© 2018 Chevron North Sea Limited

Managing well integrity on Erskine

Normally Unattended Installation

The first HPHT development in the UKCS

Iain Robertson

Erskine Petroleum Engineer

Chevron North Sea Limited

27th June 2018

© 2018 Chevron North Sea Limited

Presentation Overview

• Erskine field development

• Well design

• Well integrity experiences

– Tubing condition and liner deformation

– Scale

– Annulus Management

– Subsurface Safety Valves

– Christmas tree and wellhead

• Closing thoughts

Erskine Normally Unattended Installation - Well Bay

© 2018 Chevron North Sea Limited

Field Overview• Gas condensate field discovered in 1981

• First gas in 1997 via 5 production wells

– Still the same 5 wells producing

• Chevron (50% operator)

Chrysaor (32%)

Serica Energy (18%)

• Tied-back to the Chrysaor operated Lomond

platform via 30km multiphase pipeline

– Condensate exported to the Forties Pipeline

System

– Gas exported to CATS

• High pressure (960 bar) and high temperature

(175oC)

– Currently depleted by ~600 bar

• Water depth 100m

• Field developed using an innovative NUI

– Normal POB of 12

– Maximum of 134 days attended per year

– Minimal facilities design

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017

Erskine Field Historic Gas Production

Erskine Field Map

2000’E 2001’E 2002’E 2003’E 2004’E 2005’E 2006’E 2007’E

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Machar Field boundary

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GW

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N2 km

2000’E 2001’E 2002’E 2003’E 2004’E 2005’E 2006’E 2007’E

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(above 12000’)

GW

C

N2 km

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Beta

Terrace

Alpha

Terrace

Main

Field

Machar Salt Dome

Reservoir and Fluid Properties• Jurassic sandstone

• Heather Tubidite

• Erskine (Puffin)

• Pentland

• CGR 180-210 bbl/scf

• Condensate gravity 40o API

• Column height: 500ft

• Reservoir depth: 15,500ft

• Porosity 20%

• Permeability 80mD

SPE 56899

Erskine Field: Early Operating Experience

Top Erskine Z Structure TVDSS(m)

E&A Wells

Production Wells

Erskine Well Design

• Design Considerations

– High pressure and high temperature

– Flow rates up to 60MMscf/d

– Ability to perform rig-less interventions (i.e. plug back

wells and perforate in upper sands)

– High reliability

• Design Features

– Monobore completion for through tubing plug backs

– PBR instead of production packers

– Corrosion resistant alloys

– Tubing Retrievable Subsurface Safety Valve (TR-SSSV)

with the option for Wireline Retrievable Subsurface

Safety Valves (WR-SSSV) in case of TR-SSSV failure

– Designed for a 20 year life (now at 21 years) with

several years to COP date

• W4 was successfully worked over in 1999 following

failure of the tubing

SPE 30364: HPHT Drilling and Completion Design for the Erskine Field

SPE 67779: Erskine Field HPHT Workover and Tubing Corrosion Failure InvestigationExample Erskine well schematic

5” liner

7” liner

16” casing

12 1/8” x

10 ¾” x

10” casing

20” casing

30” casing

9 5/8” x 8” x 7 5/8”

tie-back

4.5”

tubing

Well Integrity Experiences

1. Tubing condition & liner deformation

• In order to assess the condition of the liner and

tubing, calliper logs are routinely run on all

Erskine wells

• Tubing condition is good throughout

• All wells have experienced some form of liner

deformation

– Shear Deformation

– Axial Buckling

• Following initial deformation, subsequent

surveys show that limited further deformation

has occurred

– Risk of well failure due to liner deformation is

therefore presumed to be low

• Deformation can restrict access to the

perforations putting limits on data-gathering and

well interventions

Example of a typical deformation features in

the 5” liner

Well Integrity Experiences

2. Scale

• Severe scale deposition has occurred on some wells

where we have experienced significant water production

– W5 lost production due to scale in 2005 . A coiled

tubing intervention was required to restore production

• Moderate scale deposition has been observed on all

wells

– Recent impact of scale has been on deposition across

the SSSV which has required wireline milling

operations to mitigate

• Calliper logs have shown scale deposition across the

perforations on several wells

– Scale can restrict access to the perforations

– May be limiting production

• Most common scales are barium sulphate, zinc

sulphide, lead sulphide and calcium carbonate

• No downhole inhibition or scale squeezes have been

performed

• Scale inhibition is used for protection of the platform

pipework

Scale deposition profile above the SSSV pre and post

wireline milling operations

Coiled Tubing on W5 in 2005

Well Integrity Experiences

3. Annulus Management

• Annuli are monitored constantly using real-

time pressure transducers linked to PI

– Alarm and trip levels defined to prevent

exceeding safe limits

– Monitored at Lomond and by Chevron

onshore team

• Periodic bleed-downs of annulus pressure

required to maintain well integrity

– Can require rapid intervention when

Erskine is unattended

– Bleed-down fluids are analysed onshore

as required

• Majority of bleed-offs for the C and D annuli

– A and B annulus bleed downs are very

infrequent

0

2

4

6

8

10

12

14

A B C D

2017 Annulus Bleed Down Counts

W1(P1) W2(P2) W3(E2) W4(KA) W5(E3)

Well Integrity Experience

4. Subsurface Safety Valves• All wells were initially fitted with TR-SSSVs

• Over time some TR-SSSVs have been replaced with

WR-SSSVs

• Two wells have suffered from SSSV control line

failures so have had storm chokes fitted

– Removes the need for a workover

– Storm chokes cannot be tested in-situ

– Requirement for annual changeout

– Inspections after each replacement have found no

significant issues

• Alternatives to storm chokes that don’t require a

workover would be beneficial to the asset

– Could be tested in-situ

– Remove the annual changeout requirement

– Save on the cost of replacement and a workover

Storm choke valve before and after

cleaning

Well Integrity Experiences

5. Christmas Tree and Wellhead

• Tree and wellhead are rated to 15,000psi

• Tree valves and wellhead are subject to

annual testing and inspection (PMR)

• If a pressure test cannot be achieved, either

maintenance is performed or a risk

assessment is done to ensure sufficient

barriers are in place to safely operate the well

• All wells have had a tree change in the past

• The main issue experienced is the wellhead

test-port elastomeric seals failing. This

prevents adequate testing of the metal to

metal seals

– More prevalent when testing cold

– This needs to be monitored as the wellhead

ages

OTC 8742 :HPHT Platform Wellheads &Christmas Trees- Performance Testing to

Installation

Erskine wellhead and Christmas tree

Example Tree Change Photos - 2010

© 2018 Chevron North Sea Limited

Closing Thoughts

• Erskine wells are still operating safely after 21 years and need to keep going to

maximise economic recovery

• The well design has facilitated low cost interventions to maintain well integrity

• Liner deformation has been observed in all wells but does not appear to be

dramatically worsening with time

• Wireline offshore days have typically been used for well integrity related activities

rather than production enhancement opportunities

• Scale management has been reactive. Options are being looked at for proactive

scale management

• Alternatives to storm chokes that don’t require a workover would be beneficial for

the asset

Acknowledgements

• Yusif Zeynalzade (Chevron) and Paul Ness (Chevron) for providing

technical review

• Chrysaor and Serica Energy for kindly agreeing to this presentation