the tailpipe. However, nowadays tapered string completions are commonplace and there is a wider use of no-go nipples in each tubing size section. No-go nipples are preferred to selective nipples as they have positive location for installation of lock mandrels. A more recent development by manufacturers has been slim shouldered no-go nipples which still give the benefit of the positive location but provide as large a bore size as possible. The Baker 'Sur-Set' system was the first of this type which uses the slim no-go for location of the lock mandrel. During the setting process the lock is pulled up into the lock profile exporting the no-go shoulders, hence preventing deformation to the slim area due to forces caused by pressure from above. This is shown in Figure 2.7.28. Other similar systems are now available.

WIRELINE OPERATING LIMITS IN DEVIATED WELLS The maximum practical deviation for wireline lock mandrel setting is 65° - 70° from vertical. At higher deviations, downward jarring action may not be effective - refer to Topic 7.6. In these instances, coiled tubing may be used for installing and retrieving wireline tools

7.2.6 FLOW COUPLINGS In high flow rate wells flow couplings are installed above (and sometimes below) flow control devices, including SSDs and SCSSSV landing nipples, in the completion string to protect against internal erosion caused by flow turbulence. When well fluid encounters a restriction in the conduit such as a landing nipple, excessive turbulence will develop immediately above and possibly below the nipple. In a completion string this flow erosion would reduce the life of the completion as it would weaken and eventually cut through the tubing. To allow for this erosion a heavy-walled tubular is run above (and sometimes below) the nipple. Although the same amount of erosion would still be experienced, the added thickness of the flow coupling leaves enough material intact to provide adequate strength over the projected life of the well.

8:39 PM

6/7/2007

M A-Mohsen

(25)

COMPLETION



In oil or water injection wells generally, one flow coupling should be installed directly above and one below the safety valve landing nipple. Flow couplings may be required for other completion devices depending on the nature of the fluid flowing.  In gas wells all bore restrictions such as at SPMs and swedges, should have flow couplings installed directly above them. Flow couplings should be provided for safety valve landing nipples as in oil wells above. Calculations to determine flow velocities and criteria for erosion are given in API Specifications.

7.2.7 BLAST TS Blast ts are installed opposite perforations (non gravel packed) where external cutting or abrasive action occurs caused by produced well fluids or sand. In actual fact they perform the same task as flow couplings but protect against external erosion. They are constructed from a heat treated alloy material and are heavy walled tubulars. Blast ts are usually available in 10, 15, and 20 ft lengths. Completion designs should ensure that blast ts extend at least 4 ft on either side of a perforated interval.

7.2.8 GRAVEL PACK WHAT IS A GRAVEL PACK ? A gravel pack is a completion procedure that is performed to prevent sand production from unconsolidated sandstone formations and high production rate wells. It consists of placing a screen in the well bore, then filling the perforation tunnels and the annular area between the screen and the casing with specially sized, highly permeable gravel pack sand. The formation sand bridges on the gravel pack sand, and the gravel pack sand bridges on the screen. It may be referred to as a 'two-stage filter' for this reason. This two-stage filter allows for sand-free production at any rate. A brief overview of gravel packing completion equipment and tooling follows below. A typical gravel pack installation procedure is given in Topic 7.7.5.

SERVICE TOOLS Service tools are defined as the equipment necessary to perform the gravel pack, but which are removed from the well after gravel packing. Common GP tools are described below.

Setting tool The hydraulic setting tool generates the force required to set the gravel pack packer. It is attached to the crossover tool and it bumps up against the setting sleeve of the packer. A setting ball is dropped to the ball seat in the crossover tool to plug off the ID of the tool. Applied tubing pressure acts on a piston in the hydraulic setting tool to set the packer.

Crossover tool The crossover tool creates various circulating paths for fluid to flow during the gravel packing operation. It consists of a series of moulded seals surrounding a gravel pack port midway down the tool and a return port near the top of the tool. See Figure 2.7.32. Most crossover tools have a 'squeeze' position, a 'circulating' position, and a 'reverse circulating' position. The 'squeeze' position exists to perform squeeze gravel packs and to inject acid treatments into the formation. The 'circulating' position provides a path to circulate the gravel pack into place in the perforations and around the screen. The 'reverse circulating' position allows reversing excess sand out the work string after gravel packing.

8:39 PM

6/7/2007

M A-Mohsen

(26)

COMPLETION

Figure 2.7.32 : Typical crossover tool

There are two release mechanisms available to release the crossover tool from the packer after it is set - a mechanical release requiring rotation and a hydraulic releasing mechanism.

Shifting Tool The shifting tool is run below the crossover tool to open and close the sliding sleeve in the extension. When the gravel pack is complete, the service tools are pulled out of the gravel pack assembly. The shifting tool is pulled through the sliding sleeve so that the collet catches the fingers in the sliding sleeve, thus shifting it to the closed position.

Washpipe Washpipe is run internal to the screen and blank to insure that the carrier fluid carries gravel to the bottom of the interval. The bottom of the washpipe should be positioned as close to the bottom of the screen as possible in a water pack. Research indicates that maximising the washpipe OD increases the resistance to flow into the washpipe/screen annulus and increases gravel pack efficiency (Ref. SPE 6805). The ratio of washpipe OD to screen base pipe ID should be as close to 0.8 as possible. In some instances this will require the use of flush t washpipe.

8:39 PM

6/7/2007

M A-Mohsen

(27)

COMPLETION

COMPLETION EQUIPMENT The completion equipment is defined as the gravel pack equipment that remains in the well after the gravel pack operation is completed. Following is a single zone gravel pack assembly for a 'water pack'. A water pack is a gravel pack that is performed using largely non-viscosified completion brine as the gravel carrier fluid. The components of the gravel pack assembly, shown in Figure 2.7.29, will be reviewed from the bottom up.

Sump packer The purpose of the sump packer is to provide a positive base for the gravel pack. The sump packer is usually run into the well prior to perforating and is set at a specified distance below the perforations. It can be either a retrievable or permanent seal bore type packer, however, it is typically a permanent packer set on wireline; Refer to Topic 7.2.1 for packers. The advantage of using a packer as opposed to a bridge plug is that a packer provides a sump below the completed zone for debris such as that produced during perforation. The sump may also be required to facilitate the running of production logs.

Snap latch seal assembly The gravel pack assembly is latched into the sump packer through a snap latch seal assembly. This tool has threaded fingers that collapse inward as it the top of the packer. When the assembly is fully lowered into the sump packer, the threaded fingers expand and engage the left-hand square threads at the top of the sump packer. Two moulded seals provide a seal between the lower packer bore and the snap latch assembly. This tool can be snapped in and out of the sump Figure 2.7.29 : Gravel pack assembly packer to that the gravel pack assembly is properly positioned.

Gravel pack (production) screen The Screen is a filter that retains the gravel pack sand which is placed between the screen and open hole or into perforations. This allows formation sand to bridge on the gravel pack sand, and the gravel pack sand to bridge on openings between wire wraps of the screen.

Standard wire wrapped screen The gravel pack screen is ed on a length of standard oilfield tubing, referred to as 'base pipe'. The base pipe is drilled with a sufficient number of holes to create a greater amount of flow area per foot of pipe than the internal flow area of the pipe - see Figure 2.7.30. This ensures that the screen design will not be the limiting factor for flow capacity in the completion design. The preformed screen 'jacket', consisting of the outer wire wrap, sized to prevent age of the gravel Figure 2.7.30 : Bakerweld screen pack sand, and the longitudinal ribs, is then welded to the base pipe at each end of design the jacket. The ribs hold the wire wrap off of the base pipe, creating an annular area between the inside of the screen jacket and the outside of the base pipe. This will allow fluid at all the openings in the screen to be able to drain to the holes in the base pipe.

8:39 PM

6/7/2007

M A-Mohsen

(28)

COMPLETION

Pre-packed screen Prepacked screens are screens that incorporate a thickness of resin-coated gravel pack sand inside the screen which may act as a bridging agent should the screen jacket fail. Prepacked screen may be recommended for use in any of the following circumstances:  Highly deviated wells  Non-gravel packed wells  Heterogeneous permeability through the producing interval  Lengthy producing intervals  Multiple zone wells in which the zones are too close to create a gravel reserve  When there is any other reason to doubt the ability to achieve a good gravel pack There are a number of various configurations of pre-packed screen from different suppliers, and the new generation incorporate sintered metal elements

Blank pipe Blank pipe is incorporated to position the packer away from the screen and to provide a reservoir of gravel above the top of the screen. This reservoir will allow voids created by pack settling to fill from above. There is no hard rule on how large the reservoir of gravel should be, however, 20 metres (60 ft) of packed gravel above the top of the screen should be sufficient for all but very long zones. For water Figure 2.7.31 : Typical welded packs, 20 metres (60 ft) of blank pipe is recommended in addition to the 10 metres screen (30 ft) of screen above the top perforation to provide the gravel reserve. Ideally, the blank pipe should be the same size as the base pipe of the screen. This prevents a drastic change in annular flow area at the blank pipe and screen interface. Alternatively, the next larger blank pipe size can be used with flush t connections to provide a constant OD assembly. The use of smaller blank pipe very often results in the formation of a bridge at the top of the screen. Blank pipe should be centralised similarly to the screen.

Shear-out safety t A shear-out safety t consists of two subs that are connected by a number of shear screws. This device should be incorporated into most gravel pack assemblies to allow for retrieval of the packer and extension independently of the blank pipe and screen. After applying straight tension to shear the screws, the packer and extension may be retrieved. The blank pipe and screen may then be washed over and retrieved. Alternatively, if the screen is securely anchored in the hole with gravel and no shear-out safety t is run, the tubing below the packer must be cut to retrieve the packer. The shear-out safety t must be shear pinned to the weight of the assembly with some safety factor, therefore, due to limited shear value, it is not recommended to be used in long assemblies, such as horizontal gravel pack assemblies.

Knock-out isolation valve A Knock-Out Isolation Valve is a mechanical fluid loss device that minimises completion fluid losses and damage to the formation while retrieving the gravel pack assembly and running the production string. It is usually positioned above the blank pipe and below the extension. While gravel packing, the flapper valve is held in the open position by the washpipe. When the washpipe is retrieved after the gravel pack, the flapper is allowed to close downward on a seal. Production will open the flapper naturally; however, if necessary it may be broken hydraulically or mechanically.

8:39 PM

6/7/2007

M A-Mohsen

(29)

COMPLETION

Gravel pack extension Gravel pack extensions are available in two types, perforated and sliding sleeve. The gravel pack extension houses the crossover tool and provides a path for the gravel from the tubing to the screen/casing annulus and for fluid returns. If a perforated extension is used, the holes in the extension should be isolated during the production mode with a seal assembly. Isolating the holes is a precaution to prevent any gravel production. If a seal assembly cannot be used to isolate the holes or a long seal assembly is not desired due to increased cost, a sliding sleeve gravel pack extension should be used. After the gravel pack is completed, the sliding sleeve is closed when the shifting tool is pulled back through it from below.

Gravel pack packer At the top of the assembly is a gravel pack packer. This packer may be permanent or retrievable; however, retrievable type packers are recommended should a workover become necessary.

SUB-SURFACE SAFETY VALVES 7.3.1 WHY USE A SUB-SURFACE SAFETY VALVE ? A sub-surface safety valve (SSSV) is a downhole safety device installed in a well which can be closed in emergency situations. An emergency may arise on or around a well from equipment failure, human error, collision with an offshore facility by a third party vessel, fire, leaks or sabotage. The reason for using an SSSV is to provide protection to site and off-site personnel, surface facilities (especially on offshore installations), the environment and the reservoir. This reason has even greater implications for wells which have been drilled and completed in geologically or politically unstable areas and potential war zones. It also provides general protection against any 'what if' scenario which may arise. Nowadays, in the light of the potential effects of oil and gas discharges into the environment, most operating companies have a definitive policy regarding wells which can sustain natural flow. In many countries, government legislation insists that an SSSV is installed as the primary safety device. A secondary use of an SSSV is that it may be considered as a barrier in well plugging to allow remedial well operations to be conducted to the christmas tree, or removal of the tree for rig operations, provided it has been satisfactorily leak tested.

7.3.2 TYPES OF SUB-SURFACE SAFETY VALVES Two types of sub-surface safety valve are available for production tubing strings - direct controlled and remote controlled valves

DIRECT CONTROLLED SSSV This type of SSSV uses flow rate changes of a well to operate the valve. The valve is normally open under 'normal' flowing conditions but any deviation from this normal condition (e.g. destruction of the wellhead or a rupture of a surface production flowline producing an increase in flow rate) will cause the safety valve to close. Such valves are generally termed sub-surface controlled sub-surface safety valves or 'storm chokes'. They have several weaknesses, however:  some emergency situations (e.g. surface fire near oil and gas separation equipment) do not directly affect the flowing characteristics of the well; in such situations closure of the safety valve will not occur.  they are difficult to calibrate and set to a desired flow rate  the "normal" flow rate changes with time - either because of reservoir pressure decline or because of the requirements of production scheduling - and every time it changes significantly the storm choke must be replaced by one with a different setting.  they are very difficult to test

8:39 PM

6/7/2007

M A-Mohsen

(30)

COMPLETION

Since such a system lacks human control, the use of safety valves of this type is diminishing.

REMOTE CONTROLLED SSSV This type of safety valve, as the title suggests, moves the point of control from downhole to the surface. The remote operation of this type of valve can be integrated with pressure pilots, emergency shutdown systems (ESD, PSD) and surface safety control manifolds. Therefore, surface controlled subsurface safety valves ( SCSSSVs ) are better suited for both manual and automatic action required by today's industry. In the simplest system, a remotely controlled safety valve is held open by transmitting a supply of hydraulic pressure from the control system on surface through small bore tubing to the valve. The pressure is provided by a hydraulic pump, or bank of pumps, through a pressure regulator contained in the control system. A system of sensors (pressure and/or fire) are installed at some strategic points near the wellhead and around the plant and, when activated, signals the control system to remove the hydraulic pressure from the control line, allowing the safety valve to close and shutting off well flow. A typical SCSSSV installation is shown in Figure 2.7.33 which features an annulus safeguard for the gas lift system. Figure 2.7.33 : A typical SCSSSV installation

SCSSSV INSTALLATIONS There are two main versions of surface controlled sub-surface safety valves:  Wireline retrievable safety valves (run and installed in a wireline nipple in the completion string after the completion has been landed, tested and the christmas tree installed).  Tubing retrievable safety valves (installed as an integral part of the completion string). For valve setting depths see Topic 7.3.5.

SCSSSV DESIGNS Figures 2.7.35 and 2.7.36 are typical examples of a fail-safe close ball type WRSV and a flapper type TRSV. In these examples, the important features are the valve mechanism and the hydraulic operation. WRSVs and TRSVs are available with optional ball or flapper type closure, although, increasingly the flapper type is becoming more popular due to its reliability, brought about by a simpler design and operation. TRSVs are usually full-bore valves i.e. the inside diameter is compatible with the production tubing. TRSVs which have to through tubing to reach the SVLN, have comparable bore sizes much less than that of the tubing.

8:39 PM

6/7/2007

M A-Mohsen

(31)

COMPLETION

Wireline retrievable SCSSSVs After the completion string has been installed, a wireline retrievable SCSSSV is run, located and locked into a safety valve landing nipple (SVLN) prior to production. The SVLN is installed in the tubing string. The components required for the installation of a wireline retrievable safety valve (WRSV) system are; the WRSV, SVLN, lock mandrel, hydraulic control line and fittings, hydraulic control manifold and wireline installation and retrieval tools. A safety valve landing nipple is a short tubular component primarily designed as a receptacle in which to lock the WRSV. It is run on the production tubing string. The main features of an SVLN are the control line port, locking groove or profile, polished seal bores above and below the control line port, polished seal bore below the control line port and the no-go shoulder. These features are illustrated in Figure 2.7.34. The internal locking profile receives the matching keys of the appropriate lock mandrel to which the WRSV is assembled. This assembly is run, located and locked into the SVLN. The control line port in the SVLN exits through a lug which, being raised, offers a degree of protection for the hydraulic control line and its fitting. In general, SVLNs are usually of a non-welded construction designed to be robust against shock and knocking while being installed. The material selected for the SVLN must resist the corrosion effects of the well Figure 2.7.34 : Typical safety valve landing environment. The control line is attached to the SVLN and tubing hanger by compression fittings and nipple the material selected for these must be compatible with the nipple and hanger materials and also resistant to corrosion from annulus or packer fluids. SVLNs are available in various configurations depending on the WRSV design, weight of tubing and tubing thread connection. A lock mandrel, as stated earlier, is a carrier for the WRSV and is a removable locking device used to locate, lock and seal off within the matching SVLN. The WRSV is attached to the lower end of the lock mandrel to make up the valve assembly. The lock mandrel keys are mechanically driven out and locked into the internally machined recess of the SVLN. When running a WRSV, a prong on the running tool (R/T) of the wireline tool string is used to hold the valve in the open position to allow fluid by when entering the nipple otherwise it would become pressure locked. When successfully locked into the SVLN, hydraulic pressure is applied to the control line to hold the valve open allowing retrieval of the prong, R/T and tool string. Pressure sealing within the nipple is achieved by packing stacks on both the lock mandrel and the WRSV which positions in the landing nipple's upper and lower seal bores. These packing stacks provide a seal above and below the control line port within the nipple. The area between the packings is the communication path from the control line into the valves operating system. Control fluid from the control line, which is usually 1/4 " OD tubing, enters the valve's hydraulic piston and actuates the valve.

Tubing retrievable SCSSSVs A tubing retrievable SCSSSV is run as an integral part of the completion string. The equipment requirements for a tubing retrievable safety valve (TRSV) system are: the TRSV assembly, hydraulic control line and fittings, and a hydraulic control manifold. Similar to the WRSV, the control line is attached between the TRSV and tubing hanger. When running a TRSV, hydraulic pressure is applied to the control line holding the valve open to prevent pressure locking when the tubing string engages a packer or liner hanger. The valve of this hold open pressure is provided in the manufacturer's design and test pressures.

8:39 PM

6/7/2007

M A-Mohsen

(32)

COMPLETION

If a TRSV develops a failure while in service, an option to allow the well to continue in production is to install a WRSV insert valve within the TRSV using a lockout tool, insert wireline retrievable safety valve (WRSV) and wireline installation and retrieval tools. NOTE: If the reason for the TRSV failure is due to a leakage of the control line, then this remedy is not appropriate as the WRSV also relies on control line integrity. The TRSV insert procedure locks open the valve mechanism with the lockout tool, which also opens communication to the control line, and installs the insert valve in exactly the same manner as given previous WRSV installation procedure. This option is a cost effective method of safety valve re-instatement but may reduce production due to its smaller bore size. If this was unacceptable, a workover would be necessary to plug and kill the well and pull the completion.

VALVE MECHANISM Ball valve mechanism Figure 2.7.35 shows an exploded view of a ball and seat assembly. This assembly consists of the ball, seat, control arms, sleeve weldment and alignment pins; the ball is provided with slots to accommodate the drive pins. The ball and seat assembly provides a metal-tometal sealing system and is the primary seal to well pressure below the safety valve when closed. Downward movement of the valve seat and control arms within the sleeve weldment will move the ball downwards. When the sleeve weldment butts up against the lower assembly, a 90° rotation of the ball will have occurred moving it to the open position. The rotation is due to the slots in the ball acting on the drive pins. When hydraulic pressure is removed the spring pulls back the ball, assisted by any well pressure, hence Figure 2.7.35 : Schematic of a fail-safe close ball type WRSV reversing the opening action. Additional force from well pressure will assist in making a pressure tight seal.

8:39 PM

6/7/2007

M A-Mohsen

(33)

COMPLETION

Flapper valve mechanism Figure 2.7.36 shows an exploded view of a flapper and seat assembly. During actuation, the

flow

tube

moves

downwards

and

mechanically opens the flapper system. Reverse of the above action closes the flapper valve; closure is initially assisted by the flapper spring and then by well pressure. This flapper closure system has a metal-to-metal 'hard' seat for high pressure sealing and a 'soft' seat for low pressure sealing.

Figure 2.7.36 : Schematic of a fail-safe close flapper type TRSV

HYDRAULIC ACTUATION As discussed above, both ball and flapper valve mechanisms require the downward movement of an internal actuator to open the valve. This motion is achieved by the application of hydraulic pressure from surface, down through the control line to the valve and acting on a piston (or pistons) forcing it downwards against the opposing force of an internal power spring and well pressure. This spring provides the stored potential energy to close the valve when hydraulic pressure is removed or lost. Two methods of a achieving this actuation are shown in Figure 2.7.37.

Figure 2.7.37 : Two methods of hydraulic actuation

8:39 PM

6/7/2007

M A-Mohsen

(34)

COMPLETION

CONCENTRIC PISTON ACTUATION Hydraulic fluid is pumped into an annular space within the valve which moves a concentric piston downwards against the force of the power spring.

ROD PISTON ACTUATION Hydraulic fluid is pumped into small bores and forces rod pistons downwards against the force of opposing power springs. Rod piston actuation reduces the hydraulic chamber volume and permits operation of valves at greater depths, however the penalty is higher operating pressures and the corresponding impacts on the system reliability and costs.

7.3.3 SCSSSV EQUALISATION When an SCSSSV has been closed in a producing well, the well will build up pressure below the valve to static conditions. This pressure may be many times higher than the flowing pressure at the valve at time of closure and, to re-open the valve with a differential pressure across the closure mechanism, will require higher than normal control line pressures. This in turn will subject the internal components of the valve to higher stresses, especially the primary sealing surfaces. In most circumstances, the pressure required will exceed the rating of the wellhead, the tubing hanger or the SCSSSV hydraulic control line. To prevent damage to a safety valve system due to such stresses, the pressure differential across the valve must be reduced or eliminated. When this condition has been established, hydraulic pressure can then be re-applied to the SCSSSV control line to open the valve.

METHODS OF PRESSURE EQUALISATION The following methods can be used to equalise fluid pressures above and below a closed SCSSSV:  Re-pressurising the production tubing above the SCSSSV from another well (if sufficient well pressure exists) via the production manifold.  Pumping a fluid which is compatible with the produced well fluid (e.g. diesel for thin oils) into the production tubing and pressurise this fluid until equalisation is achieved across the valve.  Pumping a supply of inert gas (e.g. nitrogen) at sufficient pressure into the production tubing until equalisation occurs.  Using a combination of the methods described in 1 and 3. If other wells cannot supply sufficient pressure, this deficiency can be made up by an additional supply of inert gas.  Using the available built-in equalisation feature of the SCSSSV installed; this may be used in conjunction with some of the methods described above.  Equalisation via the annulus through the (gas lift) blowdown loop. Whichever method of SCSSSV equalisation is chosen will be dependent upon the available source of pressure and, possibly, Company policy.

NON-EQUALISING SCSSSVS As the name implies, non-equalising SCSSSVs have no internal mechanism to assist in the equalisation of pressure across the safety valve. Therefore, the only method available is the re-pressurisation of the production tubing above the safety valve via the christmas tree. After equalisation, the appropriate control line pressure, as recommended by the SCSSSV manufacturer, is applied to the valve; the magnitude of this pressure is dependent on the valve opening pressure, the setting depth of the valve, the control line fluid gradient and a safety factor margin. The advantage over an equalising SCSSSV is that it is more reliable due to simpler design. The disadvantages are that an external source of pressure is required for equalisation and improper operation against differential pressure can damage the valve.

8:39 PM

6/7/2007

M A-Mohsen

(35)

COMPLETION

EQUALISING SCSSSVS Equalising SCSSSVs provide an internal mechanism whereby pressurised well fluid below a closed valve can be introduced into the production tubing above the valve to facilitate equalisation of pressure. In general, pressurised well fluid below a safety valve is allowed to by the closed valve by moving a secondary valve offseat. This small movement of the secondary valve is provided by applying an appropriate control line pressure which only opens the secondary valve system; the magnitude of this pressure is dependent on the valve opening pressure, the setting depth of the valve and the control line fluid gradient. The only advantage of this valve vis-a-vis the non equalisation valve is that it requires no outside source of pressure. However, it is much less reliable as there are more seals and sealing surfaces.

7.3.4 SURFACE CONTROL MANIFOLDS SCSSSV CONTROL MANIFOLDS Since SCSSSVs are fail-safe close valves, they must be held open by an external pressure source. Surface control manifolds are designed to provide and control the hydraulic pressure required to hold an SCSSSV open. Figure 2.7.38a illustrates a typical portable SCSSSV surface control manifold; such a manifold might be used by wireline operators to keep a TRSV open (after isolation from the main ESD system) during routine wireline work on a well. The main components of such a manifold are the air supply and regulation system, low pressure system for pneumatic control (3-way controller, fusible plug, hi-lo pressure pilot, manual shutdown) and hydraulic system for valve actuation (control line).

Figure 2.7.38 : SCSSSV control manifolds

A manifold may have one or more air driven hydraulic pumps to maintain the desired hydraulic pressure for safety valve operation. Hydraulic pressure is maintained by a hydraulic control valve which is actuated by the low pressure air control system. Loss of pressure in either the low pressure control system, SCSSSV control line; or the manual shutdown will close the safety valve. Figure 2.7.38b illustrates the use of single well control manifold. In this illustration, it is assumed that a hi-lo monitor pilot and a fusible plug are integrated into the low pressure pneumatic control system and the hydraulic system is connected via the control line from the manifold down to the SCSSSV.

8:39 PM

6/7/2007

M A-Mohsen

(36)

COMPLETION

Appropriate hydraulic pressure is maintained from the hydraulic pump, through the hydraulic controller and SCSSSV control line to hold the safety valve open. Appropriate pneumatic pressure is maintained in the low pressure control system for the flowline monitor pilot and the fusible plug; See Figure 2.7.38c. If the monitor pilot senses a pressure variation outside a pre-set range, e.g. due to flowline rupture or to the compound within the fusible plug melting by fire temperature at the wellhead, pressure will be lost from the low pressure control system. As this pressure exhausts, a relay valve on the hydraulic controller blocks hydraulic pump pressure to the SCSSSV; See Figure 2.7.38d. Simultaneously, the hydraulic controller will allow pressure in the SCSSSV control line to bleed off to the manifold reservoir. Additional devices can be integrated with the low pressure control system such as:  Melting or rupture of pressurised plastic air line at the wellhead.  Operation of a sand (erosion) probe on the flowline.  Manual operation of the emergency shutdown (ESD) system.  Automatic operation of production shutdown (PSD) system (due to e.g. a high separator liquid level). Surface control manifolds are supplied as complete units containing a hydraulic fluid reservoir, pressure control regulators, relief valve, pressure gauges and pump with manual override. An SCSSSV control manifold installation requires a pneumatic supply and hydraulic connection to the SCSSSV control line; a pneumatic connection is also required to the low pressure pilot control system.

MULTI-WELL CONTROL SYSTEM To enhance safety at the wellhead, automatic control of the entire christmas tree and SCSSSV are usually incorporated into one single surface control manifold system; See Figure 2.7.39

Figure 2.7.39 : Typical well shut-in control

8:39 PM

6/7/2007

M A-Mohsen

(37)

COMPLETION

This ties in complete control of the well and may save undue stressing of the SCSSSV by either only closing surface valves or having a time delay between surface and downhole closures whereby the surface valves, closing first in sequence, will reduce the differential pressure across the SCSSSV before its activation. For a well on gas lift, automatic sequencing of safety valve closure would be injection gas valve first, the tree surface valves second, and then the SCSSSV along with the annulus safeguard system. A predetermined time interval between closures would be incorporated into the hydraulic control system.

7.3.5 SCSSSV SETTING DEPTHS FACTORS INFLUENCING SCSSSV SETTING DEPTHS The depth at which an SCSSSV should set in a well will depend on the following factors: Well environment

Setting depth considerations

Land well Offshore well Simultaneous drilling and production. High blowout potential

Recommended minimum SCSSSV setting depth 100 ft. below ground level. Recommended minimum SCSSSV setting depth 50 ft. below deepest pile penetration on fixed steel platform. Below deviation kick-off depth Below estimated cratering depth.

Well Production

Setting Depth Considerations

Wax deposition Hydrate formation

Wax deposition depth (oil wells). Hydrate formation depth (gas wells).

Well temperature will be an influence on these factors during production.

SCSSSV Characteristics

Setting Depth Considerations

Valve closing pressure

Maximum fail-safe setting depth.

The valve closing pressure is depended upon the control line fluid gradient, operating valve friction and manufacturer's recommended operating safety margin.

When the control line pressure is removed by the surface control manifold, the force of the power spring in the SCSSSV must be able to overcome the hydrostatic head of control line fluid and seal friction during the closing cycle. These forces are illustrated in Figure 2.7.40. The closing force and, hence, the closing pressure will be the determining factor for establishing the maximum depth at which a TRSV or a WRSV can be set in the tubing. The maximum fail-safe depth for a particular model of safety valve is not standard. The maximum fail-safe depth must be determined for each particular SCSSSV installation. Figure 2.7.40 : SCSSSV force considerations for maximum setting depth

8:39 PM

6/7/2007

M A-Mohsen

(38)

COMPLETION

7.3.6 SCSSSV CONTROL LINE FLUIDS Hydraulic control line fluid is normally static and is held under pressure for long periods of time. This fluid is also subjected to relatively high temperatures during production. It must, therefore, be able to sustain these conditions without decomposition and with minimal changes in its physical characteristics (e.g. viscosity). The proper choice of a control line fluid will depend on the production temperature at the SCSSSV, control line material, SCSSSV material and SCSSSV seal materials. Oil-based hydraulic liquids are generally used since they are less likely to induce corrosion in the control line and the SCSSSV material, and less likely to degrade the SCSSSV seals. Water-based hydraulic liquids are diminishing in use since they may cause corrosion in some metals or alloys. Also, due to their water content, hydrate ('ice') formation may be promoted in a gas wells if a leak develops past an SCSSSV seal. Hydraulic control fluids must be filtered, typically to NAS 6 as fluid cleanliness has a large bearing on wear and tear of the hydraulic system due to particle erosion of valve seats and piston seals, etc. Any ingress of sand/debris into the control line may induce mechanical problems; for example, wear of dynamic seal areas within an SCSSSV. Tell-tale signs may be the discoloration of the hydraulic oil within the reservoir supply tank. The back flow of well fluids up the control line are indicative of a serious SCSSSV problem and remedial actions should be instigated. The speed of closure of an SCSSSV is an important factor in the choice of hydraulic control fluid. Since the force of the power spring must displace control fluid back to surface, the viscosity of the control liquid will determine the flow rate through the control line and hence the rate of closure of the valve. A highly viscous fluid may slow down valve action to an unacceptable rate.

7.3.7 ANNULUS SAFETY VALVES The sub-surface safety valves discussed so far, i.e. tubing retrievable and wireline retrievable, only provide flow control on tubing strings. In completions where artificial lift or secondary recovery methods are employed e.g. gas venting in electric submersible pump (ESP), hydraulic pump, and gas lift installations annulus safety systems are often used. This is to reduce the potential hazard of a large gas escape due to the huge inventory within an annulus in the event there is an incident where the tubing hanger seal is breached. There are a number of designs of such systems on the market and the variety is too wide to be covered in detail in this document, however the basic concepts are the same. With any annulus system, there must be a sealing device between the tubing and the casing through which the flow of gas can be closed off. This is generally a packer or a casing polished bore nipple into which a packing mandrel will seal. Contained in the sealing device is a fail safe valve mechanism operated by hydraulic pressure similarly to an SCSSSV. The valve mechanism opens a communication path through the tool to allow annulus flow. Figure 2.7.41 : Typical annulus-type safety valve system

8:39 PM

6/7/2007

M A-Mohsen

(39)

COMPLETION

CHRISTMAS TREES A christmas tree (often known as xmas tree) is an assembly of valves and fittings which forms the top of the completion. It is connected to the tubing hanger spool and directs the flow of fluids from the production tubing(s) into the production flowline(s). It also provides vertical access to the production tubing(s) for well servicing and side access to the production tubing(s) for pumping services, i.e. well kill, circulation and chemical injection facility. In essence, a christmas tree is a manifold of valves which is installed on top of a tubing head upper flange or adapter of a wellhead. Sub-sea christmas trees are designed to perform the same functions as surface christmas trees but are significantly more complex due to the operation of the sub-sea valves, the methods of installation and the interfacing with workover systems. Due to the individualistic nature of these, their details are not addressed in this manual although a typical system is shown in Figure 2.7.45.

7.4.1 TYPES OF CHRISTMAS TREE COMPOSITE TREES If the individual valves and fittings are flanged and/or clamped together, the tree is referred to as a 'composite' type tree, as shown in Figure 2.7.42. There are many variations in the arrangement of the valves and fittings within these trees to meet with specific requirements of a particular application. Composite trees are generally used for low pressure applications only. Figure 2.7.42 : A composite christmas tre

The advantages of using composite trees are that they utilise standard components and, in the event of damage, individual items can be replaced at relatively low cost. Also due to the modular construction, composite trees are easily adapted for special applications. However, composite trees have a high leak potential due to the large number of connections and are difficult to handle. They are also taller than solid block versions.

SOLID BLOCK TREES If valves and fittings are incorporated directly into a solid steel forging, the tree is referred to as a 'solid block' tree. Although solid block trees utilise forged bodies, they are still designed to use standard valve components such as the actuator, gates and seats. Top and bottom connections may be either flanged or clamp-type. On high rate wells, models with Y shaped block forgings are used to reduce flow turbulence compared to that caused in the 90° spool pieces used in composite trees. An example of a solid block christmas tree is shown Figure 2.7.43. A solid block christmas tree used for dual completions is shown in Figure 2.7.44 and a sub-sea version is shown in Figure 2.7.45. In comparison with the composite tree, the solid block has less potential leak sources.

8:39 PM

6/7/2007

M A-Mohsen

(40)

COMPLETION

Figure 2.7.43 : Example of a single string solid block christmas tree

7.4.2 CHRISTMAS TREE VALVES Typically from bottom to top, a christmas tree contains the following valves on each production bore:

Lower master valve (LMV) The LMV is a valve utilised on all christmas trees for contingency to the UMV (see below) to shut off well flow in the event of a leaking UMV or the connection between them. It also is used as a barrier in well isolation to allow work or repair in downstream equipment. It should never be used as a working valve. It is normally a manually operated valve, although in moderate to high pressure wells such a valve may be furnished with a valve actuator system for automatic or remote controlled operation (i.e. a part of the surface safety valve system). This is often a regulatory requirement in sour gas or high pressure wells.

8:39 PM

6/7/2007

M A-Mohsen

(41)

COMPLETION

Figure 2.7.44 : Example of an onshore dual string solid block christmas tree

Upper master valve (UMV) The UMV is used on moderate to high pressure wells as an emergency shut-in system. Company policy is that the valve must be capable of cutting at least 7/32 " size braided wireline. The valve can be actuated pneumatically or hydraulically. The UMV valve is a surface safety valve and is normally connected to an emergency shut-down (ESD) system.

Flow wing valve (FWV) The FWV permits the age of well fluids to the choke. This valve can be operated manually or automatically (pneumatic or hydraulic) depending on whether is to be included in the surface safety system design. On moderate to high pressure wells, often two production wing valves are usually installed, one manual and the other equipped with a valve actuator.

Choke valve The choke valve is used to restrict, control or regulate the flow of hydrocarbons to the production facilities. This valve can be operated manually or automatically and may be of a fixed (positive) or an adjustable type valve. It is the only valve on the christmas tree that is designed and used to control flow. All other main valves are invariably gate type valves, although needle valves are used on instrumentation and chemical injection lines.

Kill wing valve The Kill Wing Valve permits entry of kill fluid into the completion string and also for pressure equalisation across tree valves e.g. during wireline operations or prior to the pulling or opening of a sub-surface safety valve. The kill wing valve is usually operated manually.

8:39 PM

6/7/2007

M A-Mohsen

(42)

COMPLETION

Swab valve The Swab Valve permits vertical entry into the well for well servicing such as wireline (slick line and electric line), coiled tubing. It is also used for BPV installation in the tubing hanger. This valve (often referred to as the lubricator valve) is operated manually and is the uppermost valve on the christmas tree.

7.4.3 CHRISTMAS TREE CAP The christmas tree cap provides the connection for vertical well servicing equipment such as a wireline lubricator, injection head and rod BPV lubricator which are installed directly above the swab valve. The christmas tree cap normally has a quick union type connection and is capable of ing the lubricator stresses encountered in well servicing operations. The inside diameter of the cap is compatible with the tree bore and tubing to accommodate the largest size tools which can be run. During normal production, the cap has a plug in situ with a threaded part to accommodate a needle valve pressure gauge. This gauge is used for periodic visual checking of well pressure. The needle valve is used to bleed off trapped pressure above the swab before removing the plug.

7.4.4 INSTRUMENT BLOCK An instrument block or flange is an integral part of christmas tree design; See Figure 2.7.46. This allows the installation of various instrumentation to provide visual indication or continuous electronic monitoring of wellhead data e.g. surface pressures and temperatures.

Figure 2.7.46 : Instrument block

8:39 PM

6/7/2007

M A-Mohsen

(43)

COMPLETION

Artificial lift Natural flow in a well occurs where there is enough reservoir pressure to lift the formation liquids to the surface into the production system. Many reservoirs however cannot sustain such natural flow due to depletion of the reservoir pressure by geological processes or by the extraction of fluids. In other cases it is desirable to improve the economics of a project by increasing production over that which can be obtained by natural flow. In order to maximise the production of hydrocarbons under these circumstances one possibility is to artificially maintain or increase the reservoir pressure by re-injecting produced gas or water, or even water from an outside source. The alternative method of maximising the production rate is to increase the pressure differential between reservoir and bore hole not by increasing the reservoir pressure but by decreasing the borehole pressure. This is done by removing the back pressure exerted on the formation by the column of produced fluids. Energy is supplied at some point in the well, depending on the composition of the fluid and the available pressures, to remove the fluid artificially. Artificial lift encomes gas lift and pumping systems. The systems covered in this Topic are  gas lift  electrical submersible pumping  hydraulic pumping and the thousands of year old method  beam pumping

7.5.1 GAS LIFT INTRODUCTION Gas lift is a process whereby liquids are "lifted" to surface by injecting pressurised gas into the production conduit where it commingles with the produced fluid. This is usually done by gas injection into the tubing from the annulus. It is particularly useful for lifting wells where large volumes of high pressure (non corrosive) gas is available from a nearby well or field. In the absence of an external source of gas a closed system may be used. Gas lift may be continuous or intermittent. The choice of method will depend on the flowing characteristics of the reservoir.

Continuous gas lift Continuous gas lift is an extension of natural flow by supplementing solution gas with pressurised gas injected continuously at a particular point in the production tubing. (The depth of injection will depend on the available injection gas pressure.) The injection gas mixes with the produced well fluids and decreases the flowing pressure gradient of the mixture from the point of gas injection to surface. This has the desired effect of reducing the flowing bottomhole pressure and increasing the rate of inflow from the reservoir. In a continuous gas lift design there is an optimum gas injection rate at which production is maximised; beyond that the higher injection rates increase bottom pressure due to friction losses in the tubing and are counter productive.

Intermittent gas lift In many wells continuous flow cannot be sustained even when the bottom hole pressure has been reduced to the lowest possible pressure, which is the separator pressure of say 20 psi or 150 kPa. This would be the case in very low productivity wells, or high productivity wells with very low reservoir pressures. In these cases intermittent gas lift can be applied. This involves allowing the reservoir fluid to flow into the well against a negligible back pressure (as mentioned this would be the separator pressure) for a certain period and then injecting a relatively large volume of gas for a short period to displace a liquid slug to the surface. When the injected gas has expanded through the separators the cycle begins again. A typical injection cycle would be to

8:39 PM

6/7/2007

M A-Mohsen

(44)

COMPLETION

inject gas for two minutes every half hour to an hour, but the cycle could be as long as once per day, or even longer. Because the well production rate is by definition very low, and the cost of installing compressors plus a high pressure gas line system is high, an intermittent gas lift system is normally only a economic proposition if gas at a sufficient pressure is available from an external source. There is also the physical problem that compressor output is continuous whereas the consumption is not. There are however two situations when it would become attractive even without an external source of gas:  If the majority of wells in a field are being produced using a continuous gas lift system the marginal producers can be intermittently lifted at little incremental cost.  If a very large number of wells can be included in the system so that the cumulative production is sufficient to "pay for" the compressors, plus the necessary operating costs.

THE GAS LIFT SYSTEM The most widely used type of gas lift system is one in which lift gas is injected from the casing/tubing annulus into the production conduit. Figure 2.7.47 shows an example of a gas lift system.

Figure 2.7.47 : Example of gas lift system

The requirements for such a system are: Gas lift valves These provide down-hole control of the rate of injection and the timing. They can be fitted with a range of orifice sizes to govern the injection rate. The bellows pressure can be regulated to govern the pressure differentials at which the valve opens and closes. A typical valve is shown in Figure 2.7.48. Side pocket mandrels these are run as part of the completion string - see Topic 7.2.4. Gas lift valves (GLVs) can be installed into and retrieved from them by wireline methods utilising a kickover tool system. GLV depths and injection pressures must be carefully calculated and planned. these are installed on surface to provide control for pressure regulation, injection Surface control devices volume and timing. Separation system to separate gas from produced liquids and provide liquid and gas metering. The production flowline to the separator must have minimum restriction, i.e. no chokes and the separator back pressure must be as low as possible. to take gas at separator pressure and supply it at the required injection pressure. Compressor In other words to add the required energy to the system.

8:39 PM

6/7/2007

M A-Mohsen

(45)

COMPLETION

CONTINUOUS FLOW GAS LIFT During the naturally producing life of an oil well, the side pocket mandrels installed in the completion string will contain dummy gas lift valves. When required, these will be retrieved and replaced with functional gas lift valves. The required setting depths and opening/closing pressures of these valves can be determined when the following information is known:  Surface casing injection gas pressure  Gradient of injection gas in casing  Gradient of produced liquid  Gradient of produced liquid/injection gas mixture  Reservoir pressure  Well P.I.  Wellhead pressure This information is thus essential during the design of the completion in order to place the side pocket mandrels at the correct depths. When the gas lift valves are installed in the side pocket mandrels, some type of completion fluid (usually brine) will fill the tubing and the annulus. This completion fluid will need to be removed, i.e. unloaded, before liquids can flow from the formation. Figure 2.7.48 : A typical gas lift valve Figure 2.7.49 shows an example of an unloading sequence from a continuous gas lift installation provided by four gas lift valves.

Gas is injected into the annulus at surface and displaces liquid through each valve in turn until the liquid level in the annulus reaches the valve. When the valve is "uncovered" it will then gas into the tubing to assist the lifting process. The system is normally designed in such a way that as the second valve is uncovered the first closes, and as the third is uncovered the second closes, etc. Unloading in a properly designed gas lift installation should be an automatic process in which all valves above the operating valve should be closed and all valves below should be open. This process will continue until the situation occurs where the formation will deliver liquids into the well bore at the same rate as liquids are being lifted up the tubing and the well then stabilises. After the well has unloaded, the production rate will be governed by the size of the orifice in the operating valve .

INTERMITTENT FLOW GAS LIFT In intermittent lift, gas is injected very rapidly into the tubing to form a gas column under a liquid slug that then expands and lifts the slug to the surface. In a field operation, gas will be injected into the tubing for a short period of time several times a day. Unloading a well which is to be lifted intermittently, is very similar to that for continuous

8:39 PM

6/7/2007

M A-Mohsen

(46)

COMPLETION

lift. The only difference is that when a valve is uncovered, a liquid slug is moved to surface by expansion of a gas bubble below the slug. This process continues until the bottom valve is uncovered - see Figure 2.7.50. This system requires a standing valve at the bottom of the tubing to prevent the pressure in the gas column being transmitted down to the producing interval.

Figure 2.7.50 : Unloading sequence - intermittent gas lift

Gas lift valves above the operating valves are designed to stay closed unless there is a liquid slug in the tubing above the valve. Figure 2.7.51 shows the operating cycle of an intermittent gas lift installation. With the surface controller closed, formation liquid enters the well bore and rises in the tubing

Figure 2.7.51 : Intermittent lift cycle of operation for a conventional closed installation

8:39 PM

6/7/2007

M A-Mohsen

(47)

COMPLETION

CHAMBER LIFT One of the disadvantages of intermittent lift as described above and shown in Figure 2.7.51 is that the oil column rises to its equilibrium level inside the tubing. The volume which is expelled during each injection cycle is thus limited by the tubing diameter. Furthermore the tubing used in intermittent lift has normally a relatively small diameter so that the flow regime during the lifting period is optimised - i.e. fallback is minimised. An alternative type of intermittent lift is called chamber lift. In this process a larger diameter section (the chamber) is installed at the lower end of the tubing, and the latter is extended into the chamber by means of a so-called "dip tube" with no direct connection between the top of the chamber and the inside of the tubing (apart from a very small breather hole). The inflow for a given drawdown is thus maximised. The operating gas lift valve injects gas into the top of the chamber, forcing the liquid to flow downwards in the chamber and enter the tubing via the dip tube. This ensures that the slug of liquid already has a considerable velocity before the gas starts following it up the tubing, minimising gas breakthrough.

7.5.2 ELECTRICAL SUBMERSIBLE PUMPS INTRODUCTION Even in wells where natural well pressure is sufficient to generate good early production, many wells will still have a need for artificial lift as they mature. Whenever development plans are raised for a single well, platform or an entire field, the inclusion of artificial lift including electric submersible pumps (ESPs) may be considered and catered for in the final plans. This practice, although involving higher initial development costs will bring significant future cost savings. The main advantage of an ESP system over gas lift and hydraulic pumps is the avoidance of bulky, costly topside facilities (capex). Other advantages are the higher efficiency and the ability to handle higher rates. The disadvantage is the higher workover costs (opex) if the run times are short. ESP developments in the early days were hindered by the unreliability of the system - short pump life or cable insulation breakdown - but improvements in materials technology have enormously increased performance, durability and reliability. The reliability is still however very much a function of the type of completion and run times may still vary from six months to ten years. High temperatures and high horsepowers make it more difficult to achieve the long end of this range. Although improvements have been made, it is some Shell operating units' view that they are still not reliable enough for sub-sea completions where workover costs are very high. An assessment of the viability of any particular system will require an economic life cycle evaluation.

EQUIPMENT DESCRIPTION ESPs may be run on coiled tubing or cable, but the most common system uses tubing. The following paragraphs relate to a tubing conveyed type system only, as shown diagramatically in Figure 2.7.52. Cable There are two basic cable types used in all ESP installations. The motor lead extension (MLE) runs between the pump and the top of the packer. It has a flat configuration and includes the connection into the motor which is called the pot head. The main power cable extends from the connector above the packer to the connector below the tubing hanger. A range of cable types and sizes are produced with a typical cable O.D. of 1·25". Both types of cable have copper conductors that are covered with various layers of insulation and protection, of which the outer layer is galvanised Figure 2.7.52 : Schematic of an ESP completion steel or monel armour.

8:39 PM

6/7/2007

M A-Mohsen

(48)

COMPLETION

If cables are damaged this is mostly caused by:  hanging up on BOPs or tie-backs on the way in  crushing/pinching on the run in especially on highly deviated wells  rapid decompression after pressure testing, or  pulling out of the hole too fast or. Penetrators Penetrators form an integral part of the cable system and are the means of connecting the cable through pressure barriers such as packers, tubing hangers and any other such device, maintaining pressure integrity. 'Y' tools A Y-Tool is a tool which enables well servicing or pressure surveys to be conducted below the ESP - see Figure 2.7.53. The tool is actually an upside-down Y and allows vertical access through one lower leg of the Y while the other leg is the production path. The access is only available when a plug is pulled out of the base of the tool. Without the plug, the pump fluid would circulate around in a loop. The nipple used for the wireline plug is also used for hanging off gauges. The access can also be used to carry out perforating work and will allow coiled tubing for stimulation operations, etc. Figure 2.7.53 : 'Y' tool

Pumps, intakes and gas separators The pump section, illustrated in Figure 2.7.54, is a multi-stage centrifugal type, incorporating either radial or mixed flow type impellers, depending on the flow rate required. Each impeller is designed for a particular capacity range and the number of stages is determined by the head required. Capacity ranges of 80-100,000 bpd are available, and a total dynamic head of up to 14,000 ft. are possible.

Figure 2.7.54 : ESP pump

Protectors The protector is the next component and provides a motor oil reservoir, pressure equalisation and isolation between motor fluid and well fluid. The one shown in Figure 2.7.55 is fitted with a thrust bearing to take the axial loads of the pump shaft, although that is normally provided for in the pump itself. There are two main types of isolation - positive seal and labyrinth.

8:39 PM

6/7/2007

M A-Mohsen

(49)

COMPLETION Figure 2.7.55 : Protector

The positive seal type (bag type) provides isolation by a flexible neoprene diaphragm that expands and contracts with pressure and temperature differences. The labyrinth type is the original type of protector and has been used for over fifty years and is still used in hotter applications today where neoprene may deteriorate prematurely. The isolation here is provided by two chambers connected by small diameter tubes. The well fluid and motor fluid move in and out of the upper chamber as pressure and temperature changes demand. A combined system can be used in more difficult applications such as high deviation wells; in critical situations two protectors can also be used in tandem.

Motors The motor is the rotary power force which turns the pump . ESP motors are two pole, three phase squirrel cage induction type motors. They are filled with a highly refined mineral oil that provides high dielectric strength, lubrication for bearings and thermal conductivity. The thrust bearings carry the load of the motor rotors. The heat generated by the motor is transferred to the motor housing by the oil which in turn conducts it to the well fluids ing the exterior surface of the motor. Therefore, adequate fluid flow past the motor is of critical importance. Motors are available in many different sizes and ratings. The horsepower requirements are largely determined by the required pump throughput and head.

Pressure, temperature and flow Instruments Integral motor pressure and temperature sensing devices are available from most submersible pump manufacturers. These sensors transmit a DC signal through the main power cable and thereby eliminate the need for a separate instrument cable. Figure 2.7.56 : A motor

Also available are proprietary sensors using separate instrument cables. These separate cables have to through the packer and this can be achieved with a pressure transmitting capillary or another cable, space permitting. Turbine and venturi flow meters can also be installed in the discharge of the pump which can either be permanently installed or run on wireline.

FUTURE ESP DEVELOPMENTS ESPs for subsea completions These could significantly increase the production obtainable from subsea satellite and template wells, and developments are currently being undertaken to develop wellhead designs, power transmission and handling equipment for installation. The first subsea well ESP system completion was installed by Petrobras in 1993.

8:39 PM

6/7/2007

M A-Mohsen

(50)

COMPLETION

Cable suspended ESPs These are being developed to reduce the costs of installation and retrieval of the ESP unit. A conventional ESP uses a tubing suspended pump set, which requires a full workover rig to handle the tubing. A cable suspended ESP would simply locate into a deep set packer and produce up the annulus, hence no tubing handling would be necessary during the installation or retrieval process. This should greatly increase the speed of the workover, reduce the equipment and personnel required and correspondingly reduce cost.

Coiled tubing deployed systems These are being developed by a number of companies and potentially have similar advantages to cable suspended types

7.5.3 HYDRAULIC PUMPING SYSTEMS Until recently the most common and available methods of artificial lift for high flow rate applications have been gas lift and electrical submersible pumps. Hydraulic jet pumping systems using a downhole jet pump have also been used successfully for many years on low flow rate wells and downhole hydraulic turbine pump systems are a more recent development marketed as an alternative to ESP systems.

JET PUMP SYSTEM Hydraulic jet pumping systems use the venturi effect for providing lift energy. A power fluid is pumped down either the tubing or the annulus and is directed through a nozzle in the jet pump. The venturi effect of the fluid ing through the nozzle draws the production fluids from below the pump into the flow stream. The jet pump is generally installed by wireline and set into an SSD or ported nipple which provides the circulation path for the fluids. Although the great benefit of this type of pump is that it has no moving parts, it still suffers from flow erosion and, hence it is desirable to have it retrievable by wireline methods. The configuration of pumps for forward or reverse circulation is shown in Figure 2.7.57. The ratio of well fluid to power fluid required is dependent upon the required flow rate and head. Because the produced fluids and the power fluid are commingled in the production conduit this system is really only viable in two cases:  if the produced crude is suitable for recirculation as power fluid after separating out the gas and any produced water  if a field contains two (or more) reservoirs with different crude characteristics. For instance the produced fluid from a shallow viscous oil reservoir could be jet pumped by using light crude produced from a deeper reservoir. Figure 2.7.57 : Typical Jet Pump System

A new application for the jet pump is its use with coiled tubing for the clean out of completed horizontal well sections which do not clean up naturally. This problem is usually associated with the tail end of horizontal wells where the differential pressure is too small to provide the energy required, which may be confirmed from logging surveys. A jet pump is run on coiled tubing with two resettable packers, the packers are set across the target zone and, by pumping fluid down the coiled tubing, the fluids are drawn from the formation between the packers up into the flow stream. This allows the formation fluids to expel any impeding solids or blocking fluids. The packers are then unseated and moved to the next section and the process repeated until all zones have been cleaned up.

8:39 PM

6/7/2007

M A-Mohsen

(51)

COMPLETION

DOWNHOLE HYDRAULIC TURBINE PUMP SYSTEMS The manufacturers of these systems developed them in the belief that the hydraulic pump systems would be more reliable than comparable ESP systems with their inherent problems associated with electric power transmission and motor systems. In actual fact the reliability of ESP systems has significantly improved over recent years so that they effectively compete with hydraulic pumps, and it is true to say that ESP systems may be preferred to hydraulic pump systems because of the simpler surface handling systems required. ESPs also operate more efficiently as hydraulic pump systems must move the power fluid as well as the produced fluids. The advantages of hydraulic pump are  lightweight construction  ease of installation  ability to operate under unstable flowing conditions  ability to cope with high GOR  ability to work with high viscosity crudes (given access to a low viscosity crude to use as power fluid). The system consists of a downhole hydraulic pump and surface power plant. The downhole pump is a turbine system driven by power fluid pumped down the tubing from the surface plant. Just as for the jet pump, the produced and power fluids are normally commingled in the production conduit. Unlike the jet pump however, the possibility does exist of keeping the streams separate by installing an additional string of tubing connected to the turbine discharge. In this way a closed circuit power fluid system could be used. The complication and additional cost would however mean that that would only be economic under very exceptional circumstances.

PUMP CONSTRUCTION The pump consists of two elements - the turbine and hydraulic pump. They are coupled together into the pump set by a coupling housing. The turbine drive shaft and pump shafts are coupled together with a solid coupler. Turbine The turbine is the power producing section of the pump and contains a balance drum, hydrostatic thrust bearing and a start up thrust bearing contained in a stainless steel housing. Pump The pump section comprises the necessary hydraulic components, these being the impellers, chambers, ring sections and diffs, and a balance drum all housed in a stainless steel casing. In order to prolong the life of the pump, the bearings are lubricated by the power fluid and not exposed to the produced fluid which is an advantage over ESPs. Figure 2.7.58 : Hydraulic turbine pump

7.5.4 BEAM PUMPING The most common method of artificial lift on land is the beam (or rod) pump system. Beam pumping systems essentially consist of a surface unit, a sucker rod string and a sub-surface pump. The reciprocating motion produced by the surface unit is transmitted by the rods to the pump.

8:39 PM

6/7/2007

M A-Mohsen

(52)

COMPLETION

Figure 2.7.59 : Typical beam pumping system

SURFACE UNIT The surface pump unit consists of a prime mover (either an electric motor or a diesel engine), a speed reducer (gears), a crank arm, metal arms (pitmans), horsehead and bridle. The prime mover, through the speed reducer, turns the crank arms which move the pitmans in a vertical reciprocating motion. This motion is transferred to the sucker rods via the horsehead and the bridle. In a field with many wells in a relatively small (uninhabited) area it is a common practice to utilise a single, central, prime mover to pump a large number of wells. The prime mover drives one or more horizontal eccentrics to which are attached reciprocating cables or sucker rods running cross-country to the individual wells. At each wellhead the motion is converted from horizontal to vertical by a simple crank mechanism.

SUCKER RODS Sucker rods are usually 8 metres (25 ft) long and are manufactured from solid high-grade steel with special couplings. The latter are shown in Figure 2.7.60. The first sucker rod t which hangs from the Bridle is termed the "polished" rod. A set of packing in a stuffing box on the wellhead seals against the polished area on the rod. Fibreglass sucker rods are also available for light service applications.

Figure 2.7.60 : Sucker rod connector

8:39 PM

6/7/2007

M A-Mohsen

(53)

COMPLETION

DOWNHOLE PUMP The basic elements of a sub-surface pump are a barrel, plunger, standing valve and travelling valve - see Figure 2.7.61. As the rod string is moved up and down by the surface unit, the plunger moves up and down inside the barrel. As the plunger moves upwards, the ball in the travelling valve is forced on-seat so that the plunger lifts the fluid above it, transferring the liquid load to the sucker rods. Simultaneously, the ball in the standing valve is lifted off-seat by the influx of formation fluid into the barrel from below the standing valve. On the downstroke of the plunger, the travelling valve opens, the standing valve closes to the fluid column and the plunger moves down through the well liquids. Repeated reciprocation of the barrel conveys the well liquids to surface. There are three principal types of subsurface pump:  Tubing Installed as part of the completion string. Their advantage is a larger size, but the disadvantage is that a pumps workover is required to replace the pump barrel.  Rod pumps Installed and run on the end of the sucker rod. For the (also called same size of tubing, rod pumps have a smaller capacity insert pumps) than tubing pumps. Figure 2.7.61 : Types of beam pump



Casing pumps This is a larger version of the tubing pump, with a packer attached to the barrel and set in the casing.

WIRELINE TOOLS 7.6.1 INTRODUCTION To install a completion involves the use of many services but the service mostly required is wireline. The wireline referred to here is simply used for running tools into the well and/or pulling them out again; it is usually a single strand of piano wire and is not used for transmitting electrical signals, unlike the conducting cable used by wireline logging service companies. If a distinction has to be made between the two kinds of wireline the one used in production services is usually called "slickline" (because piano wire is smooth) and the logging cable is called "electric wireline". Slickline comes in three standard diameters - 0·072", 0·082" and 0·092". If extra strength is required a multistrand line can be used. This is no longer "slick" and is called a "braided" line. Braided lines can be up to 3/16 " diameter. Wireline tools are used in completions to:  drift tubing  open/close circulation devices  install/remove safety valves  install/remove plugs

8:39 PM

6/7/2007

M A-Mohsen

(54)

COMPLETION

It also used for many tasks when the well is in production such as:  making bottom hole pressure and temperature surveys  making calliper surveys  install/remove gas lift valves and circulating devices  tagging and cleaning out fill or obstructions  removing wax or scale The assembly which is run downhole to perform a specific wireline operation is referred to as the wireline 'tool string'. The tool string is run, retrieved and manipulated by upward and downward movement of the wire which is itself raised and lowered by the wireline winch. The tool string consists of a number of components which are selected according to the operation to be performed. Tool string make-up, therefore, varies for each different type of operation. Wireline operations are conducted with a basic tool string with the necessary service tools attached to the bottom connection. A typical basic wireline tool string is shown in Figure 2.7.62. In addition to the basic tool string, there are a number of standard tools that are used frequently for tubing control and general maintenance work. The exact configuration of the tool string is altered by the operator for the operaion to be performed and in consideration of other factors such as well (height) access, deviation, depth, pressure, completion configuration, well log history, etc. It is essential that an accurate record of the tool string configuration and dimensions are taken prior to running it in the hole as contingency for fishing operations. It must be ensured that the largest fishing neck in the tool string can be fished by a pulling tool within the smallest tubing size of the completion. Figure 2.7.62 : Typical basic Overview of tool string components wireline tool string

ROPE SOCKETS A rope socket provides the means to attach the wireline or braided line to the tool string. There are two types of slickline rope sockets for the different sizes of wireline - tear drop and knot type. The "knot" in a wire line is made by making a very small loop in the wire and wrapping the free end back round the fixed part. In order to avoid putting a kink into the wire at the loop, thus weakening it, the loop is usually made round a small bobbin (shown as "disc" in the figure). The spring is used to reduce shock loading on the line when jarring up, or when the line has been slack in the well and the winch takes the weight when it is already reeling in line at an appreciable rate. For braided lines a different type of rope socket is utilised, as shown in Figure 2.7.64.

Figure 2.7.63 : Rope sockets for slick line

8:39 PM

6/7/2007

Figure 2.7.64 : Rope sockets for braided line

M A-Mohsen

(55)

COMPLETION

WIRELINE STEM Wireline stem or 'sinker bar' is required as part of the wireline tool string to increase its weight to overcome well pressure acting on the wire cross sectional area and to provide inertia when jarring. An increase in stem weight increases the impact force delivered by the jars. The tool string should not however be over-weighted as excessive mass dampens the 'feel' and premature shearing of shear pins may occur. Various stem diameters are available for the range of tubing sizes, normally in two, three and five feet lengths.

HEAVY WEIGHT STEM In applications where greater weight for the same diameter and length is necessary, lead-filled stem is used. This stem has regular steel connections and a tubular steel outer barrel. The inside is filled with lead to provide extra weight. This stem is used primarily for running pressure and temperature survey tools in flowing wells to obtain maximum weight with minimum cross-sectional area, thus reducing the risk of the tools 'floating' or being blown up the hole by pressure differential and fluid friction. Other types of high density, heavy weight stem available include tungsten, uranium and mallory (mercury alloy) filled stem.

ROLLER STEM Roller stem is used for work on deviated wells, or in wells with paraffin, asphaltene, etc. which adheres to the tubing walls. It allows the stem to roll down the tubing wall, thus avoiding the friction incurred when using regular stem.

JARS Jars are a principal component normally included in every tool string except those with delicate gauges used for pressure, temperature and flow rate surveys. Their purpose is to provide an impact force to operate, set and retrieve downhole devices. Wireline has limited pulling capability especially in deviated and deep wells; jars are therefore essential to generate the forces required. If the jars are not being operated correctly or if the jar action is lost then very little force can be exerted on the tools. There are four main types - Spang jars, tubular jars and spring jars, which have a mechanical action, and hydraulic jars. Jars are activated by upward or downward motion imparted by the winch, or by hand if working at shallow depths. It is essential that an operator can recognise the precise opening and closing point of the jars on the wireline unit weight indicator. If working by hand it is easy to feel when the line gains or loses tension as the jars operate.

STRETCH SIMULATORS/ACCELERATORS Figure 2.7.65 Roller Stem

: Stretch

simulators or accelerators, see Figure 2.7.68, are installed in the tool string immediately below the rope socket when spring or hydraulic jars are to be used at shallow depths. The spring replaces the 'stretch' of the wireline which is available when jarring upwards at greater depths. Its function is to reduce the shock loading at the rope socket and cause the stem to 'accelerate' faster when the jars fire. This creates a more effective impact. The device works by applying tension on the wire with the winch whereby the internal spring is compressed. When the jar fires, the spring expands which in turn accelerates the tool string to give more impact. This limits excessive loading on the wireline. In theory it would be a good practice always to utilise this device, but it makes the tool string assembly over complicated.

8:39 PM

6/7/2007

M A-Mohsen

(56)

COMPLETION

7.6.2 TOOLSTRING ACCESSORIES QUICK-LOCK SYSTEM Quick-Lock system tool strings may be used instead of (or in conjunction with) the threaded type tool string. Quick-Lock connections are incorporated into a wide range of equipment. Given that there is no requirement for wrenches when using the system, it is faster to use than threaded connections. It is also stronger and will not accidentally back off. Anotheradvantage of the Quick-Lock connector is that no wrench marks or burrs are caused, which reduces wear and risk of hand injuries. Figure 2.7.69 : Typical Quick-Lock System

KNUCKLE TS Knuckle ts are used to offer a degree of flexibility in the tool string. They incorporate a ball t assembly allowing rotation and some angular movement. During wireline operations in deviated wells, lengthy tool strings require knuckle ts to round bends or kinks. They are also used to allow alignment of pulling tools with devices being retrieved.

KNUCKLE JAR The Wireline knuckle jar is constructed of a special ball and socket design which provides the same flexibility as a knuckle t but additionally has a small stroke for jarring. It is used when only light jarring is necessary and replaces the regular jar. It may be typically run with pressure/temperature gauges in conjunction with a shock absorber or when there is not enough lubricator height available to use regular jars in the tool string.

Figure 2.7.70 : Knuckle t and knuckle jar

8:39 PM

6/7/2007

M A-Mohsen

(57)

COMPLETION

7.6.3 TUBING CONDITIONING TOOLS GAUGE CUTTER It is good wireline practice to run a gauge cutter, shown in Figure 2.7.71, before starting any wireline operation in a well, to check the tubing ID. It is also used to tag TD, locate nipples and to cut sand, scale, paraffin and other deposits from tubing walls. Gauge cutters are also used to determine blockage sizes/profiles by running successively smaller cutters and plotting the depth reached against diameter to establish the shape of the restriction. Figure 2.7.71 : Wireline gauge cutter and lead impression block

LEAD IMPRESSION BLOCK (LIB) Lead impression blocks are used to obtain an image of the top of a fish, which then enables a choice of the appropriate fishing tool to be made. The lead impression block is filled at its lower end with lead which extends below the bottom edge. The LIB is run and set lightly down on the fish and the jars are tapped down softly to obtain an imprint. It should only be tapped once otherwise the imprint will look like a photograph with double exposure.

SWAGE A swaging tool, shown in Figure 2.7.72a, is used to clear minor restrictions caused by light collapse in the tubing string. Although this may allow further wireline operations, the tubing collapse strength will be impaired and further production questionable.

TUBING BROACH The tubing broach, shown in Figure 2.7.72b, can be used to remove a restriction in the tubing, e.g. scale deposits or a minor tubing t collapse caused by connection over torque. The use of a broach, like the use of a swage, will impair subsequent tubing performance.

Figure 2.7.72 : Swaging tool, tubing broach and wire scratcher

8:39 PM

6/7/2007

M A-Mohsen

(58)

COMPLETION

WIRE SCRATCHER A wire scratcher, Figure 2.7.72c, is made from a piece of stem drilled with a series of holes on at 90° intervals. Pieces of braided line or slickline (the length dependent on the tubing ID) are inserted in these holes and locked in place with grub screws. Wire scratchers are usually run on a pulling tool in order that the tool string can be retrieved if the scratcher becomes stuck. They are used to dislodge scale, salt, paraffin etc. from tubing. Wire scratchers can also be used to fish small pieces of wireline lying loose in a well or used to locate nipples, side pocket mandrels, etc.

TUBING END LOCATOR Tubing End Locators, illustrated in Figure 2.7.73, are used to locate the end of the tubing and give a cross reference check of depth when running the completion. They are used also to accurately measure hold up depth (HUD), or plugged back total depth (PBTD) with respect to the bottom of the tubing. They can also be used to position/temperature gauges instead of more expensive electric line correlating equipment. When the tool is run and es out of the tubing, the spring loaded 'finger' trips out to the horizontal position. When pulled back, the bottom of the tubing is indicated by overpull. After repeating the procedure to confirm the depth, a further quick pull into the tubing shears a brass pin and allows the 'finger' to collapse against tool body, permitting retrieval. Figure 2.7.73 : Tubing end locator

7.6.4 RUNNING/PULLING TOOLS Pulling tools are for recovering flow control devices and other items of downhole equipment. Some service companies also use them for running particular downhole tools. The industry has developed a range of standard sizes of external and internal fishing necks which pulling tools engage. Therefore, if a size of, say, a piece of stem is known, then its fishing neck size will also be known. Pulling tools from different manufacturers often have slightly differing designs. For this reason, only compatible tools (from same company as the tool to be run or fished) should be used. However, in practice these small differences normally Figure 2.7.74 :Pulling tools do not affect compatibility; an example is shown in Figure 2.7.74. There are two types of fishing neck, internal and external as described earlier. External fishing necks are used generally on tool strings, running and pulling tools. The advantage of internal fishing necks is that they have larger flow area and, for this reason, are often used on flow control assemblies. Both downhole assemblies and pulling tools are operated by upward or downward jar action. Sometimes combinations of both are used depending on the operation to be performed and the equipment design. The pulling tool is fitted immediately below the Spang jar and the assembled tool is then run to a depth predetermined by the location of the device to be retrieved. Where necessary, a knuckle t can be fitted between the pulling tool and the Spang jar to assist in the latching operation. There is a vast range of both internal and external pulling tools available, too large to be covered in this manual. Typical tools are shown in Figures 2.7.75 and 2.7.76.

8:39 PM

6/7/2007

M A-Mohsen

(59)

COMPLETION

Figure 2.7.75 : External pulling tool

Figure 2.7.76 : Internal pulling tool

COMPLETION PRACTICES This topic covers, briefly, various subjects related to the practices and procedures involved in installing a completion. These are:  General handling/running of tubular components  Tubing string installation  Tubing string pressure testing  Subsurface safety valve installation and testing  Gravel packing  Leak detection  Wireline equipment and procedures.

7.7.1 GENERAL HANDLING/RUNNING OF TUBULAR COMPONENTS Well tubulars are specialised lengths of tubing manufactured to high standards in order to withstand high stresses, pressures and temperatures, often in a corrosive environment, for long periods. Failure to select and install these properly can result in expensive workovers or remedial operations and even loss of the well. In view of the importance of the proper installation of tubulars in a well, strict procedures for the care, handling and running of strings should be closely followed. These procedures cover  Transportation  Site handling  Storage  Running and pulling. Many procedure guides, instructions and recommendations have been published, however, the main source of these is API Report 5C1, "Recommended practice for care and use of casing, tubing and drill pipe".

8:39 PM

6/7/2007

M A-Mohsen

(60)

COMPLETION

Tubulars with connections, especially those with metal-to-metal seals or those supplied in CRA (corrosion resistant alloy) material need special care, which should be strictly adhered to.

MAKE-UP TORQUE Proper torque values must be applied to obtain an optimum stress distribution throughout each thread connection and to ensure a pressure tight seal. Make-up to below the recommended minimum torque can result in leaks and/or t failure. Over-torquing may damage the seals and, when shoulder-to-shoulder connections are used, may result in crimping towards the pipe axis at the inside (restricting the bore) and/or belling outwards at the outside. The make-up torque that is to be applied to a connection should be recommended by the thread manufacturer, perhaps in consultation with the steel mill. The make-up torque value is dependent on the connection type, grade of material, size and weight of tubing. It is not uncommon for a thread manufacturer to recommend a lower torque value for a given size and weight of connection in CRA material than would be applied to a carbon steel grade of tubing of the same yield strength. This is because the higher grades of CRA tubing are more susceptible to galling effects should excess torque be applied. The effect of the type of thread compound to be used must also be considered. It cannot be over-emphasised that the recommendations given by the manufacturers of the thread connection in respect to the torque value and the thread compound must be followed. As tubular size increases in both outside diameter and weight, more care should be taken during handling and running to avoid the risk of damage to the connection threads and sealing faces. By increasing the radial friction and supplying greater loads, the risk of galling is more likely. The power tongs that are to be used should be in good condition, incorporate an integral hydraulic back-up tong and be fitted with dies of a fine tooth design to avoid undue marking of the tubing. The use of reduced hardness dies should be considered when running CRA tubulars. The dies should be regularly inspected and cleaned during running and pulling operations and changed if required. The use of pipe wrenches or rig tongs is not recommended. A reliable and calibrated torque gauge should be used and where possible a computer controlled make-up system whereby the connection make-up can be analysed with respect to number of turns to shoulder points, turns after shouldering and respective torque valves. This ensures that the t is made up correctly and any problem rectified prior to the tubing t being run in the well.

Figure 2.7.77 : Power tongs Figure 2.7.78 Computer controller for power tong make-up system

8:39 PM

6/7/2007

M A-Mohsen

(61)

COMPLETION

DRIFTING THE TUBING When wireline equipment such as landing nipples, circulating devices, etc. are to be run as part of the tubing string, it is essential that it is dimensionally checked to ensure the free age of service tools through the string. The tubing should be drifted on the pipe rack using a 42" (107 cm) long non-metallic API drift. The t should be drifted from the box to the pin end as it prevents damage to the seal surface. On completion of the tubing running programme, the tubing (each section if tapered) must be drifted again using a wireline gauge cutter. For tubulars up to 27/8 " OD drift diameter the drift size is tubing ID less 3/32". For tubulars of 31/2 " OD and over drift diameter the drift is tubing ID less 1/8 ".

HANDLING OF TUBULARS The storage preparation and handling of tubulars is vitally important to ensure that the pipe and its connections are in prime condition for running into the well. Procedures for handling tubulars are provided in both SIEP and Shell local manuals which should be adhered to. These procedures should include the methods of site preparation, cleaning, logging, protection of tube body and thread connection, layering of ts, slinging, drifting, handling from pipe racks to the rig floor, stabbing and connection make-up. They should also cover similar procedures for chrome tubulars. These manuals should also contain procedures for the pulling and retrieval of pipe. These should include the cleaning, logging, rejection criteria, and connection refurbishment.

7.7.2 TUBING STRING INSTALLATION Most completions have the production tubing connected to a packer or liner hanger already installed in the well or alternatively have a retrievable packer requiring to be set at a predetermined depth. Regardless, this results in the tubing length having to be adjusted to cater for the fixed distance between the packer and the tubing hanger system. This adjustment is referred to as 'spacing out'. Spacing out to packers or liner hangers already installed usually entails tagging the packer or liner hanger, marking the pipe at the rig floor then pulling back to adjust the tubing length taking into consideration tubing movement, distance from rig floor to tubing hanger hang off point and length of the hanger assembly. To allow accurate spacing out, a range of pup ts lengths must be provided. When running retrievable packers, a GR/CCL electric log is run to enable the string to be set at the correct depth by tying in to a marker in the casing or formation gamma ray profile. A unique marker must also be placed in the tubing string, such as a short pup, wireline nipple or RA sub. After determining the depth of the marker in the string relative to the marker in the formation the position of the string can be adjusted before setting the packer. In most cases there is sufficient tolerance in the position of retrievable packers for spacing out using pup ts not to be necessary.

7.7.3 TUBING STRING PRESSURE TESTING The procedures for pressure testing when running the completion string and/or after it has been landed, is dependent upon the type of completion design, producing conditions, well location, e.g. high pressure gas wells or low pressure oil wells, corrosive or non-corrosive, offshore or onshore, etc. Usually tubing strings will have a wireline nipple located near the bottom into which a standing valve will be run. In many cases, the standing valve will be installed at surface and left in place to allow testing as it reaches predetermined depths until the tubing is landed, after which it is retrieved. In monobore completions without nipples, retrievable bridge plugs are used. The magnitude and duration of pressure tests should be detailed in the well programme. The use of high quality connections that undergo strict quality checks prior to dispatch will reduce the risks of tubing leaks (refer to Topic 7.7.1).

8:39 PM

6/7/2007

M A-Mohsen

(62)

COMPLETION

The alternative to testing the entire string is to test each tubing connection with an internal or external tubing tester. These use packing elements to seal above and below each connection after it is made up creating an annular space into which water (or sometimes gas with the internal tester) is pumped to test the connection seal. Originally the external method was preferred since it had distinct advantages over the internal methods;  it was far less time consuming because the tester was clamped around the t like a power tong, whereas the internal tester is operated by wireline techniques  it used less hydraulic fluid for testing Most operating companies have forgone these time consuming tubing connection testing methods.

7.7.4 SCSSSV INSTALLATION AND TESTING Each type of SCSSSV should have a manufacturer's installation and testing procedure unique to that particular valve. These procedures should be incorporated into the well programme and carried out during the completion installation.

PRE COMPLETION TESTING On deck, each valve should be connected to a hydraulic supply to check its operation. The valve should then have a body pressure test and a test below the valve mechanism.

INSTALLATION PROCEDURES TRSVs are installed in the tubing string and are run to depth with the valve held open by hydraulic pressure trapped in the control line. After spacing out, pressure testing and connection to the tubing hanger, the valve is usually held open by a temporary hold open tool to prevent pressure locking below the valve when stinging into packers or liner hangers. Once landed, control of the valve is achieved by the control system through the hanger porting, after which the hold open tool can be retrieved. If running a WRSV, only the wireline landing nipple is installed in the string. To allow pressure testing, a dummy valve is installed which enables pressure testing of the tubing and control line. After landing of the completion, the dummy valve is retrieved and the WRSV installed.

POST COMPLETION LEAK-OFF TESTING Routine leak-off tests should be performed on all SCSSSVs, the first being prior to production start up. A leakoff test will ensure that leakage rate of well fluids past the valve are within the criteria specified by company policy or API specification. The policy usually specifies regular frequency testing at 6 monthly intervals. To conduct the leak-off test, the pressure above the SCSSSV must be bled down to provide a known differential pressure across the valve. The well is left for a fixed time and the pressure above the valve recorded. The rise in pressure, in conjunction with the known original pressure, GOR and volume between the valve and christmas tree can be used in a calculation to determine the leak-off rate. By maintaining records it will be seen when a valve's performance has declined to the point where well safety is jeopardised and remedial operations are necessary. Each facility should have written test procedures with calculated leak off rates for each well. If an SCSSSV fails a leak-off test, the safety valve should be equalised, the valve cycled open then closed, and the leak-off test repeated. If the SCSSSV again fails the test, the only option will be to replace the valve or, in case of TRSV, install an insert valve.

7.7.5 GRAVEL PACKING Gravel emplacement in a gravel pack completion is one of the most difficult completion practices to be carried out. First the gravel pack assembly is run and installed in the casing on a combined setting tool/crossover tool which sets the packers; see Figure 2.7.83.

8:39 PM

6/7/2007

M A-Mohsen

(63)

COMPLETION

Following this, the gravel must be placed behind the gravel screen. This is achieved by carrying the gravel suspended in a carrying agent or slurry and pumping it down the tubing and through the crossover tool to behind the screen. As the slurry es through the screen to return up the washing pipe and annulus via the crossover tool, the gravel is sieved out and deposited behind the screen; see Figure 2.7.84. As the gravel is deposited, pressure builds up behind the screen forcing the gravel out into the perforations. When the screen is fully covered the pump pressure rises quickly indicating 'sand out'. When sand out occurs, the crossover tool is moved to the reversing position to circulate out the excess gravel; see Figure 2.7.85. Following this, the work string is retrieved and the completion run - Figure 2.7.86. The main challenges of gravel packing are to obtain a slurry design which has necessary properties to carry the gravel but be non damaging to the formation and to obtain good fluid cleanliness levels.

7.7.6 LEAK DETECTION After a completion is installed leaks may be found, or they may develop later when the well is in production. Leaks are generally detected by the observation of pressure on one side of the tubing while applying test pressure on the other. In production mode, leaks are generally indicated by the continual presence of pressure on the annulus. Before remedial operations can be planned, it is necessary to find the location of the leak, e.g. packer, tubing, safety valve, hanger, etc. The normal method of leak detection is to install a wireline plug in a landing nipple and, applying tubing or perhaps casing pressure, to determine whether the leak is above or below the plug. The procedure is repeated using the available landing nipples until the position of the leak is narrowed down to the section of tubing between two nipples. Nipples are usually strategically placed in a string for such a procedure refer to Topic 7.2.5. Once it is narrowed down to a particular section of tubing, packer, etc., then this is usually sufficient to determine the remedial procedure and equipment required. However, if it is necessary to determine the exact depth of a leak then another method would have to be employed. Generally, nowadays, a resettable packer would be run on either wireline or coiled tubing and moved up or down the hole while applying pressure as before until the leak point is found. An earlier, cruder, method was to run a 'pony's tail' on wireline. A pony's tail is a piece of unravelled rope or string which is tied to a wireline stem and run in the well while circulating the leak at as high an rate as possible. The rope is sucked into the leak as it es and the tool string loses weight, indicating the leak depth. A more sophisticated method is to run a sonic tool on electronic line and 'listen' for the leak.

7.7.7 WIRELINE EQUIPMENT AND PROCEDURES The different types of wire line and the tools which are used on a "mechanical" wire line were described in Topic 7.6. These tools are run in and pulled out of the well attached to the end of a wire fed from the drum on the wireline winch. The force required to run the tools into the well is supplied by gravity; wireline is thus of limited use in high angle or horizontal wells. The force required to retrieve the tools is provided by a hydraulic power pack (electric or diesel driven) through a gear box to the wireline drum. The power pack is often remote from the winch to aid shipping and positioning when there is limited space such as on a platform wellhead deck. Figure 2.7.87 illustrates a typical equipment layout for wireline operations on a land location. The layout for offshore locations varies due to the wellhead and wireline unit deck levels,but in essence is very similar. The equipment requirements also differ due to offshore locations usually having lifting facilities in the way of a rig or a mast, whereas a land unit would require the use of a crane or gin pole.

8:39 PM

6/7/2007

M A-Mohsen

(64)

COMPLETION

Figure 2.7.87 : Typical wireline rig-up

Wireline units must be adequately anchored to prevent movement caused by the loads on the wireline; even the heavier skid mounted and tmck mounted types must be securely anchored regardless of the operation being performed.

LUBRICATOR SYSTEM For the introduction of the tools (known as "lubricating") into or out of the well a lubricator system is employed which consists of an adapter, for connection to the christmas tree, a BOP for pressure control in the event of leak, sufficient lubricator sections to accommodate the length of the tool string to be run, and a stuffing box to seal around the wire. Additionally there may be a tool trap just above the BOP, a wireline clamp and, if the lubricator is under pressure, a high pressure control head. A typical installation is shown in Figure 2.7.88 and the component parts are described on a separate page.

Figure 2.7.88 : The components of a lubricator set-up.

8:39 PM

6/7/2007

M A-Mohsen

(65)

COMPLETION

To install a tool string, the christmas tree swab and upper master valves are closed, the lubricatordisconnected from the BOPs and the tools pulled up into the bore of the lubricator with the winch. The wire line is then made fast in the clamp in order to take the tension out of the wireline while the lubricator is being manoeuvred back over the BOPs and reconnected. The lubricator is then pressure tested, and the upper master and swab valves are opened. The wireline is tensioned by the winch, the clamp released, and the tools are run into the well bore to conduct the specific wireline operation. To retrieve the tools, they are pulled back into the lubricator, the swab and upper master valves are closed and the pressure bled off the lubricator. The line is made fast in the clamp and the lubricator is disconnected from the BOPs to retrieve the tools. The tool trap is a type of one-way valve for the tools and has to be manually opened to allow them to down. Its advantage is that when the tools have reached the lubricator during retrieval they cannot drop back down the well again. This is especially useful during fishing operations when the fishing tool may have an insecure grip on the fish - as the tool string is pulled into the lubricator even a slight impact of the rope socket against the stuffing box may cause the fish to drop free.

TOOL STRING MANIPULATION The wireline unit contains a weight indicator and depth counter for the accurate and efficient manipulation of tool strings. The operator must be able to run, position and manipulate the jars efficiently to successfully accomplish tool operations. Manipulation of mechanical jars requires fast acceleration of the wire by using the power of the motor and high gear speeds. Due to these factors and the relatively low tensile strength of the wireline, there is a high risk of wire breakage when jarring in shallow wells. In deeper wells the elasticity of the wire gives it more capacity to absorb shock loading. Some operations may only require simple running and pulling out of the hole while others, such as installing gas lift valves, require multiple upwards and downwards manipulation of the wireline before the task is achieved.

WIRELINE FISHING Due to the nature of wireline, it is not uncommon for wire to break or be cut through overpull or inadvertent closure of a valve respectively. When this occurs, the wire is pulled back or ejected out of the well by pressure. The wire and tool string left in the hole is referred to as the "fish", the same term as used in drilling operations. Fishing with wireline for a wireline fish is often a difficult task. If the wire parted because the tool string was stuck the best method is to try to break it again at the rope socket so that the wire can be recovered first. This can be done by running a length of stem with as high a velocity as possible so that when it hits the fish the original line is bent over at the top of the rope socket and cut by the impact. If the wire itself has been recovered but the tool string is left in the hole this can be caught by the fishing neck, but additional lubricator length is required to accommodate both the fishing tool string and the fish. It may also be necessary to use stronger braided line if the weights and combined drag exceeds the capability of the slickline. Before fishing operations are started, they must be thoroughly planned and programmed to cover all contingencies. Even with sound planning it is not uncommon for the situation to be made worse with fishing tool strings becoming stuck and stacking up. For exceptional heavy duty fishing operations, heavy duty units and tools are available.

WIRELINE RIG UP AND PRESSURE TESTING All wireline pressure containing equipment is tested at regular intervals for condition and fitness. It is also tested at the well site before use.

8:39 PM

6/7/2007

M A-Mohsen

(66)

COMPLETION

WIRELINE BOPS The wireline BOPs are an intrinsic part of a lubricator system and are a safety device for closing on the wireline in the event of a leak developing above them. When the leak has been repaired, the pressure is equalised via a valve in the BOP and the rams opened to recommence operations. BOPs for use with braided or electric line cables may have up to three sets of rams, i.e. two sealing rams and one set of shear/blind rams. To initiate a seal on cable, the two sets of sealing rams (the upper being inverted) are closed and grease is injected between them at a pressure slightly higher than well pressure creating a "grease seal". For a slick line, BOPs may have one or, more likely, two sets of rams. The rams are blind type rams which can seal either around the wire or without wire. These BOPs are also used to help in fishing operations in that they can be closed on wire which has been fished and pulled back into the lubricator. The BOPs are closed on the wire to hold the fish below and allow the original wire to be re-threaded back to the wireline winch. It may also be used when fished wire has been doubled over to "strip" out the doubled up ends and find the end connected to the tools. Many operators do not, however, condone this practice today as there is a risk of injury to personnel conducting the stripping.

STUFFING BOX The stuffing box provides a seal around the wire where it es through the top of the lubricator. It has a set of packings through which the wire is threaded. The packings are squeezed by a nut to press against the wire and the packing housing, forming a seal. The packings should only be energised sufficiently enough to form the seal otherwise excess friction may be produced, preventing the tools from entering the well and causing premature wear to the packings. In a well with a high tubing head pressure the stuffing box will be replaced by a control head as shown in Figure 2.7.88. This has nipples for injecting grease at high pressure to form the seal. The stuffing box/control head also incorporates a sheave which directs the path of the wire leaving the lubricator down to the sheave attached to the tree (which is referred to as the "hay pulley" - see below). The stuffing box sheave has a guard to keep the wireline in the sheave groove and is contoured such that, if the wire breaks at surface, between the winch and stuffing box, it may be caught by the guard.

HAY PULLEY The hay pulley directs the wire from the wireline drum up to the stuffing box. This arrangement is exceedingly important as it takes the horizontal forces generated by the wireline winch and prevents side loading on the lubricator. The Hay pulley is attached to the tree by hooking it onto a chain wrapped around the latter. When working with downhole wireline tools, as opposed to simple pressure and/or temperature surveys, a weight indicator sensor will be positioned between the Hay pulley and the chain to give the operator a better idea of what is happening down hole. If the weight indicator is being used, the Hay pulley must turn the wireline through 90° as the indicators are calibrated for that situation. Even without a weight indicator the Hay pulley gives a visual indication to the wireline operator when tool weight is being gained or lost as it moves up or down (respectively) under the influence of the tension in the wire.

8:39 PM

6/7/2007

M A-Mohsen