well completion techniques

WELL COMPLETION

Open hole or "barefoot" completions

thick reservoir sections relatively competent rock type, the oldest form of well completion final drilling of the pay zone is done with special nondamaging drilling fluids or an underbalanced mud column

Advantages

Entire pay zone is open to the wellbore; No perforating expense; Log interpretation is not critical as entire interval is open to

flow; Drawdown reduced because of the large inflow area; Slightly reduced casing cost; Well can be easily deepened; Can be easily converted to a liner or perforated casing

completion; No cementation, so no risk of formation damage

DISADVANTAGES/LIMITATIONS

Excessive gas-oil and/or water-oil ratios cannot normally be controlled (except in the case of bottom water)

Casing may need to be set before the pay is drilled or logged;

Well control during the completion is difficult Not acceptable for layered formations consisting of

separate reservoirs with incompatible fluid properties; Separate zones within the completion interval cannot be

selectively stimulated Will require frequent clean-outs if the producing sands are

not completely competent

Screen and liner completion

To overcome the problems of collapsing sands plugging the production system, producers placed slotted pipe or screens across the openhole section acting as a downhole sand filterThe use of uncemented liners as a method of sand control remains popular today in some areas

Simplest and oldest form, Slotted pipe is run into the openhole. The slots are cut small enough that the produced sands

bridge off on the opening rather than passing through. For very fine sands, the slots cannot be cut small enough so wire-wrapped screen or sintered bronze is used.

Technique is a reasonably effective sand control method in uniform coarse sands with little or no fine particles. Sometimes this is the only sand control system that can be used, because of pressure loss and placement considerations

ADVATAGES

No formation damage due to completion work, No perforation required, Log interpretation is not critical, Easy to control sand production, Adaptable to other special technique to control

sand, Cleanout problem can be avoided, Deepening of the well can be accomplished easily.

DISADANTAGES

Sand movement into the wellbore tends to cause permeability impairment by the intermixing of sand sizes, and of sand and shale particles;

Fine formation sands tend to plug the slots or the screen;

At high rates, the screen often erodes as formation sand moves into the wellbore;

Poor support of the formation can cause shale layers to collapse and plug the slots or the screen;

Formation failure can cause the liner itself to colla

Perforated Completions

With liner Normal casing

most commoncommunication with formationto create a clean conduitwell control is easier completion costs reduced

Using depth control techniques, decide precisely which sections of pay should be perforated and opened to flow, to avoid undesired fluids (gas, water),

Dependent on a good cementation, adequate perforating, allows a single wellbore to produce several separate reservoirs

Done by setting isolating packers within an unperforated section,

Selective perforation can also be used to control the flow from, or stimulation of, various parts of the pay.

ADVANTAGES

Safer operations Better informed selection of the zones to be

completed Reduced sensitivity to drilling damage Facilitation of selective stimulation Possibility of multizone completions Easier planning of completion operations

disadvantages:

Wellbore diameter through pay zone is restricted specially for liner completion

Log interpretation is critical, Good quality liner cement job is difficult to

obtain Additional costs are involved due to perforation

work, additional cement work and rig time Formation damage caused by cementing and

perforation work

Perforated Liner Completion

Completions for pumping wells

ROD PUMPING: Generally completed with an open annulus The gas is bled off at the surface. All pumping systems (except plunger lift) become inefficient in the presence of gas.

Failure to anchor the tubing in rod pumping installations decreases the efficiency of the pump because of tubing stretch, can result in rod or tubing wear because of buckling

Tubing anchor may not be necessary where clearances between casing and tubing are small

Recommended for deeper wells Shallow wells are not equipped with tubing

anchors

Submersible Pump well

SUBMERSIBLE PUMPING Casing size is a critical limit The downhole configuration provides adequate cooling of the pump motor with production Exstreme care should be taken to protect the electrical cable that carries power to the pump.

Hydraulic Pumping

HYDRAULIC PUMPING A number of tubing configurations are used Single string, dual-string, multi-string To handle power oil and produced fluids, to separate gas, To isolate casing from corrosion Most common is the casing-free pump Tubing is used for power oil supply Produced fluids are lifted up the annulus. Pump installation requires a packer to isolate the production interval.

Plunger lift pumping

PLUNGER LIFT PUMPING Installed easily into open-ended tubing An open annulus is required to store gas energy to operate the plunger

GAS LIFT High pressure gas is injected in casing Gas is fed into the tubing through valves installed on mandrels on the tubing string. Hydrostatic head is lowered Flow of oil to the surface is assisted by gas

SINGLE-STRING FLOWING WELL COMPLETION

Casing and tubing flow Casing flow Tubing flow

CASING AND TUBING FLOW WITH PROVISION OF ONLY CASING FLOW

Flow is up both the casing and tubing string. Flow potential is lower than possible via unrestricted casing flow but capability still exists for high flow rates. Tubing string can be used as a kill string and for chemical injection. The "no-go" nipple provides a means of pressure testing the tubing.

CASING FLOWTUBINGLESS COMPLETION

Flow unrestricted by tubing or packersCompletion restricted for wells 1.Capable of producing at extremely high rates 2. With low to medium flowing and shut in pressures.

Tubingless completions are Low-cost installation For marginal flow operations, low-rate gas developments. They are also used in high gas-oil-ratio oil fields, Problem

when artificial lift is required. Hollow sucker rod pumps or "macaroni" tubing strings

may be installed. Small liquid build-up in gas wells can be blown out with

flexible small diameter tubing

Single-tubing string completion with a packer

Flowing wells can be completed be completed with or without a packer. Wells that are equipped artificial lift are temporarily produced by natural flow. Flowing a well without a packer is the possibility of heading, Heading can result in alternating slugs of liquids and gas being produced

Flowing well – tubing flow

SELF FLOWING WELL - TUBING FLOW

Tubing string and production packer are installed Maximum potential flow rate is restricted when compared with casing or casing-tubing flow

Packer for casing protection and subsurface well control “No-go" nipple for bottom hole choke, regulator, or safety

valve service. Landing nipple run for flow control device Flow coupling positioned above or above and below the

landing nipple to absorb erosion due to turbulence and abrasion.

Circulating sleeve for displacing the tubing with a low density fluid after installation of the well head

1CONCENTRIC KILL STRING. 2.TWO STINGS WITH CIRCULATING HEAD

1. Sometimes a small diameter, concentric "kill string“ is used to circulate fluids to kill the well when required2.Two strings of tubing also are run externally to each other and connected downhole by circulating head Design is used in wells subject to sulphur, salt, and scale plugging problems. Chemicals can be circulated down either string while producing up the other

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SINGLE COMPLETION FOR LOW PRESSURE HIGH RATE

Production packer and tubing safety valve are installed at some shallow depth in the well Well flows through the tubing and annulus upto a point below the packer, then enters the tubing through a ported nipple and then flows through the packer and valve, and then again continues up both the tubing and annulus by means of a second ported nipple.

Single-tubing-string liner completion

MULTIZONE COMPLETIONS

A well may encounter multiple pay zones then the key issue is whether it is desirable to produce more than one zone at a time.

If decision is made to produce more than one zone then the alternatives available for such completion must be evaluated for their suitability as well as economic considerations

Alternatives available are Single string with multizone completions. Crossover dual completion - single string. Dual string completion. Triple completion. Multistring tubingless completions.

SINGLE STRING WITH MULTI ZONE ORALTERNATE COMPLETION

In this type of well the alternate zone is perforated on initial completion, but is kept isolated by packers. It is put on production when the lower zone is depleted by perforating the tubing opposite the alternate perforations.

Blast joints are thick-walled subs used for abrasion resistance opposite producing perforations.Normally not installed in an alternate completion

DUAL COMPLETION – SINGLE-PACKER, SINGLE-TUBING STRING

Production of the lower zone is through tubing; upper-zone flow is through casing-tubing annulus. The primary advantage is reduced cost. Several disadvantages. Only the lower zone can be put to artificial lift. Production casing is exposed to well pressure, corrosive fluids. Solids settling from the upper zone can stick the tubing string. Necessary to kill the lower zone before working over the upper interval

Two zones – Two-packer, single-tubing string. Tubing/casing crossover dual completion.

Possible to produce either zone through tubing by utilization of a crossover or regular flow choke. This technique retains the disadvantages of casing exposure, plus inability to Workover the upper zone without killing the lower. However, it does permit selectivity as to which zone is produced up the annulus.

DUAL COMPLETION – PRORATED FLOW, SINGLE-TUBING STRING

Proration control is accomplished by regulating flow from each zone through specifically sized orifices within the dual flow choke. Streams are then commingled in the tubing above the choke.

upper packer is , but recommended, This device prevents exposure of the casing to well pressure and corrosive fluids.

With this completion design, flow from the weaker zone will be "assisted" by flow from the stronger zone. In addition, both zones can be artificially lifted simultaneously up the same string of tubing. However, proration control by this method is not permitted in certain states. Sand production creates orifice erosion and plugging problems

Two zones, two packers – Two-tubing strings dual “parallel” dual completion

Separate flow from each zone is maintained by use of two tubing strings and two packers. Either zone can receive selective artificial lift or concentric remedial attention. Proration control is more positive. This design is adaptable to special techniques of sand control. Disadvantage is higher initial cost.Workovers that require removal of the existing production equipment setting is very expensive

Dual well with two alternate completions

Alternate completions are installed in both the long string and short string completions.

Triple completion – Three zones (2 or 3 packers, 2 or 3 tubing strings)

This design can be accomplished using either two or three tubing strings and packers. Yields high total daily production per wellbore and generally improved well cost payout. Triple completions are difficult to install and are susceptible to communication problems.

REDUCED DIA OR TUBINGLESS COMPLETIONS

Reduced diameter single completions are miniaturised versions of conventional configurations. Multiple tubingless completions are a more modified approach.

advantages : Reduced completion cost. Multiple completions less difficult to install. Wells can be worked over selectively limitations : Lower maximum potential productivity. Lower maximum potential stimulation rate. Paraffin, scale and corrosion problems more critical. Difficulty experienced in obtaining good primary cement job.

Completion configurations can be Single flowing well, Potential single and completion variations Triple completions.

SINGLE TUBINGLESS COMPLETION FLOWING WELL

This is a miniaturised version of the basic perforated casing . The integral landing nipple is used for safety valve service, as a pump seating nipple

VARIOUS DESIGN POSSIBLITIES FOR TUBINGLESS COMPLETION

TRIPLE TUBINGLESS COMPLETION

This is comparable to a conventional triple completion in which the casing string has been deleted And the packers have been replaced by cement. Single-string, multizone completions are often found to be preferable because in dual tubing strings the casing size limits the diameter, which, in turn, limits the flow rate obtainable through each string. These completions may also be used to minimise completion costs, which often is the reason for limiting the size of the production casing.

Horizontal /Multilateral Completion Technology with Intervention options

The last decade witnessed major advancement dealing with :• Horizontal & Multilateral well production –drilling ,

window cutting and re-entry tool• Coil tubing for work over, well completion – re-entry

drilling• Intelligent well completions – deep water / Multilayer

production• 3D seismic, time lapsed seismic(4D), & visualization for

remaining recoverable reserves• More effective products & method for stimulation &

treating wells• New logging tools – more understanding of reservoirs

1. Conventional Horizontal/Drain Hole Completion

• Open Hole• Slotted Liner• Cemented and Perforated• ECP

1. Openhole Completion (OHC)

Advantage • Stable formation which remains stable through out

the life of well• Low to Medium permeability reservoirs• Suitable for reservoir having little zonal isolation

requirement• Almost no formation damage from completion• Lime stone and chalk formation• Inexpensive

1. Openhole Completion (OHC)

Disadvantage• No effective zonal isolation & stimulation• No control over production or injection • OHC restrict wells full potential – as no selective

stimulation is possible – less recoveryOHC is recommended in situation• Running a casing in well is either impractical or

impossible• Formation is competent enough

1. Slotted Liner Completion

• Additional stability to openhole without adding substantial cost

• Designed slots of various dia and distributed over the length can be made as tool to control inflow

• No selective stimulation• No selective production or injection• Impossible to abandon Usually recommended –where cementation and

perforation of casing is not feasible

1. Cased, cemented and perforated Liner Completion

• Liner is cased and cemented through out the H/section and perforated

• Most advantageous completion in all cases• Maintain control of productive interval

through out life of well• Selective perforation and stimulation – max.

recovery• Full exploitation of drainage area of the well

1. Cemented cased and perforated Liner Completion

• Untill recently, success of cementing a casing was poor in H/section

• Reciprocating and rotating technique has enable successful cementation as high as 97 deg

• Long radius drilling (even medium radius) facilitates reciprocating & rotating of liner

• Open hole cementing practices have proven very useful tool, for zonal isolation

• Cementation and perforation of H/section is very costly

1. ECP Completion (for Open Hole)

• Horizontal section is divided into several producing section – depending upon logging, downhole camera, & information obtained while drilling

• ECPs & port collars run with liner and selectively placed through out the H/section as decided

• Open hole cementing packers can also be run with liner as back-up if ECP fails

• ECP set hydraulically• Each zone can be tested / treated through port collars

opposite the interval• Port collar can be closed /opened with closing /opening

tool. This completion proved has been very successful

A complete Horizontal Completion

Categories of drain holes - BH Field 2 t0 8 ½ ” hole1. drain hole Bare foot compln2. drain hole with blind & slotted tubing

compln 3. lateral (single layer) bare foot compln

(more than one lats)4. laterals (single layer) with branched

drain holes of 100-500 m, bare foot

5. Dual layer multi-laterals (two layers)6. Multilayers

2. Complexity ranking (TAML grup), Completion, & Entry tool - Ml

TAML operating group : 1) Complexity ranking (tier 1)2) Functionality (tier 2)

The Complexity Ranking consists of a single numeric character

Functionality; other completion detail type of well and lift etc

2. Complexity Ranking

• Wells are ranked from Level 1(simple open/unsupported junction) through 6S (complex junction).

• Junction Levels 1 and 2 do not have a seal between the vertical and horizontal/inclined wellbores and may be considered Simple Junction Multilaterals (SJML). Level 3 has a mechanical connection

Complexity Ranking


Level 1• Open/

Unsupported Junction

• Barefoot mother-bore & lateral or slotted liner hung-off in either bore


Level 2• Mother-Bore Cased

& Cemented Lateral Open

• Lateral either barefoot or with slotted liner hung-off in open hole


Level 3• Mother-Bore Cased &

Cemented • Lateral Cased But Not

Cemented• Lateral liner

'anchored' to mother-bore with a liner 'hanger' but not cemented


Level 4• Mother-Bore &

Lateral Cased & Cemented

• Both bores cemented at the junction


Level 5• Pressure Integrity

At the Junction(Cement is not acceptable) Achieved with the completion


Level 6• Pressure Integrity

at the Junction(Cement is NOT acceptable)Achieved with the casing


Level 6S• Downhole Splitter

Large main well bore with 2 (smaller) lateral bores of equal size

2. Functionality Classification 'Well Description'

1. Number of Junctions – An Important contributor to the well’s complexity. The majority of wells to date has been dual lateral. As the technology develops however, the average number of laterals per well will be increase

2. Selection of appropriate completion for Multilaterals :

Depends upon :• I) producing and• II) Well intervention requirements during the life of

wellThese requirements/considerations are- Lateral isolation- Type of well interventions- Type of flow control- Mechanical access- Commingling, spacing


• Based on these requirements & cost complexity & risk various completion options of

• Incorporate many completion tools - for flow control from various branches Characterized by upper & lower packers – provide high pressure seal within the primary well bore between branches

• Commingling devices- sliding sleeves or ported nipples for flow control or to isolate branches


- Based on these requirements, cost complexity & risk, various completion options of: - simple pumpings (or A/L) completion to very complex reentry completions have

been developedSuch completion are :

(1) Dual String Multilateral Systems (DSMLS)(2) Lateral Re-entry System (LRS)

1. Dual string Multilateral System (DSML)

• A three – packer system :- A packer or seal bore in the branch lateral- A packer in primary well bore below the

branch juncture - A dual string packer above branch juncture-- Provide full hydraulic isolation of the lateral

juncture as well on isolation of the branch & primary laterals

1. Dual string Multilateral System (DSML)

• Unique feature – mechanical access to each lateral by conventional through tubing tools

• Provide – flow control from either lateral with surface equipment provide multiple use of well

• Selective stimulation & injection in a sigle well bore

• Generally limited to two lateral in a well

2. Lateral Re-Entry System (LRS)

• Provides feature of NAML system with addition of through tubing access to any branch of lateral

• Packers – Upper and lower packer – provide a H/Pess seal within primary well bore and between various branches

• Commingling device – a window joint located in tubing string

FIG:


• A workover defective device can be run on CT or wireline for mechanical access to branch lateral to facilitate normal opns or W/O opns.

• Flow from individual lateral is shut-off by conventional wire line or CT conveyed plugs


• An isolation sleeve across the tubing window shut off lateral flow in the primary well bore

• Number of laterals can be completed with LRS• A single production tubing is used - an LRS

system requires commingled production.

2. Access to Multilaterals : MLT Tool

CT conveyed – CT MLT Tool• A combination of MLT tool and CT to access laterals

and Multilaterals• CT Softwares are used to get important downhole

parameters• Tool orientation relative to lateral windows• Accurate real-time downhole information• Required tubing CT size, entry extent w.r. to dogleg severity

• CT BHA consist of – A motor head assembly incorporating a dual flapper check valve– A down hole filter and MLT tool

2. Re-entry Tool (Access to Multilaterals) : MLT Tool

2. Case History

• Upper Zakum field (offshore) Abu Dhabi• Purpose – to increase productivity of

multilateral by stimulation and various treatments• Job done with Schlumberger CoilCADE CT

software design and program- showed 1 ¼” CT required for job• MLT Tool OD 2.125” with a 0.2” tolerance

between the minimum restriction of the completion


• Well detail– Dual string Completion (9 5/8”), 8473’ depth

• Upper lateral in short string • The main leg 8 ½” depth 10246’ • CT MLT tool run without activation in mother hole

(10238’) and activated on window. CT running in the hole at 10 ft/min CT speed and pumping rate of 1.6bpm and allowed to go to depth 10178’ in leg. No. 3


• The formation acidized at this depth and displaced with nitrified diesel while reciprocating CT into targeted lateral to insure complete coverage of the hole

• Production increase is 30% after job

3. Completion for controlling water and gas:

Water & Gas conning Problem:• Considerable pressure loss experienced along

H/section of horizontal & draiholes• Friction pressure act as a choke on prodn from toe

to heel – toe area experieces additional back pressure – inhibit inflow in toe area

• Liner/openhole : - Pressure - increases exponentially from heel to

toe end - Drawdown & Influx decreases - exponentially from toe to heel end• Thus inflow is asymetrically skewed towards the

heel area of well

3. Completion for controlling water and gas:

Water & Gas conning Problem:• The upstream part close to toe contributes less than

down stream part close to heel• Decline in drawdown along the hole becomes

important in high permeable reservoirs where pressure loss through the reservoir may be of same magnitude as pressure loss along the horizontal wellbore

• Initially heel produces more oil than toe

Typical Pressure and influx profile along a conventional completed horizontal well

Thanks

A complex multizone TFL subsea completion

Well service functions