A multilateral well has two or more branches connected to one main wellbore. These branches can contact different reservoir layers or different parts of the same reservoir while sharing the upper well. Their trajectories may be horizontal or deviated. Junction design determines how the branches are supported, isolated and accessed. [1, 2]
This guide connects reservoir objectives to lateral layouts, explains TAML junction levels and follows the design through construction, production and intervention. Two hypothetical examples and two separately attributed field reports show why the required functions matter. Directional drilling provides the trajectory-control methods; a multilateral completion must also preserve the intended flow and service paths.
Multilateral, Horizontal and Sidetracked Wells: What Is Different?
A horizontal well describes trajectory. A multilateral describes a branching architecture, so one well can be both. A sidetrack creates a new route from an existing bore; when the original route is abandoned, it does not provide the multiple active drainage paths intended in a multilateral completion. Several wells with separate wellheads on one pad or platform are not a single multilateral with a shared downhole trunk. [1, 2]
For a new well, junction locations can be incorporated into the casing and completion design. A retrofit must work within the existing casing, restrictions and well condition. Review sidetracking options against the required final architecture rather than assuming that every casing exit produces an equivalent multilateral.
Multilateral Drilling Wells Terminology and Layouts
The main bore, also called the parent, mother bore or trunk, is the shared wellbore. A lateral departs from it, and the junction is their intersection. A branch may itself divide again. These terms identify the geometry; none proves that the branch is pressure-isolated, lined, accessible or independently controllable. [1]
A dual lateral has two branches; opposed laterals extend in approximately opposite azimuths. Stacked laterals leave at different depths. Branched, crow’s-foot and herringbone layouts describe other arrangements. The branch/splay labels in Figure 1 are descriptive conventions, not TAML levels. Specify each branch’s depth, inclination, azimuth and reservoir target on the actual well schematic.
Trajectory planning must accommodate the drilling assembly, lateral liner and future intervention tools. A branch that can be drilled may still be difficult to complete or revisit. Check well-trajectory design and horizontal-well geometry against those later-life requirements, not just the reservoir intersection. [1, 2]
Reasons for Drilling Multilateral Wells
Multilateral wells can extend reservoir contact while reusing the upper bore and surface infrastructure. Applications include separate reservoir compartments, thin or layered targets, heavy-oil developments and additional drainage from an existing well. IADC highlights the potential to avoid repeatedly drilling the upper section from surface; Rabia also identifies slot recovery and complex drainage patterns. These are opportunities to evaluate, not guaranteed savings. [1, 2]
The alternative may be a separate well, a longer single lateral or a replacement sidetrack. Compare incremental recoverable production, execution cost and the ability to service each branch. Sharing the upper well can save duplicated construction, but a failure in that common route can affect several branches. The limitations of cost-per-foot comparisons are especially relevant here. [1, 2]
Where an offshore platform has limited slots, sharing infrastructure can be attractive. However, extra contact does not automatically give proportionally higher production: reservoir communication and the shared production path also affect performance. Pressure compatibility and the required commingling strategy therefore belong in the selection study. [1; 3]
Reservoir Conditions and Lateral-Layout Selection
Start with the reservoir target and the required production arrangement, then choose the junction. Rabia links drainage objectives, pressure compatibility, formation strength and later intervention to multilateral planning. The matrix below applies those considerations; it is a screening framework, not a rule assigning one completion to every reservoir type. [1]
| Objective | Layouts or alternatives to evaluate | Evidence that can change the choice |
|---|---|---|
| Contact layers at different depths | Stacked laterals versus separate wells. | Target separation, pressure differences, fluid compatibility and the need to keep streams apart. |
| Reach separate compartments | Branches directed toward the mapped targets. | Connectivity, pressure data, structural uncertainty and feasible exit-to-target trajectories. |
| Distribute contact in one interval | Opposed or branched layouts versus one longer lateral. | Expected drainage, interference, junction stability and useful incremental production. |
| Add drainage from an existing well | A retrofit retaining the productive bore versus a replacement sidetrack. | Existing casing condition, exit dimensions, completion restrictions and remaining life of the parent well. |
Why More Contact May Not Mean More Useful Production
A branch must add useful drainage, not merely drilled length. Ask whether it reaches a distinct target, communicates with another branch, or mainly increases demand on an already constrained common production path. The reservoir and well models must answer those questions together. A longer contact length alone cannot establish additional reserves or a proportional rate increase. [1, 2]
For each shortlisted layout, specify the entry position, target uncertainty and completion passage. A plan that reaches the geology but cannot accommodate its liner or future tools has not solved the design problem. Use the geosteering discussion for placement context; branch access and isolation still require their own design.
How a Multilateral Well Is Drilled and Completed
The following stages connect the reservoir plan to a usable completed well. They describe functions, not a universal rig procedure: the drilling order, temporary barriers and installation sequence depend on the chosen junction and the condition of the existing well. [1, 2]
| Planning or construction stage | Purpose | Key check |
|---|---|---|
| Define the completed well | Set targets, production modes and future intervention needs. | Decide which branches must remain accessible and independently controllable. |
| Prepare the parent bore and exits | Provide the casing, openhole kickoff or window arrangement. | Confirm location, orientation, bore condition and the required lower-bore protection. |
| Construct the branches | Drill the planned trajectories and evaluate the targets. | Maintain the approved barrier state and manage cuttings and milling debris. |
| Install the junction and completion | Provide the specified support, seals and flow-control paths. | Reconcile the installed assembly with the planned pressure boundaries and tool routes. |
| Verify and hand over | Confirm required isolation, access and equipment function. | Record the tests, actual configuration, branch identification and unresolved restrictions. |
A new well can incorporate orienting or prepared-window components into its initial design. A retrofit must fit the existing casing and completion. In both cases, plan how each branch will be suspended, reentered and eventually abandoned before constructing an intersection that later becomes difficult to reach. [1]
TAML Classification: Multilateral Junction Levels 1–6
Technology Advancement of Multilaterals (TAML) classifies the junction, not the number of branches. Levels 1–4 describe increasingly supported casing/cement arrangements. Level 5 obtains pressure integrity from the completion, whereas Level 6 obtains it from the casing-junction assembly. The required service functions determine the appropriate choice. [1, 3]
| TAML level | Junction arrangement | Key distinction |
|---|---|---|
| 1 | Open main bore and open lateral at the intersection. | The junction has no structural casing connection or engineered pressure seal. |
| 2 | Cased and cemented parent bore; lateral open at the junction. | An optional liner farther into the lateral does not create a tieback at the junction. |
| 3 | Cased and cemented parent bore with the lateral liner mechanically attached; lateral uncemented at the junction. | Mechanical support does not establish hydraulic sealing. |
| 4 | Parent and lateral are cased and cemented at the junction. | Casing and cement provide support, but the category does not qualify a pressure-tight junction. |
| 5 | A suitable tubing, packer and seal arrangement isolates the junction. | Pressure integrity depends on the installed completion. |
| 6 | A pressure-containing casing-junction assembly joins the bores. | Pressure integrity comes from the casing junction rather than reliance on the upper completion. |
Level 1 Junction: Open and Unsupported
The intersection has no casing support or engineered pressure seal. Formation competence must preserve a usable opening. A liner elsewhere in the branch does not protect the exposed junction itself. [1]
Openhole sidetracking can create the branch. The drilling and tripping plan must establish branch identification and reentry after pulling above the junction. The appropriate assembly and method depend on the rock and trajectory; a generic toolface sequence is inadequate. [1, 2]
Level 2 Junction: Cased Parent and Open Lateral Exit
Casing and cement support the parent bore, while rock remains exposed at the lateral exit. A liner farther into the branch does not create a mechanical tieback across that intersection. Junction stability and pressure exposure therefore still need evaluation. [1]
A whipstock and casing-exit system may create the window. Confirm its geometry, casing condition and the later liner/tool route. Toolface reference supports orientation; it does not verify a later intervention’s branch selection.
Selective reentry is not excluded by a Level 2 label. SLB’s RapidAccess TAML 2 system specifically describes access to the branches and main bore. That is a capability of the named system; it should not be assigned to every open lateral exit. [4]
Level 3 Junction: Mechanical Connection Without a Pressure Seal
The lateral liner connects mechanically to the parent casing but is uncemented at the junction. This adds support without establishing a hydraulic seal. [1]
Figure 4 contrasts a liner obstructing the lower bore with a legacy window-and-latch arrangement. Compare the actual routes available after completion installation; the system-family name alone does not establish access.
Check the liner-hanger interface and residual passage for the intended tools. Through-tubing access, access after pulling tubing and access restored by milling are different workover scopes. [1, 2]
Level 4 Junction: Both Bores Cased and Cemented
Casing and cement support both bores at the intersection. That construction does not, by itself, establish a rated pressure seal. A Level 4 junction can provide structural continuity while still needing additional pressure isolation for the intended duty. [1]
Rabia describes removing a liner extension or opening through the liner/whipstock to restore the lower route. Specify the required final drift before selecting the method: an opening that passes fluid may not pass the intervention assembly. [1]
Level 5 Junction: Isolation Provided by the Completion
Tubing, packers and seals create the pressure boundary. SLB describes Level 5 completion isolation over an underlying Level 2, 3 or 4 junction. One fixed packer count is therefore not the definition of this level. [1, 3]
Check the boundary both with the completion installed and during workover. Pulling a seal assembly can change the isolation state. The general packer classification is background; the installed junction-completion drawing identifies the actual barriers and access routes. [1]
Level 6 Junction: Isolation Provided by the Casing Assembly
The casing-junction assembly supplies pressure integrity without relying on the upper completion for that function. Rabia includes a downhole splitter, often called Level 6S, dividing a larger bore into two smaller bores. [1]
Verify deployment clearance, branch diameters and qualified pressure, temperature and load conditions. A casing-sealed junction does not automatically provide branch valves or unrestricted tool access, and historical hardware examples are not a current product catalog.
Support, Isolation and Reentry Are Separate Requirements
| Function | What must be demonstrated | What it does not prove |
|---|---|---|
| Mechanical support | The bore intersection and attached tubulars withstand the specified loads and formation conditions. | A sealed pressure boundary or an accessible intervention route. |
| Junction pressure isolation | The identified casing/completion boundary retains the required differential pressure in its installed state. | Independent flow control of every branch. |
| Selective reentry | The selected toolstring can be directed into, pass through and return from the required branch. | Pressure integrity or a usable route for every other tool size. |
| Branch flow control | The installed valves, seals and flow paths permit the intended commingling, segregation or shutoff. | That the junction itself has become a higher TAML category. |
Halliburton’s FloRite Level 5 completion provides a named example combining junction isolation and reentry without pulling the upper completion. Its documentation distinguishes dual-completion segregation from single-string commingling. Those are options within a defined equipment arrangement, not automatic results of a TAML number. [5]
Junction Selection Example: Isolation, Water Shutoff and Reentry
Hypothetical design brief. A dual-lateral producer must isolate the junction from surrounding formations, permit later shutoff of Branch B while retaining Branch A production, and allow a planned coiled-tubing logging assembly to reach either branch without pulling the upper completion. No equipment dimensions or ratings are assumed.
| Proposed arrangement | What it answers | Decision against the brief |
|---|---|---|
| Level 4 junction with a simple commingled completion | Mechanical support, but no demonstrated junction seal or selective branch control. | Does not meet the stated functions as specified. Additional equipment and verification are required. |
| Level 5 isolation completion with branch controls and selective access | Could provide all three functions in a compatible assembled system. | A candidate for detailed design—not accepted until seals, valves and the complete tool route are verified. |
| Level 6 casing junction, with no branch controls specified | Could address junction pressure integrity. | Incomplete: separate branch shutoff and the required access are still unproven. |
The Decision and the Remaining Acceptance Checks
Of the three proposals as described, only the Level 5 option explicitly includes all three requested functions. It can proceed to detailed verification, but the label does not demonstrate that its equipment meets the brief. A Level 6 option could also qualify once the missing branch controls and tool-access provisions are specified and verified.
For the Level 5 candidate, verify differential-pressure direction, temperature and loads; demonstrate the valve state that isolates B without blocking A; and check the logging assembly through every restriction and deflector. Also define what protects the well when completion seals are removed. The equipment supplier must provide the applicable ratings, dimensional drawings and verification evidence for the proposed configuration.
Multilateral Well Design and Intervention Checklist
| Design question | Evidence required | Consequence if unresolved |
|---|---|---|
| Where should each junction be placed? | Formation strength, pore/fracture pressure, casing program, exit orientation and target geometry. | An unstable or exposed weak point compromises later drilling and treatment. |
| Can all branches remain compatible? | Reservoir pressures on a common datum, expected depletion, fluid compatibility and planned flow states. | A branch can receive crossflow or lose its useful contribution. |
| Can the completion and tools pass? | Minimum drift, window geometry, sealbore sizes, bending limits and the complete toolstring envelope. | The bore may pass fluid yet reject a completion or intervention assembly. |
| Can the junction remain clean? | Milling-debris transport, cleanout, protection of profiles and verification before sealing/latching. | Swarf or cuttings prevent a tool from seating, sealing or releasing. |
| What is the recovery strategy? | Selective-access method, verification, isolation options and contingency for inaccessible branches. | A nominally serviceable lateral becomes an unplanned workover or abandonment problem. |
| What is the lifecycle alternative? | Incremental recovery, shared-infrastructure savings, construction risk and later intervention/abandonment scope. | A cheaper initial arrangement imposes higher future cost or loses recovery. |
Window Milling and Debris Management
Rabia identifies milling debris as a significant junction-construction problem. Steel swarf, cuttings and cement fragments can interfere with sealing elements, packers and retrieval mechanisms. Do not carry a generic quantity of swarf or a single cleanout velocity from an example into another well. [1]
The milling plan should connect the selected casing exit to debris removal and subsequent equipment installation. Establish how the window is conditioned, how the lower bore is protected where required, and what evidence confirms usable profiles and passages before running the next assembly. Mechanical access and clean sealing surfaces are separate checks.
Junction Pressure Exposure During Drilling and Workover
An intersection that remains open to the formation can be a pressure-limiting point even when casing supports the parent bore. Rabia compares an unsealed junction with an exposed casing shoe: formation fracture resistance at that point matters during well-kill operations. Include the junction in the review of exposed formations and planned pressure loads rather than assuming the deepest shoe is the only relevant weak point. [1, Section 7.11]
For a Level 5 completion, review the pressure boundary again for any workover state in which tubing, packers or sealing assemblies are removed. A seal that contains pressure during production cannot be credited after its sealing engagement is lost. Define the replacement barrier arrangement in the approved program; a TAML designation alone supplies no allowable pressure or kill procedure. [1, Sections 7.9–7.11]
Reentry, Branch Isolation and Later Workovers
Define reentry by the actual tool: a logging assembly, coiled-tubing string, stimulation assembly and milling BHA may require different passages and bending capability. Verify the selected branch and the return route. Passing the construction assembly once is not proof that every later tool will pass after the completion is installed. [1, 2, 4]
A compatible sliding sleeve or other flow-control arrangement can manage a branch’s flow path. It does not by itself prove pressure isolation around the junction or prevent bypass through the formation. Draw the complete pressure boundary for normal production, a shut-in, stimulation and equipment retrieval. Rabia also includes workover and abandonment requirements in multilateral planning. [1]
Production Management: Whole Well, Lateral and In-Lateral Control
The control point determines what can be managed. A common upper-well restriction affects the combined stream. A branch valve acts on one lateral. An in-lateral valve acts on a smaller producing interval, provided the completion also prevents unintended bypass. Selecting that control scale is a separate decision from selecting the junction. [1, 9]
For example, SLB’s electric-completion overview distinguishes control at multilateral junctions from in-lateral monitoring and control. Targeting a smaller interval can preserve other producing sections. That requires the corresponding equipment and isolation arrangement; it is not a capability supplied by every multilateral well. [9]
Sand Control, Artificial Lift and Stimulation Interfaces
Sand control: evaluate the exposed formation and the selected liner or screen arrangement in each branch. Check how installation, cleanout and access fit together. A sand screen filters formation solids; it is not a substitute for a qualified junction pressure seal. Rabia treats debris, lateral isolation and workover needs as connected design issues. [1, 3]
Artificial lift: establish where the lift equipment will sit and whether fluids can reach its intake under the planned producing conditions. Then check the consequences for access to the junction and branches. An upper-bore pump location and a pump below a junction create different access questions; the system drawing and well model must resolve them. [3]
Stimulation: identify the intended treatment route and the boundary that protects the junction. Some systems provide temporary junction isolation for a high-pressure treatment without making the permanent junction Level 5. Qualify that treatment configuration and restore the intended production state afterward. [3]
Use Measurements to Check the Control Decision
Record the available zonal pressure, temperature, flow and water information together with valve states and surface test conditions. After a planned adjustment, compare the observed responses rather than assuming that a lower water fraction proves improved oil recovery. A model and an appropriate observation period are needed to distinguish changed allocation from a sustained improvement. [9, 10]
Stanford’s multilateral monitoring-and-control research links measurements to reservoir-model evaluation and control decisions. It supports this feedback concept, not a universal valve setting or a demonstrated result for the reader’s well. [11]
Worked Example: Unequal Branch Pressure and Commingled Production
Hypothetical screening example—not a production forecast or operating instruction. Assume two liquid-producing branches at the same pressure-reference depth, fixed reservoir pressures and constant productivity indices. Ignore branch friction, multiphase effects, depletion and reservoir interference. The common junction pressure is treated as the sandface flowing pressure only within this simplified model.
For forward inflow, use q = J × (Pr − Pj), where q is stock-tank barrels per day, J is the assumed productivity index in STB/day/psi, Pr is reservoir pressure and Pj is junction pressure in psig. The SLB productivity-index definition expresses the relationship between delivered rate and drawdown; the inputs below are invented. [7]
| Assumed input or result | Branch A | Branch B |
|---|---|---|
| Reservoir pressure Pr | 3,500 psig | 3,100 psig |
| Productivity index J | 2 STB/day/psi | 1 STB/day/psi |
| Common junction pressure Pj | 3,000 psig | 3,000 psig |
| Forward drawdown | 500 psi | 100 psi |
| Calculated forward inflow | 2 × 500 = 1,000 STB/day | 1 × 100 = 100 STB/day |
What Changes When Junction Pressure Rises?
At an assumed junction pressure of 3,200 psig, Branch A still has 300 psi forward drawdown, giving 600 STB/day in this model. Branch B instead sees the wellbore 100 psi above its reservoir pressure. It no longer has positive producing drawdown; an open connection can expose it to crossflow.
Do not report −100 STB/day as a verified injection rate by extending the production equation backward. Reverse flow requires injectivity, fluid and transient behavior that this model does not contain. SLB’s completion definition of crossflow describes communication between zones with different pressure characteristics. [8]
The selection lesson: two branches do not necessarily give twice the useful rate, and changing the shared pressure can change one branch from a producer to a potential receiving path. Evaluate flow control and shut-in conditions before assuming commingling is acceptable. A pressure-tight junction alone does not equalize the reservoirs or close an intentionally open branch connection.
From the Teaching Model to a Production Forecast
In an actual well, junction pressure is an output of the connected reservoir, branch and upper-well system—not an independent setting chosen to maximize this arithmetic. A forecast needs branch pressure losses, fluid properties, depletion, interference, valve states and the common tubing/surface performance. Compare pressures on the same datum and solve the connected system before calling the summed branch potentials a delivered rate. [1, 7, 11]
Field Example: Why a Cemented Junction May Need Added Isolation
Problem and response: a Halliburton Middle East case describes a dual-lateral well completed in 2009. Gas migrated along a poorly bonded cemented liner and entered through its Level 4 junction. In 2017, a FloRite Level 5 completion isolated the path. The supplier reports restored productivity, eliminated gas ingress and retained lateral access. [6]
Lesson and limitation: identify the unwanted communication path before choosing the remedy. This case concerns junction isolation, not proof that all cemented junctions leak. The public report does not disclose the full well dataset or establish long-term recovery or economics for another well.
Field Example: Six Control Stations in a Trilateral Well
Problem: Saudi Aramco wanted to monitor and control differing conditions within three laterals during cleanup. SLB’s supplier-reported trilateral case describes six Manara stations, with two stations per lateral. [10]
Reported response: measurements identified free gas forming during high drawdown. Adjustments allowed the affected lateral to stay online during cleanup; subsequent monitoring supported balancing contributions among the six compartments. These are the supplier’s reported observations, not independently audited results or the experience of this article’s author. [10]
Design lesson: the useful control scale may be smaller than a whole lateral. Unlike the preceding gas-migration case, this example concerns identifying and managing contributions inside the producing branches. The public summary does not establish a universal recovery increase or return on investment.
Multilateral Well Questions and Answers
Are all multilateral wells horizontal?
No. The defining feature is multiple connected branches, not a particular inclination. Their paths depend on reservoir targets, the junction arrangement and the completion requirements. [1]
Does TAML Level 4 mean pressure integrity?
No. Casing and cement at the junction provide mechanical support, but the TAML 4 category does not establish a qualified hydraulic seal. Level 5 obtains that function through completion equipment; Level 6 obtains it through the casing-junction assembly. [1]
Does a higher TAML level guarantee reentry?
No. Confirm the deflection/orientation system, minimum passage, tool envelope and installed completion. Some engineered Level 2 systems offer selective access, while other arrangements obstruct a route despite having more extensive junction support. [1, 4]
Technical References and Scope
[1] H. Rabia, Well Engineering & Construction, Chapter 12, Sections 7.1–7.14, printed pp. 533–550. Used for terminology, layouts, planning, junctions, intervention, pressure exposure and debris management. Historical product illustrations and model-specific operating values are not universal requirements.
[2] International Association of Drilling Contractors, IADC Drilling Manual, 12th edition, 2015, “Directional Drilling,” printed DD-15–DD-16. Used for multilateral departures, hole-size constraints and the connection between intervention requirements and system complexity.
[3] SLB, The Defining Series: Multilateral Wells, published 19 April 2021. Used for junction distinctions and the ability to obtain Level 5 isolation over different underlying junction constructions. Historical market/general capability statements are not adopted as current product limits.
[4]–[6] SLB RapidAccess, Halliburton FloRite, and Halliburton’s Middle East dual-lateral retrofit report, linked where discussed. The retrofit report identifies a 2009 completion and 2017 workover. These sources describe named equipment or supplier-reported results, not independently verified performance for other wells.
[7]–[8] SLB Energy Glossary: productivity index and crossflow. These definitions support the forward-inflow example; its inputs and arithmetic are hypothetical. Reverse-flow rate and delivered surface production are outside the model.
[9]–[11] SLB’s Electris completions overview; SLB’s Saudi Aramco trilateral cleanup case; and Stanford SUETRI-D, Monitoring and Control of Multilateral Wells. Linked in the relevant sections. They support, respectively, in-lateral control, the separately attributed field report, and the measurement/model/control feedback concept. Public sources were rechecked on 17 October 2026.
Scope: this is an educational comparison, not a certified junction design or operating procedure. The two design/pressure examples use stated hypothetical assumptions; the field cases retain their supplier attribution. Use the approved program and exact equipment documentation for installation, testing and intervention. The five retained historical or conceptual illustrations (Figures 1 and 3–6) have reuse permissions that are not established by this text revision. Figures 2 and 7 are original educational schematics, not manufacturer drawings or equipment specifications.
Multilateral Well Video Overview
The Drilling Manual video provides an additional introduction. Its terminology and equipment examples should be read alongside the distinctions in the written guide; the video itself has not been technically re-edited as part of this revision.