Multiple-zone completions: commingled and segregated production

Quick refresher

We develop zones that have different pressures, fluid properties or contacts as separate units, if impermeable beds that continue across the whole area lie between them. One well can produce them commingled, in a multiple-zone (segregated) completion, or one after another.
In commingled production the zones share one bottomhole. Each zone gives $J_i(\bar p_{R,i} - p_{wf})$ . This is in proportion to its productivity index (the rate per unit of pressure drop) and to the difference between its own pressure and the common bottomhole pressure, with both pressures referred to one depth. A zone with a lower pressure does not produce when the well rate is low. In a shut-in well it takes in fluid from the other zones. This is crossflow through the wellbore.
When one zone starts to produce water, the column of fluid in the tubing gets heavier. This raises the bottomhole pressure for all the zones, so the water of one zone takes oil away from another zone. At a high enough water cut (the share of water in the produced liquid), it pays to close the watered-out zone.
Segregated production gives back control of each zone: the rate, testing, workovers and treatments. But it needs more equipment, smaller pipe diameters and higher costs. Every packer and valve is one more place where something can fail.
We allocate the production of a commingled well among the zones by calculation, by production logging (PLT: a tool run in the well to measure how much each zone gives) or by the composition of the oil. Allocation in proportion to $kh$ (permeability times thickness) or to productivity does not see the differences in pressure and water cut between the zones. It can be wrong by a factor of several.
In Kazakhstan, one well may produce two or more development units at the same time, but separately, only if its equipment meters (measures) the production of each unit separately and lets each unit be tested. The mandatory set of surveys of multi-zone units includes measurements of pressure and rate in each zone.

Key relationships

q_i = J_i\,(\bar p_{R,i} - p_{wf})

rate of zone $i$ at the common bottomhole pressure; pressures referred to one depth

p_{wf} = \dfrac{\sum_i J_i\,\bar p_{R,i} - q}{\sum_i J_i}

common bottomhole pressure at a total rate $q$

p_{ws} = \dfrac{\sum_i J_i\,\bar p_{R,i}}{\sum_i J_i}

pressure in the shut-in well; zones with a pressure below $p_{ws}$ take the crossflow $J_i(p_{ws} - \bar p_{R,i})$

f_1 = \dfrac{C_{\text{mix}} - C_2}{C_1 - C_2}

share of zone 1 in the mixture, found from a tracer property (a property that differs between the zones and so marks them) that mixes linearly

Common pitfalls

Comparing the pressures of zones that were measured at different depths, without converting them to one common depth.
Assuming that the sum of the rates of zones tested separately equals the rate when they produce together. The zones share one lift, so the sum comes out too high.
Allocating the production of a commingled well in proportion to $kh$ without checking it by measurements.
Forgetting about crossflow at shut-in. Oil, gas or water from the other zones goes into the zone with the lower pressure, and with it go incompatible salts and particles.
Installing a complex multi-packer arrangement in a highly deviated hole without assessing the risk of running it and of future workovers.

After this lesson you can

tell commingled, multiple-zone (segregated) and alternate production apart, and explain what each one gives and what it costs
calculate the rates of the zones at a common bottomhole pressure, the pressure in a shut-in well and the crossflow through the wellbore
explain, and estimate by calculation, how one zone that starts to produce water reduces the oil production of another zone when they are lifted together, and when it pays to close the watered-out zone
describe the arrangements for two or more zones (production up the annulus, two tubing strings, or one string with zone switching) and their equipment
allocate the production of a commingled well among the zones by different methods, and understand where each method goes wrong
describe what intelligent completion (a well with valves and gauges at the bottom that are controlled from the surface) offers, and what requirements for separate accounting and testing of the zones are set in Kazakhstan

Several zones in one well: three strategies

The productive section of a field often includes several beds of sandstone or carbonate, with shales (clay-rich rock) or tight rocks (rocks with very low permeability) between them. The vertical permeability of these interbeds decides whether the beds are connected (Reservoir heterogeneity and permeability averaging). If the vertical permeability is negligible, the beds are in essence separate accumulations. Their contacts and their oil can differ from the very start. During development each bed is depleted on its own, so their pressures move apart (differential depletion of the beds).

Such beds are combined into development units or kept separate. This is the first stage of designing the development of a field. Under the Unified Rules for the Rational and Integrated Use of Subsoil, zones with the same oil column, similar oil and reservoir properties, similar drive mechanisms (the natural energy that pushes the oil out) and similar reservoir pressures are combined into one production unit. If two or more units are identified, there must be impermeable beds between them that can be traced everywhere across the area. We can drill a separate pattern of wells for each unit. But if the units lie one above another, it is tempting to open them with one well.

Commingled production: All the zones are open and produce into a common wellbore. The production mixes at the bottom of the hole and is lifted through a single conduit. This needs the fewest wells, and the equipment is the same as for a single-zone well. But we cannot control, measure or test the zones separately.
Multiple-zone completion (segregated production): The zones are separated by packers. Each zone has its own conduit or its own controllable downhole equipment. We can set the operating mode of each zone, measure its rate, and test it, treat it or shut it off without stopping the others. For production, the practice is also called simultaneous separate production. For injection, it is called simultaneous separate (dual) injection.
Alternate production (alternate completion): The well opens several zones but produces from only one. A plug or a closed sliding sleeve cuts off the others. When a zone is depleted or has started to produce water, we isolate it and switch the well to the next zone, usually from the bottom up. The arrangement stays simple, as in a single-zone well. But each zone waits its turn. To produce from all the zones at the same rate we need more wells, and the development takes longer.

Three strategies for several zones

Feature: Wells for the same offtake
Commingled: fewest
Segregated: the same as commingled
Alternate: more

Feature: Control of each zone
Commingled: none
Segregated: yes
Alternate: of one zone at a time

Feature: Accounting and testing by zone
Commingled: indirect
Segregated: direct
Alternate: direct

Feature: Complexity and risk of failures
Commingled: low
Segregated: high
Alternate: low

Feature: Conduit diameter
Commingled: full
Segregated: reduced
Alternate: full

Feature	Commingled	Segregated	Alternate
Wells for the same offtake	fewest	the same as commingled	more
Control of each zone	none	yes	of one zone at a time
Accounting and testing by zone	indirect	direct	direct
Complexity and risk of failures	low	high	low
Conduit diameter	full	reduced	full

The comparison is qualitative; in each project it is checked by calculating production and costs over the whole life.

Commingled production: a common bottomhole and crossflow through the wellbore

When the zones are open into one wellbore, they have one bottomhole pressure. More precisely, the pressures in the wellbore opposite the zones differ only by the weight of the column of fluid between them. That is why we compare the zone pressures and the bottomhole pressure at one depth, for example at the tubing shoe (the bottom end of the tubing). We convert the zone pressure to this datum depth (the reference depth) by subtracting the weight of the column of fluid in the casing between the zone and the datum.

Zone rates at a common bottomhole pressure

q_i = J_i\,(\bar p_{R,i} - p_{wf}),\qquad p_{wf} = \frac{\sum_i J_i\,\bar p_{R,i} - q}{\sum_i J_i},\qquad q = \sum_i q_i

where:

$q_i$ rate of zone $i$ at standard conditions (fixed reference pressure and temperature); negative means the zone is taking fluid, m³/d
$J_i$ productivity index of the zone, referred to the datum depth, m³/(d·MPa)
$\bar p_{R,i}$ average reservoir pressure of zone $i$ , referred to the datum depth, MPa
$p_{wf}$ bottomhole pressure at the datum depth, MPa
$q$ total rate of the well, m³/d

Units: metric oilfield units (any consistent system will do)

Holds when

The inflow of each zone is linear: single-phase (only liquid flows) and above the bubble point pressure (Inflow performance relationship (IPR)). For two-phase inflow we use the IPR curves of the zones (curves of rate against bottomhole pressure) instead of straight lines, and we find the common pressure by a numerical calculation.
The pressures are referred to one depth: $\bar p_{R,i} = p_i - \rho g\,(z_i - z_0)$ , where $p_i$ is the pressure at the depth $z_i$ of the zone, $z_0$ is the datum depth, and $\rho$ is the density of the fluid in the casing between them.
Pressure losses in the wellbore between the zones are small. The productivity indices do not change during the period considered.

The common bottomhole pressure is the average of the zone pressures, weighted by $J_i$ , reduced by $q/\sum J_i$ . A zone with a high productivity index gives more even at a lower pressure. A zone with a pressure below the bottomhole pressure does not produce but takes in fluid. A reservoir simulation model solves the same problem for a well that opens several layers of the grid (a well in several layers).

Pressure in a shut-in well and crossflow through the wellbore

p_{ws} = \frac{\sum_i J_i\,\bar p_{R,i}}{\sum_i J_i},\qquad q_x = \sum_{\bar p_{R,i} < p_{ws}} J_i\,(p_{ws} - \bar p_{R,i})

where:

$p_{ws}$ pressure in the wellbore of the shut-in well at the datum depth, MPa
$q_x$ crossflow through the wellbore: the rate taken by the zones with a pressure below $p_{ws}$ ; the others give the same amount, m³/d
$J_i,\ \bar p_{R,i}$ productivity index and reservoir pressure of the zones, as above, m³/(d·MPa), MPa

Units: metric oilfield units

Holds when

The well is closed at the wellhead, but the zones are connected through the wellbore.
The injectivity (how easily a zone takes in fluid) of the zone that takes the crossflow is taken as equal to its productivity. If water or gas, with a different viscosity, goes into it, the injectivity will be different too.
The estimate uses the productivity indices at constant average zone pressures. In the first hours after shut-in, while the pressure near the wellbore builds up, the crossflow is different. During a long shut-in the zone pressures converge and the crossflow dies out.

A shut-in well with several open zones keeps working inside itself. The zone with the higher pressure gives up fluid, only not to the surface but into the neighbouring zone. The volume of crossflow grows with the duration of the shut-in.

Worked exampleTwo zones in a common wellbore: rates, shut-in and crossflow

Given (assumed data)

Zone A (upper): middle of the perforated interval at 2010 m, reservoir pressure at this depth 16.58 MPa, $J_A$ = 40 m³/(d·MPa)
Zone B (lower): 2040 m, 17.83 MPa, $J_B$ = 25 m³/(d·MPa)
Datum depth: tubing shoe at 2000 m; below the shoe the casing contains oil of 0.85 g/cm³
Operating mode: a pump holds the bottomhole pressure at 12.0 MPa at the datum depth; then the well is shut in for 3 d

Solution

We convert the pressures to 2000 m: $\bar p_{R,A} = 16.58 - 0.00981\cdot0.85\cdot10 = 16.50$ MPa, $\bar p_{R,B} = 17.83 - 0.00981\cdot0.85\cdot40 = 17.50$ MPa. At their own depths the two pressures differ by 1.25 MPa. At one depth they differ by 1.00 MPa.
Rates at 12.0 MPa: $q_A = 40\cdot(16.50 - 12.0) = 180.0$ m³/d, $q_B = 25\cdot(17.50 - 12.0) = 137.5$ m³/d, and 317.5 m³/d in total.
Shut-in: $p_{ws} = \dfrac{40\cdot16.50 + 25\cdot17.50}{65} = 16.885$ MPa. This is above the pressure of zone A. The crossflow from B into A is $40\cdot(16.885 - 16.50) = 15.4$ m³/d, which is about 46 m³ in 3 d.
Zone A stops producing when the bottomhole pressure rises to its own pressure of 16.50 MPa. The total rate is then $25\cdot(17.50 - 16.50) = 25.0$ m³/d. At a lower total rate, zone A takes in fluid.

Answer: The zones give 180.0 and 137.5 m³/d. In the shut-in well, zone B flows into zone A at a rate of about 15.4 m³/d. At a total rate below 25.0 m³/d, zone A does not produce.

What it means. Zone A is more productive, so it gives more at a lower pressure. But as soon as we reduce the offtake, it is the first to shut off, and in a shut-in well it takes fluid in. While the fluid that flows across is the oil of zone B, the loss is small, because most of it comes back at start-up. It is worse if B has started to produce water, or if its water is incompatible with the water of A. Then water, salts and particles enter the near-wellbore zone of A (scale deposits). If we had compared the pressures without referring them to one depth, the difference would have been overstated by a quarter. The data in this example are assumed for illustration.

CalculatedCalculated straight-line IPRs of zones A and B from the example, and the composite line of the well. The pressures are at a depth of 2000 m. Above 16.5 MPa the rate of zone A is negative: the zone takes in fluid. In the shut-in well the pressure settles at 16.885 MPa, and zone B flows into zone A.

If the bottomhole pressure is below the bubble point pressure, the IPR lines of the zones curve (Vogel's equation). Then we plot the composite curve point by point: at each bottomhole pressure we add the rates of the zones. The principle is the same.

How the watering-out of one zone takes oil from another

The zones share not only the bottomhole but also the lift (the tubing and the energy that raises the fluid). The column of mixture in the tubing sets the bottomhole pressure of a producing well (Multiphase flow in tubing, Nodal analysis of the production system). If one zone starts to produce water, the mixture in the tubing gets heavier and has less gas per unit of liquid. Water is added, but oil, which carries the gas, is not. The bottomhole pressure needed for lifting rises for all the zones at once. The watered-out zone “pushes back” on the dry zone too: the dry zone gets a smaller drawdown and gives less oil.

Worked exampleWatering-out of the lower zone in a flowing well

Given (assumed data)

Zones: A and B from the previous example: $\bar p_{R,A}$ = 16.50 MPa, $J_A$ = 40; $\bar p_{R,B}$ = 17.50 MPa, $J_B$ = 25 m³/(d·MPa) at a depth of 2000 m
Well: naturally flowing, from the lesson on multiphase flow: 73 mm tubing (inside diameter 62 mm) down to 2000 m, wellhead pressure 1.5 MPa; oil of 850 kg/m³ carries 100 m³ of free gas per 1 m³
Water breakthrough: after a few years zone B produces 70% water of density 1100 kg/m³; zone A is still dry; the zone pressures are maintained by injection (pumping in water or gas to keep the pressure up), and the productivity indices for liquid are unchanged (an assumption of the example)

Solution

While both zones are dry, the inflow and outflow curves cross at a bottomhole pressure of 11.93 MPa. Zone A gives $40\cdot(16.50 - 11.93) = 183$ m³/d, zone B gives $25\cdot(17.50 - 11.93) = 139$ m³/d, and the total is 322 m³/d of oil.
Zone B has started to produce water. The new crossing is at 13.44 MPa. Zone A gives $40\cdot(16.50 - 13.44) = 122.4$ m³/d of oil. Zone B gives $25\cdot(17.50 - 13.44) = 101.5$ m³/d of liquid, and the oil in it is $0.3\cdot101.5 = 30.45$ m³/d. The oil fraction of the liquid is $(122.4 + 30.45)/(122.4 + 101.5) = 0.6827$ . The liquid in the tubing is heavier: $850\cdot0.6827 + 1100\cdot(1 - 0.6827) = 929$ kg/m³. It also has less gas: 68 m³ per 1 m³. The total oil is 153 m³/d.
Suppose we close zone B, by a plug in a nipple or by a sliding sleeve. This is possible only in an arrangement with separated zones. Zone A is left. The crossing is at 11.03 MPa, and $40\cdot(16.50 - 11.03) = 219$ m³/d of dry oil. This is more than the two zones give together.
A calculation for different water cuts of zone B (figure below) shows that closing it pays when its water cut is above 44%. At about 90% the well stops flowing altogether.
For comparison, here are tests of the zones separately before water breakthrough. Zone A alone gives 219 m³/d, and zone B alone gives $25\cdot(17.50 - 10.81) = 167$ m³/d. The sum of 386 m³/d is 20% more than the 322 m³/d when they produce together.

Answer: After zone B waters out, the well gives 153 m³/d of oil instead of 322, and the dry zone A gives 122.4 instead of 183. If B is closed, zone A alone will give 219 m³/d.

What it means. The water of zone B took a third of the rate away from the dry zone A. The bottomhole pressure rose by 1.51 MPa, because there is more heavy water and less gas in the tubing. On its own, zone B with 70% water would not flow: the gas of zone A lifts its water. Closing the watered-out zone means putting off its oil until later. We decide this by looking at its reserves, the costs of lifting and treating the water, and whether the water can be shut off in the zone itself. The sum of the separate tests overstates the commingled rate, because the zones share one lift. The model does not allow for slip of water relative to oil. With slip the column would be even heavier, and the effect of the water stronger. As in the lesson on well completion, the inflow of the zones is taken along straight lines, ignoring gas coming out of solution in the reservoir, although the gas in the tubing is already free at the shoe. The data in this example are assumed for illustration.

CalculatedCalculated oil production of the flowing well of the example against the water cut of zone B: the total and that from zone A when they produce together, and from zone A alone if zone B is closed (dashed line). To the right of the intersection point it is better to close the watered-out zone.

Water is not the only thing the zones pass to each other through a common wellbore.

Gas. The gas of one zone lightens the column and helps to lift the liquid of the others. This is an argument for commingled production. But if gas from a gas cap has broken through in one zone, we can shut it off only together with the whole well.
Corrosive components. If even one zone produces hydrogen sulfide or carbon dioxide, we need resistant materials for the whole tubing string and the surface equipment. We choose them for the worst zone.
Sand. A weak zone that produces sand forces us to protect the whole lift from erosion, and sand control for one zone in a common wellbore is more difficult (Sand control methods).
Scale. Incompatible waters from different zones mix in the wellbore and the tubing and form scale deposits (scale and incompatible waters).
Treatments. Acid and fracturing fluid go into the most permeable zone. We can direct them into the zone we want only by temporary isolation: packers, plugs or diverters (placement and diversion).
Different oils. Light and heavy oils, and low-sulfur and sour oils, from different zones are mixed, and we can no longer sell them separately.

Arrangements for segregated production of two zones

To work with the zones separately, we separate them with packers: one packer between the zones, and another above the upper zone if production is not to flow up the annulus. Then we choose which conduit the production of each zone will take. The equipment is the same packers, nipples and sliding sleeves as in a single-zone well (Completion string equipment), plus a few special components.

One tubing string, the upper zone through the annulus: The lower zone produces through the tubing, which passes through the packer between the zones. The upper zone produces through the annular space. This is the simplest and cheapest arrangement, with full conduit diameters. But the production casing is exposed to the pressure of the production and is in contact with it. The annulus stops being the second barrier and becomes a flow path (the barrier system). So the arrangement is suitable if the production of the upper zone is not corrosive and carries no sand. Offshore, such an annulus may need an annulus safety valve (safety valves). The strength of the casing limits the treatment of the upper zone.
One string with a crossover: A crossover (a connector that swaps the flow paths) swaps the conduits: the lower zone flows into the annulus above the upper packer, and the upper zone flows into the tubing. In this way the less corrosive production is directed up the annulus. The arrangement is more complex, and access to the zones with instruments is limited.
Two parallel tubing strings (dual-tubing arrangement): The long string passes through both packers to the lower zone. The short string ends in the upper, dual-bore packer (a packer with two openings, one for each string) above the upper zone. Each zone gets its own conduit, its own operating mode, its own metering and its own testing. Both strings hang in one tubing head. The price is smaller-diameter tubing and difficult running and workovers.
Two concentric strings: The inner string goes to the lower zone. The annulus between the inner and outer strings goes to the upper zone. A ring-shaped conduit fills the round cross-section of the production casing more fully than two pipes side by side, so the flow area is larger. On the other hand, a string inside a string is harder to run and pull, and instruments can pass only into the inner one.
One string with zone switching: Two packers separate the zones. There is a sliding sleeve in the tubing opposite the upper zone, and a nipple for a plug below the lower packer. We open the sleeve and set or pull the plug with wireline operations (Wireline operations). This switches the well to the lower zone, to the upper one, or to both at once. The two zones cannot produce separately and at the same time in this way. But the arrangement is simple, the diameter is full, and it is convenient for alternate production and testing.

SchematicTwo arrangements for two zones (diagram, not to scale). On the left, two parallel tubing strings. The short string ends in the dual-bore packer and takes the production of the upper zone. The long string passes through both packers to the lower zone. Blast joints (thick-walled pipe sections) are installed on the long string opposite the perforations of the upper zone. On the right, one string with zone switching: an open sliding sleeve opposite the upper zone and a plug in a nipple below the lower packer, so that only the upper zone produces.

Equipment for two strings. The upper packer is a dual-bore packer: both strings pass through it. The lower packer is a single-bore packer, and it separates the zones from each other. For a third zone we add a triple-bore packer and an intermediate string. It is awkward to turn two strings, or to put weight down on them, separately. So multi-bore packers are more often set by pressure, with the strings closed off by plugs in nipples (ways of setting packers). The choice between a retrievable and a permanent packer is the same as in a single-zone well. A permanent packer holds large pressure differences, and the forces from the lengthening and shortening of the tubing, more reliably (why tubing changes length). A retrievable packer is pulled out together with the strings without milling, and for a well with two strings this noticeably shortens a workover. At the wellhead, a single hanger must close off the annulus although there are two strings. So the hanger is made split. Each string sits in the tubing head on its own part, the parts together close off the annulus, and passages are left in them for the control lines of the safety valves (tubing hanger).

Blast joints. The zone yields fluid in jets from the perforation tunnels. Where the long string passes by the perforations, the jets hit it directly. Gas, and even more so gas with sand, cuts through the wall of an ordinary pipe within months. So we make up the section of the long string opposite the perforations of the upper zone from thick-walled joints.

Diameters. Two tubing strings with couplings must fit side by side in the production casing. So we have to use smaller-diameter tubing, with reduced-diameter couplings, or couplingless tubing. If a zone can give more than the narrow tubing will pass, the segregated arrangement will limit its rate (tubing diameter). That is why we often choose a larger-diameter production casing for dual-tubing wells.

Multiple-zone completions with pumps, and dual injection

In a flowing well (a well that flows by its own energy), segregated production comes down to conduits and packers. In an artificial-lift well (a well with a pump or gas lift), we also have to lift the liquid of each zone. Arrangements with two pumps are common. One pump takes the liquid of the lower zone from below the packer, and the other takes that of the upper zone above the packer. The production is lifted through separate conduits, or it is metered separately (two pumps in one well, Sucker-rod pumping). There are also single-pump schemes. Downhole chokes or valves regulate the offtake of each zone, and sequential measurements or downhole gauges give the rates of the zones. The more pumps, packers and valves there are in a well, the more expensive each of its workovers is.

In injection wells, dual injection (simultaneous separate injection) shares the water out among the zones. Packers separate the zones, and opposite each zone there is a regulator, which is a replaceable choke or valve. We select it so that the zone takes its allotted rate. Without regulators almost all the water goes into the most permeable zone, and that zone waters out the producing wells sooner than the others (Why water is injected: pressure maintenance and oil displacement, Displacement in heterogeneous reservoirs).

The Unified Rules name these tools directly. When multi-zone units are developed, the differences in the flow properties of the zones combined into a unit are taken into account by multiple-zone (simultaneous separate) production or injection, where reliable equipment is available. The injection target of a multi-zone unit is distributed among the individual zones.

Production accounting by zone

We measure the production of a well at the surface, as a total. But reserves, material balance (a bookkeeping of the fluids in the reservoir), and the analysis and regulation of development are done zone by zone and unit by unit (General material balance equation for oil reservoirs). If the zones produce separately, each has its own measurement. If they produce together, we have to reconstruct the rates of the zones. This is called production allocation.

In Kazakhstan, the Unified Rules for the Rational and Integrated Use of Subsoil (the version in force in 2026) establish separate accounting. One well may produce two or more units at the same time, but separately, only with downhole and surface equipment that provides separate accounting of the production and field testing of each unit. The mandatory set of field surveys includes measurements of the pressure of the individual zones of a multi-zone unit, and of the rates of the individual zones with downhole flowmeters (production logging). In injection wells it also includes the injectivity of the individual zones. When wells are tested, each productive zone is tested separately. Zones may be tested together only if the main parameters of each zone are measured separately at different regimes (State regulation of field development).

Methods of allocating the production of a commingled well

Method: In proportion to $kh$ or productivity
What it gives: shares of liquid from logs and tests
Where it goes wrong: does not see differences in pressure, water cut and damage between the zones

Method: By IPR lines at a measured bottomhole pressure
What it gives: liquid rate of each zone
Where it goes wrong: needs current zone pressures and productivity indices; does not see where the water comes from

Method: Sequential measurements with zones shut in
What it gives: rate and water cut of each zone
Where it goes wrong: separately the zones give more than together; shut-ins are needed

Method: Production logging
What it gives: inflow profile and composition of the mixture opposite each zone
Where it goes wrong: a one-off measurement; accuracy falls at low rates and in deviated holes

Method: Oil composition and tracers
What it gives: shares of the zones in the mixture
Where it goes wrong: needs clean samples of each zone and a noticeable difference in composition

Method: Separate metering (multiple-zone completion)
What it gives: continuous accounting of each zone
Where it goes wrong: the well is more expensive and more complex

Method	What it gives	Where it goes wrong
In proportion to $kh$ or productivity	shares of liquid from logs and tests	does not see differences in pressure, water cut and damage between the zones
By IPR lines at a measured bottomhole pressure	liquid rate of each zone	needs current zone pressures and productivity indices; does not see where the water comes from
Sequential measurements with zones shut in	rate and water cut of each zone	separately the zones give more than together; shut-ins are needed
Production logging	inflow profile and composition of the mixture opposite each zone	a one-off measurement; accuracy falls at low rates and in deviated holes
Oil composition and tracers	shares of the zones in the mixture	needs clean samples of each zone and a noticeable difference in composition
Separate metering (multiple-zone completion)	continuous accounting of each zone	the well is more expensive and more complex

The methods complement each other: surveys and sequential measurements check and refine the calculated allocation factors.

Worked exampleWhose rate is it: allocating production after water breakthrough

Given (assumed data)

Well: from the previous example after zone B has watered out; 223.9 m³/d of liquid is measured at the surface, of which 153 m³/d is oil (water cut 31.7%)
Productivity indices from tests before water breakthrough: $J_A$ = 40, $J_B$ = 25 m³/(d·MPa)
Production logging (converted to standard conditions): between the zones the flowmeter shows 101.5 m³/d of liquid with a water cut of 70%; above zone A it shows the whole rate of the well

Solution

Allocation in proportion to the productivity indices: zone A gets $223.9\cdot40/65 = 137.8$ m³/d of liquid, and zone B gets $223.9\cdot25/65 = 86.1$ m³/d. With the same water cut in both zones, the oil of A is 94.1 m³/d and the oil of B is 58.8 m³/d.
By production logging: zone B gives 101.5 m³/d of liquid. Of this, the oil is $0.3\cdot101.5 = 30.45$ m³/d and the water is 71.05 m³/d. Zone A gives $223.9 - 101.5 = 122.4$ m³/d, and it is all oil.
The error of allocation by productivity indices: the oil of zone A is understated by 23%, and the oil of zone B is overstated by a factor of $58.8/30.45 = 1.9$ . In a month, about 850 m³ of the oil of zone A would be credited to zone B.

Answer: Zone A gives 122.4 m³/d of oil. Zone B gives 30.45 m³/d of oil and all the water of the well. Allocation in proportion to productivity indices would credit zone B with almost twice as much oil as it gives.

What it means. The error is not random. Allocation by productivity indices knows neither the difference in pressures nor which zone has started to produce water. On such data zone B looks better than it is, and zone A looks worse. This distorts the material balance of each unit, the forecast and the decision about which zone to isolate. Allocation by IPR lines at a measured bottomhole pressure would divide the liquid correctly (this checks the model of the previous example), but it would not find the water. That is why we survey commingled wells from time to time, and why separate production of units needs separate accounting. The data in this example are assumed for illustration.

Intelligent completion

Intelligent completion (smart well) combines the advantages of commingled and segregated production. Packers separate the zones, and the production goes up a single tubing string. At the inlet of each zone there is an interval control valve (ICV), which is operated from the surface, either hydraulically or by cable. Next to it are permanent downhole pressure and temperature gauges for each zone. Control lines and cables pass through the tubing hanger and through packers that have feed-through passages for the lines.

Control without a workover. We can open, throttle (partly close) or close a zone from the control panel. We can restrict a zone where water or gas is coming in, or close all the zones except one for the duration of a test.
Accounting by zone. We calculate the rates of the zones from the pressures in the zones and in front of the valves, the valve characteristics, and shutting the zones in one after another. Sometimes we also install downhole flowmeters.
Protection against crossflow. When the well is shut in, the valves are closed and the zones are not connected through the wellbore.
Price. The equipment is expensive. The number of zones that we can control is limited by the number of lines that fit in the hanger and pass through the packers. We can put right a failure of a valve or a line only by pulling the string. That is why intelligent completion pays off mainly where a workover is especially expensive: offshore, and in subsea and horizontal wells (completion of a horizontal hole).

How the arrangement is chosen

Differences between the zones. The more the pressures, gas–oil ratios, water cuts, and hydrogen sulfide and salt contents differ, the stronger the argument for separating the zones.
How many wells. Offshore, and on restricted sites, wells are few, and each must work for several zones. Onshore it is often cheaper to drill separate wells for each unit, or to produce the zones in turn.
Well profile. Two tubing strings and multi-packer arrangements are hard to run, and still harder to pull, in a highly deviated hole. There we more often choose a single string with valves.
Diameters. A segregated arrangement means smaller-diameter tubing. If the zones are highly productive, it will limit the rate.
Method of production. Natural flow, gas lift and pumps combine with two conduits in different ways. Pumps for two zones noticeably complicate the arrangement.
Workovers and surveys. How many times in the life of the well will we have to shut off water, treat zones and change equipment? And what will each such workover cost?
Accounting requirements. If the zones belong to different development units, separate accounting and testing of each unit are mandatory.

Terms and symbols

Development unit: A zone or group of zones developed by one pattern of wells. Laterally continuous impermeable beds separate different units.
Commingled production: Several zones produce into a common wellbore, and their production mixes at the bottom of the hole.
Multiple-zone completion: Several zones are produced by one well. Packers separate them, and each zone is controlled, metered and tested separately. Dual injection is the same arrangement for injection.
Alternate production: The well opens several zones but produces from only one. The others are cut off until their turn.
Wellbore crossflow: Fluid flows from a zone at a higher pressure into a zone at a lower pressure through a common wellbore, above all in a shut-in well.
Long and short strings: The tubing strings of a dual-tubing arrangement. The long one goes to the lower zone, and the short one goes to the upper zone.
Blast joints: Thick-walled joints of the long string opposite the perforations of the upper zone. They take the erosion caused by the jets.
Production allocation: The reconstruction of the rates of the zones of a commingled well from the total measurement, surveys and calculation.
Intelligent completion: Separated zones with interval control valves that are controlled from the surface, and permanent downhole gauges.

Common mistakes and misconceptions

Wrong

“A shut-in well produces nothing, so nothing is happening to the zones.”

In fact

If the zones are connected through the wellbore, the zone with the higher pressure flows into the zone with the lower pressure. In the example in this lesson, this is about 15 m³/d. With the crossflow, foreign water, salts and particles enter the zone.

Wrong

“The sum of the zone rates from separate tests is the rate of the well when they produce together.”

In fact

The zones share one lift. When they produce together, the bottomhole pressure is higher than for each zone alone. In the example in this lesson, the sum of the separate tests is 20% more than the commingled rate.

Wrong

“The lower zone has watered out — that does not concern the upper one.”

In fact

Water makes the column in the tubing heavier and raises the bottomhole pressure for all the zones. In the example in this lesson, the dry zone lost a third of its rate, and when the water cut of the lower zone is above about 44%, it pays to close it.

Wrong

“The production of a commingled well can be divided in proportion to the $kh$ of the zones.”

In fact

This divides the liquid correctly only if the pressures and the condition of the near-wellbore zone are the same for the zones. It does not see at all where the water comes from. We check the allocation by surveys, sequential measurements or the composition of the oil.

Wrong

“The more zones per well, the better.”

In fact

With every zone, the number of packers and valves, the probability of failure and the cost of workovers grow, and the conduit diameters shrink. What the arrangement can reliably endure over the whole life limits the number of zones per well.

In depth: advanced detail

Allocation by oil composition

The oils of different zones often differ in composition: the content of sulfur and metals, or the ratios of hydrocarbons on a chromatogram (a record from a laboratory instrument that separates the components of the oil). If there is a property that adds up in proportion to the shares when the oils mix, we can find the share of each zone from a sample of the mixture, as in the problem of mixing two solutions. We take samples of the oil of each zone in advance, when the zone is producing alone, for example during a test.

Share of a zone in a mixture from a tracer property

f_1 = \frac{C_{\text{mix}} - C_2}{C_1 - C_2},\qquad \delta f \approx \frac{\delta C}{\lvert C_1 - C_2\rvert}

where:

$f_1$ share of zone 1 in the mixture — by mass if the property is given per unit of mass (like sulfur content), or by volume, —
$C_{\text{mix}},\ C_1,\ C_2$ values of the property in the mixture and in the oil of zones 1 and 2, units of the property
$\delta C,\ \delta f$ error in determining the property of the mixture and the resulting error of the share, units of the property, —

Units: any, the same for all three values of the property

Holds when

There are two zones, and the property mixes linearly.
The oil samples of the zones are representative, and they have not changed since they were taken.
The error of the share includes only the error of the mixture sample. The errors of the zone samples add to it.

The more the oils differ, the more accurate the method: the error of the share is inversely proportional to the difference $C_1 - C_2$ . For three zones we need at least two independent properties. It is more reliable to use many properties at once and to fit the shares by least squares (making the total squared mismatch as small as possible).

Worked exampleShares of two zones from sulfur content

Given (assumed data)

Oil of zone 1: sulfur 1.42% by mass, density 0.87 g/cm³
Oil of zone 2: sulfur 0.86%, density 0.83 g/cm³
Mixture at the wellhead: sulfur 1.21%; analytical error ±0.03%

Solution

Share of zone 1 by mass: $f_1 = (1.21 - 0.86)/(1.42 - 0.86) = 0.625$ .
By volume: $\dfrac{0.625/0.87}{0.625/0.87 + 0.375/0.83} = 0.614$ .
Error of the share: $\delta f \approx 0.03/0.56 = 0.054$ . That is, the share by mass is between 0.57 and 0.68.
If the oils differed in sulfur by only 0.1%, the same analytical error would give $\delta f \approx 0.03/0.1 = 0.3$ . The method would become useless.

Answer: Zone 1 gives about 61% of the mixture by volume. The share by mass, 0.625, is known to within ±0.054.

What it means. The method is cheap, because it needs only a sample at the wellhead. But its accuracy depends entirely on how different the oils are. That is why we check one tracer against others, and compare the results with production logging or sequential measurements. The data in this example are assumed for illustration.

Connections to other topics

Completion string equipment — packers, nipples, sliding sleeves and safety valves from which multi-zone arrangements are assembled.
Well completion: opening the reservoir and the tubing string — the bottomhole completion, the flow conduit, tubing diameter and well barriers.
Inflow performance relationship (IPR) — the IPR lines of the zones and their sum.
Nodal analysis of the production system — the operating point of a commingled well: the inflow of all the zones against one lift.
Multiphase flow in tubing — why water makes the column heavier and raises the bottomhole pressure.
Pressure measurements in producing reservoirs: barriers and accuracy — the pressures of the beds in an accumulation under development, and differential depletion.
Well model in a grid block — the same problem of distributing the rate among layers in a reservoir simulation model.
Electric submersible pumps (ESP) — two pumps for two zones and other special ESP arrangements.
Sources of formation damage — scale and damage to a zone by foreign water during crossflow.
State regulation of field development — the design documents and the monitoring of development in Kazakhstan.
Multilateral wells — laterals in different zones produce into a common bottomhole — the same problem.

Check yourself

1
Two zones are open into a common wellbore. Zone A: pressure 15.0 MPa, $J$ = 30 m³/(d·MPa); zone B: 18.0 MPa, $J$ = 10 m³/(d·MPa) (pressures at one depth). The well is shut in. What happens?
1. A.Nothing: the well is closed
2. B.Zone B flows into zone A at a rate of about 22.5 m³/d
3. C.Zone A flows into zone B
4. D.The pressure in the wellbore equals 18.0 MPa
Show the answer
Correct answer: B. Zone B flows into zone A at a rate of about 22.5 m³/d
$p_{ws} = (30\cdot15.0 + 10\cdot18.0)/40 = 15.75$ MPa. Zone A, whose pressure is lower, takes $30\cdot(15.75 - 15.0) = 22.5$ m³/d — zone B gives the same amount: $10\cdot(18.0 - 15.75) = 22.5$ m³/d.
2
The pressure of zone A was measured at a depth of 1800 m — 17.10 MPa, and that of zone B at 1850 m — 17.50 MPa; the casing between them contains oil of 0.85 g/cm³. In which direction will the crossflow go in the shut-in well?
Show the answer
Convert the pressure of B to 1800 m: $17.50 - 0.00981\cdot0.85\cdot50 = 17.08$ MPa. At one depth the pressure of A (17.10) is slightly higher, so a weak crossflow will go from A into B. If we compared “17.10 against 17.50” without converting them to one depth, we would get the opposite direction.
3
Why do two zones tested separately in a flowing well give less than the sum of their rates when they produce together?
1. A.Because of crossflow between the zones in the reservoir itself
2. B.Because of measurement errors
3. C.The zones share one lift: at a higher total rate the bottomhole pressure is higher, and the drawdown on each zone is smaller
4. D.That does not happen: the rates add up
Show the answer
Correct answer: C. The zones share one lift: at a higher total rate the bottomhole pressure is higher, and the drawdown on each zone is smaller
There is one outflow curve for all the zones. The total inflow is greater, so the operating point shifts to a higher rate. On the rising branch of the outflow curve it also shifts to a higher bottomhole pressure, so each zone works at a smaller drawdown than in a separate test. In the example in this lesson, the sum of the separate tests is 20% more than the commingled rate.
4
In an intelligent well a pump holds the bottomhole pressure at 12.0 MPa. Zone B (17.50 MPa, $J$ = 25 m³/(d·MPa); pressures at one depth) has watered out, and it has been decided to limit its offtake to 60 m³/d with an interval control valve. What pressure drop must the valve create?
Show the answer
Without the valve the zone would give $25\cdot(17.50 - 12.0) = 137.5$ m³/d. For 60 m³/d the drawdown on the zone must be $60/25 = 2.4$ MPa, so the pressure in front of the valve is $17.50 - 2.4 = 15.1$ MPa. The valve must cut $15.1 - 12.0 = 3.1$ MPa. The pressure drop across the valve grows roughly as the square of the rate. So we select the valve position from its characteristic and refine it using the downhole gauges.
5
Where is multiple-zone completion with two tubing strings most justified?
1. A.An offshore platform with few wells; zones with different pressures, one containing hydrogen sulfide
2. B.Two zones with the same pressure and the same oil, onshore, where wells are cheap
3. C.A highly deviated hole of small diameter
4. D.A highly productive zone that would give more than narrow tubing can pass
Show the answer
Correct answer: A. An offshore platform with few wells; zones with different pressures, one containing hydrogen sulfide
Two strings give complete separation, and we need it most when the zones differ greatly and wells are few. Identical zones are easier to produce commingled. In a deviated hole of small diameter, two strings are hard to run. For a highly productive zone, narrow tubing will limit the rate.
6
The water cut of a well producing from two zones has risen from 5 to 40%. How can one find out which zone has watered out without pulling the equipment?
Show the answer
If there is access below the tubing, run production logging: a flowmeter and mixture composition sensors will show the inflow and water cut opposite each zone. We can close the zones one after another with a plug or a sliding sleeve and measure the production. In an intelligent well we can throttle the valves one after another. Water chemistry helps too. If the waters of the zones differ in salt composition, a sample at the wellhead shows whose water has come in.

Updated: 18 October 2026