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SPE-171741-MS

Ageing Offshore Well Structural Integrity Modelling, Assessment and Rehabilitation Ramesh Ramasamy, 2H Offshore Engineering Ltd.; Manea AlJaberi and Hamad AlJunaibi, ZADCO

Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 10–13 November 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 necessar ily 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 prohi bited. 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

Zakum Development Company (ZADCO) is operating Upper Zakum (UZ) Field offshore Abu Dhabi consisting several

offshore wellhead platform towers (WHPT) which have been in service for over 30 years and evidence of severe corrosion

has been found on majority of these well’s conductors and casings.

A major challenge faced by ZADCO is to repair corroded well’s conductor casing to prevent well structural collapse and

extend the life further to allow for safe and planned retirement. The challenges faced during the assessment includes the

absence of design basis, well age, data accuracy and drilling quality for 30 years, the challenges takes another dimension

when factoring the number of wells and possible different configurations. They way forward was to categorise the wells into

several groups with close design configurations and then reverse engineer the design basis to a build a structural model for

that fits the various wells configuration to establish the minimum thicknesses to assure well’s structural integrity, and the

requirement for life extension by suitable repair method.

This paper outlines the activities undertaken to design and implement an effective process for evaluating the structural

integrity of aging well conductors considering over 6000 possible well configuration scenarios. The paper describes the

engineering methodology involved in the integrity assessments for well conductor evaluation using analytical methods to

assess the present strength and stability states of the conductor/casing assembly based on corrosion inspection data and the

knowledge of existing cement elevations and operating conditions of the well. Operability guideline plots are generated to

present the available safety margin of the aging conductor/casing system, and to enable well conductors with unacceptable

structural integrity to be identified. Where safety margins are poor, repair solutions and mitigation methods are also

developed for implementation on the affected conductors and casings.

A detailed rehabilitation flow-chart is also developed to assist engineers in the repair/replace decision-making process, with

comprehensive guidelines for assessing and executing the rehabilitation steps for extended safe operations of ageing

conductors, hence prolonging the well operating life.

Learn more at www.2hoffshore.com

2 SPE-171741-MS

Introduction

The increase in ageing offshore well conductor assets and the continued requirement to maintain operations beyond their

original design life is beginning to be a major challenge faced by operators worldwide. This problem is further compounded

by the limited availability of well construction records, unknown operational conditions and inadequate through-life

maintenance.

Zakum Development Company (ZADCO) is responsible for the operation of a large number wells located on jacket

platforms in the Upper Zakum (UZ) field offshore Abu Dhabi with an average water depth of 13m (43ft). Many of these

wells have been in service for over 30 years and evidence of severe corrosion has been found in some of the well conductors

as shown in Figure 1, including complete collapse on some more extreme cases. There are also reported observations on loss

of cement in the internal annular space between the conductor and surface casing, leaving the surface casing exposed to

seawater spray and eventual wall loss due to corrosion.

Figure 1: Ageing Conductor Platform on UZ Field

Establishing a fit for service solution and building the way forward was an imminent need for ZADCO in order to extend the

life of the wells. The challenges faced during the assessment includes the absence of reliable design basis, well age, data

accuracy and existing concerns on quality of drilling prevented the company from taking forward a solid rehabilitation

program. The above challenge took another dimension when factoring the number of wells and possible different

configurations which will cause a serious delay in planning the repair or even abandoning the wells. ZADCO team decided to

conduct a special simulation study after categorizing the wells into several groups with close-to-design configurations and

then reverse engineering the design basis to a build a structural model for that fits the various wells configuration to establish

the minimum thicknesses value that will assure well’s structural integrity, and the requirement for life extension by suitable

repair method.

(a) Platform on UZ Field

(b) Heavily Corroded Conductors and Casing Cement Shortfall Found on UZ


SPE-171741-MS 3

ZADCO established a taskforce team to carry out survey and inspection campaign, and to record all critical information for

each well which includes, but not limited to, conductor thickness measurements – 4 thickness readings per meter height up to

MSL, top of cement level in the well annuli, well configuration and materials based on drilling data. Since the above survey

was estimated to take up to one year to complete, and due to the urgency, the team decided to propose a few pre-assumptions

as a way forward for a specialised engineering study that will enable the company to categorize the wells into several groups

according to their physical conditions. This resulted in over 6000 possible well configuration scenarios that need to be

assessed to cover all offshore wells within the UZ field.

In line with this information, ZADCO has initiated a plan to carry out strength and integrity assessments of these conductors

using the finite element (FE) analyses and identify the current strength state as compared to the as-built design limits in terms

of conductor and casing wall thickness (WT). The conductor pipe WT from as-built design data were used to estimate the

limiting capacity, whilst the current corroded WT were used to identify the in-place condition of these wells, and thus to be in

a position to highlight the acceptability for continued operation or to propose repairs and/or abandonment plans. The annular

cement shortfalls were also considered in these assessments and to cater for a wide range of possibilities in the top of cement

(TOC) elevations in the well annuli.

Two well configurations were considered to accommodate for both conductor-supported and casing-supported wellhead

scenarios resulting from soil consolidation and conductor settlement over the decades. For each well configuration, the wells

were further grouped according to the TOC and well preloads, and these groupings represent almost every well in the UZ

field, considering all possibilities of annuli cement degradations. For the casing-supported wellhead configuration, the

absence of adequate TOC may result in the casing pipe buckling inside the wellbore, thus increasing bending stresses as a

resultant of curvatures on the casing and the interaction with the conductor inner diameter and wellbore. This leads to the

cement top-up assessments to identify the critical TOC for safe continued operation of the wells. The cement top-up

assessment considers a range of cement bond strength sensitivity to account for heavily corroded pipe walls, with formation

of rust flakes (Figure 2), which may resist the cement bonding hence rendering the entire cement top-up efforts ineffective.

The conductor and casing repairing philosophy/strategy and methodologies can then be established once the well states are

known from the strength assessments and also depending on the level of degradation of the conductors and casings. These

repair strategies will be used as criteria and guideline for engineers to identify wells with integrity issues and require repair

works.

Figure 2: Formation of Rust Flakes Inside Conductor-Casing Annulus

Case Study

A typical case considered in this assessment activity will be looked at, where the well layout and schematics are shown in

Figure 3. The UZ well considered consists of 30in conductor, with a 13-3/8in surface casing hung from the surface wellhead

on the platform, followed by the 9-5/8in inner casing and dual 3-1/2in tubings. The annular spaces between the conductor,

surface and inner casings are ideally cemented, except in the presence of aquifers in the wellbore elevations. The surface

wellhead and tree weight approximately 5Te in total. The ultrasonic WT measurement activity carried out around the

conductor pipe from 1m below mean sea level (MSL) to the top of the conductor, spanning 16m total elevation is shown in

Table 1 for one of the conductor pipe on a wellhead platform being considered, indicating the splash zone area to be very

heavily corroded with more than half of the wall being lost over the years. The corrosion level below MSL is observed to be

very minimal, if none at all, and hence the nominal WT of 22mm (0.875in) is assumed. For the surface and internal casings, a

conservative average wall loss of 20% will be assumed throughout due to absence of measured data on these pipes.


4 SPE-171741-MS

Figure 3: Well Layout and Casing Arrangements

Elevation above Seabed (m) WT Along Conductor Circumference (mm) Mean WT Loss

Bottom Top 0deg 90deg 180deg 270deg Mean (mm) (%)

26 28 16.0 16.8 17.0 18.0 16.950 5.250 23.65

24 26 17.2 16.5 17.2 16.8 16.925 5.275 23.76

22 24 15.3 17.5 17.8 17.1 16.925 5.275 23.76

20 22 14.5 16.0 17.5 12.0 15.000 7.200 32.43

18 20 15.0 16.5 16.0 13.0 15.125 7.075 31.87

16 18 8.7 9.0 8.5 10.0 9.050 13.150 59.23

12 16 11.0 11.0 9.0 10.0 10.250 11.950 53.83

Table 1: Conductor Wall Thickness Measurement

The environmental conditions are extracted from surveys carried out and identified for 1-year (operating) and 100-years

(extreme) return periods for both currents and waves in the gulf area, shown in Table 2. The UZ field soil datails are

extracted from geotechnical surveys carried out in the UZ vicinity and shown in terms of the soil stiffness (P-y) curve in

Figure 4.

Current Data

Elevation Current Speed (m/s)

Height to Depth Ratio Above Mudline (m) 1 Year 100 Year

1.0 13.10 0.89 1.46

0.4 5.24 0.74 1.22

0.1 1.31 0.59 0.98

0 0.00 0.30 0.49

Wave Data

Parameters 1 Year 100 Year

Maximum Wave Height (m) 4.58 8.40

Significant Wave Height (m) 2.46 4.52

Wave Period (s) 6.24 8.89

Table 2: UZ Environmental Data


SPE-171741-MS 5

Figure 4: UZ Soil P-y Data

The various TOC elevations in the conductor-casing annuli were considered to cater for all possible scenarios in the wellbore,

and are listed in Table 3. The shortfall of cements near the surface and also presence of aquifers are accounted for in these

scenarios to estimate the weights and overall system stiffness. One extreme (anomaly) scenario was also considered for a case

with no cement in the conductor and casing annuli at all, to establish a lower bound of the assessment.

The majority of the UZ wells are water injection wells, with no significant pressure and temperature variation, hence the

operating pressure and temperature effects are ignored in the well residual preload calculations, due to their negligible

contributions to overall well loads.

30in to 13-3/8in Annulus 13-3/8in to 10-3/4in Annulus

Scenario Cement Elevation below RT Annular

Content Scenario

Cement Elevation Below RT Annular

Content Top (m/ft) Bottom (m/ft) Top (m/ft) Bottom (m/ft)

S1 12 / 40 1713 / 5621 Cement I1 12 / 40 3094 / 10150 Cement

S2 26 / 86 1713 / 5621 Cement I2 26 / 86 3094 / 10150 Cement

S3 40 / 132 1713 / 5621 Cement I3 40 / 132 3094 / 10150 Cement

S4 84 / 276 1713 / 5621 Cement I4 84 / 276 3094 / 10150 Cement

S5

12 / 40 914 / 3000 Cement

I5

12 / 40 305 / 1000 Air

914 / 3000 1652 / 5420 Aquifer

305 / 1000 3094 / 10150 Cement 1652 / 5420 1713 / 5621 Cement

S6

12 / 40 305 / 1000 Seawater

I6

12 / 40 914 / 3000 Air

305 / 1000 914 / 3000 Cement

914 / 3000 3094 / 10150 Cement 914 / 3000 1652 / 5420 Aquifer

1652 / 5420 1713 / 5621 Cement

S7

12 / 40 610 / 2000 Seawater

610 / 2000 914 / 3000 Cement

914 / 3000 1652 / 5420 Aquifer

1652 / 5420 1713 / 5621 Cement

Table 3: Annular TOC Scenarios

Analysis Methodology

The well axial preloads are first calculated based on overall well construction sequence and the pipe strings set depth,

combined with the presence and interactions with annular fluids. The axial loading on the conductor and casings are

evaluated for both the conductor-supported and casing-supported well configurations, for the entire range of TOC in the

annuli, and the resulting axial compressions on the conductor and casing are presented in Figure 5. Wells

within the same magnitude of loads are grouped together for more effective assessment, contrary to assessing each of the

hundreds of wells in the field individually. There are 5 groups for the conductor supported wells and 4 groups for the casing-

supported wells identified as shown in the plots, representing almost every well within the UZ field.


6 SPE-171741-MS

(a) (b)

Figure 5: Well Construction Loads on (a) Conductor, and (b) Casing

The commercial FE package FLEXCOM [1] was used to perform the transient nonlinear analyses on the wellhead conductor

systems, with the casings modelled as multi-pipe-in-pipe (PIP) system with the gaps between individual strings, as shown in

Figure 6. The model extends from the surface tree, down to the 6 degrees-of-freedom fixity at 50m below the seabed to

adequately model the structural response, as no significant lateral motion is expected below this fixity. The conductor guides

were modelled as lateral constraints with radial clearances where applicable. The environmental loads were modelled in the

form of current profile and Stoke’s 5th

Order waves (Table 2) with the hydrodynamic coefficients applied as per API RP 2A

WSD [2]. Waves are considered to be omni-directional with no wave spreading, as this is anticipated to give conservative

results. Marine growth and wall loss due to corrosion are also taken into account and modelled appropriately. The lateral soil

stiffness is modelled using nonlinear soil springs as per the soil behaviour in Figure 4.

29.042m

Mezzanine Deck 29.106m

MSL 13.106m

Seabed 0 m

13-3/8in Casing

30in Conductor with different corrosion zones

Surface Wellhead

Surface Tree

-50.00m

28.042m

Lower Deck 26.106m

31.042m

16m

18m

20m

22m

24m

12m

10-3/4in Casing

Soil Springs

Conductor Guide at 16.15m and 8.65m

Figure 6: FE Model of the Wellhead Conductor and Casings System

The loadcase matrix for the FE analyses of the well considers the TOC in both the conductor-surface casing annulus and the

3000

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nd

ucto

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om

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ssio

n (

kN

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Cementing Scenarios

Zakum Field Corroded Conductor Assessment

CONDUCTOR PRELOAD (UZ-108 WELL) - CONDUCTOR SUPPORTEDPreload Grouping Based on 30in Conductor Compression

Preload Group 1 (Anomaly Case)

Preload Group 3

Preload Group 4

Preload Group 2 (Maximum Compression)

Preload Group 5(Minimum Compression)

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sin

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om

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ssio

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Cementing Scenarios


CASING PRELOAD (UZ-108 WELL) - CASING SUPPORTEDPreload Grouping Based on 13-3/8in Casing Compression

(Anomaly Case)

(Maximum)

(Intermediate)

(Minimum)


SPE-171741-MS 7

surface-internal casings annulus, preload grouping and the various conductor/casing corrosion levels, resulting in about 630

analyses files generated for a single well configuration being considered. The bending moment and effective tension obtained

from the FE analyses are used to calculate the resulting von Mises stresses and the unity check (UC) was performed based the

material specified yield strength for uncorroded and corroded pipes. Based on the UCs for corroded pipes, the

interpolated/extrapolated pipe WTs are evaluated to satisfy the minimum required utilization as per API RP 2RD [3]. This

will now provide an indication of whether the well is within the code specified safe operating bounds for the wellhead

conductor system, for both the well configuration.

For the conductor-supported well configuration, failure to meet the required WT based on the UC as per API RP 2RD criteria

means the repair on the conductor has to be carried out either by installation of repair sleeves or complete sectional

replacement of the conductor pipe.

As for the casing-supported well, the failure to meet the WT requirement is deemed more complex. A helical buckling check

is performed for the surface casing inside the wellbore to assess the likelihood of failure of a corroded section of the casing in

the event that buckling instability using equations obtained from energy analysis in [4] and [5]. From this assessment, the

helical shape or curvature of the casing, as well as the settlement of surface wellhead is evaluated for the un-cemented free

spans based on the various cementing scenarios, as shown in equations (1) and (2). The casing stresses resulting from the

increased bending moment and casing eccentricities subjected to wellbore helical buckling are also evaluated to determine

whether the corroded casing is overstressed for a range of wall thickness losses due to local corrosion on the conductor and

casing.

∆𝐿 = 𝐿 2𝜋𝑟

𝑝

2

+ 1 − 1

(1)

𝑝 = 8𝜋2𝐸𝐼

𝐹

(2)

where:

r = radial clearance of the casing and conductor/wellbore

L = casing un-cemented free span

L = wellhead vertical settlement

p = helical pitch formation in the wellbore

F = axial compressive force

E = Elastic modulus

I = Moment of inertia

The cement top-up assessment is then carried out following the identification of the critical shortfall which causes the surface

casing buckling and wellhead settlement. A range of cement bond strength was considered, to account for the uncertainty of

the cement bonding onto the heavily corroded conductor and casing surfaces, intensified further by presence of rust flakes as

shown in Figure 2. These bond strengths were evaluated based on the conservatively derived characteristic strength in

equation (3) [6] for a PIP configuration, and will represent the bond efficiency of the cement onto corroded steel pipes. The

80MPa (11ksi) compressive strength cement was considered for the top-up assessment, resulting in a bond strength range of

10kPa (1.5psi) to 200kPa (29psi).

𝑓𝑏𝑢𝑐 = 𝐾𝐶𝐿 9𝐶𝑆 𝑓𝑐𝑢 (3) where

fbuc = characteristic bond strength (or )

fcu = cement compressive capacity

CL = coefficient of cement length to casing diameter, conservatively taken as 0.7

CS = surface condition factor bond, taken as 0.5

K = stiffness factor

m = modular ratio of steel to cement

t = wall thickness

D = outer diameter

Following these assessments, the decision to repair the conductor and/or top-up of the annular cement can be made. Due to

the heavy corrosion on the conductor and possible heavy corrosion on the surface casing, the impact on cement top-up over

elevation above seabed needed to be verified for burst and collapse requirements as per API RP 2RD [3] for the conductor


8 SPE-171741-MS

and casing respectively. This will also dictate the specific repair sequence to be undertaken, i.e. to repair the conductor prior

to cement top-up or vice versa. A post top-up failure assessment was carried out to determine the requirement to top-up both

the annuli to mitigate any failure resulting after cement top-up on the conductor and surface casing.

Results and Discussions

The series of FE analyses carried out on the loadcase matrix for the well configurations resulted in the extraction of bending

moment and overall stress UC along the spans for conductor-supported and casing-supported well configurations, for each of

the preload group, corrosion levels and environmental conditions. The sensitivity of the conductor-supported well

configuration towards the corrosion on the conductor pipes and the environmental loads were looked at to further understand

the well behaviour, and found to be influenced greatly by the waves, in addition to the governing axial compressions from the

different preload groups on the corroded conductor, as shown in Figure 7 (a) and (b) for a conductor-supported well

configuration.

Based on this outcome, the minimum allowable WT on the conductor can be extrapolated and plotted against stress UC,

indicating the API recommended limits, as shown in Figure 8. It can be observed for the conductor that the anomaly Preload

Group 1 (extreme case with no cement in annuli) is the governing condition, and the more realistic case would be Preload

Group 2 (with 2000ft cement shortfall on conductor annulus) highlighting a minimum required conductor WT of 10mm

(0.42in) for safe continued operation under a stress utilization of 0.8, or 15mm (0.6in) WT under a more stringent 0.6

utilisation requirement. Similarly for the surface casing, the minimum required WT can be extrapolated and the extreme case

of Group 1 is governing, whilst Group 2 (with 3000ft cement shortfall in the casing annulus) shows a minimum required WT

of 6mm (0.25in) necessary on the surface casing for continued operation under the 0.8 utilisation factor.

The large cement shortfall inside both conductor (2000ft) and casing (3000ft) annuli resulted in the governing minimum WT

requirement for both conductor and casing under the compression sustained by the conductor from axial well loading.

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Von Mises / Yield


VON MISES / YIELD (UZ-108 WELL)Preload Group 2; 100 Year RP; 30in Conductor

Measured Corrosion No Corrosion

TOC in 30in x 13-3/8in annulus = -44m below mudlineTOC in 13-3/8in x 9-5/8in annulus = Surface

0.354"

0.335"

0.512"

0.354"

0.472"

0.602"

0.650"

Measured Wall Thickness

0.875"(uncorroded)

0.629"

Upper Guide

Lower Deck

Lower Guide

Mean Sea Level

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VON MISES / YIELD (UZ-108 WELL)100 Year RP; 30in Conductor; Measured Corrosion

Preload Group 1 Preload Group 2 Preload Group 3

Preload Group 4 Preload Group 5

Measured Wall Thickness

0.875"(uncorroded)

0.650"

0.629"

0.602"

0.472"

0.512"

0.335"

0.354"

0.354"

Upper Guide

Lower Deck

Lower Guide

Mean Sea Level

(a) (b)

Figure 7: Conductor Stress UC Effect Due to (a) Corrosion Levels and (b) Preload Group (TOC)


SPE-171741-MS 9

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.65 0.70 0.75 0.80 0.85 0.90

vo

n M

ise

s S

tre

ss /

Yie

ld S

tre

ng

th

Peak Minimum Wall Thickness (in)


WALL THICKNESS ACCEPTANCE GUIDELINE (UZ-108 WELL)30in Conductor; Conductor Supported

Preload Group 1 Preload Group 2 Preload Group 3 Preload Group 4 Preload Group 5

59.5% corrosion0.354in wall

thickness

No corrosion0.875in wall thickness

48.6% corrosion 0.450in wall thickness

von Mises / Yield = 1.0



0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50

vo

n M

ise

s S

tre

ss /

Yie

ld S

tre

ng

th



WALL THICKNESS ACCEPTANCE GUIDELINE (UZ-108 WELL)13-3/8in Casing; Conductor Supported

Preload Group 1 Preload Group 2 Preload Group 3 Preload Group 4 Preload Group 5




20% corrosion0.384in wall thickness


No Corrosion 0.480in wall thickness

(a) (b)

Figure 8: Conductor-Supported Minimum Required WT on (a) Conductor and (b) Surface Casing

The casing-supported well configuration was also looked at in the event that the wellhead had settled onto the surface casing

due to settlement of the conductor bottom soil support over the many years in service. The casing-supported well distributes

large percentage of the well loads through the surface casing, thus relieving the conductor from high stresses which was

experienced in a conductor-supported well, and this is shown in Figure 9 (a). Once again the cement shortfall inside the

casing annulus also governs the response of the corrode casing towards the well loads, as seen in Figure 9 (b).

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Von Mises Stress / Yield Strength


VON MISES / YIELD (UZ-108 WELL)Max Possible Preloads; Measured Corrosion;

Casing Supported; 100 Years RP

30in Conductor 13-3/8in Casing

Upper Guide

Lower Deck

Lower Guide

Mean Sea Level

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VON MISES / YIELD (UZ-108 WELL)20% Corrosion; 13-3/8in Casing;Casing Supported; 100 Years RP

Anomaly Preload Maximum Preload

Intermediate Preload Minimum Preload

Upper Guide

Lower Deck

Lower Guide

Mean Sea Level

Wall Thickness :

0.480" for cemented section

0.384" for un-cemented section

No cement in all anulli,anomaly preload

Cement to mudline (S3-I6),maximum possible preload

Cement to -44m (S4-I4),intermediate preload

Cement to -600m (S7-I1),minimum preload

(a) (b)

Figure 9: Stress Distribution of a (a) Casing-Supported Well Configuration, and (b) for Range of TOC

The minimum required WT on the surface casing for the casing-supported well configuration can be presented and shown in

Figure 10, indicating WT of 8mm (0.32in) and 9mm (0.37in) for the surface casing continued safe operations under the

utilization requirement of 0.8 and 0.6 respectively, for the casing annular cement shortfall scenario of 1000ft.


10 SPE-171741-MS

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5

vo

n M

ise

s S

tre

ss /

Yie

ld S

tre

ng

th



WALL THICKNESS ACCEPTANCE GUIDELINE (UZ-108 WELL)13-3/8in Casing; Casing Supported

Anomaly Preload Maximum Preload Intermediate Preload Minimum Preload




20% corrosion0.384in wall thickness


No Corrosion 0.480in wall thickness

Figure 10: Casing-Supported Minimum Required WT on Surface Casing

In the event of a casing-supported well configuration, with large cement shortfall lengths, the casing may buckle within the

conductor and wellbore annuli, forming a helical coiling just above the TOC. It is therefore critical to determine the

maximum shortfall (or the minimum TOC elevation) allowable in the casing annulus for top-up requirement using Equations

(1) and (2), and the results are shown in Table 4 for each of the possibly casing corrosion levels. For a nominal casing

corrosion resulting in 20% average WT loss, the buckling calculation results indicate that the casing may be overstressed in

the event of a helical buckle formation. The results also indicate that for cases where the cement shortfall is in the region of

150m (492ft), there is a risk of helical buckling occurring, if the corrosion level on these casings are unknown.

Parameters No

Corrosion

20%

Corrosion

40%

Corrosion

m ft m ft m ft

Critical Cement Shortfall Length

for Onset of Helical Buckling 181.8 596.5 167.5 549.5 150.9 495.1

Maximum Top Settlement 0.02 0.07 0.03 0.10 0.05 0.16

Maximum Stress UC 0.84 1.04 1.46

Table 4: Wellbore Buckling Assessment on Surface Casing

The cement top-up assessment carried out for the range of cement bond strengths considered for both conductor and casing-

supported wells based on the grout-steel and grout-soil shear resistance. The post top-up failure scenario at MSL was also

considered to ensure the cement top-up is able to effectively mitigate the loading through alternative paths within the system.

For the conductor-supported well configuration, the factor of safety (FoS) of the cement shear load against the bond strength

used are shown in Figure 11, for cement top-up of conductor-surface casing (Annulus B) and the surface-internal casings

(Annulus C) annuli. For an event of collapsed conductor at MSL, top-up of the C annulus is more effective in distributing the

well loads from the conductor into the casing. Top-up of both B and C annuli imparts additional weight of cement into the

system and is thus unnecessary.

For the casing-supported well, cement top-up of both annuli B and C are seen to be more effective in transferring the loads in

the event of casing failure at MSL due to the dual load transfer path provided by the cement in both these annuli for the well

loads on the surface casing, shown in Figure 12.


SPE-171741-MS 11

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

0 20 40 60 80 100 120 140 160 180 200

Co

nd

ucto

r In

terf

ace

Fo

S

Cement Bond Strength (kPa)

20809 Zadco Corroded Conductor Assessment

CEMENT TOP-UP ASSESSMENTConductor Supported Well (Conductor Interface FoS)

C-Grouting (Failure at MSL) B&C-Grouting (Failure at MSL) Figure 11: Cement Top-Up Assessment on Conductor (Conductor-Supported Well)

(a) (b)

Figure 12: Cement Top-Up Assessment on (a) Conductor, and (b) Surface Casing (Conductor-Supported Well)

Repair and Rehabilitation Strategy

A conductor supported wellhead model with the conductor-casing annular TOC of 610m (2000ft) was selected for the repair

strategy design under a 100 years environmental return period loads, and as a pilot study to establish the requirements for

resources, costs, risks involved and the overall required repair duration. The repair criterion is based on the minimum

conductor WT of 12.7mm (0.5in) required to sustain the well loads under the selected well’s Preload Group 5 shown in

Figure 8 (a). Three categories are set to define the significance of well repairs to be carried out. For conductors not meeting

this minimum WT requirement, immediate repairs are crucial and must be carried out immediately with well shutdown

procedures in-place, and for WT between 12.7mm (0.5in) and 17mm (0.67in) the conductor repair are to be carried out for

life extension. For conductors with WT above 17mm (0.67in), no action is required for continued service. This process is

shown in Figure 13.

The proposed repair strategy on the conductor is to install repair sleeves (Figure 14) over the affected segment of the

conductor, from the same nominal uncorroded as-built conductor WT, i.e. 22mm (0.875in). The important criterion for

employment of sleeves is to ensure adequate WT remaining on the conductor for girth welding of the sleeves, as shown in

Figure 14 to ensure the effective load transfer from the upper part of the conductor into the sleeve (by-passing the corroded

conductor section), into the lower part of the conductor. The minimum WT was selected from a highly likely TOC and

environmental condition to be 15mm (0.6in) based on a stress UC of 0.6, or alternatively WT of 10mm (0.4in) for a UC of

0.8. Failure to have this WT on the conductor at the sleeve welding girths can possibly lead to replacement of the entire

conductor section with new 30in pipe instead, as described in the flowchart in Figure 13. The sleeves are installed in 3

segments to address any excessive ovality on the corroded conductor.

0

1

2

3

4

5

6

7

8

9

10

0 20 40 60 80 100 120 140 160 180 200

Co

nd

ucto

r In

terf

ace

Fo

S



CEMENT TOP-UP ASSESSMENTCasing Supported Well (conductor Interface Fos)

c-grout(no fail) B&C grout (no fail) C-grout (fail at MSL) B&C-grout (fail at MSL)

0

1

2

3

4

5

6

7

8

9

10

0 20 40 60 80 100 120 140 160 180 200

Ca

sin

g I

nte

rfa

ce

Fo

S



CEMENT TOP-UP ASSESSMENTCasing Supported Well (Casing Interface FoS)

C-Grouting (No Failure) C-Grouting (Failure at MSL)

B&C-Grouting (No Failure) B&C-Grouting (Failure at MSL)


12 SPE-171741-MS

Figure 13: Conductor Repair Strategy

15mm

LMIN

Adequate conductor WT (above MSL) required before the sleeve weld to ensure effective load transfer into sleeve.

Repair S

leeve

Corr

oded C

onduct

or

Sect

ion

15mm

Adequate conductor WT (below MSL) required after the sleeve weld to ensure effective load transfer out into conductor.

C/L

30”

EL. 13m (MSL)

Figure 14: Conductor Repair Sleeve Design and Installation

The proposed conductor repair installation steps are presented in Figure 15 to Figure 20 for a typical conductor sectional

replacement (Figure 15 to Figure 17) and ZADCO pilot well repair sleeves (Figure 18 to Figure 20). The installation of the

repair sleeves which was selected for the ZADCO pilot well requires clear access to the affected region of the conductor

where the sleeves are required to be installed. For the UZ conductors the existing complexities are in the form of heavy

corrosion at splash zone (around MSL) and the presence of conductor lateral guide at this region. To install the sleeve it will


SPE-171741-MS 13

be necessary to plug the well below the heavily corroded section, and a cofferdam to be constructed around the conductor to

provide access to the conductor in the splash zone region that is unaffected by waves. In addition, it will be necessary to

remove the upper guide while the sleeve is being fitted, and for a replacement guide to be retro-fitted around the conductor

once the sleeves are installed. These activities will add complexity and cost to the repair operation. The lifting requirement

can be very critical in this repair, and the limited lifting capacities must be quantified to avoid any overstressing on the casing

while the conductor is being repaired and is unable to support any axial loading from the well. Once the repair sleeve

installations are completed, the conductor guides will be refitted and coating/painting will be applied to prevent further

corrosion.

Figure 15: Tensioning Support to Well Conductor via Lifting Equipment [7]

Figure 16: Example of Conductor Cutting and Removal of Existing Annulus Cement [7][8]

Figure 17: Example of Temporary Vertical Beams to Support Remaining Conductor Section [9][8]


14 SPE-171741-MS

Figure 18: Coffer Dam and Repair Access Decks

Figure 19: Installation of Conductor Repair Sleeve

Figure 20: Refitting of Conductor Guides and Centralisers

To ensure a complete well integrity during extended operating life, the well annuli are recommended to be cemented to the

surface. For the casing annulus cement top-up strategy for either B annulus only or B and C annuli can be done based on the

remaining WT on the surface casing. A minimum WT on the surface casing of 10mm (0.4in) is required for top-up in B

annulus only, and any WT less than 7mm (0.3in) shall be governing factor for top-up in both B and C annuli. During top-up,

the conductor burst requirement and casing collapse requirement were also evaluated to establish an absolute minimum WT

on both conductor and casing to be 2mm (0.08in) for an arbitrary 12m cement head and 6mm (0.2in) on the casing for 50m

cement head columns. The annular cement top-up steps are summarized into a process flowchart shown in Figure 21.

.


SPE-171741-MS 15

Figure 21: Surface Casing Cement Top-Up Strategy

Summary and Conclusion

Ageing asset and its rehabilitation is now affecting almost every oil companies worldwide. The assessment and repair of

ageing wellhead conductors are now being considered at various levels from visual inspection programs to corrosion

monitoring and measurement schemes. The in-place strength assessment of the conductors and casings must be carried out in

order to identify the current fitness-for-service of these systems for continued operations, as compared to the as-built

conditions. The minimum required WT on the conductor ad casing can be established for required material yield stress

utilisations based on well grouping carried out for similar well arrangements, corrosion levels and TOC in the annulus. This

will provide grounds for decision-making pertaining to the continued service of the well, or if any repairs are required. Based

on the thousands of analyses carried out for every possible well conditions, a spreadsheet based software tool has been

developed to assess the integrity level of any possible combinations of conductor/casing support, TOC, corrosion levels and

environmental conditions against the allowable stress limits.

Additional cement integrity assessments were also carried out to determine the survivability of the cement column in the

event of post top-up conductor collapse and the environmental loading are deemed to exceed the cement tensile capacity thus

resulting in possible cracking on extreme fibres. The conclusion derived from this is that the conductor must be kept intact at

all time for the safe continued operation of these wells, specifically the surface casing, as it is carrying all bending loads

resulting from the environmental effects. For a post top-up casing collapse scenario however, with an intact conductor, the

system has been verified to be safe and operable.

The repairs are proposed for the conductor by means of repair sleeves or complete sectional replacement where the WT are

well below the allowable limit. The annular cement top-up is also proposed to mitigate well loads through alternative paths

for any post-repair failures at unforeseen locations on the conductor and casings. The criteria for repair strategy selection has

also been presented to allow for effective rehabilitation to be carried out considering various well state scenarios and range of

cement-steel interface bonds. The methodology and criteria developed throughout this activity are represented as a process

flowchart as shown in Figure 13 and Figure 21, and combined with the software tool for WT requirement assessment for each

well condition, will be to provide a comprehensive guideline for integrity assessment, rehabilitation and way forward.


16 SPE-171741-MS

Acknowledgement

The authors wish to express their gratitude to ADNOC, ZADCO and 2H Offshore Engineering Ltd for their approval and

support in the production and presentation of this paper.

References

[1] MSC International – “FLEXCOM-3D Three Dimensional Nonlinear Time Domain Offshore Analysis Software”.

Version 7.3.2, 2007.

[2] API – “Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms”. API-RP-2A

WSD, 21st Edition, December 2000.

[3] API – “Recommended Practice for Design of Risers for Floating Production Systems and TLPs”. API-RP-2RD, 1st

Edition; June 1998.

[4] “Coiled Tubing Buckling Implication in Drilling and Completing Horizontal Wells” by Jiang Wu and H.C. Juvkam-

Wold, SPE Drilling and Completion, March, 1995.

[5] “Buckling of Tubulars Inside Wellbores: A Review on recent Theoretical and Experimental Works” by J.C Cunha,

SPE Productions and Operations, March 2003.

[6] DOE - “Grouted and Mechanical Strengthening and Repair of Tubular Steel Offshore Structures”. UK Department

of Energy, Offshore Technology Report OTH 88 283.

[7] MADCON, www.madcon.com

[8] Society of Petroleum Engineers, www.spe.org

[9] Core Grouting Services, www.coregrouting.com


http://www.madcon.com/

http://www.spe.org/

http://www.coregrouting.com/

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