spe-171267-ms complex well design for multilaterals offshore north caspian sea

7/25/2019 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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Experience Drilling a Record Reach Well, paper IADC/SPE 151046 presented at the 2012 IADC/SPE

Drilling Conference and Exhibition held in San Diego, California, USA, March 6-8McDermott J.R. et alet al..: Extended Reach Drilling (ERD) Technology enables Economical

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21-23

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spe-171267-ms complex well design for multilaterals offshore north caspian sea

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