spe-171267-ms complex well design for multilaterals offshore north caspian sea
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SPE-171267-MS
Complex Well Design for Multilaterals Offshore North Caspian SeaAlexey Valisevich and Vasiliy Zvyagin, Lukoil; Robert Famiev, Mirat Kozhakhmetov, Alexey Paramonov,and Marat Akhmetov, Schlumberger
Copyright 2014, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Russian Oil and Gas Exploration and Production Technical Conference and Exhibition held in Moscow, Russia,
1416 October 2014.
This paper was selected for presentation by an SPE 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 and are subject to correction by the author(s). The material does not necessarily reflect
any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written
consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may
not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract
The success of the drilling campaign including drilling efficiency, service quality, personnel safety and
cost is critically dependent on robust solutions developed during the design phase of the overall well
construction process.
One of the most critical stages of the overall well construction process is the well design phase. The
drilling project service quality, personnel safety, drilling efficiency and cost directly depend on the robust
solutions elaborated at the design phase.
This paper describes the advanced technical engagement between an operator and an integrated
services company to generate a basis of design for drilling and completing development wells in the
Filanovskogo offshore field, in the north of Caspian Sea. The basis of design is a document that describes
well design principles, engineering solutions and technologies required to drill and complete the wells.
The paper explains the design approach selected by the project team, project design stages, foreseen
challenges and technical solutions to deliver efficient well designs that could meet operator requirements
and comply with Russian regulatory rules.
The key technical challenges of the Filanovskogo field are that the reservoir zone is located at shallow
true vertical depth (TVD); the high formation collapse gradients and low mud loss gradients create a
narrow mud weight window environment, along with complicated well profiles involving multilateral
horizontals and extended reach (ER) wells. This paper illustrates the development of a basis of design to
ensure cost-effective access to reserves. It covers the operator and the service company experience in thedrilling of ERD wells, applying advanced technologies for windows milling, completion options screening
process and designing a multilateral junction. It also provides an understanding of the importance of
operator and service company departments integration processes in order to achieve well objectives. To
support the basis of design development, a comprehensive risk register was generated to minimize drilling
risks.
The process of technical integration between the operator and the service company in the early stages
of operational planning by developing drilling and completion design is unique for Russian O&G
operators and was done by assuming that it would be very efficient through providing technical integrity
and minimizing the project risks. The drilling and completion design consideration processes described in
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this paper can be used to provide valuable insight for future projects where up-front complex technical
study is key to success.
Introduction
The Filanovskogo oil and gas condensate field, named after Vladimir Filanovsky, is located offshore in
the north of Caspian Sea and is planned to be operated by Lukoil. The field was discovered in 2005 by
drilling and testing six exploration wells from 2005 to 2011. The closest fields to the Filanovskogo areRakushechnoye and Korchagina where development wells are currently being drilled. The Korchagina
field is a good reference for the advanced drilling and completion technologies as it is one of the first fields
in the region where shallow TVD horizontal ER wells are being drilled.
The Filanovskogo field development plan is to drill 20 development horizontal wells, maximizing field
coverage. Of these 20 wells, 14 will be production wells and 6 injector wells. The main objective is to
produce oil from the Neokomian sandstone reservoir with further workover operations to produce gas and
condensate from the upper Aptian formations. Eleven out of the fourteen production wells are planned to
be dual-lateral wellbores to produce oil from both the lower and the upper part of the Neokomian
formation separately, with the remaining three wells being monobore.
Filanovskogo field geology is represented by carbonates and sandstone formations located 1,513 m
TVD below the sea level with Cretaceous, Paleogene, Neogene, and Quarternary systems lying above.The target reservoir is the Neocomian formation lying at 1,405 to 1,513 m TVD. There are 18 faults
determined within the field area and some wells are planned to be drilled through those faults.
The drilling of the 20 wells is planned from two fixed platforms and a jacket using a jack-up rig. All
horizontal wells will be drilled in different azimuths from 3 rig locations as shown in Figure 1below.
The main drilling challenges in the Filanovskogo field are related to the complex geology of the field,
relatively shallow TVD of well targets, wellbore instability and drilling through faults. A complex
geomechanics study of the field revealed stresses anisotropy, high formation collapse gradients and low
mud loss gradients, creating a narrow mud weight window environment.
At the field planning stage, Lukoil decided to apply an integrated approach in drilling and completion
design of the wells, engaging a leading service company, which had experience in designing such complex
fields. This integrated design process between the operator and the service company will be discussed
further in this paper.
Parties involved in the drilling and completion design
The basis of design (BOD) for drilling and completion of development wells in the Filanovskogo field was
developed in 2013 in order to generate technical solutions for the 20 planned wells using a uniform
technical approach involving proven technologies and experience. The process of developing the BOD
involved three parties who worked together to achieve the same objectives. Lukoil as the field operator
had initiated and leaded the BOD development and was the main decision maker. The second party (the
operators engineering and research institute) Lukoil-Engineering - VolgogradNIPImorneft was respon-
sible for technical assurance and conformance to the Russian regulations. Lastly, Schlumberger (the major
integrated oilfield services provider in the region) was responsible for developing the design and solutions
based on operational experience in the region and worldwide engineering expertise. A multidisciplinary
Schlumberger technical team consisting of engineers with expertise in directional drilling, geomechanics,
drilling fluids, drilling bits, window milling, formation evaluation, geosteering, and completions were
involved in the design, which was led by the Integrated Project Management (IPM) segment.
The design process
The Filanovskogo field BOD process was performed in three main phases. The first phase included input
data gathering, offset wells data analysis, wells trajectory generation and optimization based on geome-
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chanics model, wellbore stability analysis and casing seat selection and a preliminary high level
completion sizing. The second phase included the well design development and a casing design. During
this phase, the completion sizing was finalized and production casing size was determined. The well
design was driven by selecting the optimum open hole and casing size in order to allow drilling the well
without wellbore collapse and mud losses, trouble-free casing installation and cementing. All casing
strings were designed to withstand the expected loads throughout the well life cycle. The last phase of the
project was aimed to perform the detailed engineering in each area of the well construction cycle, such
as drilling fluids, bits selection, directional drilling and surveying, well control, running and cementing
casings, formation evaluation, rig equipment sizing, window milling and detailed completion design.
During this phase, a detailed operational risk register was developed to highlight all potential drilling
hazards for each wellbore section accompanied with proper prevention and mitigation measures. The
Filanovskogo BOD process workflow is presented in Figure 2below.To ensure the technical integrity of the BOD, the project was divided into three milestones. Upon
achieving the first milestone when the first two phases were completed, a casing design technical peer
review was held between three parties to ensure design objectives were met and approval was obtained.
This milestone required that all well trajectories were prepared and optimized for a wellbore stability and
that the final well design for each well was complete. Out of all wells, a base (reference) well was selected
to perform detailed engineering that would be fit-for-putpose for all other wells in the field. The most
challenging well was selected as a base well with the longest measured depth (MD), multi-lateral
completion and worst direction of drilling from the wellbore stability perspective.
Figure 1Filanovskogo field development plan map.
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Wellbore stability
Wellbore stability is a major risk for the Filanovskogo field. Maximum attention was brought to the
wellbore stability analysis while designing the wells. The offset Korchagina field has similar geological
conditions, so the Filanovskogo field was assumed to have the same risks relating to poor wellbore
stability and narrow mud weight window environment, which led the team to decide to build a 3D
geomechanical model. In general, this model is a set of stress-regime data for the formations covered in
it. After the model is built, wellbore stability analysis may be performed along the each well path, which
is inside the model boundaries. Wellbore stability analysis involves estimation of the pore pressure,
wellbore collapse, loss, and formation fracturing pressures gradients. Plotting these gradients altogether
allows a safe equivalent circulating density (ECD) window or mud weight window to be estimated for
mud weights at which the well will be drilled without wellbore collapse or cavings, losses or fracturing
of the formation.
The area covered by the 3D geomechanical modelling included all planned wells within the model
boundaries as shown in Figure 3. The main model input is the data obtained from exploration wells
Rakushechnaya 2, 4, 5, 6 and 8. This data includes: stratigraphy markers, the 3D amplitude cubes in time
and depth scale, the cube of interval velocities, the formations surfaces and corresponding faults in time
and depth scale, vertical seismic profiling data.
Trajectory optimization
The minimum and maximum horizontal stress orientations within the field were obtained using the 3D
geomechanical model. It was concluded that drilling in the direction of the minimal horizontal stress
(which is 60 to 240 degrees in azimuth for the Filanovskogo field) would be the least problematic.
Figure 2Filanovskogo BOD workflow.
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Trajectories of the wells oriented along or close to the maximum horizontal stress of 150 to 330 degrees,
needed to be optimized. The main optimization principle was reducing the hole inclination and the
azimuth change along with the reducing the length drilled in the unstable intervals. A wellbore stability
analysis was performed for an initial trajectory of every well to estimate the mud weight window. If the
mud weight window was narrow or not existent in any of the intervals, then the trajectory optimization
was performed. After that the wellbore stability analysis was repeated again. These iterations continued
until the wellbore stability analysis showed an acceptable mud weight window. At this moment the
trajectory was considered to be optimal. The main well trajectories optimization results are shown in
Figure 4. Finally all well trajectories were optimized to improve wellbore stability, which resulted in a
sufficient mud weight window to be able to drill the wells without wellbore collapse and lost circulation.
Casing seat selection
Casing seats selection was done based on the given geological conditions: pore pressure and gradients of
wellbore collapse, loss and formations fracturing pressures. Another factor that influenced the casing seat
selection was a requirement to drill the second lateral from cased hole. A 762-mm (30-in) conductor was
designed to be piled down to 120 m from the sea level, in the first tough semisolid clays. A 508-mm
(20-in) surface casing was planned to be set before drilling through gas-saturated Aptian and Albian
formations at the Maykop formation bottom, at 658 m measured depth (MD), 649 m TVD. An
intermediate casing was planned to case-off gas-saturated Aptian and Albian formations and to be set at
1,333 m MD, 1,221 m TVD. A production casing seat was selected to be as close as possible to the target
reservoir interval and assuring there is a room to mill a window from it to drill the second borehole to its
target. A typical dual-lateral well schematic is presented in Figure 5. For the base well, the shoe of the
production casing was set at 3,000 m MD and 1,447 m TVD. The trajectory optimization for some of the
wells resulted in a long interval of the production casing section (over 1600 m for the most critical wells)
to be drilled horizontally inside the reservoir. The window was planned to be milled at 2,000 m MD and
for the most challenging wells, inclination at that depth was almost 90 degrees, creating additional
challenges for sidetracking.
Figure 3Filanovskogo field 3D geomechanical model boundaries.
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ECD management, well schematic and drillstring selection
The main objective of the well design and a drillstring selection was to keep static mud weight above the
collapse gradient and the drilling ECD below the loss gradient. As the first solution, the engineering team
decided to use conventional wellbore and casing sizes for the well design such as: 762.0 x 508.0 x 339.7
x 244.5-mm (30 x 20 x 133/8
x 95/8
-in) casing with 660.4 444.5 311.2 215.9-mm (26 x 17.5 x 12.25
x 8.5-in) borehole. Further hydraulics and torque and drag analysis for the most critical wells indicated
that the conventional wellbore and casing sizes were not appropriate for all of the wells. The objective was
to standardize the wells design for all Filanovskogo field. To drill with commonly used wellbore and
Figure 4 Well trajectory optimization results.
Figure 5Base well schematic.
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casing sizes, light weight drill pipe (DP) needed to be used to optimize the hydraulics. This apparently
limited the maximum weight on bit (WOB) due to buckling effect. Involving the light weight DP also
required keeping of the three different sizes of DP on the rig which complicated the pipe management.
Although the analysis was done for contingency case, where mud rheology would be higher than planned,
it was found that for some wells even the use of the light weight DP resulted in the drilling ECDs
exceeding the loss gradient.
To allow some margin in the well design, it was decided to upsize casings and wellbores to 762.0 x
508.0 x 406.4 x 273.1 mm (30 x 20 x 16 x 103/4
) and 660.4 x 469.9 x 342.9 x 241.3 mm (26 x 18.5 x
13.5 x 9.5) accordingly. The change enabled the use of the tapered 127 x 139.7-mm (5 x 5.5-in) drill pipe
(DP) which allowed higher maximum WOB and hence higher rates of penetration (ROP). The hydraulics
analysis with the tapered drillstring confirmed ECD reduction with acceptable safety margin before
reaching the loss gradient while drilling
The main design challenges for each wellbore section and their addressed technical solutions will be
described below in the paper.
Mud weight and mud type selection
Mud weight selection for the top sections of the wells was driven by the drilling experience acquired from
the offset wells. For the production 342.9-mm (13.5-in) and the lateral 241.3-mm (9.5-in) holes mud
weight selection was driven by the formation collapse gradients taken from 3D geomechanical model. An
appropriate mud weight was selected for each wellbore section for each well in the field. Based on the
offset exploration wells of the Filanovskogo field and development wells of the Korchagina field, 1.24-SG
mud weight was selected for a 660.4-mm (26-in) surface section, and 1.35-SG mud weight was selected
for a 469.9-mm (18.5-in) intermediate section.
The wells in the Filanovskogo field were designed to be drilled in different directions and therefore the
stress regime for each well was different. The stress regime and pore pressure for each well defined a
particular mud weight window. The mud weight window estimation for the 342.9-mm (13.5-in) and the
241.3-mm (9.5-in) hole sections was based on the output of the wellbore stability analysis which wasperformed after final trajectory optimization process. The mud weights for the above sections were
selected to minimize the risks of the wellbore collapse and to keep the drilling ECD below the loss
gradient (Figure 6). As the result, required mud weights for the 342.9-mm (13.5-in) section were set
between 1.45 SG and 1.48 SG, and for the 241.3-mm (9.5-in) section were set between 1.35 SG and 1.40
SG (depending on the well).
The worldwide experience and the local experience from the Korchagina field confirm that drilling
wells with extended horizontal section in a narrow mud weight window environment using water-based
mud (WBM) systems has a number of limitations. These limitations include wellbore instability, relatively
high friction factors and as a result - higher torque and drag loads while drilling and running casings. The
majority of the Filanovskogo field wells have long horizontal sections and are of a complicated
dual-lateral design, so, to avoid significant design limitations relevant to WBM, the oil-based mud (OBM)
system was selected for drilling all the wellbore sections from top to bottom. The most suitable base oil
for the drilling conditions of the Filanovskogo field was the DF-1 mineral oil. The DF-1 based mud was
successfully applied on Korchagina field ER wells and resulted in maintaining low friction factors while
drilling horizontal wells up to 7,600-m MD, improved wellbore stability (cavings volume and reaming
time were significantly reduced), improved resistance to any type of drilling fluid contamination (cuttings,
cement, formation water), stable mud rheology and mud weight. Additionally, this OBM was re-usable
and allowed for long storage.
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Sidetrack design
The kick-off point to the second lateral in the dual-lateral wells of the Filanovskogo field was designed
to be in the tangent section with the inclination of 70 to 90 deg. Setting a whipstock, milling a window,
and kicking off the wellbore of such inclination is challenging and therefore the operations should be
engineered thoroughly.
A single-run whipstock system was selected to be able to run a milling assembly with the whipstock
simultaneously, then orient and set the whipstock and then mill the window within the same run in the hole
without an extra trip. The whipstock system contains an expandable retrievable hydraulically activated
hanger, which could be retrieved after the liner is run in the second lateral hole. A special multiramp
whipstock should be used. It has a multiple-angle whip design allowing a high-quality useable window
delivery. The combination of ramp angles maximizes milling efficiency, prolongs a window mill life, and
produces an optimum dogleg through the window. Milling assembly is presented inFigure 7. Milling will
be performed by triple-mill assembly consisting of a lead mill, a follow mill, and a dress mill. The
triple-mill provides a hydraulic path from the milling bottomhole assembly to the whip and anchor via a
hydraulic hose.
A Dual-lateral well trajectory design requires the whipstock to be set at -45 degrees or45 degrees
of the gravity toolface using a regular directional control measurement-while-drilling telemetry system
(MWD). After a window is milled, a rathole of approximately 5 m should drilled in the formation. As per
the Sakhalin-1 project sidetracking experience, a milling assembly normally has a dropping tendency of
around 0.5 deg per 5 m. To ensure proper sidetracking, a special sidetrack process (presented in Figure
8) resulting from the Sakhalin-1 sidetracking experience was taken into consideration for a design
purpose. After the rathole is drilled, the milling assembly needs to be pulled out of the hole and a drilling
Figure 6Mud weight window for the base well.
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bottomhole assembly (BHA) with a rotary steerable
system (RSS) to be run in hole to continue the
sidetrack. The first eight meters should be drilled
with 100% build setting of the RSS and the follow-
ing 25 m should be drilled in neutral RSS setting
mode (tangent).
Main well design solutions
In this section, the design solutions will be de-
scribed for each of the challenges for the most
critical hole sections.
Top hole sections
The main challenges faced by the engineering team
while designing the top hole sections were related to
a potential risk of well collisions. The planned well
slot separation at both platforms and at the jacket
was just 2.4 m. The first step to minimize the risk ofa well collision is ensuring a proper wells-to-slots
allocation according to the targets direction. The
second design solution is to drive the conductors in
a predetermined direction and with a predicted po-
sition of the shoe at the final penetration depth. The
engineering team came up with this solution after
having had problems with undesired position of the
conductors shoes, which created high collision risk
among neighbor wells at the Korchagina field platform. Unpredicted deviation at the conductor shoe
created many high collision risk situations. To get the predicted direction and deviation at the conductor
total depth, special conductor drive services may be used. Predicted direction and deviation at the total
conductor depth can be reached by using a special directional drive shoe. The directional drive shoe
consists of a 2.4-m section of the conductor that is welded to the shoe joint with predetermined settings,
and stabilizer bars along the outer wall of the conductor to hold the direction while driving. There are
some conductor directional driving service providers in the market. Another solution that intended to
reduce a collision risk for the surface section was the use of the gyro while drilling (GWD) measurement
system instead of the regular MWD system. GWD tool will reduce the ellipses of uncertainty for a
direction survey, hence will improve the directional survey accuracy and as a result will help to reduce
the collision risk. In a case of the GWD tool failure, installation of a special oriented sub as a component
of the surface section BHA was planned. The sub will enable running gyro survey on a wireline to confirm
wellbore position.
The surface 660.4-mm (26-in) section is to be drilled by steerable motor and milled-tooth rollercone
bit due to the large hole size and in order to improve BHA steerability in increased collision risk
environments. Designed drilling parameters are as follows: weight on bit of 8 to 16 metric ton, flow rate
of 3,300 to 4,500 lpm, string rotation speed of 120 to 160 rpm, and expected rate of penetration in
660.4-mm (26-in) section of 16 to 21 m/h.
It was decided to drill the following 469.9 mm (18.5) section by push-the-bit rotary steerable system
and 5-blade steel body polycrystalline diamond compact (PDC) bit. Using the RSS improves hole cleaning
due to continuous string rotation, reduces reaming time and hence increases average ROP per run. Steel
body bit was selected due to the wider junk slot area to prevent high risk of bit balling. Designed drilling
Figure 7Milling assembly and whipstock system.
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parameters are as follows: weight on bit of 14 to 16 metric ton, flow rate of 3,800 to 4,200 lpm, string
rotation speed of 120 to 150 rpm. The expected rate of penetration in the 469.9-mm (18.5-in) section is
35 to 40 m/h. The 406.4-mm (16-in) intermediate casing is designed to be a flush joint and to be run
conventionally.
The surface 660.4-mm (26-in) section is to be drilled by a steerable motor and a milled-tooth
roller-cone bit to maintain a good BHA steerability in a big hole size across a high collision risk interval.
Designed drilling parameters are as follows: weight on bit of 8 to 16 metric ton, flow rate of 3,300 to 4,500
lpm, drillstring rotation speed of 120 to 160 rpm, and expected rate of penetration for the 660.4-mm(26-in) BHA is 16- 21 m/h.
The following 469.9 mm (18.5) intermediate wellbore section was decided to be drilled by a
push-the-bit RSS and a 5-blades steel body polycrystalline diamond compact (PDC) bit. The use of the
RSS improves hole cleaning due to continuous string rotation, reduces reaming time and hence increases
average ROP per run. The steel body bit was selected due to the wider junk slot area to prevent a high
risk of bit balling in the section. Designed drilling parameters are as follows: weight on bit of 14 to 16
metric ton, flow rate of 3,800 to 4,200 lpm, drillstring rotation speed of 120 to 150 rpm. The expected rate
of penetration for the 469.9-mm (18.5-in) BHA run is 35 - 40 m/h. The 406.4-mm (16-in) intermediate
casing is designed with flush connections in order to comply the Russian regulations for the minimum
clearance requirements between the open hole and casing couplings (39-45 mm for the 469.9 mm
borehole).
The 342.9-mm (13.5-in) hole section
The main challenges for the 342.9-mm (13.5-in) section are wellbore stability, narrow mud weight
window, and running 273-mm (103/4
-in) production casing for some wells.
To be able to drill safely and efficiently within the narrow mud weight window constraints, compre-
hensive engineering was performed to select an optimum combination of the bit, drillstring and casing
sizes. Particularly for the 342.9-mm (13.5-in) section, the narrow mud weight window challenge was
addressed by the solution to increase annular space while drilling by upsizing the hole from a regular
311.1 mm, which allowed using 139.7-mm (5.5-in) DP in the drillstring (Figure 9). The maximum
expected drilling ECD for a 1.45 SG static MW would be 1.52 SG for the contingency case while
assuming that the mud rheology would be 20% higher than planned (as per the referenced Well 4
example).
Since the reduced ECD loads allowed to increase the drillstring size from 127-mm (5-in) DP to
139.7-mm (5.5-in) DP, the maximum WOB limit while rotary drilling generally increased for most of the
wells because the larger and heavier drillstring has higher buckling resistance. However for the critical
wells, maximum WOB before buckling while rotary drilling is still limited down to 7 metric ton (Figure
10).
As seen inFigure 10, the drillstring reaches the sinusoidal buckling limit with 0 WOB while sliding
starting from 2100 m measured depth. This also means that running the BHA on elevators is the only
Figure 8 Sidetracking schematic.
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possible if friction factors are between 0.2 and 0.3. In case of higher friction factors, the BHA should be
rotated in to get to the section total depth. Therefore, the application of the RSS technology for directional
drilling is obligatory because the 342.9-mm (13.5-in) section may only be drilled with full string rotation
(one of the advantages of the RSS).
The design solutions to drill the 342.9-mm (13.5-in) section are push-the-bit RSS for wells with a turn
in the trajectory of less than 30 degrees and point-the-bit RSS for wells with a turn from 30 to 90
degrees. For the both RSS options, it was decided that a 6- to 7-blade PDC bit with increased nozzle count
Figure 9 Drilling ECD calculation results for 342.9-mm (13.5-in) section (base Well 4).
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would be used. Designed drilling parameters are as follows: weight on bit of 10-15 metric ton (but for
some wells, limited to 7 metric ton), flow rate of 3,800 to 4,200 lpm, drillstring rotation speed of 120 to
160 rpm, and the expected maximum ROP in 342.9-mm (13.5-in) section is up to 48 m/h.
273-mm (103/4-in) Production Casing
The 273-mm (103/4
-in) production casing setting depths vary from 1,720 to 3,100-m MD (~1,400 to
1,460-m TVD) for all wells except for the Well 14. Well 14 is one of the longest among the Filanovskogo
Figure 10Maximum WOB before buckling calculation results for 342.9-mm (13.5-in) section (base Well 4).
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field development wells with a trajectory that intersects faults between 3,700 to 4,150-m MD. Due to the
presence of faults and the narrow mud weight window, the 273-mm (103/4
-in) casing shoe should be set
at least at 4,200-m MD.
The main design solution for the wells (except for Well 14) is to run 273-mm (10 3/4
-in) casing
conventionally with the rotation possibility as a contingency. As per the engineering calculations,
production casing may be run conventionally for the design friction factors of 0.25 in a cased hole (CH)
and 0.4 in the an open hole (OH) in all wells. The casing may also be rotated as a contingency and
Figure 11Drag loads for 273-mm (103/4-in) casing installation with partial floatation (Well 14).
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maximum expected surface torque will be 85.9 kN*m for the above-mentioned friction factors. Planned
rigs top-drive systems maximum torque limit is 97.6 kN*m at 100 rpm. To be able to rotate the casing
as a contingency, rigs should be equipped by casing running tools (CRT) allowing running of the casing
with rotation. The CRT operating torque limit should be at least 97.6 kN*m. Therefore taking into account
a safety factor of 1.25, the casing connections operating torque limit should be at least 107.4 kN*m. As
an example, Tenaris-Hydril Wedge 563 connections could be used for 273 mm (10 3/4
-in) casing string.
A 273 mm (10 -in) 55.5 ppg L80 casing with Wedge 563 connection has maximum operating torque of131.5 kN*m.
Cementing the 273-mm (103/4
-in) casing was an additional challenge that also required the specific
solutions. While designing cementing operations, intersection of faults was taken into account. For hole
intervals where faults are crossed, the cementing ECD should not exceed the formation loss gradient,
which is the existing fractures re-opening gradient. The cementing design solution was to cement most of
the wells with regular cement slurries with densities from 1.70 to 1.91 SG. For wells with the most critical
low cementing ECD limits (wells intersecting faults or drilled in the most challenging direction), specific
lightweight slurries must be used with densities of 1.65 SG down to 1.45 SG. Both regular and lightweight
cement slurries were designed to prevent gas migration.
There are two engineering solution options for the Well 14: the first is 273-mm (103/4
-in) casing
installation at 4,200 m MD with partial or mud-over-air floatation while running, the second is an
alternative well design for this particular well with additional casing string.
The mud-over-air floatation involves running the lower portion of the casing floated (i.e. filled with air)
and the upper portion filled with mud. Design calculations show that the air-filled portion of the 273-mm
(103/4
-in) casing should be 1,500 m long (Figure 11). After this, a selective float collar (SFC) will be
installed in the casing string to isolate the mud from the air-filled portion of the casing. In this case, the
higher weight casing should have been used to have reliable design factor for the collapse resistance while
running bottom portion empty. The design friction factors that were assumed for the casing running loads
calculation are 0.25 in a cased hole, and up to 0.6 in an open hole. Running the casing partially floated
is possible for these friction factors. However, the first option has an unsolved issue: high risk of losses
while cementing 273-mm (103/4
-in) casing, even using lightweight slurry. Cementing simulations show
that the ECD during cementing will exceed formation loss gradients within the fault intersecting intervals.
Because all the formation gradients are the 3D geomechanical model outputs (which involves a certain
number of assumptions), they will need to be calibrated after first development drilling starts. After the
3D geomechanical model calibration, this option may become feasible if the risk of losses while
cementing decreases.
The second option for the well 14 involves an alternative well design shown in Table 1featuring a
368.3-mm (14.5-in) open hole section instead of the 342.9-mm (13.5-in) down to 3,400 m MD and cased
by a 301.6-mm (117/8
-in) casing. The next section would be 269.9-mm (105/8
-in) under-reamed to 317.5
mm (12.5-in) and afterwards cased with a 244.5 mm (95/8
-in) flush joint drilling/production liner. Lateral
Table 1Alternative well design (Well 14).
Bi t size, mm Casing type Casing si ze, mm Casi ng seat, m
660.4 Surface 508.0 x 12.7 mm 662.1
469.9 Intermediate 406.4 x 14.4 mm
flush joint
1,335.8
368.3 Production 301.6 x 14.8 mm
regular coupling
3,400.0
317.5 Production liner 244.5 x 11.99 mm
flush joint
4,350.0
215.9 Lower completion - 4,960.0
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production hole for lower completions would be drilled with a 215.9-mm (8.5-in) bit. This solution
ensures the cementing ECD being within the limits and reduces the risk of losses while cementing.
Disadvantages of the second option are the requirement of additional casing string, differing from unified
well design and requirement for a particular wellhead for the ell 14.
Figure 12Drilling ECD calculation results for 241.3-mm section (Well I-7).
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241.3-mm (9.5-in) lateral hole sections
The main challenges for the 241.3-mm lateral sections are wellbore stability, high drilling ECD in a
narrow mud weight window, high tripping tension loads and high drag resistance loads while lower
completion installation.
Similarly to the 342.9mm section hole, drillstring and casing size were optimized to minimize the ECD
while drilling in the narrow mud weight window environment. The regular 215.9-mm (8.5-in) production
Figure 13Tripping loads analysis for 241.3-mm section at final depth (Well I-4).
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hole was upsized to 241.3 mm (9.5 in) to increase an annular space while drilling. A tapered 139.7-mm
(5.5-in) x 127-mm (5-in) DP drillstring will be used for the most critical wells to reduce the drilling ECD.
The maximum expected drilling ECD for a 1.37 SG static MW would be 1.62 SG at the Well I-7 TD,
which has the longest measured depth of the 241.3-mm section (Figure 12).
Tripping in the BHA on elevators is normally possible in the 241.3-mm section if friction factors are
between 0.2 to 0.3. In the case of higher friction factors, the BHA should be rotated to get to the sectionTD. Drilling the section also required the RSS technology application due to impossibility of the slide
drilling. Another challenge is the high pick-up loads while tripping out from TD on the most critical wells,
as in the Well I-4, for example (Figure 13). The maximum expected tension load at surface for a friction
factor 0.4 will be 159 metric ton. With the maximum overpull of 13 metric ton and assuming safety factor
of 1.25, it requires DP of S-135 steel grade.
The design solution is to drill both 241.3-mm sections using the point-the-bit RSS and 5-blades PDC
bit with five nozzles. The point-the-bit RSS will allow successful geosteering with doglegs up to 3 deg/30
m, reduced bit pressure drop and higher BHA rotation speed. Designed drilling parameters are as follows:
WOB is limited depending on the well to 7-12.5 metric ton, flow rate of 1,920 to 2,200 lpm, drillstring
rotation speed of 140 to 170 rpm. Expected maximum ROP in 241.3-mm section is up to 55 m/h.
Completion design
The completion design for the Filanovskogo field wells depends on the well type and varies for the
monobore and the dual-lateral production wells and the injector wells.
During the completion engineering, many options were considered and screened. Requirements for the
considered options were good OBM displacement to the completion fluid, providing the sand control,
inflow control possibility, selective acid treatment and isolation for the lateral open hole sections.
After screening the lower completions options, the particular design was selected for each well type.
Completion design features depending on the well type are presented in the Table 2below.
Table 2Completion option screening results
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Based on the lower completion running drag calculation results, the ability to rotate will be the main
solution for the lower completion installation. The lower completion elements should be high torque rated.
Figure 14presents the tension loads while running the lower completion with rotation in one of the most
challenging well I-4.
Dual-lateral well junction design
Six of the eleven dual-lateral wells were designed to have kick-off point to the second lateral in the
Neokomian sandstone. Since the sandstone is permeable, the additional isolation required at the junction
Figure 14Tension loads while running lower completion with rotation (Well I-4).
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point to ensure separate flow control from each lateral hole. The rest 5 wells were designed to have
kick-off point to the second lateral in the Aptian shale. Since the shale around the junction point will
isolate second bore open hole from the motherbore, the additional isolation is not required for these wells.
Two choices of dual-lateral well junction design were selected in the BOD:
For wells that have a kick-off point in Neocomian sandstones TAML5-level junction should be
used. This junction should have following features: isolation of the flows from different wellbores,open hole seal of the second bore, selective reentry to both laterals with coiled tubing or DP, full
retrievability, capability of being integrated with flow control valves and/or pressure gauges,
inflow control options, placement flexibility. The junction pass-through internal diameter should
be at least 101.6 mm (4-in).
For wells that kick-off in Aptian shales TAML3-level junction should be used. The junction
should have following features: isolation of the flows from different wellbores, selective reentry
to both laterals with coiled tubing or DP, full retrievability, capability of being integrated with flow
control valves and/or pressure gauges, inflow control options, placement flexibility. The junction
pass-through internal diameter should be at least 101.6 mm (4-in).
Conclusions
The development of the design for complex dual-lateral development wells offshore in the north of the
Caspian Sea required close cooperation between the three parties: the oilfield operator, the operators
engineering and research institute, and a major integrated oilfield services provider. The engineering team
(comprising three party representatives) worked together efficiently, which resulted in the successful
development of the Filanovskogo BOD covering the full planned scope within the planned schedule.
The Filanovskogo field has a challenging geological structure which affects the well complexity
however there are engineering solutions to make complex wells drillable and completed efficiently. These
engineering solutions were addressed while developing the drilling and completion basis of design for the
field. The narrow mud weight window environment was addressed by the trajectories optimization and the
selection of the appropriate borehole, drill pipe and casing sizes. The wellbore instability issue wasaddressed by the proper drilling fluids density and type selection. The requirement to penetrate both of the
productive reservoir sub-layers by the lateral boreholes and limit the wells count was addressed by the
dual-lateral wells design, which included thorough selection of the kick-off point positions. The kick-off
from a highly deviated and almost horizontal wellbore required the thorough window milling and
sidetracking design and engineering.
The challenge of having the shallow TVD horizontal wells was addressed by the RSS application and
by the comprehensive drilling torque and drag loads analysis which facilitated a selection of the
appropriate drillstring and casings specifications.
The requirement for zonal isolation and inflow control during production phase was addressed by
screening of the advanced completions options and deep engineering to find the solution of runnable lower
completion, which includes stand-alone screens with ICD and swellable packers, and the other specific for
each well type features. The need to control the production from both of the laterals required for the
thorough dual-lateral wells junction selection and the junction design of the different levels depending on
the formation lithology at the kick-off point. The selected junctions also fit-for-purpose for the lower
completion performance, intervention requirements and provide the required pass-through diameter.
Adhering to the specific design process that was split into three phases and involved two milestones,
allowed to develop a solid well design and ensured technical integrity of the design. All known drilling
and completion challenges were addressed by the design solutions and associated residual risks were
covered in the risk register document with the specific prevention and mitigation measures.
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The final Filanovskogo drilling and completion BOD report covered the following well design aspects:
geology description, offset wells and fields analysis, wellbore stability prediction, lower and upper
completion design, well schematic development and casing design, drilling fluids basis of design,
directional drilling basis of design, drill bit BOD, cementing BOD, sidetracking BOD, formation
evaluation considerations, well control, wellhead requirements, and rig equipment requirements. (BOD
involves design considerations for each of 20 development wells in the field.)
The Filanovskogo BOD was accepted by the operator and the engineering and research institute for thefurther execution which is planned to start mid-2015.
AcknowledgementsThe authors would like to thank the following:
Lukoil and its partners for their permission to publish this paper, technical and organizational
contribution
Lukoil-Engineering, VolgogradNIPImorneft for the opportunity to work on the design and
assuring technical integrity and Russian regulations compliance throughout the design process
Filanovskogo BOD engineering team for their expertise and engineering contribution
Korchagina project team for their technical support and providing valuable offset data
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