Lower Completion - Juan Tovar.pdf

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The lower completion must consider •

Equipment requirements for open and cased and perforated wells

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Methods of preventing or reducing the ingress of sand

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Equipment configurations with regards to both the well design and the properties of the fluids to be produced

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In cased wells, careful consideration should be given to the design of perforations to maximise production rates

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The use of new technologies (such as expandables) to reduce rig time and improve production economics

There are two basic well configurations for oil and gas wells:

The reservoir rock across the producing interval is left exposed to the wellbore. Fluid are produced directly through the reservoir rock along the wellbore and into the well.

Casing is set across the producing interval, and perforated (where required). Hydrocarbons are then produced through the perforation tunnels and into the cased wellbore.

• The lowest casing string or liner is set above the reservoir - the lower section of t wellbore is uncased • Generally only be in a consolidated formation • It is the simplest and cheapest because no equipment has to be installed

HOWEVER: • No selectivity of the reservoir zones (for production or injection) • Water or gas break-through cannot be controlled in producers • Permeability variations will result in fluid preferentially entering the most perme abl zone preventing an effective reservoir sweep in injectors

The main features and limitations of the open hole completion are:

Advantages

Lower equipment and operating costs Maximum well productivity and minimum formation damage Preferred option for horizontal wells

Limitations

Should only be used in consolidated formations No zone selectivity or flow control of gas or water production Wellbore may require periodic cleaning and maintenance

• Casing or liner string is run and cemented across the production interval, and perforated in selected zones • This is a more complicated method, hence time consuming and expensive • It offers good zonal isolation and wellbore integrity with flow control of produced water or gas

The main features and limitations are:

Advantages

Better zonal isolation and flow control Reduced productivity

Limitations

Time consuming and expensive Greater potential for formation damage and impaired productivity

There are several ways in which sand production can be mitigated in oil and gas wells: • Slotted Liners • Stand Alone Screens • Frac Pack • Gravel Pack • Expandable Sand Screens • Chemical Consolidation

The most basic mechanical sand control methods is the slotted liner.

• Tubing sections with a series of slots cut through the tubing wall • The slot width is designed to initiate inter-particle bridging • Originally considered it should be twice the diameter of the D10. • More conservative present view is they should be about the same size as D10 • The main limitation of slotted liners is their flow area – an average of 3% • The flow area, it can be calculated using the following equation:

There are two types of slot available - keystone and straight.

• Keystone slots are considered better due to their self cleaning ability • They are generally twice as expensive as straight cuts • Slotted liners are only slightly cheaper than wire-wrap and often more expensive • They are considered improved handling to be stronger • They have much less open flow area than wire wrapped screens

There are three main types of stand-alone screens:

WIREWRAPPED

PREMIUM

PRE-PACKED

• Wire wrapped screens are made from triangular shaped wrap wire. • Rectangular wires may result in jamming of grains – plugging the screen and reducing the flow area. • The triangular shape of the wrap wire reduces the chance of sand grains from getting in the slots and hence pluggingtrapped the screen.

•Sand bridges restrict passage of other grains •Formation of this structure controlling the sand

critical

to

•The fine particles are able to pass •If the fines were stopped they would plug smaller pores reducing the system permeability. •If sand grain size varies considerably, the filter cake has a reduced permeability – hence little control poorly sorted sands •In general terms, wire-wrap screens are used behind gravel packs,

• The pre-pack gravel is the main filtration medium and the wire-wrap jackets are designed to retain the proppant in place • The pre-packed screens provide against voids in the gravel pack

insurance

• Pre-pack screens are used in horizontal wells or marginal wells where the use of a gravel pack would be uneconomic • Slimmer pre-pack screens are primarily used behind frac packs or high rate water packs in horizontal wells

• A concern for operators is the difference between cured and uncured resins and its affect on screen permeability • The less precise sorting and non-sphericity of sand results in t a tighter and less porous pack • Cured resin was thought to blind off some pore throats reducing permeability • Ceramic proppants this is not an issue as, the difference is not significant at normal levels

• All metal design, with metal mesh filtration and protective outer metal shroud • Filter media is metal weave, metal fibres or powder particles embedded within square mesh • Apertures vary from 60 micron to 300 micron • Mesh prevents larger particles passing but allows formation fines to pass • Run in long horizontals, behind gravel packs • Similar sand control properties to pre-pack screens • Improved plugging resistance and ability to flow back drilling muds through the screens

• The objective of “frac packs” is to improve productivity by creating a short, wide fracture close to the wellbore • A proppant is placed inside the fracture to hold open the fracture and control sand production • In frac packing the fracture widths can be 1 inch or larger and lengths usually in the region of 20 to 50 feet • Cross-linked gels are used for optimum fracture size • The majority of wells have a conventional gravel pack in the central wellbore area in addition to the frac pack • A more recent development is to have a resin coated frac pack along with a screenless completion in the wellbore

Fracture filled with gravel /proppant

wellbore packed with screen in wellbore

Fracture filled with resin coated gravel /proppant

Wellbore free of equipment

The well performance benefits of frac packing, below, shows the typical skin behaviour of a frac pack. In terms of sand control this improved well performance will limit the drawdown required to obtain a particular rate and as the flow comes from a larger area the rates will be lower thus, reducing the fluid drag

The major advantages of frac packs are that

• They bypass near wellbore damage

• They offer a larger effective wellbore radius

• They can connect multiple thin layers

• Gravel Packs (GP) are useful for completing sand prone reservoirs in a wide variety of reservoir sand types and completions. • GP systems have been in common use for many years, and on their application exists a wealth of experience and knowledge • Gravel packing in open-hole (EGP – External Gravel Pack) is useful for preventing annular flow and controlling sand in heterogeneous formations. • Gravel packing in cased-holes (IGP – Internal Gravel Pack) is useful for protecting the sand screens from erosional flow.

TUBING

PACKER Cemented and perforated casing/line r

SCREEN

Gravel Squeezed into perforations

Under-reamed Open hole section with gravel pack

Gravel packing is more complex with increased hole angle and length In open hole, high permeability streaks / washouts can interfere with uniform gravel placement Low net to gross pays can also intermix with the gravel during pumping and impair the gravel pack permeability and hence productivity To counteract these problems, the industry has responded by developing specialised techniques and equipment - alternative path technology Some systems use shunt tubes on the exterior of the screens and allows the gravel to by-pass blockages in the well-bore annulus Alternative approaches are offered by other service companies, which aim to achieve the same result

• Used in formations with little or no cementaceous material • Can also be used as a remedial technique • The principle is to bond the quartz grains together using a liquid resin • This provides artificial cementing material between the grains • A major benefit is that the wellbore is left free of obstructions

In order for chemical consolidation to be effective the resin must: • Fully coat the grains of the formation • Concentrate the resin at the grain’s contact points • Leave the majority of pore space available for flow

Grain to Grain contact points

Resin coated grain

• Sand grains must be coated with resin to wet the exposed sand surface to form a good adhesive bond • The resin will concentrate in the grain contact points • Before the resin can harden a non-reactive fluid (usually oil) is placed in the pore space to partially displace the resin • Typical volume ratios leave 35% of the pore space filled with resin • The remainder that has been displaced to oil will be open for flow once the resin has set

For the two basic well configurations (open hole and cased and perforated) there are a number of lower completion options:

• Horizontal • Multi Laterals • Multi Zone • Injectors

Horizontal wells have an increased borehole contact area with the formation This could be as much as 6000 feet or more of completed reservoir zone Productivity is a function of well length and interval height Horizontal wells may have the following completion configurations:

• Open hole • Cased and perforated • Slotted liner

Applications for horizontal wells are predominantly based around more effective and efficient drainage of the reservoir, while minimising production problems which may have been encountered had a vertical well been used. They include: • Intersection of naturally fractured reservoirs • Minimisation of gas and water coning • Low permeability gas wells – improved drainage area • High permeability gas well – reduce near wellbore velocities

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Multilateral technology was developed to increase reservoir exposure by using complex drainage architecture connecting one or many lateral wellbores to the main borehole at the multilateral junction

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The junction can be designed in a new well application or created in an existing wellbore for re-entry. The main and lateral bore designs can be vertical, directional, or horizontal and are based on individual reservoir requirements

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From lateral additional laterals, branches, or splays can be addedthe to tie backbore, additional reservoir targets.

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Increase well-bore leverage

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Developed to increase reservoir exposure

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Reduce surface infrastructure

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Obviate requirement for slot recovery

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Commingle reservoirs production from different zones or

Multi lateral applications include:

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Reservoir exposure

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Multiple targets

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Comingled flow

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Auto gas lift

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Dump flood

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Slot reductions / infrastructure

Six ‘levels’ of multilateral completion technology

Six ‘levels’ of multilateral completion technology

Level 1

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Six ‘levels’ of multilateral completion technology

Level 2

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Six ‘levels’ of multilateral completion technology

Level 3

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Six ‘levels’ of multilateral completion technology

Level 4

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Six ‘levels’ of multilateral completion technology

Level 5

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Six ‘levels’ of multilateral completion technology

Level 6

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Multi zone completions utilised where more than one distinct reservoir layer is encountered.

The depletion of multiple zones can be achieved by: • Co-mingled flow from various layers • Segregated but multi-zone completion • Alternate well completion strategy

Multi zone completion options are based on the number of zones to be produced and the properties of the reservoir fluids, and the flow path of the zones.

Can also use single string selective completion can produce from one zone or the other

• Normally never run more than 3 tubing strings • Multi-zones become complex and expensive • Difficult to run, retrieve and susceptible to failure

The use of injection wells to restore or help maintain reservoir pressure within the field is widely utilised, however the following considerations should be made: • Identification of layers suitable for water migration • Impact of water production on the rest of the producing system • Associated production problems – scaling fines migration etc. • Sand control requirements for injectors • Water shut off options – timing and strategy • Thermal Induced Fracturing (TIF)

The purpose of perforating a well is to create a series of communication tunnels, known as perforations, between the wellbore and the formation The characteristics and placement of perforations influences the productivity of a well Careful consideration must be given to the design and execution of the perforation programme and operation Perforations are the only means by which production fluids enter the wellbore and they must provide an adequate inflow area The perforations must be deep enough to penetrate any mud damaged zone around the well bore as well be free of any debris which would impair productivity

The following well condition factors should be considered in the perforation programme: • Type of completion • Cement thickness and casing / formation bond integrity • Type and level of wellbore fluid • Specification (and conditions) of wellbore tubulars and equipment • Formation permeability, characteristics and type • Post perforation stimulation and/or completion programs

Cement & Casing support

Wellbore Damaged zone

Steel casing

Perforation cavity

Debris

Entrance Hole

Cement sheat

Four main factors must be considered to achieve optimum perforation of a particular reservoir. The factors vary in importance depending on the reservoir and completion type, they are:

• Shot Density – the number of shots per foot • Perforation Diameter – dependant on the gun type • Perforation Phasing – the angel of the perforations around the wellbore • Perforation Length – dependant on the gun type

• Underbalanced perforation - the wellbore pressure is less than the formation pressure • Improved well productivities due to flow out of the formation immediately on perforating • This flow removes crushed materials from the perforations, ensuring clean perforation tunnels • Well performance is greatly affected by well cleanliness, underbalanced perforating can give better productivity

• Economic over short intervals • Multiple runs required for longer intervals • Can pull out immediately after perforating • Suitable for low angle wells only • Limit level of underbalance • Mainly used for re-perforating

• Perforation in high angle wells • Increased underbalance level • Length limited by rig up restrictions • Long intervals require multiple runs

• Use more rig time to run – but can perforate long intervals. • Can be run at same time as part of the completion • Important to ensure that guns can be run to depth and space out is correct • Can be left in situ once perforating is complete • Can run larger guns – increased phasing or higher shot densities

• Check performance with rock strength and confining stress • Check quality control of charges

• Removal of perforation debris •• Sufficient underbalance Will TCP guns have to be pulled after killing the well

Perforate in filtered inhibited brine – do not induce formation damage by perforating in ’dirty’ fluids If more than four wireline runs are required, TCP will be cheaper. Check QA / QC on shaped charges: • Check origin / source • Check storage • Test fire in lab?

• New / developing technology • Slotted expandables (e.g. ESS®) for sand control • Solids expandables (e.g. Metalskin™) for other applications • Allow reduced running OD while maximising production ID • Provide improved inflow performance with with additional borehole support

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EST Base Pipe

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Woven Filter Media

Outer Shroud

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ESS® Screen Expansion

• Repair existing casing strings • Suitable for cladding • Operationally simple • Suitable for zonal isolation (LC or swelling shales) • Reduced mechanical properties after expansion

Solid Tubular Expansion

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Gas lift works by reducing the hydrostatic head of the reservoir fluids by adding gas.

• Gas lift will be at its most efficient if injected at the maximum depth

• Install/recover gas lift valves at deviations beyond 60° may be troublesome

• Lift gas will displace the annular contents down to the deepest injection point

• The casing must be designed for higher loads

• The lift gas must be dry if corrosion of the tubing / casing is to be avoided.

Turbine type of pumps rotating at high speed

• A pump section and a power section(turbine)

• Can accommodate very high rates and high GOR

• Very sensitive to solids in the power fluid

• Fixed pump setting depth

• Texaco Mariner, BP forties.

Positive displacement pump

• Moderate to low rate

• Pump activated from surface using a metal rod 1/8” 5/8” sizes

• Good for heavy crudes and tolerant of solids

• Require proper design

Centrifugal pumps

• All rate ranges up to +60000 bfpd

• Pump activated from surface using a metal rod 1/8” 5/8” sizes

• Good for heavy crudes and tolerant of solids

• Require proper design

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