Well Completion Design

• Crucial drilling and completion operations determine the wells' long-term ability to meet objectives in hydrocarbon reservoir development.
• Production and injection well design and completion aim to optimize performance, ensure safety, maximize completion integrity and reliability, and minimize total costs per fluid volume.
• Completion design should consider reservoir characteristics and development constraints, such as sand production control.
• The design process involves creating conceptual designs and then developing detailed designs that specify components and assess the sensitivity of well and completion performance to reservoir data variations.

Key Decision Areas in Completion Design

• Bottom-hole completion technique specification.
• Production conduit selection.
• Completion string facilities assessment.
• Well performance/productivity-injectivity evaluation.
• This process typically begins with exploration well data, which may be uncertain.
• Multiple alternative designs are selected as contingencies.
• Detailed design focuses on specifying equipment and materials, optimizing completion and well performance.
• An interactive approach is essential at both design stages, involving various disciplines like drilling, reservoir, and production engineers.

Bottom Hole Completion Techniques

• The method for fluid communication between the reservoir and borehole post-completion must be determined.
• Three approaches available for reservoir zone completion: open hole completion, pre-drilled/pre-slotted liner or screen completion (uncemented), and casing or liner with annular cementation and subsequent perforation.

Open Hole Completion

• This simple technique leaves the drilled reservoir section open, also known as "barefoot" completions.
• Cost and time savings achieved due to no equipment installation.
• Offers no selective control over fluid production/injection, unsuitable for reservoirs with permeability variations affecting sweep efficiency during water flood or gas injection.
• Difficult to isolate water/gas breakthrough unless at the well's base, with limited correction for inter-zonal cross flow or zonal back pressure.
• Suitable only in consolidated formations to prevent borehole instability and sand production.
• Applied in: low-cost/multi-well developments, deep/consolidated wells, naturally fractured reservoirs, and some horizontal/multi-lateral wells.

Screen or Pre-Slotted Liner Completions

• This involves installing a wire-wrapped screen or slotted steel pipe to prevent sand migration into the production flow string.
• Sand production control success depends on screen/slot and sand particle sizes; 100% effectiveness requires slot sizes equal to the smallest particles, potentially causing plugging and productivity loss.
• Sometimes used in inclined/high-angle wells to prevent borehole collapse or aid logging tool passage.
• Lacks zonal control over production/injection, offers limited sand production control.
• Lower cost compared to casing string to surface, plus cementing and perforating.
• Applicable as an alternative to open hole completion in reservoirs with large, homogenous sand grains.

Cemented and Perforated Casing/Liner

• This involves installing a casing string to the surface or a liner into the previous casing string shoe, cemented in the annulus.
• Perforation creates flow paths using explosive charges.
• Completion integrity depends on effective cement hydraulic seal in the casing-formation annulus for zonal isolation.
• The absence of cement can lead to fluid migration.
• Perforations can be closed with a cement squeeze operation.
• Higher costs and time compared to other options.
• Liners reduce costs; controlling zone depletion, fluid inflow, and injection are crucial for reservoir management, making cemented and perforated liners or casings the most common technique.

Selection of the Flow Conduit

• Methods for fluid flow to the surface in production wells or to the formation in injection wells exist.
• Considerations include cost, flow stability, control, safety, preventing corrosion/erosion, and zonal characteristics in multizone reservoirs.
• Alternatives for a single zone completion: tubingless casing flow, casing and tubing flow, tubing flow without annular isolation, and tubing flow with annular isolation.

Tubingless Casing Flow

• After drilling and implementing the bottom hole completion, the well is induced to flow, producing fluid up the casing.
• Simple and cost-effective, but has disadvantages such as unstable flow due to low fluid superficial velocities in large diameter casings.
• Only applicable for high rate wells.
• Fluid direct contact with casing can cause corrosion (H2S or CO2), erosion (sand), and casing burst at the wellhead if production changes from oil to gas without withstanding casing burst limitations.
• Well killing requires squeezing wellbore contents back into the formation (undesirable due to particulate lodging) or circulating across the wellhead using the Volumetric Technique.
• Suitable for high well productivities with minimal workover requirements, provided abrasion or corrosion are absent.
• A variant involves individual tubing strings opposite each zone, cemented in place, and perforated with orientated guns, known as a "tubingless completion," but problematic workovers are precluded.

Casing and Tubing Flow

• For highly productive wells, production tubing installation allows flow up the tubing and tubing-casing annulus, with the advantage of deep circulation for displacing reservoir fluids with kill fluid.
• This completion avoids reinjection into the reservoir, eliminating high squeeze operation pressures.
• Very useful for high flow rate wells without erosive or corrosive compounds.

Tubing Flow without Annulus Isolation

• Closing the annulus at the surface prevents flow in casing-string completion to reduce phase slippage, but gas can accumulate in the annulus if flowing bottom-hole pressure is at or below the bubble point, increasing casing head pressure.
• This leads to annular heading, causing cyclical production instability, and casing exposure to produced fluid increases erosion or corrosion risks.
• Annulus should not be left open without annular flow requirements.

Tubing Flow with Annular Isolation

• To avoid open annulus complications, a packer is installed to isolate the annulus, normally close to the reservoir top to minimize gas accumulation.
• A packer removes the ability to circulate fluid between the tubing and annulus, necessitating a tubing component for annulus communication or tubing perforation.
• This widely used system offers maximum security and control.

Completion String Facilities

• The design should initially identify minimum functional requirements and assess additional options based on complexity versus benefit.
• In high operating cost areas, simple designs with basic operational facilities are favored for continuous production.

Basic Completion String Functions and Facilities

• String must allow continuous production/injection without major repairs, ensuring safe operation and shutdown. The completion string, production casing, and wellhead must form a pressure system preventing fluid escape except via the production tubing and Xmas Tree into the surface processing facilities.
• Essential attributes: pressure and flow containment, annulus isolation, downhole shut-in ability, annulus and tubing communication, and tubing isolation.
• Pressure is contained within the production casing, tubing, wellhead, and Xmas tree, with the casing and tubing designed to withstand anticipated internal pressures; tubing size optimizes production rates and flow stability.
• Annulus isolation prevents annulus heading cycles and casing damage, using a packer to fill the annulus.
• Downhole closure via subsurface safety valve (SSSV) provides emergency closure if surface access is impossible or valve failure occurs; circulation capability is important. A sliding side door (SSD), side pocket mandrel (SPM), or ported nipple facilitates this process.

Additional Completion String Functions

• Tubing isolation is supplemented by a downhole SSSV and a plug in a wireline nipple.
• Downhole tubing detachment allows disconnection and reconnection for replacing completion components, requiring hydraulic isolation below the detachment point.
• Moving seal systems accommodate tubing expansion/contraction to prevent damage.
• Wireline nipples allow installation of pressure/temperature gauges for P&T monitoring.

Controlled Fluid Injection

• The annulus introduces chemicals to the flow string, and side pocket mandrels with valves control fluid flow from the annulus into the tubing.
• Gas lift installations inject gas to lighten hydrostatic head and maintain production, and downhole pumping systems require pump inclusion in the completion string design.
• A wireline entry guide aids wireline operations below the tubing string.

Completion String Components

• String design involves component selection for necessary facilities and flexibility.
• Equipment selection depends on providing necessary facilities and flexibility, with operating companies favoring specific suppliers based on experience.

Wellhead/Xmas Tree

• Wellhead suspends casings and tubulars, allows installation of blowout preventer stack and Xmas tree, and provides hydraulic access to annuli.
• The Xmas tree controls fluid from/to the well, comprising wing valve outlets, a master valve (sometimes duplicated), and valve-controlled outlets.

Production Tubing

• Factors to specify include: steel grade, wall thickness, and threaded coupling.

Provision of an Annular Pressure Seal

• Improve flow stability and production control, protect outer containment systems, and choose or isolate zones.
• Annular seal is provided using a packer which are classified by retrievability, setting mechanism, and ability to withstand differential pressure.

Flow-Control Accessories

• Increases the flexibility of the cased-hole completion design and perform various tasks, from temporarily plugging off the tubing string to establishing temporary communication between the tubing and the annulus.
• Profile seating nipples and sliding sleeves have a special locking groove and a honed sealbore to allow a flow-control device to lock in the nipple and seal off when installed.
• This is especially true in any case in which through-tubing operations or perforating are planned.
• Correct application of flow-control accessories can greatly reduce the time and money spent on diagnosing well problems

Wireline Re-Entry Guides

• used when running electric wireline, slickline tools, or coiled tubing past the end of the tubing string and into the casing below; internally bevelled, bell-shaped ID, it eliminates any sharp edges or square shoulders and helps align the tools as they are pulled back up into the tubing string.

Profile Seating Nipples

• also referred to as “top no-go,” “bottom no-go,” and “selective” types; has a unique machined profile with a locking groove to accept a flow-control device that is run and installed on slickline or coiled tubing; allows the accurate placement of slickline plugs, check valves, bottom-hole chokes, downhole flow regulators, and bottom-hole pressure recorders. Top No-Go Profile Seating Nipple
• The “top no-go” nipple accepts a lock assembly with a no-go shoulder located on the lock itself (Fig 4.10). Bottom No-Go Profile Seating Nipple
• The “bottom no-go” nipple has a no-go shoulder located in the bottom of the nipple; always run as the lowermost nipple in the completion; the benefit is that any other slickline tools or tubing swabs that are lost in the tubing string should not fall to the bottom. Selective Profile Seating Nipple
• type profile nipples are perhaps the most versatile of the three; the locking assembly or flow-control device is able to find and selectively land in any of them.

Sliding Sleeves

• It provides a means of establishing communication between the tubing and annulus for fluid circulation, selective zone production, or injection purposes (Fig 4.11); the sliding sleeve is ported from ID to OD and has an internal closing sleeve that can be cycled multiple times using slickline or coiled-tubing shifting tools.

Blast Joints

• used in multiple-zone wells in which the tubing extends past a producing zone to deter the erosional velocity of the produced fluids and formation sand from cutting through the tubing string.

Flow Couplings

• They are run above and below any profile seating nipple and sliding sleeve in which it is anticipated that the turbulence created by the flow through the nipple restriction can reach erosional velocity and damage the tubing string.

Blanking Plugs

• It may be landed in profile seating nipples or sliding sleeves to temporarily plug the tubing string, allowing pressure to be applied to the tubing string to test tubing or set a hydraulic packer, or to isolate and shut off the flow from the formation. Slickline blanking plugs always have an equalizing device incorporated into the design.

Bottom-hole Choke

• restricts flow in the tubing string and allows control of production from different zones. It can be used to prevent freezing of surface controls.

Subsurface Safety Systems

• the subsurface safety valve provides a means to automatically shut off the flow of the well to avoid disaster.

SCSSVs

• SCSSVs are also installed in the tubing string below the surface tubing hanger; however, they are controlled by hydraulic pressure through a capillary (control) line that connects to a surface control panel

Side Pocket Mandrel (SPM)

• This component, as depicted in Figure 4.9, contains an off centre pocket with ports into the annulus; A valve can be installed in the packer which allows fluid flow between tubing and annulus

Sliding Side Door (SSD) Sliding Side Door (SSD)

• This device permits communication between tubing and annulus; Using wireline or coiled tubing, the inner sleeve can be moved upwards or downwards to align the openings on both sleeves

Packers

• Packers key features: slip, cone, packing-element system, and body or mandrel; Production packers can be classified into two groups: retrievable and permanent.

Retrievable Tension Packer

• The tension packer (Fig 5.1) is typically used in medium to shallow-depth (LP/LT) production or injection applications; Constant tubing tension must be maintained to keep the packer set and the packing element energized. Tension packers typically are set mechanically and are released by means of tubing rotation.

Wireline Set—Tubing Retrievable

• There are several retrievable packers designed to be installed in the wellbore on electric wireline and retrieved on the tubing string (Fig 5.4); On the top of the packer is located a special nipple.

Tension-Compression Set—Versatile Landing

• Tension- or compression set packers that allow the tubing to be landed in tension, compression, or neutral are the most common types of mechanical-set retrievable packers run today.

Retrievable Hydraulic-Set Single-String Packer

• The hydraulic-set packer (Fig 5.6) has a bidirectional slip system that is actuated by a predetermined amount of hydraulic pressure applied to the tubing string; This promotes safety and allows better control of the well while displacing tubing and annulus fluids.