Well completion: opening the reservoir and the tubing string

Quick refresher

A completion concept (the outline design) is built from four decisions: the bottomhole completion, the flow conduit, the set of functions of the tubing string, and a calculation that checks the expected productivity.
Open hole is cheap and does not block the inflow. But it gives no control over individual intervals, and it suits only stable rock (rock that will not collapse). A slotted liner holds the wall of the hole and the sand back, but it does not separate the intervals either. Cemented and perforated casing costs more, but it lets us choose which intervals to open. This is why it is used most often.
In wide casing the mixture of liquid and gas moves slowly. The gas slips up through the liquid, and the column of fluid becomes heavy. At moderate rates, tubing lifts the liquid with a lower bottomhole pressure (the pressure at the bottom of the flowing well) than casing does.
Tubing with a packer protects the production casing from pressure and corrosion, and it gives a steady flow. A sliding sleeve (a valve in the tubing wall) above the packer restores the link with the annulus (the space between the tubing and the casing), so that fluid can be circulated.
The tubing string must hold pressure. It must make it possible to shut off the flow inside the well and to plug the tubing. It must isolate the annulus and, when necessary, connect it with the tubing for circulation. Every extra component is a new capability and also a new place where something can fail.
Before a workover we kill the well: we fill it with a fluid whose column is heavy enough to give a pressure higher than the reservoir pressure. If we circulate the fluid through the tubing and the annulus, we can do this without forcing the contents of the well back into the reservoir.

Key relationships

\rho_{\text{kill}} = \dfrac{k_{\text{m}}\,\bar p_R}{0.00981\,h}

density of the kill fluid, with a margin factor $k_{\text{m}}$ over the reservoir pressure (density in g/cm³, pressure in MPa, depth in m measured vertically)

V = \dfrac{\pi}{4}\left(D^2 - d^2\right) L

volume of the annulus between casing with an inside diameter $D$ and tubing with an outside diameter $d$

v_m = \dfrac{q_L + q_G}{A}

mixture velocity: for the same flow rate it is inversely proportional to the cross-sectional area of the conduit (twice the area gives half the velocity)

Common pitfalls

Assuming that the wider the conduit, the easier it is for the well. At low velocities liquid collects in the well, and the well may stop flowing by itself.
Choosing open hole where we will later have to shut off water or gas.
Judging a completion option only by its first cost, without counting the workovers that will come later.
Adding equipment to the tubing string “just in case”: every connection and every valve reduces reliability.
Forgetting that after a packer is set, we can flush the well only through a sliding sleeve or through a hole made in the tubing.

After this lesson you can

name the requirements for a completion and the four groups of decisions that make up its concept
compare open hole, slotted liner and cemented perforated casing, and choose a suitable option for the given conditions
explain the difference between lifting production up the casing, up tubing without a packer and up tubing with a packer, and why the last option is the most common
explain how the cross-section of the conduit affects the stability of the flow and the pressure losses, and link the choice of tubing diameter to nodal analysis (a calculation of how the reservoir and the well work together)
list the main functions of the tubing string and the components that provide them: packer, safety valve, sliding sleeve, landing nipple
estimate the density and volume of the fluid needed to kill a well (stop it flowing by filling it with a heavy fluid) by circulation before a workover

What a completion must provide and what it consists of

A hole that is drilled and cased is not yet a working well. We still have to decide how the hole will be connected to the reservoir, what conduit the fluid will flow through, and how we can shut the well in, kill it and repair it. The same requirements apply to production wells and injection wells.

Safety. The fluid and the pressure stay under control while the well is working, while it is shut in and during workovers.
Productivity. The well must produce (or take in) as much as the reservoir allows, with the smallest possible pressure losses.
Service life without a workover. The equipment is designed to run for years. Every time the crew pulls the tubing string out of the well, production stops, it costs money, and the reservoir may be damaged.
Cost over the whole life. We compare options by the cost per unit of fluid produced or injected, including workovers and downtime. We do not compare only the price of the first installation. Special reservoir conditions also count: sand that has to be held back, and aggressive (corrosive) components in the produced fluid.

Four groups of decisions

Decision: Bottomhole completion
Main question: how the wellbore is connected to the reservoir, and whether we can control individual intervals

Decision: Flow conduit
Main question: what the fluid flows through between the reservoir and the wellhead: casing or tubing, with or without a packer

Decision: Functions of the tubing string
Main question: what the string must be able to do (isolate, shut off, allow circulation) and with what equipment

Decision: Productivity
Main question: what rate we will get: a calculation that checks the whole system (nodal analysis)

Decision	Main question
Bottomhole completion	how the wellbore is connected to the reservoir, and whether we can control individual intervals
Flow conduit	what the fluid flows through between the reservoir and the wellhead: casing or tubing, with or without a packer
Functions of the tubing string	what the string must be able to do (isolate, shut off, allow circulation) and with what equipment
Productivity	what rate we will get: a calculation that checks the whole system (nodal analysis)

This lesson covers the first two decisions in detail and the third in outline. The design of the equipment is in the lesson Completion string equipment.

First the team draws up a concept. Usually this means several options, because the first data on the reservoir come from exploration wells (the first wells, drilled to find and test the field) and are imprecise. Then the team works out the chosen option in detail. It selects the equipment and materials, and it calculates the tubing string and the expected performance of the well. The decisions depend on each other. The tubing diameter depends on the expected rate. The diameter of the production casing depends on the tubing and the equipment. The casing programme of the whole well (which casing strings are run, to what depths and in what sizes) depends on that casing (choice of casing diameters). So we repeat the calculation until all the parts agree.

Bottomhole completion: three main options

We can leave the productive interval open. We can fit it with a screen and not cement it. Or we can case it, cement it (fill the space behind the casing with cement) and open it by perforating. All other designs are combinations and developments of these three.

SchematicThree bottomhole completions in a reservoir with bottom water (water that lies under the oil). With open hole and with a slotted liner, everything that the exposed interval gives up flows into the wellbore: both oil and water. In cemented casing we perforate only the part of the reservoir that we need. The water-bearing part stays behind the casing and the cement. The diagram is not to scale.

Open hole (barefoot completion): We run the production casing (the final string of casing) down to the top of the reservoir and cement it. Then we drill through the reservoir and leave that part uncased. This is the simplest and cheapest option: there is no pipe, no cement and no perforating, and the inflow comes through the whole wall of the hole. But the exposed interval works as one unit. It is almost impossible to shut off water or gas that has broken through. The one exception is a cement plug (a column of set cement in the hole), and only if the water or gas has come from below. Nor can we direct injection or a treatment into one individual layer. The wall must be stable. Under drawdown (when the pressure in the well is lower than the reservoir pressure), weak rock will collapse or begin to produce sand.
Slotted liner (screen): We run a pipe with slots, a wire wrap or a mesh into the open hole, and we do not cement it. The screen keeps the wall from collapsing and holds sand back. We size the slots to the sand grains: slots that are too wide let sand through, and slots that are too narrow soon plug up and reduce productivity. The intervals are still not separated. This option is inexpensive. An ordinary slotted liner works well with coarse, uniform sand. Mesh screens and expandable screens (screens that are opened out against the wall of the hole after they are run in) have widened the range of use (Sand control methods).
Cased and perforated completion: We run a production casing string through the reservoir, either all the way to the wellhead or as a liner (a shorter string that hangs from the bottom of the casing above it), and we cement it. Then a perforating gun shoots tunnels through the pipe and the cement into the rock (Shaped-charge perforating). We open only the intervals that we need. Later we can perforate new ones and isolate the ones that now produce water. Everything depends on the quality of the cement sheath (the ring of cement behind the casing). If there is no cement behind the casing, or the cement does not seal, fluid will travel along the outside of the casing. It may reach a neighbouring interval, or the perforations that it was meant to be kept away from. Then the isolation has to be restored by remedial cementing (pumping more cement in to seal the leak). This is the most expensive and the slowest option: it needs pipe, cement, perforating and rig time. A liner instead of a full string to the wellhead saves pipe.

Comparison of bottomhole completions

Parameter: Fluid path
Open hole: the whole wall of the hole
Slotted liner: the wall of the hole, then the slots or mesh
Perforated casing: perforation tunnels

Parameter: Control of intervals
Open hole: none
Slotted liner: none
Perforated casing: yes

Parameter: Requirements for the rock
Open hole: stable
Slotted liner: may be weak
Perforated casing: any

Parameter: Cost and time
Open hole: lowest
Slotted liner: modest
Perforated casing: highest

Parameter	Open hole	Slotted liner	Perforated casing
Fluid path	the whole wall of the hole	the wall of the hole, then the slots or mesh	perforation tunnels
Control of intervals	none	none	yes
Requirements for the rock	stable	may be weak	any
Cost and time	lowest	modest	highest

Most fields need to choose the intervals for production, injection and treatments. So cemented and perforated casing, or a cemented and perforated liner, is the most common bottomhole completion.

We use open hole where its drawbacks do not matter. One case is a naturally fractured reservoir (a reservoir with natural cracks in the rock), where it is important not to block the fractures with cement. Another is some horizontal and multilateral wells (wells with a horizontal section, or with several branches from one main hole), where cementing and perforating a long hole is too expensive. A third is a deep, strong reservoir produced by depletion (the pressure just falls as fluid is taken out), where the intervals do not need to be separated. The last is a project where a low well cost is decisive. We install a screen in weakly cemented sandstones. In highly deviated holes (holes that are far from vertical) we also use a screen to keep the hole from collapsing and to let tools pass through it.

What decides the choice of bottomhole completion

The choice comes down to a few questions about the reservoir and about how the well will work.

Is the rock stable? Strong limestone or tight (dense) sandstone can stay open without collapsing. Weakly cemented sandstone (sandstone whose grains hold together poorly) needs a screen or a gravel pack (Sand production: types, prediction and cost of the problem).
Do the intervals need to be separated? Several reservoir layers at different pressures are an argument for cemented casing. So are water or a gas cap (free gas above the oil) close by, and waterflooding (injecting water to push the oil out) of layers with different permeability (how easily fluid flows through the rock). In open hole, fluid can flow from one layer to another (crossflow) when the layers are at different pressures. And one high-permeability layer will take over both the injection and the production.
What treatments are planned? An acid treatment aimed at chosen layers, and an ordinary hydraulic fracturing job (pumping fluid at high pressure to crack the rock), both need isolated intervals.
How badly did drilling damage the reservoir? Perforation tunnels can reach right through a shallow damaged zone. In open hole, the flow has to pass through the whole damaged wall of the hole (damage and completion). On the other hand, open hole adds no resistance from perforations, and it suffers no damage from cement.
What kind of hole is it? In a long horizontal hole, cementing and perforating are expensive and risky, and the area of contact with the reservoir is large anyway.
What will happen in ten years? The water cut (the share of water in the produced liquid) may rise. The reservoir pressure may fall. The well may need artificial lift (a pump or gas lift to raise the fluid). The completion must allow for what will be needed later.

The flow conduit: through casing or through tubing

Fluid can travel from the reservoir to the wellhead (and in an injection well, in the opposite direction) through the production casing itself, or through tubing run inside it. The choice depends on how stable the flow is, how well the casing is protected from corrosion (being eaten away) and wear, and whether we can kill the well and control it. It also depends, of course, on cost. For a single reservoir there are four options.

SchematicFour flow conduit options. From left to right: through the casing, without tubing; through the tubing and the annulus at the same time; through the tubing, with the annulus closed at the wellhead and no packer (gas collects in the annulus); and through the tubing with a packer that isolates the annulus. The diagram is not to scale.

Through the casing, without tubing: This is the simplest and cheapest option, but it has serious drawbacks. In wide casing the velocity is low. The gas separates from the liquid and slips up through it, so the column becomes heavier and the flow unstable. The production touches the casing. It corrodes the casing if it contains hydrogen sulfide or carbon dioxide, and it wears the casing away (abrades it) if sand is produced. The casing is the only shell that holds the well fluids in, and if it weakens, it may rupture at the wellhead. Finally, we can kill such a well only by bullheading (pumping its contents back into the reservoir under pressure) or by the volumetric method (letting fluid out at the wellhead in small steps, keeping the pressure in the well under control). It is rarely used.
Through the tubing and the annulus: This option is for high-rate wells that need a large cross-section. The tubing gives one main advantage here: a path for circulation. We can pump kill fluid into the annulus and displace the production up the tubing, without forcing it into the reservoir. The option is suitable only if the production contains no corrosive or abrasive components.
Through the tubing, annulus closed at the wellhead: The flow goes through the tubing, where the velocity is high enough for stable lifting. But there is no packer, so the annulus is open to the production at the tubing shoe (the bottom end of the tubing). If the bottomhole pressure is below the bubble point pressure (the pressure below which gas comes out of the oil), part of the gas rises into the annulus and collects there, pushing the liquid level down. When the gas reaches the tubing shoe, it breaks into the tubing in one large slug, and then everything repeats. These regular surges are called annulus heading. The casing is still not protected from the production.
Through the tubing with a packer: A packer closes off the annulus above the reservoir. The production goes only through the tubing, and the casing above the packer is protected from pressure and corrosion. We set the packer as close to the top of the reservoir as possible, so that the volume below it, where gas can collect, is as small as possible. The price is that circulation is lost. A sliding sleeve in the tubing above the packer brings it back or, if there is no sleeve, a hole punched in the tubing before a workover. This is the most common option: it gives the greatest protection and the best control.

A calculation with the two-phase flow model (a model for gas and liquid flowing together) from the lesson Multiphase flow in tubing shows how strongly the cross-section of the conduit affects the lifting of liquid. We take one well and compare lifting through the tubing with lifting through the casing.

Worked exampleWill the well flow up the casing?

Given (assumed data)

Well: vertical depth 2000 m, wellhead pressure 1.5 MPa, liquid density 850 kg/m³, gas–liquid ratio 100 m³/m³ (gas volume per liquid volume)
Reservoir: pressure 16 MPa, productivity index 60 m³/(d·MPa) (the rate we get for each MPa of drawdown), straight-line inflow (the rate rises in proportion to the drawdown)
Option 1: 73 mm tubing with an inside diameter of 62 mm
Option 2: 177.8 × 10.36 mm production casing without tubing, inside diameter 157.1 mm

Solution

Cross-sectional area: tubing 3019 mm², casing 19,379 mm², which is 6.4 times larger. At a rate of 200 m³/d the velocity of the gas–liquid mixture at the wellhead is 5.9 m/s in the tubing and 0.92 m/s in the casing.
A slow mixture separates. At the wellhead the liquid fills 30% of the cross-section in the tubing and 48% in the casing. The no-slip liquid fraction (the liquid share we would get if gas and liquid moved at the same speed) is the same in both, 13%. The mixture density is 265 kg/m³ in the tubing and 413 kg/m³ in the casing.
To lift 200 m³/d, the bottomhole pressure must be 10.9 MPa up the tubing and 14.2 MPa up the casing. At this rate the reservoir supplies $16 - 200/60 = 12.67$ MPa. That is more than enough for the tubing, but it is 1.5 MPa short for the casing.
The operating point (the rate at which the inflow from the reservoir and the outflow up the well balance). For the tubing, the inflow curve (what the reservoir can supply) and the outflow curve (what the well needs) cross at 273 m³/d, at a bottomhole pressure of 11.4 MPa. For the casing, the outflow curve lies above the inflow line at every rate. They come closest at 120 m³/d, but even there 1.3 MPa is missing.

Answer: Up the tubing the well flows at about 273 m³/d; up the casing without tubing it does not flow at all.

What it means. Friction in the wide casing is negligible. But gas slippage (gas rising through the liquid faster than the liquid moves) more than cancels that gain: at the wellhead the mixture in the casing is one and a half times denser than in the tubing. The conclusion does depend on the rate. The calculated outflow curve of the casing drops below that of the tubing only at rates above 390 m³/d, and this reservoir cannot deliver such rates. For a highly productive well the picture would be the opposite. This is why we choose the cross-section of the conduit for the specific reservoir. The model is simplified: the flow pattern in a wide conduit differs from that in tubing. The calculation shows the direction and the order of magnitude of the effect, not exact values. The data in this example are assumed for illustration. The pressures are absolute (counted from zero pressure), and the inflow is a straight line that ignores gas coming out of solution in the reservoir.

CalculatedCalculated outflow curves for the example: the bottomhole pressure needed to lift the liquid through tubing with an inside diameter of 62 mm and through casing with an inside diameter of 157 mm, and the inflow line (dashed). The line crosses the tubing curve on its stable branch (the rising part to the right of the minimum, where the flow is steady). This is the operating point. The casing curve lies above the inflow line at all rates.

Tubing diameter

The example showed an extreme case: the choice between tubing and casing. The same logic decides the diameter of the tubing itself. If the tubing is too wide, liquid collects when the rate is low, and the flow is unstable. If the tubing is too narrow, friction takes away too much pressure when the rate is high. Between these two extremes the outflow curve has a minimum, and the operating point must lie to the right of it (the outflow curve and its minimum).

We choose the diameter by nodal analysis: we plot outflow curves for several sizes and compare the rates we get (an example of such a comparison).
We repeat the calculation for future conditions: a lower reservoir pressure and a higher water cut. Tubing that is a good choice at the start may turn out to be too wide after a few years, and changing it means a workover.
In gas wells and gas-condensate wells (gas wells that also produce light liquid hydrocarbons), the diameter must make sure that the liquid is carried out of the well. Otherwise the liquid collects at the bottom.
The production casing sets the upper limit. The tubing couplings, the safety valve and, with artificial lift, the pump or the gas lift mandrels (fittings in the tubing that hold the gas lift valves) must all fit inside it (Artificial lift: when it is needed and how to choose the method).
The instruments and tools that will be used to survey and service the well must pass through the tubing.
We design the tubing for tension and for internal and external pressure in the same way as casing (Casing design). We choose the material according to what the production contains.

What the tubing string must be able to do

The tubing string is not just a pipe from the reservoir to the wellhead. Together with the production casing and the wellhead equipment, it forms a system. The system lets fluid and pressure out only into the flowline (the pipe that carries the production away from the wellhead). It also lets us shut the well in whatever happens. Five functions are mandatory for most wells.

Main functions of the tubing string

Function: Hold pressure and carry the flow
What provides it: tubing hung in the tubing head; the valves and the choke (a valve with a small opening that sets the flow rate) of the Christmas tree (the valve assembly at the top of the well)

Function: Shut off the flow inside the well
What provides it: a downhole safety valve

Function: Isolate the annulus
What provides it: a packer at the lower end of the tubing

Function: Plug the tubing
What provides it: a landing nipple, into which a plug is run on wireline (a thin steel wire that lowers tools into the well)

Function: Connect the tubing with the annulus
What provides it: a sliding sleeve or a mandrel with a valve above the packer

Function	What provides it
Hold pressure and carry the flow	tubing hung in the tubing head; the valves and the choke (a valve with a small opening that sets the flow rate) of the Christmas tree (the valve assembly at the top of the well)
Shut off the flow inside the well	a downhole safety valve
Isolate the annulus	a packer at the lower end of the tubing
Plug the tubing	a landing nipple, into which a plug is run on wireline (a thin steel wire that lowers tools into the well)
Connect the tubing with the annulus	a sliding sleeve or a mandrel with a valve above the packer

The lesson Completion string equipment covers the design and the types of this equipment.

SchematicThe tubing string of a naturally flowing well (a well that flows without a pump) with a packer, and its main components. Production rises from the perforations up the tubing to the Christmas tree. The annulus above the packer is filled with packer fluid. The diagram is not to scale.

Christmas tree: The wellhead equipment of a producing well. It has two parts: the tubing head, in which the tubing is hung, and the block of valves above it, which is the tree proper. The master valves shut off the tubing. The side outlets lead through a choke to the flowline, and a kill line can be connected to them.
Subsurface safety valve (SSSV): A valve in the tubing, tens or hundreds of metres below the surface. It shuts off the flow if the wellhead equipment is damaged or cannot be reached. A valve controlled from the surface is held open by the pressure in a thin hydraulic line, and it closes when that pressure is lost. Offshore, in wells that contain hydrogen sulfide and near populated areas, this kind of backup way to shut in the well is, as a rule, mandatory.
Packer: A device with a rubber sealing element. When it is set, it expands between the tubing and the casing and closes off the annulus. Most naturally flowing wells need one, for stable flow and to protect the casing from corrosion. Injection wells and reservoir treatments need one for another reason too: so that the high injection pressure does not act on the casing and the wellhead.
Landing nipple: A short piece of pipe (a sub) with a specially shaped inside surface, called an internal profile. A plug, a downhole gauge or another device run on wireline locks into it (Wireline operations). A plug in the nipple shuts off the reservoir, for example so that the tubing can be pressure-tested (tested for leaks under pressure).
Sliding sleeve: A sleeve with windows (ports) in its wall. A tool run on wireline opens and closes them. We flush and kill the well through the open ports. While the well is producing, the sleeve is closed.

Beyond these five, the tubing string may need other capabilities. One is an assembly that makes up for the tubing getting longer and shorter when the temperature and pressure change. Another is a disconnect device, so that the upper part of the string can be pulled out without unsetting (releasing) the packer. Others are injection of chemicals at depth, gas lift mandrels or a pump, and a place for downhole gauges. But every capability means more parts, connections and seals, and so more places where something can fail. That is why we first decide the minimum set of functions that is necessary. Then we assess each addition separately: what it gives and what risk it carries.

Killing before a workover: why circulation is needed

Sooner or later the tubing string has to be pulled out, for repairs, a change of equipment or work on the reservoir. Before that, we kill the well. We fill it with a fluid whose column gives a pressure at the bottom that is higher than the reservoir pressure, so the well cannot flow. How we can do this depends on the flow conduit that was chosen.

By circulation. If the tubing is open to the annulus at its lower end, we pump kill fluid down one side (the tubing or the annulus), and the production is pushed up the other side to the wellhead, as in a U-tube. The reservoir takes almost nothing.
By bullheading. If there is no circulation, we force the contents of the well back into the reservoir (bullheading). Mill scale (flakes of oxide from the steel), rust and deposits from the walls of the pipes are carried with it into the perforation tunnels and pores, so productivity after the workover may fall (Formation damage and damage skin). The pumping pressure rises as more fluid is forced in, and the strength of the casing limits it. In wide casing without tubing there is another problem: the heavy fluid falls through the light production without pushing it out.

Kill fluid density

\rho_{\text{kill}} = \frac{k_{\text{m}}\,\bar p_R}{g\,h}

where:

$\rho_{\text{kill}}$ density of the kill fluid, kg/m³
$\bar p_R$ current reservoir pressure at depth $h$ (gauge pressure, that is, measured above atmospheric pressure), Pa
$h$ vertical depth of the reservoir (measured straight down), m
$k_{\text{m}}$ margin factor over the reservoir pressure, for example 1.05; it is set by the rules and the work plan, —
$g$ acceleration due to gravity, m/s²

Units: SI

Holds when

The well is filled with a uniform fluid from the bottom to the wellhead, and the wellhead is open.
The reservoir pressure is the current one, from the latest measurements.
Too large a margin is harmful: the higher the overbalance (the amount by which the pressure in the well exceeds the reservoir pressure), the more fluid will be lost to the reservoir.

The pressure of a column of such a fluid is higher than the reservoir pressure by the chosen margin. We round the density up to the nearest step in which the fluid can be prepared.

In other unit systems (2)

Metric units

\rho_{\text{kill}}\,[\text{g/cm}^3] = \frac{k_{\text{m}}\,\bar p_R\,[\text{MPa}]}{0.00981\; h\,[\text{m}]}

density in g/cm³, pressure in MPa, depth in m.

0.00981 MPa is the pressure of a column of fluid with a density of 1 g/cm³ and a height of 1 m.

Oilfield units

\rho_{\text{kill}}\,[\text{ppg}] = \frac{k_{\text{m}}\,\bar p_R\,[\text{psi}]}{0.052\; h\,[\text{ft}]}

density in ppg (pounds per gallon), pressure in psi, depth in ft.

0.052 psi/ft per ppg — from the oilfield formula for hydrostatic pressure.

Worked exampleKilling a well by circulation through a sliding sleeve above the packer

Given (assumed data)

Reservoir: vertical depth 2000 m, reservoir pressure 21.6 MPa
Tubing: outside diameter 73 mm, inside diameter 62 mm; sliding sleeve at 1940 m, packer at 1950 m
Production casing: 177.8 × 10.36 mm (outside diameter × wall thickness), inside diameter 157.08 mm
Margin over the reservoir pressure; pump rate: 5%; 6 L/s

Solution

Kill fluid density: $\rho_{\text{kill}} = \dfrac{1.05\cdot 21.6}{0.00981\cdot 2000} = 1.156$ g/cm³, which we round up to 1.16 g/cm³. Then the overbalance on the reservoir (how far the fluid column pressure is above the reservoir pressure) is $0.00981\cdot 1.16\cdot 2000 - 21.6 = 1.16$ MPa.
Capacity (volume per metre of length): tubing $\frac{\pi}{4}\cdot 62^2\cdot 10^{-3} = 3.02$ L/m; annulus $\frac{\pi}{4}(157.08^2 - 73^2)\cdot 10^{-3} = 15.19$ L/m.
Volumes down to the sleeve at 1940 m: tubing 5.9 m³, annulus 29.5 m³, total 35.3 m³. At a pump rate of 6 L/s, pumping one full volume takes 98 min.
There is no circulation below the sleeve. 1.0 m³ of reservoir fluid remains in the 10 m of tubing and the 50 m of casing below the packer.
For comparison, in the same well without tubing we would have to bullhead the whole volume of the casing down to the perforations into the reservoir: 38.8 m³.

Answer: We need a fluid with a density of 1.16 g/cm³. Replacing the contents down to the sleeve takes about 35.3 m³ and 98 min at 6 L/s.

What it means. Circulation replaces almost everything that was in the well. Only the small amount that the overbalance of 1.16 MPa drives in enters the reservoir. What remains below the sleeve and the packer, about 1.0 m³, has to be bullheaded or bled off gradually (let out a little at a time). That is why we set the sleeve as low as possible and the packer as close to the reservoir as possible. In practice we pump more than one volume, until the density of the fluid coming out equals the density of the fluid going in. The data in this example are assumed for illustration.

The completion as a system of barriers

In a producing well, as in drilling (barriers in drilling), two independent barriers must stand between the reservoir and the surface. A barrier is something that can stop fluid from reaching the surface out of control. In simple terms, the first barrier is made up of the tubing with the packer, the safety valve and the valves of the Christmas tree on the flow path through the tubing. The second is the production casing with its cement, the casing head and tubing head, and the annulus valves. Standards, and the barrier scheme that the operating company has adopted, set the exact make-up of each barrier for a particular well. While the first barrier is intact, the second carries no load. When the first fails, the second takes the pressure, and the production casing is designed for exactly this case (tubing leak).

Failures of completion equipment and their consequences

Failure: Leak in the tubing or a coupling
What happens: the tubing is open to the annulus
What it threatens: the casing is under production pressure: only one barrier is left

Failure: Packer leak
What happens: the annulus is open to the reservoir
What it threatens: the same, and the casing corrodes

Failure: Safety valve failure
What happens: the well cannot be shut in below the wellhead
What it threatens: no backup shut-in if the tree is damaged

Failure: Leak in the tree or a head
What happens: fluid escapes to the outside or between casing strings
What it threatens: a direct threat to people and the environment

Failure: Pump or gas lift valve failure
What happens: the well does not lift liquid
What it threatens: lost production, workover

Failure	What happens	What it threatens
Leak in the tubing or a coupling	the tubing is open to the annulus	the casing is under production pressure: only one barrier is left
Packer leak	the annulus is open to the reservoir	the same, and the casing corrodes
Safety valve failure	the well cannot be shut in below the wellhead	no backup shut-in if the tree is damaged
Leak in the tree or a head	fluid escapes to the outside or between casing strings	a direct threat to people and the environment
Pump or gas lift valve failure	the well does not lift liquid	lost production, workover

The first four failures mean the loss of a barrier: the well is shut in or restricted until the barrier is restored. The last failure means lost production, but no threat to safety.

Well integrity (keeping the barriers sound) is not ensured only during construction. We monitor the pressure in the annulus and in the spaces between the casing strings throughout the life of the well. A rise in pressure where there should be none is the first sign of a leak. We test the safety valve and the tree valves from time to time. We prevent deposits of salts, wax and asphaltenes (heavy, sticky components of crude oil), and corrosion of the tubing, by choosing the right materials and by injecting chemicals. Otherwise they both narrow the conduit and destroy the barriers.

Terms and symbols

Well completion: The bottomhole completion, flow conduit and equipment that turn a drilled hole into a working well.
Bottomhole completion: The way the wellbore is connected to the reservoir: open hole, slotted liner, or cemented and perforated casing.
Tubing string: Tubing with the equipment installed on it, through which the production rises to the wellhead.
Annulus: The ring-shaped space between the tubing and the production casing.
Packer: A device that closes off the annulus between the tubing and the casing.
Subsurface safety valve: A valve in the tubing below the wellhead that shuts off the flow if there is an accident at the surface.
Sliding sleeve: A sleeve with ports in the tubing that connects the tubing with the annulus for flushing and killing.
Packer fluid: The fluid that fills the annulus above the packer. It protects the casing and the tubing from corrosion and balances part of the pressure.
Well kill: Filling the well, before a workover, with a fluid whose column gives a higher pressure than the reservoir pressure.

Common mistakes and misconceptions

Wrong

“The wider the conduit, the smaller the losses and the greater the rate.”

In fact

That is true only for friction. In a wide conduit the mixture moves slowly, the gas slips up through the liquid, and the column becomes heavier. A well with a moderate rate can then stop flowing.

Wrong

“Open hole is always more productive: the inflow goes through the whole wall.”

In fact

Water and gas flow in through the whole wall too, and the flow has to pass through the whole damaged zone. Perforating lets us choose the intervals and shoot right through a shallow damaged zone.

Wrong

“A packer is needed only in high-pressure wells.”

In fact

A packer protects the casing from corrosion, makes the flow in the tubing stable and separates the annulus from the reservoir. Most naturally flowing wells and injection wells need all of this.

Wrong

“The more equipment in the tubing string, the better the well is controlled.”

In fact

Every component also brings seals, connections and moving parts that can fail. We limit the set to what is necessary, and we weigh the benefit and the risk of every addition.

Wrong

“A well can always be killed — it is enough to pump in heavy fluid.”

In fact

Without a path for circulation, the fluid has to be forced into the reservoir together with the contents of the well. This damages the reservoir, and the strength of the casing limits it. So we build the possibility of circulation into the completion in advance.

In depth: advanced detail

Features of different kinds of wells

The general scheme is the same: bottomhole completion, conduit, tubing string. But the requirements depend on what the well is for and how it produces.

Injection wells. The wellhead pressure during injection is high, so a packer is mandatory. It keeps this pressure off the production casing. We can control injection layer by layer only in cased hole or in a hole divided by packers.
Gas wells. Gas passes through the slightest leak, so we join the tubing and casing with gas-tight connections (threaded connections). We choose the tubing diameter so that the gas moves fast enough to carry condensate (light liquid hydrocarbons) and water out of the well.
Wells with pumps. With sucker rod pumps (driven by a rod from the surface) and electric submersible pumps (driven by an electric motor in the well), a packer is often not installed. Free gas separates at the pump intake and leaves up the annulus. We use the liquid level in the annulus to judge the bottomhole pressure (pressure from the dynamic fluid level).
Gas lift wells. We feed gas into the annulus, and it enters the tubing through valves in mandrels. The packer keeps the gas from escaping into the reservoir and protects the reservoir from the injection pressure (Gas lift: principles and choice of operating conditions).
Horizontal wells. We complete the long hole in the reservoir as open hole, with a screen or with a liner. The choice depends on how stable the rock is, how close the water and gas are, and what treatments are planned (Horizontal wells).
Several reservoirs. We can produce the reservoirs together, separately through two tubing strings, or one after another. This needs additional packers and valves (Multiple-zone completions: commingled and segregated production).

Connections to other topics

Casing: purpose, types, properties and standards — the production casing and liner in which the completion equipment sits.
Casing design — the loads the production casing is designed for: a tubing leak and emptying of the casing (evacuation).
Multiphase flow in tubing — why the column is heavier in a wide conduit: slip and the outflow curve.
Nodal analysis of the production system — choosing the tubing diameter from the operating point of the well.
Formation damage and damage skin — damage to the reservoir during opening and killing, and the choice between open hole and perforating.
Artificial lift: when it is needed and how to choose the method — how the method of artificial lift changes the requirements for the completion.
Completion string equipment — the design of packers, safety valves, nipples and sliding sleeves.
Shaped-charge perforating — how the reservoir is opened in a cased well.

Check yourself

1
Strong, naturally fractured limestone, a single productive interval, water far away, a project with a limited budget. Which bottomhole completion is best suited?
1. A.Slotted liner
2. B.Open hole
3. C.Gravel pack
4. D.Cemented and perforated casing
Show the answer
Correct answer: B. Open hole
The rock is stable, the intervals do not need to be separated, and cement could block the fractures that the inflow comes through. Open hole is both cheaper and more productive here. A screen and a gravel pack are for weak rock. Perforated casing is for cases where we must control the intervals.
2
Why is the packer set as close to the top of the reservoir as possible?
1. A.So that the volume below the packer, where gas collects, and the section of casing in contact with the production are as small as possible
2. B.So that it does not interfere with running instruments
3. C.Because a packer does not hold pressure deeper down
4. D.To increase the rate
Show the answer
Correct answer: A. So that the volume below the packer, where gas collects, and the section of casing in contact with the production are as small as possible
Everything below the packer is unprotected, and circulation does not flush it. There the casing is in contact with the production, and gas can collect under the packer and make a workover harder. The lower the packer and the sliding sleeve above it, the smaller this volume.
3
A well with a rate of 150 m³/d flows steadily up 73 mm tubing. What is most likely to happen if the tubing is pulled and the flow is sent up 178 mm casing?
Show the answer
The cross-sectional area will increase roughly six times, and the mixture velocity will fall by the same factor. The gas will start to slip up through the liquid, liquid will collect, and the column will become heavier. The bottomhole pressure that the well needs will rise by several megapascals. The rate will fall, and the flow will pulse. If the reservoir pressure has only a small margin, the well will stop flowing. In addition, the production will now be in contact with the casing.
4
The reservoir pressure is 30 MPa at a vertical depth of 2800 m. Find the density of the kill fluid with a 5% margin and the overbalance on the reservoir.
Show the answer
$\rho_{\text{kill}} = 1.05\cdot 30/(0.00981\cdot 2800) \approx 1.147$ g/cm³; rounding up gives 1.15 g/cm³. The pressure of the column is $0.00981\cdot 1.15\cdot 2800 \approx 31.6$ MPa, so the overbalance is about 1.6 MPa.
5
A few years on, one layer in the middle of the productive interval has watered out. In which kind of well is it easiest to isolate?
1. A.With cemented and perforated casing
2. B.With open hole
3. C.With an uncemented slotted liner
4. D.The bottomhole completion does not matter
Show the answer
Correct answer: A. With cemented and perforated casing
Behind cemented casing the layers are separated by cement, and we can close the holes opposite the watered-out layer. We can use squeeze cementing (forcing cement through the holes under pressure), a plug or a patch. In open hole and behind an uncemented screen, the water will bypass any barrier inside the hole. It will go round it through the annulus or through the rock itself.
6
Tubing with an inside diameter of 62 mm has been run to 2500 m. What is its internal volume, and how many minutes will a pump delivering 5 L/s need to fill it with kill fluid?
Show the answer
Capacity: $\frac{\pi}{4}\cdot 62^2\cdot 10^{-3} \approx 3.02$ L/m; volume $2500\cdot 3.02 \approx 7550$ L, that is, about 7.5 m³. Time: $7550/5 \approx 1510$ s — about 25 minutes.

Updated: 28 October 2026