SPE/IADC-178166-MS

Enhanced Sand Control of Multiple Branches Connected to a Single Wellbore

Doug G. Durst, Halliburton

Copyright 2016, SPE/IADC Middle East Drilling Technology Conference and Exhibition

This paper was prepared for presentation at the SPE/IADC Middle East Drilling Technology Conference and Exhibition held in Abu Dhabi, UAE, 26 –28 January 2016.

This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s).
Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to
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Abstract
Drilling, completing, and the production monitoring and control of multilateral wellbores in highly
unconsolidated sandstone formations have achieved technical and operational success in recent past by
ensuring that economic viability is attained and that well life is prolonged.
Gravel packing the lateral branch on a multilateral well is no longer a challenge. Sound isolation of the
main branch is achieved to preserve the mainbore of debris when milling the window and drilling the
lateral, which will ensure seamless gravel-pack operations. Stable junction isolation exists to support sand
placement and the subsequent reverse-out of gravel-pack operations in both the main and lateral branch.
Additionally, it is no longer considered a risk to run long, stiff, bottomhole completion assemblies across
the window junction. One of the key factors in determining if a multilateral wellbore might be suitable
for a given project is the type of sand-control completion and technique that might be required. The use
of conventional standalone screens has a long and highly successful history. And now, where more
sand-control reliability is required via use of gravel packs in combination with multilateral wellbores,
technology is available and is also beginning to develop its own successful history.
Multiple successful installations of dual-bore, horizontal gravel-pack completions combined with
Level-5 multilateral completion systems has resulted in increased reservoir drainage to improve the
oil-recovery factor as well as the economic gains. In its current, form when combining advanced sandface
completions with multilateral completions, the gravel-pack operations are followed by the installation of
multilateral and upper completions. As a result of a newly developed system, one can now interconnect
the junction completion with the sand-control operations in a single, seamless operation.

Introduction
From simple slotted-liner installations in the lateral bores in the early days, multilateral (MLT) completions
today have evolved to include gravel-packed and frac-packed laterals (the latter is still evolving). When heavy
oil was exploited in the Orinoco Belt in the late 1990s and into the next decade, multilaterals were commonly
installed in combination with slotted liners to provide some minimal means for sand control. Ultimately,
hundreds of MLT installations were completed by a number of joint operators using both Level-3 and Level-4
MLT junctions (both providing mechanical support to the junction, with Level 4 also providing cement
isolation of the junction). A common MLT technology feature and benefit throughout the entire drilling and
2 SPE/IADC-178166-MS

completion development program was the extensive amount of footage drilled for each individual well,
sometimes reaching up to 60,000 ft of reservoir exposure. These installations continued into the mid-to-late
2000s but eventually were discontinued owing to internal country policy issues, but not before hundreds of
wells were drilled and completed, many with numerous junctions/laterals per well.
⬙The fact that multilateral technology has the capabilities to provide a cost-effective alternative for
traditional vertical and horizontal wells for accessing oil and gas reserves has been well documented
around the world. To date, the bulk of these installations have occurred in naturally fractured carbonate
reservoirs or in poorly consolidated sandstone reservoirs. In either scenario, the lateral borehole typically
has been drilled horizontally to obtain maximum reservoir exposure. Slotted liners or sand-screen
completions have provided very effective borehole support and/or sand control devices when deployed in
uniform sandstone reservoirs, whereas openhole completions are commonly found in carbonate reservoirs
with natural fractures⬙ (Cavender et al. 2003).
In the early to mid-2000s, the Troll Field beckoned for solutions to provide a means for taking known
reserves considered to be uneconomically viable when considering single wellbores and to drill and complete
using MLT technology. MLTs allowed the operator to geo-drill significantly more footage in the thin sands,
in some cases providing up to 50,000 ft of exposure for a single well. The MLT wells were combined with
standalone-screen technology and, in many cases, intelligent well control and monitoring to not only yield
accelerated production but also provide extended production life. For many of these wells, the shrouded
standalone screens (some up to 10,000 ft in length per lateral leg and, in some instances, multiple laterals per
well) were installed integral to the Level-5 junctions (providing isolation and pressure integrity) used for this
application. Where lateral wellbores were suspect in terms of bore integrity and tortuosity, the lateral screens
would be installed using a separate liner-deployed system with the Level-5 junction, then set and tied back to
the previously installed lateral screens. From the beginning of the Troll development, MLT technology has
been used in a number of other North Sea fields with similar systems and success, using a variety of variations
and casing sizes of Level-5 junctions with different features and benefits. Over 200 Level-5 junctions have been
installed in the North Sea (and over 250 worldwide) combined with sand control completions (typically,
shrouded standalone screens). The Level-5 junctions can also be easily configured as a platform for integrating
either middle or upper completions, including intelligent completion interfaces to remotely control and monitor
all of the lateral branches (see Fig. 1).

Figure 1—Norway Multilateral Completion – Level-5 Trilateral w/Integral Shrouded-Meshed Standalone Screens (Source OGJ Hi-Tech
Wells Conference).
SPE/IADC-178166-MS 3

⬙One of the advantages of multilateral wells is that they provide the operator with the ability to combine
targets, whether they are in the same sand package or not, that would not be economical to drill as a single
well. By drilling horizontal wells with several branches in different directions, or by drilling into multiple
layers of sands, a single multilateral well can provide as much reservoir drainage as several conventional
horizontal wells. The cost of drilling a multilateral well with three branches (trilateral) is on average less
than 75% of the cost to drill three separate horizontal wells to obtain the same production (Fipke et al.
2008). Multilateral technology uses fewer production well slots to effectively drain a reservoir, saving
time, money and improving NPV. One of the benefits of multilateral (MLT) well architecture is the
reduced cost of the subsea infrastructure. Additional cost benefits include reduced top-hole drilling costs,
reduced project execution time, accelerated production; fewer rig moves and a smaller environmental
footprint. To take advantage of the benefits, the appropriate multilateral technology must be selected to
avoid introducing additional risk and non-productive time (NPT) to the project⬙ (Lawrence et al. 2010).
Additionally, the success of these Level-4 and Level-5 MLT junctions combined with variations of
sand control solutions has carried over to further installations in offshore Australia, Middle East, Russia,
and South America. The story and success of many of these MLT installations combined with various
forms of sand-control solutions will be discussed throughout this paper. To date, there have been hundreds
of MLT installations combined with slotted liners, hundreds with advanced screen technology, including
inflow control devices (ICD) and autonomous inflow control devices (AICD), many of these inclusive of
intelligent well completions (IWC), including a number of multibranch inflow control (MIC) Level-5
MLT junctions. More recently, MLTs have been combined successfully with gravel-pack operations,
leading to the additional development of new Level-5 junctions to address gravel packing through the
MLT junction itself and also the ability to combine frac-pack operations with MLT solutions.
⬙The completion design and sand control technique will vary depending on the reservoir characteristics.
Throughout the completion phase, kill weight completion fluid will be required for well control. Cased
hole gravel packing and frac packing can be implemented along with openhole gravel packing. If desired,
expandable screens and/or ⬙stand-alone⬙ premium screens can be deployed without gravel packing. These
systems will be positioned across an openhole section and tied back to the lateral casing using a tie-back
isolation assembly. If a level 5 junction is desired, a seal bore completion packer or PBR will be positioned
in the top of the lateral just below the junction. The seal bore packer or PBR would not be required on
a level 4 junction. After the lateral is completed, the junction is milled over and the whipstock retrieved.
The intelligent multilateral well can be deployed in conjunction with a level 4 or 5 junction. With either
scenario, the control valves are run in tandem without any ⬙wet connects,⬙ and the intervals can be
produced separately or commingled (Oberkircher et al. 2002). Frac and pack is another method commonly
used for completing sandstone reservoirs. This application normally provides total sand exclusion and
typically is deployed in laminated reservoirs to increase conductivity and drainage radius⬙ (Cavender et
al. 2003).
⬙Well completion plays a critical role in well design, and more importantly, the performance of the well
in its entire life. With more and more advanced well completion options deployed in new wells, especially
in the deep and ultra-deepwater environment, the cost and the impact of well completion would be too
significant to be ignored. Unfortunately, the details of well completions are normally not taken into
account in most of the current reservoir simulators. For new wells, there are a number of completion
options available for selection. Selection of a completion for a new well is typically based on cost,
production efficiency, and the ability to handle the potential flow difficulty such as sand production. The
cost varies from a completion type to the other, and the production may also change depending on the well
and flow conditions⬙ (Ouyang et al. 2005).
⬙Typically five completion scenarios can be applied:
● OHGP: Openhole gravel pack
4 SPE/IADC-178166-MS

● CHGP: Cased hole gravel pack (with isolation string)

● SAS: Standalone (prepacked) sand screen
● CHFP: Cased hole fracpack (with isolation string)
● ESS: Expandable sand screen⬙ (Ouyang et al. 2005)

Background on Multilateral Sand Control

The author did a significant amount of research in hopes of obtaining detailed accounts (key word being
detailed) of the various types of sand-control methods that have, over the years, been combined with
multilateral technology. What was found is that there is, indeed, an expansive and broad history of these
integrated products and solutions (generally, these products and solutions are provided by different service
providers); however, many of the publications or articles researched were typically focused on the
multilateral component as being a part of the well construction or being drilling related, whereas the
sand-control (SC) component was obviously considered as being completions related. Hence, in some
articles, there was a tendency to focus primarily on the MLT component (with lots of detail), with minimal
coverage given to the SC component (minimal detail). It brings to light that a limited amount of
information is shared between the operators and the various service companies who are providing their
services, which has unfortunately been the case over the years.
That being said, this paper will demonstrate that not only is there substantial experience in combining
MLT with SC, but also that most any form of SC, from the simplest to the most complex, have been
integrated with MLT systems to provide comprehensive multilateral completion installations.
For example, from the author’s company’s perspective, it has become routine:
● To drill tens of thousands of feet of reservoir exposure in a given well and install thousands of feet
of sand-control systems in multiple laterals for a given well;
● To install thousands of feet of sand-control systems deployed in a single run, whereby either the
SC product is attached and carried in with the MLT junction, or the SC product is liner-deployed
first followed by the subsequent tie-in back to the MLT junction. Up to 7,500 ft of SC product has
been installed in a single installation, with even more footage in stacked-liner SC/screen instal-
lations. The majority of SC/screen installs have been around 6,000 ft in length at MDs of 18,000
ft.
● For both onshore and offshore (inclusive of floater installations), MLT and SC systems have been
combined and placed in a given wellbore in hundreds of case histories.
● MLT and SC installations have been deployed at junction depths as deep as 22,000 ft measured
depth (MD) and at 90° inclination.
Hundreds of Level-5 MLT and SC installations and hundreds of Level-4 MLT and SC installations
have been deployed over the years with hundreds performed off of floaters (see Fig. 2).
SPE/IADC-178166-MS 5

Figure 2—Norway Multilateral Completion – Level-5 Quad Lateral w/Integral Shrouded-Meshed Standalone Screens.

⬙Petroleum Engineering has come a long way in developing the knowledge needed to select the best
sand control method to apply in formations with sand production problems. Sand production is usually
associated with younger tertiary formations, such as the Miocene or Pliocene age sands. These formations
occur in a number of areas, especially offshore areas like the Gulf of Mexico, West Africa, Brazil, and
offshore Malaysia and Brunei. The majority of these areas have been produced for the last fifteen years
using so called modern sand control methods. With these areas having a long history with sand control
completions, one might think that experience combined with the latest technologies and engineering
practices would lead to a simple decision process for sand control selection. The truth is that, in many
instances, intangible or nontechnical aspects have a heavy influence in the final decision of the method(s)
to be used, especially when the operation is in a remote location or in an area where sand control
operations are new or not commonly performed. These nontechnical considerations include local avail-
ability of equipment, chemicals, experience, lead times, local regulations, environmental issues, existing
contracts, operator preferences, special technologies, the contractor safety record, cost, and even the
number of subcontractors. Furthermore, the locally accepted sand control method might be considered the
best practice or thought to have the highest success rate only because of familiarity. The technique finally
selected for an expansion or new project might not be the best from a purely technical point of view once
these nontechnical issues are considered. Intangible factors in sand control selection can range from
previous experience with a given technology to other operators successes in an area. Company purchasing
policies, equipment availability, installation lead time, and contractual issues can influence these factors.
If the desired equipment is not available in a cost effective way, the preferred technical sand control
method might be dropped from consideration for a less desirable method. The completion engineer must
consider all risks and costs of these changes. These increased risks include installation or infant failure to
possible reduction in production rates or lost reserves, such as perched oil. However, some method
changes can bring reduced risks or increased production. The cost of change must also be weighted against
the economics of the project⬙ (Waltman et al. 2010).
⬙Globally, technology has enabled the successful application of gravel packs in lateral lengths
exceeding 8,300 feet, and water depths exceeding 6,100 feet. The growth of frac packing in deepwater
Gulf of Mexico has intensified engineering efforts to meet the demands specified by the operating
companies for fracturing formations with high permeability. Horizontal gravel packs have evolved to
provide the operator with one of the lowest development costs per BOE. The refinement of horizontal
6 SPE/IADC-178166-MS

gravel-pack completion procedures resulted in developing and optimizing special drill-in fluids (DIF’s)
and gravel pack tools specifically designed to meet the required pumping procedures. Additional demands
were placed on the horizontal gravel-pack tool design with the introduction of ceramic proppants as the
gravel-pack material. The enhanced tool capabilities, combined with enhanced procedural changes,
resulted in the routine successful execution of deepwater, extended reach horizontal gravel-pack com-
pletions⬙ (Lorenz et al. 2006).

A Walk through the History of MLTs Combined with Sand Control Methods
The continuation of this paper will address multilateral technology combined with either slotted liners,
standalone screens, or gravel-packing and frac-packing solutions, as well as case histories associated with
projects in Venezuela, Norway, Trinidad, Australia, Brazil, and Kuwait. Additionally, there will be some
discussion on systems developed for the future to enhance gravel-pack and frac-pack operations.
Slotted Liners Combined with MLT Technology Slotted liners are made from tubulars by saw-cutting
slot configurations and are one of the more basic sand-control methods used by many operators
worldwide. There is a fairly extensive history of using slotted-liner completions combined with MLT
technology, of which some will be discussed within this paper. Most slotted-liner installs have been
simply installed as a drop-off liner positioned some distance out into the lateral, which has been the
predominant method used in single horizontal applications. However, in multilateral installations, the
predominant method for installation is to install the slotted liner attached to an MLT Level-3 or Level-4
junction. The latter MLT type requires that some length of blank pipe be installed above the slotted liner
in the junction area incorporated with a displacement valve and an inflatable packer to allow for stage
cementing the junction to provide mechanically supported cement Level-4 isolation. A number of projects
have been proposed whereby the slotted liner is run in on an inner string to allow for cleaning and jetting
the wellbore to ensure that the liner can reach the target depth. Although this latter method has most likely
been used, the author found no documentation to share with you, the reader.
In the beginning of modern drilling, there was the development of the Orinoco Belt heavy-oil reserves
in Venezuela that brought MLT technology back to the forefront. Actually, prior to this, there was some
activity in Canada, but little is documented or, at least, little is known about what types of sandface
completions were used. When the dust finally cleared, there were no less than four IOC groups that jointly
developed the Belt (joined with PDVSA, the national oil company of Venezuela) to drill and complete a
large number of MLT wells to exploit this play.
Venezuela/Orinoco Belt Activity – Multilaterals combined with Slotted-Liner Sand-Control
Completions In the beginning, multilaterals (MLT) were used in combination with sand control and
were heavily used in the Orinoco Belt, a heavy-oil formation located in Venezuela. A number of joint
operators exploited the mass reservoir by drilling tens of thousands of feet of hole in very complex drilling
patterns to optimize drainage. The operators typically used either Level-3 (provides mechanical support
of the junction) or Level-4 MLT junctions (provides both mechanical support and cement isolation of the
junction). Both of these systems were combined with long lengths of slotted-liner completions to provide
some limited sand control. The slotted liners were simply, for Level-3 junctions, installed by attaching
directly to the junction itself. For Level-4 junction installations, the lateral liners consisted of a short, solid
cemented liner beginning at the mainbore of the junction combined with slotted liners. The latter
installation was completed by running the entire lateral liner to total depth (TD) and then stage cementing
the solid liner section back to the mainbore via a displacement/differential valve and isolated with an
inflatable packer (ACP) (see Fig. 3).
SPE/IADC-178166-MS 7

Figure 3—Venezuela Multilateral Completion – Level 4 with Dropped Slotted Liners.

⬙Multilateral drilling technology has been used in many heavy oil developmental projects to achieve
maximum reservoir exposure from a single surface location. The wellbore geometry and completion
strategies for multilateral wells are planned and customized to fit the known reservoir characteristics and
sand distribution qualities. Typically, heavy oil reserves are found in unconsolidated sandstone reservoirs
that require some form of sand exclusion strategy across the reservoir as well as at the lateral mainbore
junction interface. In heavy-oil sand, effective sand-control strategies must be carefully planned since one
of the difficult problems to address in heavy-oil targets is their natural tendency to suspend formation
solids, often referred to as Basic Solids and Water (BS&W) solids. As previously mentioned, effective
lateral sand control can range from slotted liners to gravel packing. The reservoir lithology along with the
surface solids handling capability will dictate the extent of sand exclusion. Another common producing
strategy is to provide borehole support using slotted/perforated liners but co-produce the formation sand
with the heavy crude. To date, most multilateral wells are drilled and completed from the bottom up.
Typically, the lower lateral is drilled as an extension from the bottom of the mainbore across a designated
reservoir. This can be done using conventional drill mud or special, less damaging drill-in fluids. Once
drilled, a slotted liner, screen assembly or gravel pack is installed into the lateral borehole and tied-back
to the bottom of the mainbore casing. Next, a packer/plug configuration or bridge plug is installed in the
mainbore casing above the lower-lateral completion before the drilling whipstock is installed, and drilling
commences on the upper lateral. With this scenario, each lateral is completed prior to drilling the next⬙
(Cavender et al. 2004).
⬙There are now a variety of ways to achieve higher recovery factors from heavy oil reservoirs, but most
of them involve the injection of thermal energy or chemicals to reduce the oil viscosity. While these
techniques have been highly successful, they can also be expensive when the steam generation and/or
chemical injection costs are accumulated throughout the productive life of the field. A lower cost solution,
one that has been successful in the Faja Del Orinoco of Eastern Venezuela, is to use multi-branched wells
(multilaterals) to increase reservoir exposure and achieve an arguably higher recovery factor. These
multilateral wells have been shown to produce more oil over a longer period of time than conventional
8 SPE/IADC-178166-MS

wells without any additional operating costs. Currently, all the wells are constructed with two or three
horizontal branches up to 6,000 ft. long. From each of these lateral wellbores, as many as six openhole
lateral sidetracks, or ⬙fishbones,⬙ can be drilled to either side. This technique allows Petrozuata to
maximize the amount of reservoir exposure drilled on a per well basis and to connect isolated sand bodies.
Typically, a trilateral well with 18 fishbones can have approximately 45,000 feet of reservoir exposure.
In one particular well, almost 60,000 feet of hole was drilled within the same reservoir⬙ (Fipke et al. 2008).
Standalone Screens Combined with MLT Technology There are various types of sand screens used for
sand exclusion for typical single vertical, inclined, or horizontal wellbores. For multilateral wellbores,
there is a priority put on getting high-quality screens to depth without damage; hence, it is always
recommended to use shrouded-screen technology so that damage is greatly minimized or eliminated when
passing long screen sections across either a drilling whipstock or a diverter device. Typically, a service
company will qualify a manufacturere’s screens across the service company’s whipstock or diverter in a
simulated test to ensure no field installation issues can be expected. The same can be said for swellable
packer technology, which is frequently combined with sand-control systems in MLT installations. This
MLT technology exists to allow one to carry long lengths of screens into the wellbore attached directly
to the junction housing component. These types of MLT junctions are designed to support tensile loads
up to 500,000 lb and compression loads up to 200,000 lb. As an alternative, the screens can be deployed
independently of the junction housing with a tie-back receptacle looking back up toward the junction,
allowing for the tie-in and sealing of the junction housing when it is landed in its final position. In some
cases, laterals lengths (as well as mainbore laterals) are so long that liner-deployed screens will require
stacking to install the entire screen seamlessly; this has to be done routinely. Where wellbore stability and
tortuosity concerns come into play, one has the option to run a disposable motor on the front end of the
screens to aid in getting screens to depth.
To date, there is an extensive history of hundreds of standalone screen installations (many variations
of techniques, including advanced screen technology with inflow control devices and autonomous inflow
control devices) combined with MLT technology, which was addressed in some detail in the MLT SC
background section (see pages 3 and 4 for more information).
⬙In offshore Norway, multilateral technology was used to increase the total reservoir drainage area from
an existing subsea structure. The unconsolidated-sandstone reservoir needed a ⬙screen only⬙ application
to provide adequate formation-sand exclusion. Therefore, completion equipment was deployed after each
lateral was drilled. The junction assembly was installed horizontally across the reservoir. The main-bore
lateral section was drilled horizontally and completed, and then the screens were tied back to the main
bore by use of seal-bore packers. After the lower lateral section was completed, a drilling whipstock was
installed, and the lateral horizontal section was drilled. Once the lateral was drilled, the drilling whipstock
was removed and replaced with a hollow bore deflector assembly. Isolation tubing below the deflector
connects the assembly with the main-bore screen completion. Once the flexible hanger was landed and
sealed into the hollow bore deflector, a Level 5 multilateral junction (pressure integrity at the junction
achieved with completion) was formed. Production tubing was run and sealed into the seal-bore packer
above the flexible hanger for commingled production⬙ (Denney 2003).
Kuwait – Level-4 Multilaterals Combined with ICDs/Screens ⬙Kuwait Oil Company (KOC) has
recently drilled the first multilateral well in a North Kuwait field to improve oil production in productive
layers subjected to water coning problems by increasing reservoir exposure using Level 4 multilateral
technology. The multilateral well targeted the same sand in different directions with two laterals. Both of
the laterals were drilled using rotary steerable drilling systems to reduce drilling time. After comparing
the technological advancement of multilateral levels and design criteria in accordance with the specific
geological features from the field, the Level 4 was chosen. This decision was based on the need to isolate
active zones in the new lateral drilled from the window and avoid communication between the reservoir
SPE/IADC-178166-MS 9

considered to produce and upper layers. The Level 4 is characterized by running a liner, which could be
completely cemented or stage cemented with the upper section being cemented blank liners and the lower
section as slotted liners with exposition in the reservoir⬙ (Al-Khaldy et al. 2014).
⬙The lower lateral consisted of 5 1/2-in ICD completion assembly consisting of 47 ICD with sand
screens and 25 swellable packers were lowered with 2 7/8-in inner string in tandem. The inner string
stinged into the seal assembly of the outer string enables circulation in the outer annulus from bottom. The
ICD assembly was deployed by setting a 7- ⫻ 9 5/8-in. liner hanger with a liner top packer. The open hole
interval was displaced first by filtered water followed by filter cake breaker fluid to eliminate near-
wellbore damage before setting the liner top packer. Selection of the number and placement of ICDs,
swellable packers, and each ICD nozzle size is performed after reservoir simulation based on accrued
logging data. An ICD completion assembly is used to divide the lateral section into segments by swellable
packers and create custom made differential pressure across ICD nozzles to delay the water cut. The upper
lateral consisted of 4 1/2-in ICD completion assembly consisting of 32 ICD with sand screens and 20
swellable packers were lowered with 2 7/8-in inner string on 5- ⫻ 7 in. retrievable hydraulic sealbore
hanger. Filter cake breaker fluid was placed in the open hole as before⬙ (Al-Khaldy et al. 2014).
Norway – Level-5 MLTs Combined with Standard and Advanced Shrouded Standalone Screens
(ICDs and AICDs in Later Installs) One of the main challenges on Troll is to limit the drawdown in
the heel area of the well to avoid gas coning from the gas cap above. Simulations of the inflow profile
of the wells indicate that the MLT wells have a better contribution from the entire well length than a single
well. This is a result of a lower flow rate from each branch compared to a single well and, therefore, a
lower drawdown in the heal area. The MLT well will produce longer on plateau compared to a single well
with respect to gas breakthrough. In combination with inflow control device (ICD) screens, this gives a
smooth inflow profile with a good contribution from the entire screen length. The production history for
the earlier MLT wells indicates that the wells have a later gas breakthrough than a single well. In
combination with a high flow rate, this indicates that the wells are providing a good contribution from the
entire screen length.
Prior to the development of the current Y-block junction technology, there were three multilateral wells
that had been installed on the Troll field using a previously designed junction. On these three Level-4
wells, junction isolation was achieved with special cement and a resin squeeze. Eventually, junction-
related production problems were experienced on two of the three wells, with lumps of resin flowing back
and plugging surface equipment. To further improve the reliability of the junction and installation time,
a new system would be required.
Based on field operating requirements and multilateral installation experience of the original MLT
design, the following objectives were defined for a newer Y-block junction design to replace the original
Level-5 system:
● Reduce installation time
● Mechanical seal to isolate the junction (Level 5)
● Robust and simple installation process from floating rigs with no milling of steel
● Optimize flow area
● Access to mainbore and lateral
● Ability to plug both main and lateral bore above junction.
⬙The multilateral well concept has been introduced on Troll Olje primarily to increase the total drainage
area from the existing sub-sea template structures. The Troll Olje Field is located approximately 100 km
north west of Bergen, in the Norwegian Sector of the North Sea. The water depth is 315 - 340m. Troll
Olje is part of the Troll gas field in which Norsk Hydro is responsible for development of two areas of
a thin oil rim: the Troll Olje Oil Province (22 - 26m oil zone) and Troll Olje Gas Province (around 13m
oil zone). The combined development is estimated to recover a total 1.33 billion barrels of oil⬙ (Berge et
10 SPE/IADC-178166-MS

al. 2001). Side note by author: the estimate noted was at the time SPE 71837 was published; World Oil
published that as of September of this year (2015), they have actually produced 1.56 billion barrels, with
production still ongoing and new wells being drilled and completed. ⬙New horizontal producers are
continuously being drilled to recover reserves from the relatively thin oil layers before gas production
induces oil column movements that are too large. By March 2006, a total of 109 wells had been drilled
and completed on the Troll West Field, including 41 multilateral wells with a total of 54 multilateral
junctions. The field is currently producing approximately 200 000 bl/D, making it the second largest
producing oil field in the North Sea. The field accounts for more than 11% of Norway’s oil production⬙
(Ruyter et al. 2006).
The lateral screens are run with a bullnose designed to deflect off of the deflector assembly and enter
into the lateral wellbore. Above the 5-½-in. x 6-5/8-in. screens, there is a swivel sub to enable orientation
of the junction without turning the screens, followed by the flexible junction and a screen hanger/packer.
An MWD is made up to an extension under the screen hanger/packer. The lateral screen liner is RIH on
a landing string. Prior to landing the flexible junction in the deflector, the lateral leg is oriented high side,
and the mainbore leg is landed in the deflector seal receptacle. The screen hanger/packer will then be set
and the landing string with MWD retrieved (Ruyter et al. 2006). The current configured Y-block Level-5
junction allows one to carry in the entire lateral screen assembly in the same trip (see Fig. 4) or, where
hole geometry is a concern the screens, can be run in independent of the Level-5 Y-block junction (see
Fig. 5).

Figure 4 —Norway Multilateral Completion – Level 5 w/Intelligent Upper Completion and Integral Screens.
SPE/IADC-178166-MS 11

Figure 5—Norway Multilateral Completion – Level 5 with Advanced Shrouded-Meshed Screens Tie-Back.

⬙Several studies have been performed recently in order to evaluate the benefits of utilizing multilaterals
on Troll without being able to do justice to all the benefits. First of all, with an initial ⬙target⬙ number of
170 reservoir locations and a fully exploited infrastructural slot number of 110, there are few other
options. If space would permit, and if possible form an infrastructural point, the cost for subsea template
installations including flow lines and risers would put the economics out of the context. Furthermore, the
application of multilateral drilling gives the opportunity to pursue ⬙less⬙ promising targets, hence,
comparing a multilateral well with the earlier drilled monobore wells would be a dissimilar comparison.
Basically, an extra branch on a well will add to the overall well cost by approximately 30%, or, result in
a cost reduction of ⫹12 MUSD compered to drilling two single lateral well. Review of wells on
production so far indicates that the daily production rate from a dual lateral is approximately 50 % higher
than for a ⬙single bore⬙ well. However, the cumulative production over the lifetime of the well is 100%
higher, i.e. a dual lateral will produce twice as much as a single bore well. This is presumed to be due to
a more uniform inflow over a greater area of the reservoir and a thus, a limitation of the gas coning effect
which again will prolong the lifetime of the well⬙ (Ruyter et al. 2006).
Australia – Re-entry Level-5 MLTs Combined with Shrouded Standalone Screens A majority
of the Level-5 MLT installations combined with standalone screens have been in new well applications;
however, over the years, there have also been a number of re-entry well applications in both the North Sea
and in offshore Australia. The MLT junctions for re-entry wells are very similar to new wells with slight
differences in that a packer is used for all drilling and subsequent diversion requirements. A milled
window is created versus the use of pre-milled windows typically associated with new well applications.
For a milled window, a precision milling machine is used to create the window to ensure that a long,
straight window is achieved similar to a pre-milled window application. For Level-5 installations, long,
straight windows are highly preferred to ensure that all long, stiff drilling assemblies and, more
importantly, completion assemblies can easily enter and pass through the junction window.
⬙Over the past 10 years, level 5 MLT technology has been used extensively in the North Sea. It had,
however, never been used in the southern hemisphere. Because the level 5 system had a proven track
record in subsea installations and was able to provide hydraulic and mechanical isolation of connected
wellbores, it was decided that the technology would be inaugurated in the Van Gogh field in the Northwest
Shelf of Australia. For the managers of the Van Gogh asset, knowledge, experience and communication
were the key drivers that enabled them to make the dramatic step forward and exploit the entire reservoir
12 SPE/IADC-178166-MS

asset with multilateral production wells. Nine multilateral wells replaced 18 single wells, amounting to a
significant saving in capex of about 24% for an additional 97% more reservoir exposure, requiring only
41%⬙ (Lawrence et al. 2010).
⬙The oil column is relatively thin and varies in vertical thickness. To obtain adequate drainage, many
horizontal oil production legs are required throughout the field, ranging in length from approximately 0.8
to 1.4 mi to maximize exposure. Due to its remote and environmentally sensitive location, the Van Gogh
field was developed with special consideration of logistics, efficiency and environmental effect. The plan
was to develop the field almost entirely with multilateral wells in order to achieve a lower capital
expenditure, a shorter project execution time and maximized reservoir coverage. The multilateral junction
was to be located within the reservoir itself, which mandated a sealed junction to provide hydraulic
integrity and prevent sand inflow through the junction. The Level 5 MLT installation requires 9 5/8-in.
mainbore casing with 8.500-in. drill-out, pre-milled casing window (aluminum external sleeve) and a
sealed junction rated greater than 1,000 psi burst and collapse. The junction is located within the reservoir
at high angle (typically horizontal) and the lateral completion can be installed in one trip. Premium screens
run with internal wash string for cleanup circulation while the system has a compressive strength rating
capable of running screen sections up to 1,450-ft long. Additionally, the installation is well-suited for
harsh subsea conditions and involves minimal installation steps. The use of off-the-shelf technology leads
to minimized lead times⬙ (Lawrence et al. 2010) (see Fig. 6).

Figure 6 —Australia Multilateral Completion – Re-entry Level-5 w/Integral Shrouded-Meshed Standalone Screens.

Middle East – Level-4 Smart Well with Inflow Control Device (ICD) Screens in Laterals ⬙ A
multilateral (MLT) well with an advanced intelligent completion string was recently completed in the
Middle East. The well was designed as a ⬙stacked⬙ dual producer in the upper and lower reservoir, and
was drilled using the latest geo-steering techniques to accurately place the wellbore in a highly faulted and
geologically complex structure. In the existing horizontal wells in the target sand reservoir of the target
field, premature water breakthrough caused the water cut trend to increase within months of production.
This occurred because the reservoir has a very high permeability sands along with active faults containing
high viscous reservoir fluids⬙ (Samie et al. 2012).
⬙New technologies were required to overcome the issue, maximize reservoir contact and enhance a
more uniform oil production from a single location. Introducing the smart Level-4 MLT well design to
SPE/IADC-178166-MS 13

this reservoir along with inflow control device (ICD), inflow control valve (ICV), isolation ball valve (LV
ICV) and other downhole gauges proved to be the optimum solution. It also aided in managing the
production and the reservoir proactively to achieve maximum oil recovery. Moreover, drilling several
laterals from a single wellbore with the ability to control production from both laterals had a great
economic advantage because of the optimized cost effective field management⬙ (Samie et al. 2012).
⬙Estimating the productivity of the laterals presented a unique challenge in these wells because the
lateral completion was designed with ICDs that must be adjusted before installation by selecting the
correct nozzle size for the reservoir quality in each of the swellable-packer compartments. This required
an immediate interpretation of the permeability in each lateral within hours of its being drilled so that the
ICDs could be configured accordingly on the rigsite. With the expected reservoir pressures, pressure drop
across the ICDs, and flow rate from the ESP, the flow ports in both ICVs were custom designed to suit
the life of the well. After analyzing the complete formation evaluation data gathered by the LWD suite
in both laterals, the preliminary completion string design was agreed among geology, drilling, and
completion specialists to arrive at the best reservoir profiling and compartmentalization. The design was
then modeled using a simulated BHA that included collars and stabilizers gauged to match the final
swellable-packers, ICD screens and blank pipes sequences to ensure that the hole condition and DLS
compatibility allowed the completion strings to be run successfully to bottom⬙ (Samie et al. 2012) (see
Fig. 7).

Figure 7—Level-4 MLT with intelligent Completion Combined with Inflow Control Device Screens.

Brazil Campos Basin – Level 5 with Screens ⬙Petrobras philosophy is one of zero tolerance con-
cerning sand production in offshore fields lest the governing parameters for sand production are not well
established for the vast majority of actual field situations and they may change along the life-span of the
wells. Should there be the slightest chance of sand production, a sand control method is installed in our
wells. In essence, this preventative approach of sand exclusion stems from the following facts: wellbore
integrity concerns, prohibitively high well intervention costs, the need to maximize production rates, to
achieve a maximum completion efficiency index, safety concerns, payback economics, and incapability
of sand-dealing in topside equipment’s. In fact, our offshore production facilities have not been designed
to process sand-bearing crude oils. Even though there is no such thing as a panacea to deal with all sand
control problems, gravel packing has established something of a reputation along the years. It is
14 SPE/IADC-178166-MS

considered the vintage alternative for sand control in horizontal open-hole wells with good vertical
permeability, non-uniform sands and no lamination. In addition to that, filling up the screen – wellbore
annulus of an open-hole horizontal well, with properly sized gravel, creates a secondary barrier to the
migrating sand grains, thus increasing the longevity of the gravel pack screens⬙ (Marques et al. 2007).
⬙This paper presents some of the experience of drilling and completing level 4 and 5 multilateral wells
in deep waters of the Campos Basin, in the last three years. It presents the reason for this initiative, a
general description of the several types of junction building processes (both milled and pre-milled window
systems) and some aspects of the wells that were drilled and completed: the Bonito well (water
depth:200m); Voador well (water depth: 565 m) and the two Barracuda wells (water depth: 802m/ 850m).
This paper also shows the lessons learnt during these complex projects and concludes that the multilateral
well technology became a viable alternative for subsea development⬙ (Sotomayor et al. 2001).
⬙The Voador field is located in the Campos Basin, located at 563 m of water depth. The reservoir is
unconsolidated sandstone. A level 5 multilateral well with dual opposing laterals was implemented do
deliver the desired injection rate while providing maximum reservoir exposure. The level 5 junction was
needed in order to guarantee that no water being injected with pressure would leak into the formation at
the junction. Planning was very important in this project. The Service Company that provided the junction,
together with Petrobras technical group and other service companies involved started to meet in order to
discuss the project and draw a detailed book of procedures and contingencies. The main aspects of the
project include: the junction building process; a sophisticated completion with the use of screens and
sacrifice packers (these sacrifice packers were located in the contact point between normal and 13 %Cr.
tubulars, in order to allow some galvanic induced corrosion), hydraulic fully balanced long stroke bumper
subs in the string in order to accommodate the heave associated with the floating rig during more sensitive
operation⬙ (Sotomayor et al. 2001).
Norway – First Level-5 MLT with Individual Remote Control for Lateral Sand-Screen Comple-
tions The original Level-5 Y-block junction has evolved to where, today, there are over a half dozen
variations to suit customized needs or applications. One of the more recently developed variations was one
driven by the need to allow for the placement of an inflow control valve (ICV) and other monitoring
devices directly across each junction location. Prior to this newly developed system, only two ICVs could
be placed in a given wellbore: one ICV that managed the tubing flow of the lower lateral or laterals and
a second ICV to manage the annulus flow of the upper-most lateral. Where ICVs were combined with
MLTs in the original system, there was a requirement for additional hardware to create the annulus flow
and to separate it from the tubing flow. More importantly, if the well had two or more lateral branches
below the upper lateral branch (which is managed by one of the two ICVs), the remaining ICV would have
to manage the commingled flow coming from all of the lower laterals. Operationally, this is not an issue;
however, should any one of the lower laterals begin to water out early, requiring further choking or shutoff
of the ICV managing these lower laterals, this would affect the production coming from the remaining
lower laterals. With the newer system, referred to as multibranch inflow control (MIC), ICVs (as well as
monitoring equipment) can be placed at each junction associated with each lateral, providing independent
control of all laterals. The following paragraphs address some of details associated with actual MIC
completions, and to date, dozens of MIC junctions have been successfully installed.
⬙The Troll oil field has been drilled and completed with more than 100 geo-steered extended-reach
multi-lateral (MLT) subsea wells having two, three or four branches each to maximize reservoir contact.
The Troll team has drilled multi-lateral wells from semi-submersibles for more than 10 years. The wells
are equipped with complex intelligent top completion (ITC) systems to optimize production. The oil
column of the Troll oil field was initially between 11 and 26 m thick, with an overlaying gas cap. The
wells are 2-5000m long horizontal multi-lateral branches; many completed with stand-alone sand screens
and autonomous inflow control valves (AICD) for the lower completions, with up to 80-90% screen
coverage per branch lateral⬙ (Prebeau-Menezes et al. 2013).
SPE/IADC-178166-MS 15

⬙Troll has thin oil layers, with gas above and water below, where MLT wells are the best solution to
increase the drainage area and subsequently oil production. However, during production, even with the
geo-steered optimized placement, gas break-through eventually occurs, and reduces the oil production.
This poses a problem especially to Troll B and C owing to their limited capacities for gas processing. In
addition, the Sognefjord formation has the potential for high sand production, and the field has a limited
number of well slots available. Therefore, to maximize oil production and to reduce gas break-through for
as long as possible there is a need for flexibility and control for flows in Troll MLT wells⬙ (Prebeau-
Menezes et al. 2013).
To combat the challenges addressed above, the Troll team has implemented the following completion
strategies:
● Use of advanced ICDs: Autonomous Inflow Control Devices (AICDs) installed on sand screens,
separated by swellable packers in each branch for the lower completions.
● Use of ICV’s installed above the 9 5/8 in. Intelligent Completion Interface junction.

⬙The lateral branches of Troll MLT wells can extend from 2000 to 5000⫹ m MD. Stand-alone screens
are used to limit sand production. These screens contain AICD’s that are valves that choke based on fluid
viscosities. Different fluids tend to have different viscosities, and the valve restricts low viscosity fluids
such as gas. These valves, combined with swellable packers, provide zonal isolation and delay gas
break-through within the oil-producing branches⬙ (Prebeau-Menezes et al. 2013).
⬙In October 2012, the Troll team installed the first multibranch inflow control (MIC) system on the
Troll well N-24. This system is believed to be the first Level 5, three branched well with individual branch
control worldwide. With this new and innovative junction and completion system, the operator now has
the ability to optimize the oil production from new extended reach multi-lateral wells. Troll’s typical MLT
wells contain two or three branches, where each branch is geo-steered and normally placed 0.5 m above
the oil water contact. For Troll, especially drilling and completing MLT wells are most cost effective and
environmentally friendly (reduced use of drilling and well resources and smaller environmental footprint)
compared to drilling individual multiple individual wells used for the same purpose⬙ (Prebeau-Menezes
et al. 2013) (see Fig. 8).

Figure 8 —Norway Multilateral Completion – Level-5 w/Intelligent Completion Control and Monitoring at Each Junction or Zone.
16 SPE/IADC-178166-MS

Gravel-Pack Completions Combined with MLT Technology Gravel packing is an option to standalone
screens for completing horizontal wells in unconsolidated formations and is a common completion
technique used in many places around the world. In the past, there has been some minimal history of
combining MLT technology with gravel-pack (GP) technology, primarily open-hole GPs; however, with
the advent of newer MLT junction technology, which has been proven to be successful in some
installations in offshore Brazil, there is growing interest in combining these two technologies going
forward. In this section, the discussion will center around the Brazil installs using fairly new junction
technology and will also address a newer developed system, where gravel packing off the lateral leg is
performed via an inner string that accesses directly through the MLT Level-5 junction.
MLT technology has advanced from the early days of being combined with slotted liners, then leading
systems to support long lengths of combined standalone screens, as well as some limited gravel-pack
installations. Previously, when MLT was combined with gravel-pack installations, the junction of choice
was Level-4 MLT junctions; however, a need arose for MLT gravel-pack solutions in which the junction
could not only provide sand isolation but also pressure integrity. Hence, a derivative Level-5 junction
system was developed that piggy backed off the success of the significant Level5 standalone sand-screen
history. The system has had success in multiple installations in the Peregrino field in offshore Brazil, with
campaigns being planned for future years. This latter system provides the means for both the mainbore
and the lateral to be gravel packed and combined with fluid-loss valve technology to provide temporary
isolation followed by the tie-back installation of the Level-5 junction connecting to both the mainbore and
lateral legs. This system also incorporates a platform to interface with any type of middle or upper
completion, including intelligent completions, and also supports a higher pressure rating to support
drawdown associated with reverse-out pressures.
● The OHGP system uses round lateral legs (as opposed to D-shaped legs for the original Y-block
systems).
● The OHGP system uses threaded premium connections between the upper primary Y-block
junction housing and the mainbore and lateral legs. No welding, as was associated with the
standard Y-block system is required for the OHGP system.
● The new Y-block OHGP system can withstand higher collapse drawdown pressures.
● The Y-block OHGP junction can accommodate 6-5/8 –in. liner-conveyed gravel-pack assemblies
combined with 5-½-in. screens.
● A seamless junction to lateral screen tie-back is accomplished with a shrouded open-hole stinger
assembly.
● The Y-block OHGP multilateral middle and/or upper completions can range from standard up to
the most complex of intelligent completions.
● Intervention is possible in the either lateral or mainbore, but not both (pre-determined).
● If required, fluid loss valves are easily accommodated in the sandface completions.
Trinidad – Level-4/5 MLT Combined with Gravel-Pack Sandface Completion ⬙As with single
lateral wells, gravel packing of multilateral wells may be required if non-uniform reservoir sand qualities exist.
Such was the case with this well in Trinidad. This heavy oil multilateral well was constructed in an
unconsolidated sandstone reservoir which contained 12-to-18 API gravity crude. The lower lateral penetrated
a separate lobe of the reservoir than the upper lateral. A 9-5/8-in. mainbore casing, which also contained a
pre-milled window section, was used. The inclination at the window joint was approximately 60 degrees. The
lower lateral extended horizontally for approximately 1200 feet from the bottom of the mainbore casing across
the reservoir. It was gravel packed using a pressure-maintenance horizontal completion system with 5-1/2-in.
premium mesh screens. Once the lower lateral was completed, it was temporarily isolated while the upper
lateral was constructed. Approximately 600 feet of 8-1/2-in. upper lateral borehole was drilled from the
mainbore pre-milled window down to the top of the reservoir. Seven-in. casing was then deployed and
SPE/IADC-178166-MS 17

cemented back into the 9-5/8-in. mainbore. Once the 7-in. casing was cemented into place, a 6-in. horizontal
section was drilled across the reservoir for approximately 1000 feet. The upper lateral was gravel packed using
a pressure maintenance horizontal completion system with 3-1/2-in. premium mesh screens. Total reservoir
exposure was approximately 2,200 feet⬙ (Cavender 2004).
⬙This well represents several ⬙firsts⬙ for this area as it not only represents the first multilateral well in
Trinidad but also is the first in the area that integrates sand control into a multilateral. A multilateral
completion was selected over conventional well construction to horizontally access heavy-oil reserves in
the Forest 4B and 4C sands, located at true vertical depths of 3850 and 4000 ft. respectively. Since the
formation parameters included poorly sorted, non-uniform formation characteristics, the completion
would have to employ some method of sand control. After reviewing many possibilities, horizontal
openhole gravel-pack technology had been selected to provide sand exclusion. A Level 4 multilateral well
junction was selected originally because it offered a cemented junction with full casing-drift access across
the mainbore/lateral interface. When sand was encountered above the junction area, a completion
workover was required to convert the existing Level 4 multilateral junction into a Level 5 to gain pressure
integrity across the junction area⬙ (Lougheide et al. 2004) (see Fig. 9).

Figure 9 —South America Multilateral Completion – Level-4 with Meshed Standalone Screens (Lougheide et al. 2004).
18 SPE/IADC-178166-MS

⬙To date, most sand control applications deployed in multilateral wells have been used slotted liners
and stand-alone screens. These types of installations have been very effective at providing the desired
borehole support and/or formation sand exclusion. In sandstone reservoirs that require enhanced sand
control techniques such as gravel packing and/or frac-and-pack service, the completion tool configuration
for the mainbore and lateral completions must interface with the overall multilateral construction aspects.
Developing a multilateral (MLT) well design is a complex process where many issues interact, and there
are often multiple solutions and well construction possibilities from which to choose. An effective
multilateral design strategy is to adopt the ⬙bottoms up⬙ approach. The reservoir and downhole completion
requirements are determined first, and then, the well is constructed back to the surface. Before this strategy
can be adopted, the multilateral junction requirements must also have been determined. Multilateral
technology coupled with horizontal gravel pack has been proven to be a viable alternative for heavy oil
development in Trinidad. Collectively, the initial production rates from the laterals achieved 4500-BOE
rates, which is ten times that of a conventional heavy oil well in Trinidad. The learning curve associated
with the first well will enable future heavy-oil development to be practical by reducing construction costs
and drastically increasing the asset value for the customer⬙ (Lougheide et al. 2004).
Brazil Peregrino Field – Multilateral Level-5 Combined with Open-hole Gravel-Pack Comple-
tions Up until recent times, there has been very limited documentation of known cases where multilaterals
have been combined with gravel-pack completions. Early this decade, there was an interest in taking existing
Level-5 MLT junction technology and developing a derivative system of the Y-block junction, which has had
a long and successful history when combined with standalone screens. The new Y-block system supports
higher drawdown pressures than its predecessor, provides re-entry into either the mainbore or lateral, and can
be matched to any type of upper or mid-completion, including intelligent well completions. The author has
addressed this in more detail on the previous page. The remainder of this section will address the actual
installations of this new MLT junction solution. Ultimately, three wells from 2012–2014 were successfully
completed and placed on production, with plans to continue MLT installations again in 2017.
⬙Peregrino is an offshore oil field (block BM-C-7) located east of Rio de Janeiro, Brazil in the
southwest part of the Campos Basin area. The oil field was discovered in 2004. Statoil Oil and Gas, Brazil
has been operating the Peregrino Feld since 2008. The unconsolidated reservoir (Carapebus formation)
shows a mid to high permeability and produces heavy oil. Openhole lengths ranged from 800 m to 2,300
m for Peregrino producers. In order to maximize reservoir drainage, to save the platform’s slot avail-
ability, and to optimize ESP efficiency, Statoil planned to drill and complete dual horizontal multilateral
wells with horizontal gravel packs on each branch that would have the capability for selective production
from each lateral section. Originally, all producer wells were planned as horizontal, open hole, single-bore
wells. After two years producing, resources and reserve estimation were reviewed, and multilateral wells
were included as part of a plan to increase oil recovery. According to these studies, multilateral wells will
be responsible for an increase of 1.6% from the original estimated reserves⬙ (Ranjeva et al. 2014).
⬙The successful installation of a dual-bore horizontal gravel-pack completion with a Level 5 Multilateral
System offshore was an industry first for Brazil that opened ambitious perspectives for the Peregrino field in
terms of increased reservoir drainage that would improve the oil-recovery factor, and thus, the economic gains.
This first multilateral well in offshore Brazil is part of the operator’s increased oil recovery (IOR) efforts for
the Peregrino field. This is also the first multilateral well in Brazil with gravel packs in both branches. The
lower completion design requirements called for a screened completion with long openhole horizontal gravel
packs for sand control and production optimization throughout the life of the field. The initial scope for the
bi-lateral completion on Peregrino called for long, horizontal openhole gravel packs on both legs with openhole
sizes being 8½-in. and openhole lengths of up to 2,000 meters to be gravel packed and completed with 5½-in.
screens. The design did not require access to both legs, but did require the possibility for the installation of a
selective completion that would allow the production of each branch independently⬙ (Ranjeva et al. 2014).
SPE/IADC-178166-MS 19

⬙When considering the lateral open hole, the scope of design appeared to be more challenging. The 5½-in.
shrouded screens were fully qualified to be run through a pre-milled window, but there were not any existing
sandface completion systems that would allow gravel packing such long horizontal lateral open holes. Thus,
the following plan was determined. A temporary liner would be run to perform the gravel pack to mitigate or
even eliminate any constraints on the OD/ID screen/washpipe ratio that would remove any of the pressure
limitations for achieving a greater than 1,500-meters-long, openhole gravel pack on the lateral leg. This
temporary liner set across the window during the gravel-pack pumping operations also would allow a
temporary complete isolation of the mainbore leg. After the screen out and reversing out the sand excess, once
the liner-conveyed gravel-pack (LCGP) service tool had been pulled back to surface, the temporary scab liner
and a gravel-pack packer would be retrieved in a dedicated run. Then, a standard tieback multilateral system
junction would be deployed and landed into the lateral and mainbore completions, allowing production from
both legs. As part of the basis of the design was the capability to produce either branch separately, an upper
middle completion would be run to allow intervention less selectivity for the branch selected to produce⬙
(Ranjeva et al. 2014) (see Figs. 10, 11, and 12).

Figure 10 —Brazil Multilateral Intelligent Completion with Gravel-Packed Laterals.

Figure 11—Brazil Multilateral Completion – Level 5 with Gravel-Packed Laterals.

20 SPE/IADC-178166-MS

Figure 12—South America Multilateral Completion – Level 5 with Gravel-Packed Laterals.

⬙The existing liner-conveyed gravel-pack system was the option chosen to be customized, tested, and
developed for the application. The original system consisted of running a ⬙scab⬙ liner below a hanger and
having all the gravel-packing components in the 8½-in. open hole. The first installation commenced in
October 2013 on Peregrino. The mainbore gravel pack and middle completions, window opening, and
lateral drilling operations were performed as planned, and the screens were run to TD on the lateral
without any issue⬙ (Ranjeva et al. 2014).
Some highlights from the first well:
The lower lateral contained 6,345 ft of screens (5.5–in. wire wrapped and mesh screens) at a total depth
(TD) of 17,775 ft MD (7,572 ft TVD), with the sand-control scab liner packer set at 11,371 ft. The upper
lateral (top of window at 11,227 ft and inclination at ~85°) contained 3,937 ft of screens at a TD of 15,390
ft measured depth (MD) (7,486 ft TVD). For this well, the lower lateral was successfully gravel packed
and temporarily isolated; however, for the upper lateral, the inflatable packers (ECPs) did not set and,
combined with an overage of proppant pumped (over 300% more proppant than planned), led to packing
in the scab liner and inner string. Eventually, the temporary scab liner and inner string were fished out of
the well, and the junction was left as a Level-2 installation with the well considered a success with both
laterals contributing to production. Total MLT installation time was 4.78 days with some non-productive
time (NPT) experienced.
Some highlights from the second well:
In the second multilateral producer in the Peregrino field, both the main and lateral branches were placed
in the Upper Carapebus formation sands. The lower lateral has a total drilling length of 4,153 ft in the
reservoir at an MD of 15,784 ft (7,716 ft TVD), with the SC packer at 11,469 ft and screen length of 4,625
ft. The upper lateral branch has a total length of 4,160 ft and screen length of 3,093 ft installed at an MD
of 14,452 ft (7,677 ft TVD and inclination of 85°), with the SC packer at 11,174 ft MD and top of window
at 11,250 ft. This well was successfully completed (100% pack efficiency) with a Level-5 MLT junction
and upper completion for commingled production. The total time for MLT installation was 6.27 days, and
the completion budget time was 70.8 hours. This operation was expected to take 54 hours to complete;
however, the actual time was 57 hours, with 2.3 hours of downtime and. 5 hours of waiting time.
Some highlights from the third well:
In the third Peregrino well, the lower lateral had a measured depth of 15,800 ft (7,486 ft TVD), with the
SC packer set at 11,843 ft and a screen length of 2,952 ft. The upper lateral had a measured depth of
15,380 ft (7,503 ft TVD), with a top of window at 11,620 ft and screen length of 3,641 ft. This well was
SPE/IADC-178166-MS 21

successfully completed (100% pack efficiency) with a Level-5 MLT junction and upper completion for
commingled production. The total MLT installation time was 5.50 days with 0.0 nonproductive time.
Development of a Gravel-Pack MLT Junction System that Supports Gravel Packing through the
Junction A derivative version of a previous gravel-pack MLT junction used for the Peregrino project
was developed to provide an enhanced lateral leg (to allow for gravel packing with the inner string directly
through the junction itself via lateral access). It was anticipated that high drawdown at end-of-life
production scenarios would require a 5,000-psi burst/collapse junction rating in a 120° C well. The
developed system is matched to 10-¾-in. casing with a large lateral leg of 5.5-in. tubing and a mainbore
leg with an equivalent flow area to 3.5-in. tubing (see Fig. 13).

Figure 13—Proposed Level-5 Multilateral Completion – Enhanced Lateral Leg to Allow for Gravel Packing through Junction.

As with most Level-5 junctions noted within this paper, the assembly consists of three major elements:
● Y-Block w/ Diverter – Connects lateral leg, mainbore stinger, and crosses over to an 8-5⁄8-in.
extension. A pre-installed deflection face provides the access ramp for lateral access with fluid
bypass for mainbore hydraulic access. To facilitate a typical DIACS (downhole instrumentation
and control systems) installation, the junction required an integral PBR.
● Mainbore Stinger – The stinger seals within the deflector assembly, lands out after the no-go tags,
and shears down an internal ring to provide a positive indication of ⬙set on depth.⬙ The stinger has
a double-mule-shoe profile cut on the bottom to aid entry to the deflector throughbore.
● Lateral Section – Provides the flow conduit and intervention path to the lateral bore. A lower
lateral PBR (not shown) is installed below the lateral leg to provide the hydraulic seal area to
isolate from mainbore flow. The larger-sized lateral leg is such that it provides sufficient access
to the lateral for potential cementing, perforating, and gravel-packing operations.
Frac-Pack Completions Combined with MLT Technology Almost all frac-pack treatments are per-
formed in cased-hole wellbores via perforated sections; however, frac packing in the open hole of highly
permeable, unconsolidated formations is also doable. To date, there have been a limited number of installations
where frac packs and MLT technology have been combined. In the example below, the author recognizes one
MLT application whereby the lateral is a cemented liner that ties all the way back to the mainbore, thus
resulting in a Level-4 cemented junction. Using a temporary isolation system that straddles the junction, the
lateral leg can be frac packed at high pressures without the junction or other remaining laterals being exposed
22 SPE/IADC-178166-MS

to the high pressures. Once the lateral frac pack is completed, the temporary isolation device can be removed
and a lower mainbore completion installed, followed by the installation of a Level-5 junction tied to a lateral
completion and an upper completion back to surface. Additional discussion centers on the development of a
high-pressure Level-5 junction to support future frac-pack applications.
Brazil – Level 5-MLT Completion with Gravel-Packed Laterals ⬙This multilateral injection well
was completed offshore Brazil using a floating rig. The customer wanted to be able to inject into the two main
zones simultaneously from a single tubing string. The reservoir was an unconsolidated sandstone formation that
required frac and pack application. First the mainbore was drilled into the target reservoir and cased with 9 5/8
in. casing. The lateral section was drilled into the target reservoir and cased back into the 9 5/8 window. Once
cemented, the 7 in. liner top overlap into the mainbore provided a liner top pressure seal during the lateral
completion phase. The 7 in. lateral and the 9 5/8 in. wellbore were circulated with completion fluid. Two zones
were frac and packed inside the 7 in. lateral. To complete the lateral completion phase an isolation packer
assembly was spaced out and set 300 feet below the junction. A circulating bypass assembly provided fluid loss
control once the isolation packer was set. The lateral liner transition joint was washed over, retrieving the
drilling whipstock and re-establishing the mainbore below the junction. The mainbore completion called for
one frac and pack completion. During the mainbore frac and pack operation, a junction isolation tool was
positioned in the work string, which straddled the junction throughout the treating operations. The tool isolated
the junction from all reversing and circulating pressures and provided a ⬙live annulus⬙ during the frac and pack
treatment. A flapper valve was used for fluid loss control after the frac and pack. To prepare for the Level 5
installation across the junction, an isolation packer was set at a precise distance below the junction area. The
Level 5 lateral re-entry system was installed across the junction area. The Level 5 lateral re-entry system was
installed across the junction area, and a single production tubing string was run to surface⬙ (Cavender et al.
2003) (see Fig. 14).

Figure 14 —South American Multilateral Completion – Level 5 with Frac-Packed Laterals (Cavender et al. 2003).

New Development of a High-Pressure Frac-Pack MLT Junction System More recently, a Lev-
el-5 MLT junction was developed for integration with a single-trip, multi-zone cased-hole and open-hole
SPE/IADC-178166-MS 23

frac-pack system to support the deepwater market. It was developed to suit water depths of 5,000 to
10,000 ft and junction depths in the 27,000 to 30,000-ft range. The end result was a fully functional
Level-5 MLT system that required the development of over twenty plus new components related to the
junction system. All of the individual components were functionally tested, and various system assemblies
were system tested. A complete new suite of tools with new technology features and benefits were
required to support this particular application, where depth and azimuth correlation will be key to these
types of installations. For deep (not just deepwater) and extended-reach applications, where operations
with current latch technology would not support functionality at these deep depths, the new latch and
latch-coupling solution developed here has great potential. The lateral legs are both 4.5-in. tubing strings
with the Y-block matched to 11-7/8-in. casing and material strengths of 110,000 psi (Super 13Cr on
certain components) (see Fig. 15).

Figure 15—Proposed Frac-Pack Level-5 Multilateral Completion.

Having a system that is compatible with a frac-pack sand-control solution is seen as essential in tapping
into the emerging deepwater markets of the GOM, offshore Brazil, and offshore West Africa.
● It was estimated at one time that the deepwater rig count was going to increase from ⫹/-200 rigs
in 2011 to 300⫹ by 2015. With the current climate, this has obviously now changed.
● CERA projects deepwater-development growth from $4 billion to $11 billion in 2015.
● Wood Mackenzie estimates total exploration expenditures of ⬍50% in deepwater, putting total
exploration market at ⬎ $12 billion.
Conclusions
There is a cornucopia of applications where MLTs can bring value to a given project. The MLT systems
and solutions noted throughout this paper and their respective results are directly related to the large
numbers of successful installations, with a highly proven reliability track record as a result of extensive
24 SPE/IADC-178166-MS

experience, and with highly knowledgeable engineering and operational personnel to prepare, plan, and
execute MLT projects integrated with any type of sandface, mid, or upper completions.
⬙The implementation of multilateral technology (MLT) at an early planning stage enables the addition
of production intervals at a cost of 15 to 30% of the initial well cost, which makes many marginal field
developments viable projects. For mature fields in which field development costs are written off,
approximately 50% savings can be achieved by combining three laterals into a single wellbore. In
addition, the operator may retain the tail production from the two other wells for a longer period. In areas
where the production is limited by the reservoir properties or drainage length, a dual MLT well may
deliver approximately 85% of the production from two conventional wells. Because of reduced drawdown
and delayed water and gas coning, the cumulative production from the same dual MLT well is typically
greater than for single wells. Operators using MLT report an added well construction cost of approxi-
mately 30% for a single lateral, independent of the lower completion system used and the type of MLT
junction installed. This number reflects the drilling and completion costs only and does not include cost
for facilities, pipelines, and templates. With these costs included, the cost of a lateral should be
approximately 15 to 20% of the main bore. Most of the added time is time spent on lateral drilling and
completion operation; less is spent on the junction construction itself⬙ (Liland et al. 2014).

Acknowledgements
The author would like to thank Halliburton for their continuing commitment, cooperation and support, and
permission to publish this work. He would also like to thank all who have made contributions over the
years towards the evolution of integrated solutions involving multilaterals, various sandface completions,
and multiple assortments of mid and upper completions.

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