Study – Geothermal Asset Management – Guideline/Plan …...deployment of a guideline and...

Study – Geothermal Asset

Management –

Guideline/Plan Template

Prepared for: Kennisagenda Aardwarmte

Doc Ref: J001916-01-PM-REP-001

Rev: 04

Date: April 2018

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Study – Geothermal Asset Management – Guideline/Plan Template

Report

J001916-01-PM-REP-001 | Rev 04 | April 2018 of 77

Client

Kennisagenda Aardwarmte

Document Title


WG Reference Number Client Reference Number (if applicable)

J001916-01-PM-REP-001 N/A

Contact

Arnaud Barré, Integrity Operation Manager [email protected] Tel: +47 (0) 51 37 25 26 Wood Kanalsletta 2, NORWAY, 4033 Stavanger Tel +47 (0) 51 37 25 00 www.woodplc.com

Revision Date Reason for Issue Prepared Checked Approved

05 17/04/2018 Final for workshop ABA PW OI

04 27/02/2018 Issued for client review ABA PW OI

03 05/10/2017 Issued for client review ABA PW OI

02 11/09/17 Re- Issue for Internal review

accounting for Strand A ABA OI

01 04/01/17 Issue for Internal review ABA IMC

INTELLECTUAL PROPERTY RIGHTS NOTICE AND DISCLAIMER Wood Group Kenny Norge ASWood Group Kenny Norge AS, is the owner or the licensee of all intellectual property rights in this document (unless, and to the extent, we have agreed otherwise in a written contract with our client). The content of the document is protected by confidentiality and copyright laws. All such rights are reserved. You may not modify or copy the document or any part of it unless we (or our client, as the case may be) have given you express written consent to do so. If we have given such consent, our status (and that of any identified contributors) as the author(s) of the material in the document must always be acknowledged. You must not use any part of the content of this document for commercial purposes unless we (or our client, in the event that they own intellectual property rights in this document) have given you express written consent for such purposes. This document has been prepared for our client and not for any other person. Only our client may rely upon the contents of this document and then only for such purposes as are specified in the contract between us, pursuant to which this document was prepared. Save as set out in our written contract with our client, neither we nor our subsidiaries or affiliates provide any warranties, guarantees or representations in respect of this document and all liability is expressly disclaimed to the maximum extent permitted by law.

http://www.woodplc.com/


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Executive Summary

The first geothermal wells in the Netherlands were completed in 2007. In recent years, 11

geothermal doublets have been drilled. Kennisagenda’ and ‘the Dutch Geothermal Industry’

have identified a need to improve the asset management of their wells and surface facilities

based upon a review of current practice and consideration of improvements. The benefits of

proactive asset management can include, but are not limited to the following: improved

financial performance; informed asset investment decisions; managed risk; improved

services and outputs; demonstrated social responsibility; demonstrated compliance;

enhanced reputation; improved organisational sustainability; improved efficiency and

effectiveness, and last but not least management of technical and operation integrity ref./

6.

This report forms Kennisagenda Aardwarmte output from Corrosion Assessment, Wells

Materials Selection and Life Cycle Asset Management for Geothermal Energy Systems in

the Netherlands, which ran from 2016 through to 2017. This is Strand B; Strand A has

already been completed ref./ 9.

The objective of the study is to provide a draft Asset Management Guideline (AMG)

enabling the Dutch Geothermal Industry to develop asset management plan for geothermal

low enthalpy asset plants. The subset objectives are to define and standardise good asset

management practice covering the full life cycle, define the content of asset management

plans for geothermal energy systems, cover the entire asset life cycle from concept to

abandonment, create lean asset management plans which maximise production and safety

whilst optimising cost. Geothermal Asset Operators will develop or produce the plan from

the AM Guideline/AMP template.

The scope of the study includes surface infrastructure for both production and injection

wells. The primary loop includes booster and Injection pumps, heat exchanger, gas/water

separator and Piping.

The Study Introduction, section 1.0 presents the background, scope and objectives of the

study. The methodology used to develop the AM Guideline/AMP template is detailed in

section 2 and Appendix A. It includes the information collected through site visit, discussion

with DAGO representative and survey conducted.

The AM Guideline/Template is addressed in 3.0 and includes Appendix B to Appendix D.

Section 3.0 is further divided in the following sub –sections:

o Section 3.1 is an introduction to the guideline;

o Section 3.2 describes key regulation elements required for exploration, development

of licences and operation for Low Enthalpy Geothermal Asset in the Netherlands.

Relevant EU directive is also discussed.

o Section 3.3 describes the overall Asset Management Process life cycle and

provides activity details for each phase of the Asset life cycle. Key engineering,


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construction, procurement activities best practices are presented as check list or

bullet list. Typical project risks (prior operation) are presented in section 3.3.2 and

3.3.3. Section 3.4 describes Risk Management prior operation, i.e. CAPEX phase.

o Section 3.3.5 Present Asset integrity management best practice and requirements

during the Operational phase. It covers Integrity and Risk Assessment, Operational

philosophy and Requalification.

o Section 3.3.6 addresses the abandonment phase best practices and requirements.

o Having presented the process and the different phases, the development

requirement of the AMP phase by phase using the guideline is described in section

3.4.

The AMP requirements are addressed in section 3.5 Operational and Organisational

Asset Management system, in section 3.6 Reliability Management, and in section

3.7 Technical Asset Integrity management. It includes:

o Inspection, Monitoring, Test, and Maintenance; design and operational data,

parameter to be monitored, performance indicator, typical Threats/Risk and

a generic Risk Assessment for the equipment, including when possible

mitigations.

o Indicative frequency of inspection / maintenance,

o Long term Historical & Planning

Through the study, activities have been identified which could potentially enable

deployment of a guideline and improvement of geothermal asset management in general.

These are detailed below:

1. Develop a common Asset database to collect Integrity and Reliability data,

including design information. The database should also contain a means for

sharing information among stakeholders in suitable formats. It will contribute

to have a better understanding of failures and their impact on current and

future LEGE Asset (see preliminary approach in section 3.6).

2. Continue to develop the existing collaborative platforms and forums to share

geothermal data from project development and operation. A Joint Industry

Project (JIP) collaboration format as in Oil & Gas Experience could be used.

3. Adapt Value Improvement Practices (VIP) as used in the Oil & Gas industry

to geothermal projects. VIP is underutilized in capital investment &

construction projects. Typical VIP methods include Setting Business

Priorities, Design to Capacity, Technology Selection, Constructability, etc.

this in particularly relevant for The Exploration & Development phase.


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Revision History (Optional)

Revision Date Comments

HOLDS

No. Section Comment

Signatory Legend

Revision Role Comments

04 Prepared

Checked

Approved

Arnaud Barre

Paul Wood

Ogo Ikenwilo


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Table of Contents

1.0 Introduction ..................................................................................................................... 10

2.0 Study Methodology ......................................................................................................... 12

2.1 Abbreviations .......................................................................................................................... 13

3.0 Asset Management Guideline ......................................................................................... 16

3.1 Introduction ............................................................................................................................. 16

3.2 Asset Management: Objectives and Regulation .................................................................... 17

Objectives .......................................................................................................................... 17

Regulatory ......................................................................................................................... 18

Guidelines and Standards ................................................................................................. 22

3.3 Asset Management Process & Phases during Life Cycle Phases .......................................... 23

Asset Management Process overview ............................................................................... 23

Exploration Phase/Global Study to Preparation for Drilling & Construction Phase (“Voorbereidingsfase”) ....................................................................................................... 25

Drilling & Construction Phase ............................................................................................ 27

Risk Management Process - from Exploration until Drilling & Construction ........................ 28

Asset Integrity Management Plan During Production/Operation Phase ............................. 30

Geothermal Well Abandonment ......................................................................................... 35

3.4 Asset Management Plan - Development through the asset life cycle using the guideline ...... 37

Exploration Phase/Global Study to Preparation for Drilling & Construction Phase ............. 37

Drilling & Construction Phase ............................................................................................ 37

Production Phase to Abandonment ................................................................................... 38

3.5 Organisational and Operational Management Systems ......................................................... 39

Organisational Roles and Responsibilities ......................................................................... 39

Leadership Commitement and Policy ................................................................................ 40

Supply Chain Management and Knowledge Network ........................................................ 40

Competence and Training ................................................................................................. 42

HSE and Emergency Response ........................................................................................ 43

Management of Change .................................................................................................... 43

Incident, Preventive and Corrective Action Management System ...................................... 43

Lessons Learned ............................................................................................................... 44

Storage of Information – Documentation / Database ......................................................... 44

Performance Evaluation .................................................................................................... 47

Monitoring, Audit & Review ................................................................................................ 47

3.6 Reliability Studies.................................................................................................................... 48


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Reliability Prior to Operation/Production ............................................................................ 48

Reliability Data Collection during Operation/Production ..................................................... 48

Reliability, Availability and Maintainability (RAM) Analysis ................................................. 48

3.7 Technical Integrity Management ............................................................................................. 50

Geothermal System Description ........................................................................................ 50

Design Information Per Equipment ................................................................................... 52

Monitoring Operation Data and Technical and Non-techncial Performance Indicators ....... 52

Generic Threats & Risk Assessment ................................................................................. 54

Christmas-tree and Well: Inspection, Testing & Maintenance Program .............................. 61

Surface Facilities : Inspection, Testing & Maintenance Program ........................................ 63

Periodic review : Integrity Assessment and Analysis ......................................................... 69

Indicative Inspection, Testing & Maintenance Frequencies ................................................ 70

Long Term Historical & Planning : Inspection, Testing & Maintenance ............................. 73

4.0 References ....................................................................................................................... 74

Methodology to develop the Asset Management Guideline ............................ A-1

A.1 General ................................................................................................................ A-1

A.2 Guideline contents rationale ................................................................................. A-1

A.3 Literature review ................................................................................................... A-3

A.1 Asset Integrity Management Definitions ............................................................... A-4

Risk Assessment Methodology & Risk Matrices ............................................. B-6

Detailed Information on Standards ................................................................... C-1

Inspection, Testing, Monitoring Techniques .................................................... D-2


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List of Figures

Figure 1 Typical schematic sketch of a low enthalpy geothermal plant (source ref./ 36) ............... 13

Figure 2 Establishing Asset Management Process Prior to Operation/Production Phase .............. 24

Figure 3 Asset Management Process during Operation ................................................................ 25

Figure 4 Deliverables of an RBI Assessment for Inspection (ref./ 35) ........................................... 33

Figure 5 Maintenance Management System Cycle ....................................................................... 34

Figure 6 Basic P&A Plug ............................................................................................................... 36

Figure 7 Illustration Production Assurance terms (ref./ 24) ........................................................... 49

Figure 8 Diagram of Typical Production Low Enthalpy Dutch Geothermal Well ............................. 51

Figure 9 Hierarchy of elements of sustainable asset integrity management programme. (ref./ 19) A-3

List of Tables

Table 3-1 Objectives ..................................................................................................................... 18

Table 3-2 Minimum checklist of tasks to be addressed during these phases................................. 26

Table 3-3 Risk Template ............................................................................................................... 29

Table 3-4 Minimum Maintenance & Inspection activities requirements .......................................... 32

Table 3-5 Role & Responsibilities ................................................................................................. 39

Table 3-6 Stakeholder List: Suppliers, Public, Client, etc. ............................................................. 40

Table 3-7 Leadership and Policy Item List .................................................................................... 40

Table 3-8 Supplier’s Qualifications ................................................................................................ 41

Table 3-9 Network ......................................................................................................................... 41

Table 3-10 Organisation Competence and Training ...................................................................... 42

Table 3-11 Organisation Competence and Training – Planning .................................................... 42

Table 3-12 Technical Authority List ............................................................................................... 42

Table 3-13 List of Courses ............................................................................................................ 42

Table 3-14 List of Plan .................................................................................................................. 43

Table 3-15 MoC List for all phases ................................................................................................ 43

Table 3-16 Incident, Preventive and Corrective Action List for all phases ..................................... 44

Table 3-17 Lessons Learned List for all Phases ............................................................................ 44

Table 3-18 Minimum Documentation Management System Requirements ................................... 45

Table 3-19 Document& Data Storage System and Content .......................................................... 46

Table 3-20 Typical Master Document Register Content ................................................................ 47

Table 3-21 Minimum Audit and Review Plan ................................................................................. 47

Table 3-22 Reliability Data Collection ............................................................................................ 48


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Table 3-23 Design data per equipment ......................................................................................... 52

Table 3-24 Typical Design Data For Well ...................................................................................... 52

Table 3-25 Production and Injection Well Integrity PI .................................................................... 53

Table 3-26 Production and Injection Surface Integrity Operating Window & Minimum KPI ............ 53

Table 3-27 Overall Geothermal Asset System Threats ................................................................. 55

Table 3-28 Well Threat Risk Assessment ..................................................................................... 57

Table 3-29 Threats, Risk Assessment and Mitigation for Surface Equipment ................................ 59

Table 3-30: Frequencies ............................................................................................................... 71

Table 3-31 Basic Corrosion Monitoring Regime/Frequencies ........................................................ 72

Table 3-32: Inspection & Maintenance Planning template ............................................................. 73

Table 4-1 Risk = CoF x PoF (Quality) ......................................................................................... B-2

Table 4-2 Risk = CoF x PoF (Health) .......................................................................................... B-3

Table 4-3 Risk = CoF x PoF (Safety) .......................................................................................... B-3

Table 4-4 Risk = CoF x PoF (Environment) ................................................................................. B-4

Table 4-5 Risk = CoF x PoF (Public Acceptance) ....................................................................... B-4

Table 4-6 Risk Matrix .................................................................................................................. B-5


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1.0 Introduction

The first geothermal wells in the Netherlands were completed in 2007. In recent years, 11

geothermal doublets have been drilled. Client has identified a need to improve the asset

management of geothermal wells and surface facilities based upon a review of current

practice and consideration of improvements.

There is a need to define and standardise asset management practice covering the full life

cycle, and to transfer this knowledge effectively within the Industry to spread good practice.

An Asset Management plan should detail the HSSE management framework as well as the

economical delivery target and requirements. Furthermore, in addition to bringing good

practice to operational projects, the framework should ensure that knowledge relating to

HSSE, production and economic requirements are transferred to new geothermal projects.

The benefits of asset management can include, but are not limited to the following:

Improved financial performance

Informed asset investment decisions

Managed risk

Improved services and outputs

Demonstrated social responsibility

Demonstrated compliance

Enhanced reputation

Improved organizational sustainability

Improved efficiency and effectiveness

The objective of the study is to provide an Asset Management Guideline (AMG) enabling

the Dutch Geothermal Industry to develop lean, control and practical asset management

plan for their assets.

The guideline covers the entire asset life cycle and includes Concept and Drilling phase,

Surface Equipment, Well Construction and Design, Operation, Integrity, Inspection,

Maintenance and Safety.

The study also aims to facilitate knowledge–sharing and knowledge transfer in the area of

asset management for geothermal energy systems in the Netherlands through a workshop.

By providing tools to help deliver reliable and safe long-term operation of geothermal

systems, the study will increase asset performance, integrity and reliability within the HSE

framework prepared in another study. That includes maximising effective use of geothermal

energy (as opposed to non-renewable sources), maximising reliability and optimizing

maintenance, repair and other operating costs.

The Target Groups are the Dutch geothermal industry, asset operators, well designers,


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drilling contractors, surface facilities contractors and relevant institutions linked to the

geothermal industry in Netherlands.

The rest of the document is divided as follows;

Section 2 and Appendix A details the methodology

While section 3 is the actual Asset Management Guideline/Plan template. The

intention is that section 3 and Appendices B, C and D are easily extractable to make

an Asset Management plan.


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2.0 Study Methodology

The methodology that was utilised to develop the AMG is summarised below, more details

can be found in Appendix A.

Kick off meeting to agree deliverables and align expectations

A brief review of geothermal literature and risk approach

Review of asset management standards related to O&G and ISO 55000

covering Integrity and reliability of Asset

Incorporate and link relevant aspects from the past completed studies “Well

Integrity Management Guideline for Geothermal Wells” and “Geothermal

Corrosion study report” (Strand A of this proposal) to ensure the link between

design and operation

Review of available DAGO Integrity & Operation data (done via a survey and

also during a visit to select Operators facilities)

Risk assessment of relevant system threats to define appropriate inspection

methodologies, monitoring and integrity requirements on a generic basis (every

asset is different)

Development of the geothermal AM guideline including a set of tools & methods

to guide geothermal operators

A best practice and knowledge sharing workshop with Stakeholders

The guideline has been developed based on the following:

Oil & Gas standards and good practices, general Asset Management standards and

a web based literature review, all adapted to suit the Dutch geothermal industry;

The Hazid report ref./ 1 has been used to discuss and present key risks and

threats;

Risk Assessment: Identification of Threat & Risk is covered from a Generic point of

view as it is asset dependent.

Visit and interview of two Operators, including working meeting with DAGO Rep

showed the diversity of asset size, asset complexity in term of production threats

and operation, diversity of business model (e.g. single owner, multi owner).

It is planned to conduct a Workshop after the study delivery. This will be presented at the

Workshop.

The AMG covers production and injection well and surface infrastructure primary loops only

for shallow geothermal sources as found in the Dutch geothermal context.

The guideline covers the usual set of systems and equipment in LEGE assets. The primary

loop includes Booster and Injection pumps, Heat Exchanger, Gas/Water Separator and

Piping (but. not the transport system to final user – e.g. Greenhouse) as shown in Figure 1.


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Development of the practical measures for asset management for the downhole part of the

system are based on the existing Project (ref./ 9).

Figure 1 Typical schematic sketch of a low enthalpy geothermal plant (source ref./ 36)

Details on the methodology and approach to develop the guideline are presented in

Appendix A.

2.1 Abbreviations

ALARP As Low As Reasonably Practicable

AM Asset Management or Asset Integrity Management

AMG Asset Management Guideline/Plan template

AMP Asset Management Plan

BARMM Besluit Algemene Regels Milieu Mijnbouw).

BOP Blowout Preventer

CAPEX Capital Expenditure

CHP Combined Heat and Power

CMMS Computerized Maintenance Management System

CoF Consequence of Failure

CVI Close Visual Inspection

DAGO Dutch Association of Geothermal Operators

DG Decision Gate

DPI Dye Penetrant Inspection


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EIS Electrochemical Impedance Spectroscopy

ENM Electrochemical Noise Measurements

ET Eddy Current Testing

EU European Union

FEED Front End Engineering Development or Front-end

Loading

FFS Fitness for Service

GA Geothermal Asset

GVI Global Visual Inspection

HAZID Hazard Identification

HSE Health, Safety, and Environment

IMR Inspection, Maintenance and Repair

IRIS Internal Rotary Inspection System

IMT&M Inspection, Monitoring, Test & Maintenance

KPI Key Performance Indicator

LPR Linear Polarization Resistance

LTE Life Time Extension

MFL Magnetic Flux Leakage

MIC Microbial Induced Corrosion

MoC Management of Change

MPI Magnetic Particle Inspection

MTTF Mean Time To Failure

NDE Non Destructive Examination

NOGEPA Netherlands Oil and Gas Exploration and Production

Association

O&G Oil & Gas

OEM Original Equipment Manufacturer

OPEX Operational Expenditure

PI Performance Indicator

PoF Probability of Failure

RA Risk Assessment

RAM Reliability Availability and Maintainability

RBI Risk Based Inspection

RBL Radial Bond Log


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RBM Risk Based Maintenance

RCM Risk Centred Maintenance

RFT Remote Field Testing

RPN Risk Priority Number

SCSSV Surface-Controlled Subsurface Safety Valve

LEGE Low Enthalpy Geothermal Energy (also called Shallow

Geothermal Energy)

SMART Specific, Measurable, Assignable, Realistic and Time-

related

SSM State Supervision of Mines. Government body regulating

the Geothermal industry in the Netherlands

TECOP Technical, Economic, Commercial, Organisational,

Political

UT Ultra Sonic

WG Wood Group

WIM Well Integrity Management


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3.0 Asset Management Guideline

3.1 Introduction

The factors which influence the type of assets that an organization requires to achieve its

objectives, and how the assets are managed, include the following:

The nature and purpose of the organization;

Its operating context;

Its financial/contractual constraints and regulatory requirements;

The needs and expectations of the organisation and its stakeholders.

These influencing factors need to be considered when establishing, implementing,

maintaining and continually improving asset management. Asset management translates

the organisation’s objectives into asset-related decisions, plans and activities, using a risk

based approach.

This Guideline provides guidance for the application of an Asset Management Plan and

system for a geothermal asset, referred to as an “Asset Management System”, in

accordance with the requirements of ISO 55001.

This LEGE guideline/plan template addresses:

Requirements and good practices in terms of the Asset Integrity Management plan

including key regulation references;

Covers LEGE Asset primary loop Surface Geothermal Plant and equipment, wells

equipment and Safety-Critical Elements associated with geothermal production

installations in the Netherlands;

Asset Integrity Management Requirements and Processes through the different

phases of the Asset Life Cycle. It specifically describe levels of information required

for the different phases as follows:

o Business Asset Management systems requirements and processes such as

organisation, documentation, or training;

o Reliability studies, Risk Management & Integrity Assessment process;

o Primary loop systems threats & risk, Inspection Monitoring Testing &

Maintenance (IMT&T), Inspection and Frequency recommendation;

o Risk Matrices and methodology.

The guideline is intended to be implemented by LEGE asset owners and personnel who are

involved in managing the asset lifecycle. The guideline is designed to inform and influence

operator's management systems in regard to Asset Integrity (AI) and Asset Management

(AM).


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3.2 Asset Management: Objectives and Regulation

Asset Management and Objectives shall be common to all assets owned by one operator.

Objectives

The Operator’s organisation shall consider the requirements of relevant stakeholders and of

other financial, technical, legal, regulatory and internal organisational requirements in the

asset management planning process.

The Assets of the Dutch geothermal operators varies from small to large and from simple to

complex in terms of operation, number of suppliers and services, production, technical

challenges and business models. As a result, the activities shall be sized according to the

business and asset as follows:

- Perform a stakeholder management review and update it through the entire asset life

cycle.

- Update objectives as per regulations.

- Set objectives specific to assets - measurable, achievable within the timeframe, and

assignable to supplier or asset owner organisation (SMART1 principle good practice).

- The objectives shall be communicated internally and externally as required and updated

when required.

The following objectives shall be set by Operator with their Stakeholder as a minimum. Until

the Operation phase only the Objective and Objectives Target shall be set:

1 SMART an acronym to set up objectives as follows: Specific – target a specific area for improvement. Measurable –

quantify or at least suggest an indicator of progress. Assignable – specify who will do it. Realistic – state what results can realistically be achieved, given available resources. Time-related – specify when the result(s) can be achieved


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Table 3-1 Objectives

Objective Objective Target Measurement Owner in Organisation

Timeframe

Production Flowrate

Min and max flowrate Flowrate Hourly, Daily, monthly etc.

Production Availability

- Based on yearly or seasonal production - Depending on client needs

Number of days of maintenance, of production, shutdown etc

Hourly, Daily, monthly etc.

Operation Cost Cost breakdown structure plan vs accrued


Maintenance Cost

Cost breakdown structure plan vs accrued


Inspection Cost Cost breakdown structure plan vs accrued


Operational Parameters

Typical - Temperature min & max to be delivered Pressure - Electrical power consumption from grid or CHP - etc.

As per operational parameters


Training Type of training and level

Number of course, score achieved, etc.

Supplier Performance

Quality of delivery, delivery time, cost of delivery

Audit & review evaluation

As required

Improvement Objectives

Once improvements are identified, a target is to be set

As per improvement identified

As required

Regulatory

The AMP shall address the social, cultural, political, legal, regulatory, technological, and

natural environment, whether these are international (i.e. relevant European Union

Directives for geothermal energy), national, regional or local; it shall also include

relationships with, and perceptions and values of, external stakeholders to understand the

requirement and the risk and opportunities.

Specific definitions for Low Enthalpy Geothermal Energy (LEGE) are implemented in the

Netherlands such as depth of geothermal resources, installed capacity & system size,

temperature and utilization of water or resources.

Geothermal Asset installations require a careful evaluation of the subsurface conditions and

environmental impact of the installations as part of the development process. Typical

project development steps include:

Early consultation or submission of an early application of the asset development;

Completion of a feasibility study demonstrating the proposed LEGE system

construction, system size and proposed operation modes (including required


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heating and cooling demands);

Full permit and application process including Environmental Impact Assessment -

this application process commonly includes the submission of detailed construction

drawings, detailed methodologies for the drilling and completion phase and the

confirmation of proposed selected contractors for the construction operations;

Detailed monitoring and data submission programme.

This is a non-exhaustive list.

A summary of the regulation requirement is provided here after ref./ 39:

Legal Framework:

Permitting procedures. Exploration and development of geothermal

resources under 500 meter depth are subject to licensing in accordance with

the Environmental Management Act and the Groundwater Act;

Exploration and development of deep geothermal resources (>500 meter depth) are subject

to licensing under the Mining Act and the Mining Regulation.

Application for Licenses

For both exploration and development licenses, the application file shall include:

General information such as the identification of the applicant;

Financial details such as the manner in which the applicant intends to

finance the intended exploration or possible production;

Technical details:

The local geological situation and subsurface description;

The area applied for with relevant map;

The period the license is applied for;

The proposed installations and operating methods during the drilling

activities including the safety precautions and methods to prevent

pollution and nuisance;

The effects on the sub-soil including risks of subsidence and

proposed measures to avoid them;

The expected timeframe of the proposed activities;

The potential interference with other applications;

The envisaged results.

Note : The completion of energy systems is based on the requirement of a system

achieving an energy balance where the volumes of water extracted and re-injected as well


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as the amount of energy extracted in the heating and cooling modes do not result in thermal

changes to the aquifer conditions.

For licences only, the application file for an exploration license shall include:

A program describing the reconnaissance and exploration activities the

applicant intends to carry out, the pertaining time schedule and techniques

that will be used;

A geological report detailing at least: the exploratory surveys used for the

support of the application and other geological data, the interpretation of this

data and the risk analysis used thereby as well as a description of the local

and regional geology.

As for the application file for a development license, it shall also include:

An estimate of the expected geothermal resource;

A multi-annual program describing the production activities to be performed,

techniques used thereby and an estimate of the annual production,

investment and operating costs;

The technical and financial capacity of the applicant;

The sense of responsibility for society that the applicant has demonstrated in

activities under previous licenses.

The competent authority and main steps of the process are summarised hereafter:

Exploration

The Minister of Economic Affairs is the competent authority;

Obtain a BARMM (Besluit Algemene Regels Milieu Mijnbouw) - a

notification that drilling is performed in a safe and environmentally

sound way.

Application is reviewed and advice is collected from TNO (Geo-

Sciences Group), SODM (State Supervision of Mines) and the

Provincial executive of the province.

Development

The Minister of Economic Affairs is the competent authority;

A production license can be applied for once test drill has been done;

Advice from TNO, SODM, the Provincial executive and the Mining

Council.

Note that if a license for the production applies to an area in which a reservoir is present


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which can reasonably be expected to extend beyond the boundary of the license area, the

license holder is obliged to cooperate in reaching an agreement with the license holder of

the adjacent area.

A production plan is required. The plan shall address the following:

The expected geothermal resources and their location;

The commencement and duration of the production;

The manner of production and the activities relating thereto;

The expected annual production;

The annual cost of production;

The soil movement as a result of the production and the measures to prevent

such a soil movement.

A radioactivity baseline is recommended (see 3.5.5 HSE requirements framework.)

Operation phase and Abandonment

Annually, the licensee submits a report to the relevant Authority (e.g. the

Minister of Economic Affairs) on the progress of the execution of the

production plan and on any deviation from that plan.

In case of significant deviations, the licensee is required to submit an

update of the production plan, again to be approved by the Minister;

Report of water injected;

Environmental report (e.g. water from drain system);

Radioactivity.

Annually, the General Inspector of Mines shall issue an annual report to the

Minister on operations that took place during the year, including his

recommendations for the purpose of the efficient and dynamic handling of

future activities;

In the Netherlands, monitoring is implemented on larger scale systems only

as a measure to ensure the protection of groundwater resources and to

understand the hydraulic and thermal effects of the system on underground

aquifers. This monitoring process also includes annual reporting to authority;

LSA Norms. Radioactivity control is mandatory.

The abandonment of the wells will have to be carried out according to the Dutch rules and

regulations as described in the ‘Mijnbouwregeling’; Chapter 8.5. These regulations

prescribe the methods of abandonment for different well construction sections. These

methods dictate, in large, the work program and materials to be used and therefore the cost


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of the operation ref./ 41.

EU directives may impact the Netherlands geothermal asset. The Directive on Renewable

Energy Sources (2009/28/EC) has a binding definition of Geothermal Energy in the Article

2, which provides definition of geothermal systems. The rules protecting the environment in

geothermal regulatory frameworks cover principally water protection, control of emissions,

impact assessment and landscape assessment.

The following Directives are relevant for the geothermal industry:

Water Framework Directive, Directive 2000/60/EC

Natura 2000 Directive

Groundwater Directive

Surface Water Protection against Pollution under the Water Framework Directive

Environmental Impact Assessment Directive

Directive 2013/59/ Euratom, related to discharge of ionising radiation fluid

The requirement from these directives are summarised as follows:

o Member States have the option to authorise the reinjection into the same

aquifer of water used for geothermal purposes;

o Precautionary Principle

“Where there is scientific uncertainty as to the existence or extent of

risks to human health, the Community institutions may, by reason of

the precautionary principle, take protective measures without having

to wait until the reality and seriousness of those risks become fully

apparent”;

o ALARP principle;

o Monitoring of inlet and outlet temperatures, periodic monitoring of chemical,

composition of groundwater and/or surface water (including water quality).

Guidelines and Standards

Different Technical guidelines (ref./ 10) exist in the Netherlands related to LEGE systems

covering the following activities:

Distances for the completion of boreholes close to other third party properties

Design of groundwater wells

Technical drilling guidelines (under preparation)


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Standards for Groundwater Protection

The good practice guideline documentation identified as fundamental to the support and

development of the LEGE sector into the mature regions like the Netherlands are further

detailed in Appendix C.

3.3 Asset Management Process & Phases during Life Cycle Phases

Asset Management Process overview

Asset management is based on a set of fundamentals.

Value: Assets exist to provide value to the organization and its stakeholders

Alignment: Asset management translates the organisational objectives into technical

and financial decisions, plans and activities.

Leadership: Leadership and workplace culture are key of realisation of value.

Assurance: Asset management gives assurance that asset will fulfil their required

purpose.

Figure 2 and Figure 3 aim to visualise the development of a geothermal well/surface system

AMP. It covers all phases from concept to decommissioning. The AM plan shall be

reviewed at least annually and updated as appropriate. An independent

verifier/auditor/examiner should review annually the day to day implementation of the AMP

in order to apply a “fresh set of eyes” to potential improvements.


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Figure 2 Establishing Asset Management Process Prior to Operation/Production Phase


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Figure 3 Asset Management Process during Operation

The AMP shall gradually be developed as the geothermal asset project matures through

project phases; guidance is provided in section 3.4. One AMP shall be developed for each

asset.

The following section described in further details the key activities in each Asset life Cycle

phases. The following activities shall be executed by the operator together with contractor

and suppliers as part of the AM plan.

Exploration Phase/Global Study to Preparation for Drilling & Construction Phase (“Voorbereidingsfase”)

This project phase focus will be on identification, selection and definition requirements. At

these stages the activities purposes are to support the decision processes of each project

gate.

Asset Integrity / Maintenance Management Process during geothermal operation/Production phase

Input data

Output data

Yearly- Inspection data-Testing data- Monitoring data

Yearly Periodic Review

Kick off yearly process

Continuous Review

Analysis & Assessment

ITM plan/program

RA workshop

AM plan Update

Fit for service Assessement

Maintenance- Corrective data- preventive data

-Previous year data- historical data - earlier report

Reporting & Findings- KPI- failure report - Database update- procedured and plans updates- Etc

- Reliability data

RBM Maintenance plan/program

Reliablity assessement

Reliability plan/program

RA workshop

Input/output to/from Stakeholders

RBI

Maintenance data analysis


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Table 3-2 Minimum checklist of tasks to be addressed during these phases

Define Design Basis

Design life of the asset, reservoir data, production target/requirements, etc.

Define preliminary Asset and Organisation philosophy

Define and describe information and philosophy such as production level, fluid composition, type of wells, surface equipment’s, drilling information and constraints, reservoir information, Corrosion risk, etc.

Identify Risk & Opportunity and the show stoppers for each scenarios

Typical risk will be lack of information to take decision, uncertainty on data, nearby geothermal reservoir data not available or confusing, drilling complex and costly, etc.

Material selection for geothermal wells and surface

Material selection for geothermal wells components and corrosion allowance according to design basis. See WG INTETECH corrosion review and material selection for Geothermal systems and especially wells for detail on how to select material (ref./ 9)

Define qualification testing required for the project and associated cost

List of test to be performed to validate technical solution according to design basis

Identify and describe different scenarios

List potential scenario, document changes of feasibility of the scenario to ease scenario selection

Establish Preliminary Integrity Management requirements by considering CAPEX versus OPEX that includes material selection, operation philosophy, equipment selection, consequences on Maintenance Inspection, spare and repair workovers required for different options, etc

Seek and address lessons learnt from other projects to inform design decision making Use expert networks and geothermal organisation in general any source of information

Develop a list of specifications (to be included in contract) for next phase

List specification for suppliers and regulation requirements (see regulation section)

Identify resource requirements for the various project stages

Resource are personnel, engineering services, supplier, hardware, equipment (long lead item), access to database, etc.

Address Economic viability of the assets for the key scenarios

Explain the business model, your client or market, the need and requirement from your client in term of production target and availability

Recommended Minimum Functional Specification for wells (ref./ 40)

The well must be designed and constructed in a safe manner and account for the worse case such as: - Presence of gas and oil which is not detected and seismic activity, leading to explosion or

intoxication risks - Entry of free gas pocket while drilling


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Hereafter a non-exhaustive Risk list is presented. Large impact risks on project are

presented.

Reservoir condition (temperature, pressure, CO2 content, injection condition);

Heating or cooling capacity requirement and the ability to sustain these

requirements;

Uncertainty in geological situation and subsurface description, i.e. drilling risk;

Material Selection and Corrosion risk.

Drilling & Construction Phase

During this phase, the original design should align with the anticipated service life and be

factored into all design considerations. This means that:

Any deviations (see MoC in 3.5.6) to design during well construction; surface

equipment construction and commissioning should be recorded and addressed with

its impact on Operation, Workovers and Abandonment phase;

Control of change impact on OPEX, from CAPEX changes;

Update of Material selection;

Surface and Well Construction control (inspection & testing), including civil works;

Feed-back and lessons learned should be gathered, reviewed, and stored for future

/ new projects.

Hereafter a non-exhaustive Risk list is presented. Large impact risks (ref./ 1) on project are

presented:

Suppliers Cost and Delivery time overruns

Suppliers quality failure

o Well construction (cementing, stuck pipe)

o Surface construction

Drilling and well construction is one of the most expensive features of a geothermal

project. Drilling and well construction risks and any deviations shall be documented.

Safety equipment and procedure (e.g. BOP, Cementing job for isolation, etc.) shall

be addressed (ref./ 18).

Key risks will be:

o Shallow Gas during drilling;

o Existing geological characteristics and aquifer properties where systems are

proposed;

o System size and suitability of the ground conditions;


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o Flooding of asset during drilling;

o Noise Pollution;

Other risks are:

o Environmental pollution;

o Impact on other sub surface users (nearby groundwater users or other sub

surface infrastructures);

o Site preparation and restoration;

o Temperature thresholds relating to re-injection or surface water discharge;

o Thermal and hydrological effects with respect to the implications that the

system operation may have on sub-surface resource;

o Guidelines specific to construction to prevent the cross contamination of

aquifers; Collector circulating fluid and leakage prevention measures and

borehole construction requirements;

o Distances for the completion of boreholes neighbouring other third party

properties.

Risk Management Process - from Exploration until Drilling & Construction

Risk Management is paramount to understanding threats/risks related to geothermal

systems during the development phases or CAPEX phases. It may also reveal

opportunities. The risks and opportunities management allow the operator to:

Prevent, or reduce undesired effects;

Give assurance and demonstrate to others that the asset management system can

achieve its intended outcome(s);

Achieve continual improvement.

A risk register template (Table 3-3) to be regularly updated from Exploration until

Preparation Phase is presented hereafter. Risk assessment method & matrices are

described in Appendix A.

Regular Risk Review session should be held to keep the register and its

action/mitigation follow up, up-to date.

Risk shall cover Technical, Economic, Safety, Commercial, Organisational,

Regulation, and Community categories. Sufficient resources should be available to

address risks.


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Table 3-3 Risk Template

Category Description

Risk/Opportunity ID Number

Risk/Opportunity category Technical, Economic, Safety, Commercial and Contract , Organisational,

Regulation, Community , Suppliers, ,etc

Risk/Opportunity description “the Risk is …” add description ; the opportunity is ….” add description

Probability Value from Risk matrix

Consequence Safety Value from Risk matrix

Consequence Environment Value from Risk matrix

Consequence Financial Value from Risk matrix

Risk Rating R=Probability x Consequence (highest of the 4, i.e. Quality, Safety,

Environment and Public opinion)

Mitigation and action

description

Can risk be transferred, reduced, eliminated- please describe the action

Mitigation and action status Follow-up of the action

Risk Status Open , closed

Risk Owner Name


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Asset Integrity Management Plan During Production/Operation Phase

During the Production/Operational phase, a life cycle Asset Management process shall be

developed and maintained (see initiation in section 3.3.3), which describe how the asset will

be controlled and assessed during Production phase.

3.3.5.1 Integrity Assessment and Risk Assessment Steps

The AM plan shall describe when, how and why integrity assessment activities are to be

performed. Asset Integrity process during operation is summarised in Figure 3.

. The activities include:

1. Data and information collection gathering. These intend to provide information for

integrity and risk analysis and assessment. Inspection, monitoring and testing data

to be collected for each equipment and systems shall be established.

o In Section 3.5.9 data and information to be collected and set up are further

described.

o Technical data to be collected are further discussed in 3.7 (Inspection &

Maintenance program including their frequencies) and

o In section 3.6.2 specific requirements related to Reliability are described.

2. Integrity analysis and Assessment activities. Integrity is about compliance with

intended Design Limits and Standards of the equipment/systems. The objective of

the Integrity Assessment activity is to ensure a full assessment of the facilities and

systems based on inspection findings, monitoring and test results and reported

events. In principle all integrity assessments start by screening analysis. In case

more complex integrity assessments are performed, more quantifiable analysis is

used.

o See Performance indication and monitored data in section 3.7.3 data to be

monitored, assessed and analysed.

3. Risk Based Assessment Inspection and Maintenance

An anomaly (e.g. defect, pressure peak, CO2 Corrosion, etc.) can be critical or could

become with time. While the risk assessment purpose is to establish the current

condition of the anomaly, the ranking will help to provide appropriate actions and

allocate resource in term of inspection, monitoring, testing; it will also provide

recommendation in term of mitigation (e.g. preventive maintenance, repair,

replacement).

o Section 3.3.5.2 Detailed RBI and RBM method.

o An overview of typical Threats & Risk for LEGE assets are discussed in

section 3.7. As all LEGE assets are different, RBI and RBM must be run

based on this generic assessment.


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4. Asset Management planning. Based on previous activity (2 and 3) frequency of

inspection, maintenance, monitoring or testing and associated assessment can be

updated from baseline.

o See section 3.7 for Indicative frequencies per equipment.

5. Inspection, Monitoring & Testing Programs.

These are established during construction phase and revised according to Risk

Assessment and Integrity Assessment.

Inspections may reveal degradation or failures of equipment and in these cases,

corrective measures must be taken to rectify, re-instate, and maintain the integrity

level. For most of the geothermal plant equipment, fixed intervals are used for the

maintenance and inspection activities. These intervals can range from weeks up to

several years, which can be based either on calendar time or usage.

o Minimum maintenance & inspection activity requirements to be established

for each equipment are listed in Table 3-4.

o Inspection, monitoring, testing and maintenance generic technical

recommendations by equipment are presented in section 3.6.

o More information relating to the main inspection & monitoring techniques are

further detailed in Appendix D.

6. Long Term Plan: it is important to maintain an Inspection, Monitoring, Testing &

Maintenance plan.

o Template of how to build one is provided in section 3.7.9.

7. Mitigation activity. These are maintenance, repair or replacement activities to be

performed to reinstate and improve the asset integrity.

o See section 3.5.9 for required documentation

8. Fit for service activity will provide, on a yearly basis, the current status of associated

equipment or components. It is recommended to have regular review during the

year.

o See section 3.5.9 for required documentation


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Table 3-4 Minimum Maintenance & Inspection activities requirements

Description of requirements Information

Inspection

Inspection, monitoring, testing Program

See section 3.7 for technical details per equipment

Define reporting and alert criteria Reporting criteria are criteria when an anomaly must be reported during Inspection Alert criteria is a criteria providing an alert during Monitoring of Parameters

Maintenance

Maintenance programme, technique and procedure

See section 3.7 for technical details. Program should be risk based and set procedure for:

- Corrective maintenance: The unscheduled maintenance or repair to return items/equipment*).

- Preventive maintenance: All actions carried out on a planned, periodic, and specific schedule to keep an item/equipment in stated working condition through the process of checking and reconditioning. Preventive maintenance can be time based (e.g. cleaning filter on regular basis) or Conditioned Based **)

Define Maintenance criteria Workload and resource based

Note:

*) it is crucial that corrective maintenance is kept at a minimum, with typically only non-critical

equipment chosen to be in that category.

**) Predictive maintenance: The use of advanced measurement and signal processing methods to

accurately diagnose item / equipment condition during operation, and intervene to maintain

equipment on an as-required basis in advance of any significant degradation / failure

In addition to the Integrity Assessment routines described above, un-planned events should

also be assessed following a similar process described above.

When potentially unacceptable damage or an abnormality is detected, an integrity

assessment should be performed and should include a thorough evaluation including the

possible impact on the safety and operation of the Geothermal Asset. This means

quantification, Root Cause identification, additional inspection, monitoring and testing if

required to mitigate further degradation; identification of common failures across other

assets should be performed.

Note that a temporary damaged Asset system can potentially be operated (see 3.3.5.3).

3.3.5.2 Risk-Based Inspection & Risk-Based Maintenance

Risked Based Inspection

Whilst there are a range of risk assessment processes, an evidence based approach (ref./

22 ) should be used to screen out threat categories which are not relevant to the specific

Geothermal asset plant (e.g. seismic activity is not relevant for all asset) when developing

initial RBI.


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This avoids in-depth focus and assessment of threats which can be qualitatively assessed.

Risk can be evaluated qualitatively (expert Judgement) and/or quantitatively (i.e.

modelling), depending on availability of input data, and feasibility / cost efficiency. RBI

should be carried out for all elements of the geothermal installations.

Risk-Based Inspection (RBI) will be used as a key decision making technique for inspection

planning. Risk comprises the Consequence of Failure (CoF) and the Probability of Failure

(PoF). It is a formal approach designed to aid the development of an optimised inspection

regime. This evaluation will be carried out as per risk matrices and Methodology given in

Appendix B.

Figure 4 summarizes the principle and benefit of an RBI.

Figure 4 Deliverables of an RBI Assessment for Inspection (ref./ 35)

Risk-Based Maintenance

A Risk Based Maintenance assessment using risk assessment methodology and matrices

(see appendix A) (see ref./ 37) shall be used to prioritize maintenance in order to optimize

maintenance resources available. The outcome of the RBM will define priority and

frequency/interval of maintenance tasks. A typical maintenance process system is

presented in Figure 5. It is recommended to follow this process.

The scope of the RBM will encompass all systems in the geothermal plant. This evaluation

will be carried out as per risk matrices given in Appendix B.


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Figure 5 Maintenance Management System Cycle

3.3.5.3 Operation Philosophies and Integrity Management

Operation/Production Philosophy and integrity management are closely related. Asset

Integrity in normal operation is covered by the AMP. However, any change of operation

might impact the AMP and shall be addressed.

An asset system with damage / anomalies may be operated temporarily under certain

conditions. However, an integrity assessment shall be performed to define the temporary

operational conditions that the system can be operated in.

So long as the defect has not been removed or repairs have been carried out, it must be

documented that the asset integrity and the specific safety level is maintained, which may

include reduced/new operational conditions and/or temporary precautions/measures (see

section 3.5.6 Management of Change ).

Changes in operating conditions have the potential to impact the operability and technical

integrity of the geothermal systems. Problems that can result from changes in operating

conditions are addressed in further details as follows:

Design data and Operational Procedure are detailed in section 3.7.2

3.3.5.4 Requalification and Life Time Extension

Re-qualification is a re-assessment of the design and operation under changed design

basis conditions. A re-qualification may be triggered by a change in the original design

basis, including an extension to the original design life, by not fulfilling the design basis or

by mistakes or shortcomings discovered during normal or abnormal operation. The impact

of changes / updates to the original design code(s) or other relevant/ recognised design

codes should also be assessed when required.

AMP shall be revised according to changes to ensure engineering and operation continuity

until re-assessment is completed.


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Geothermal Well Abandonment

The abandonment of a well requires sealing it in a permanently safe manner that precludes

the possibility of any internal well flows from the reservoir to shallower formation or to

surface.

The law (see section 3.2.2) explains how different sections of the well will have to be

technically abandoned using cement, possibly in combination with (physical) plugs, and

how the quality of the shut-off has to be tested.

The construction of individual wells will vary with respect to casing design, cement depths,

cement quality and completion. As a result, the work programs to abandon wells will differ.

The following main items are included in the abandonment:

1. Production well

a. Including well head (X-mas tree), ESP, Production tubing

2. Injection well

a. Including. well head (X-mas tree)

b. Injection tubing

3. Production installation and pipelines

a. Including separator, filters, injection pump(s), metering, etc.

b. Cleaning equipment of Naturally Occurring Radioactive Material (NORM)

4. Well site area

The whole anticipated closure and removal process will have to be described in an

abandonment or Closure Plan. The plan should contain a detailed description of how the

abandonment will be executed from a technical and operational perspective.

A study performed for DAGO (ref./ 41) shows that up to 4 concrete plugs located at

different well location might be required. More details about abandonment plan and cost

estimate can be found in ref./ 41.

Despite disparities around the world, the intent of abandonment operations is to achieve the

following:

Isolate and protect all freshwater zones;

Isolate all potential future urban zones;

Prevent in perpetuity leaks from or into the well;

Following permanent abandonment, the elevation and plan location of the top of the

remaining casing shall be surveyed and all surface equipment removed.


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Figure 6 Basic P&A Plug

Typical P & A Requirements are as follows

All distinct permeable zones penetrated by the well must be isolated, both from each

other and from surface by a minimum of one permanent barrier

Two permanent barriers from surface are required if a permeable zone is

hydrocarbon bearing (if any) or over-pressured and water-bearing

The position of permanent barriers must be set based on the actual geological

setting

Note that the well should be monitored for losses or gas flows between stages and

pressure tests should be undertaken where practicable to determine the integrity of

cement plug and casing if identify as a risk.


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3.4 Asset Management Plan - Development through the asset life cycle using the guideline

This section defines how AMP is developed and contents of each phase using the

guideline.

Exploration Phase/Global Study to Preparation for Drilling & Construction Phase

During this phase the Asset Management Plan requires:

o Initiate AM plan development,

Specifically address requirement in section 3.2.2,

Project risk as per section 3.3.4,

Organisational & Operational Asset Management as 3.5. Note the

plan shall contain the data available at the time.

o Reliability study 3.6.1 shall be initiated

o Need for Reliability study section 3.6.3 shall be decided

o Address regulation as per requirements in section 3.2.2.

Drilling & Construction Phase

During this phase the Asset Management Plan requires to be further detailed.

o Address regulation as per requirements in section 3.2.2,

o Continue to develop Organisational & Operational Asset Management systems as

per 3.5. Specifically develop and establish Asset Management Plan for Operational

phase needs such as Asset Management documentation and data amongst others.

o Technical Integrity Asset Management as per section 3.7, including:

o Failure Mode and Effect Cause Analysis (FMECA) per equipment to Address

critical failure mode into the design

o Develop an initial Risk Based Inspection (RBI) and Risk Based Maintenance

(RBM);

o Acceptance Design criteria

o Inspection, Test, Monitoring and Maintenance (IMT&M ) program and plan

per equipment

o Equipment initial condition status baseline such as wall thickness of piping

(see details in section 3.7.6)

o Detailed plans for hand-over including check-sheets of handover requirements for

Production & Operation shall be prepared;

o Transfer of documents and databases relevant for the operational phase;


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o Identification and cooperation with the project organisation to resolve any

engineering and/or technical concerns and issues;

In addition, specific Production/Operation activity shall be transferred:

Training of personnel on equipment’s maintenance, inspection and operation.

The following shall be considered depending of the geothermal asset risk profile:

Online methods and tools to support diagnostics and failure analysis to improve

maintenance and reliability growth shall be defined and implemented such as:

o Seismic monitoring

o Radioactivity monitoring

Production Phase to Abandonment

At this phase, the Asset Management Plan shall be fully completed:

o Organisational & Operational Asset Management Systems section 3.5 shall be

completed and updated;

o Technical Integrity Asset Management section 3.7 shall be completed and updated

with supplier information;

o Reliability data collection system section 3.6.2 shall be set up and data to be

collected during Operation specified;

Integrity Management activities during Operation described in section 3.3.5.1 and

risk assessment, i.e. RBI & RBM (see section 3.3.5.2) further detailed in section 3.7.

shall be performed continuously;


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3.5 Organisational and Operational Management Systems

Equally important to Technical Asset Management; Organisational and Operational

management systems aspects must also be addressed.

Organisational Roles and Responsibilities

For an organisation, the key is to ensure clear roles & responsibilities and interface with

stakeholders to close any gaps. Operators shall address in the following tables:

Role & responsibilities.

o Experience and skills shall drive the selection of the individual;

o Example is provided in Grey. Role and title can change from one

organisation to another. Role and responsibility for the function listed must

be addressed;

Stakeholders interfacing with internal organisation;

The interfaces between functions.

For small Dutch LEGE organisation, one employee may cover several function presented in

the table hereafter.

Table 3-5 Role & Responsibilities

Function Job Title

Role and responsibility description Years of experience

Name of the person

Operation/ production

In charge of day to day operation and delivery

Inspection In charge of leading or performing Inspection function

Maintenance In charge of leading or performing Maintenance function

Commercial Supply chain

In charge of Contract and commercial

HSE In charge of safety

Asset Integrity In charge of ensuring fit for purpose well and surface equipment

Technical services (Supply chain)

In charge of technical delivery follow up

Internal /external reporting

Reporting Asset status internally and externally

Technical Authority Decide best technical solution for surface or/and well

Others To be added as required


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Table 3-6 Stakeholder List: Suppliers, Public, Client, etc.

Stakeholder: Services and Products

Service or reporting Person in charge internally (Job Title)

Additional information

Inspection service All equipment & Service

Maintenance services

All equipment & Service

Drilling services All equipment & Service

Consultant services e.g. Law. Project management, technical services, etc.

Network and industry association

Any network and Association supporting asset management

Leadership Commitement and Policy

Asset management leadership is demonstrated by top management positively influencing

the organisation. In common with other aspects of responsible and prudent operatorship,

sound Asset Integrity Management (AIM) is largely shaped by effective leadership which

should be expressed in the operator's HSE policy and Asset management system (in

Dutch: 'Veiligheid en Gezondheids- zorgsysteem'/ 'VG systeem').

Note that Leadership Engagement is usually included as part of Asset Management best

practice. However, considering that LEGE organisations in Netherlands are usually small,

the associated activity should be dimensioned according to the company size. Nevertheless

less, the Operator should have a policy statement on how they will manage their asset,

personnel and the environment.

Table 3-7 Leadership and Policy Item List

Item Description of information Information

Owner Name of owner/accountable person Any additional information

HSE Objectives List objectives Any additional information

Owner site visit and/or town-hall meeting

Once year is recommended Any additional information

Owner meeting with all personnel

To address importance of operation objective, Inspection and maintenance, and review of system in place .Quarterly is advised

Any additional information

Policy statement A short statement that sets out the principles, Vision, and priority by which the organisation intends to apply asset management to achieve its objectives, and improvement.

Any additional information

Supply Chain Management and Knowledge Network

Supply chain risks from Concept to Operation should be identified, with careful control and

planning of all activities. Physical and service interfaces should be identified, agreed and

documented.

For the Dutch Geothermal operator, it is particularly important as the industry is in infancy


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phase where different uncertainties, new technical issues, or different operational

philosophy are new.

For a LEGE asset, Supplier control & Supplier qualification records shall ensure control of

cost, delivery time, and quality of the scope delivered from Concept to

Construction/commissioning (see detailed requirements in 3.3.2, 3.3.3 & 3.3.4), and

Planning of Inspection, Monitoring, Testing and maintenance supplier during Operation.

Supplier qualifications are addressed in Table 3-8.

It is also important to maintain a network of national/international services, organisation and

different subject matter experts to answer potential new issues and challenges or bring

additional knowledge. This is addressed in Table 3-9.

Table 3-8 Supplier’s Qualifications

Supplier name and service/product

Description of information Information

Does the selected Supplier have a track record?

Delivery on time, Cost and quality

Are the supplier’s personnel qualified? Check CV’s and qualification

HSE track record HSE Statistic, Environmental incident if any while drilling, etc.

How the Operator/Supplier interface is managed for risk and engineering delivery?

Check and justify

Is the supplier informed about operator HSE and Production Objectives

Check and justify

How is the Supplier/Operator informed of changes during concept design, fabrication, commissioning, production phase?

Check and justify

Does Supplier understand Engineering requirements of equipment defined by Operator?

Check and justify

Does Supplier understand Integrity, Inspection and Maintenance requirements of equipment defined by Operator?

Check and justify

Is the supplier optimizing OPEX / Capex as per Operator requirement and needs?

Check and justify

Does the Contract Terms and Condition cover all risks identified

Check and justify. see Risk sections 3.3.4 and 3.3.5.2

Table 3-9 Network

Name and service/product

Description of Product & Services Contact details Description of the information, knowledge sharing, product or services that can be provided by the network organisation

Contact details

Dutch Geothermal Platform Organisation – sharing forum Operator and Contractor

DAGO – Geothermal Operator Network


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Competence and Training

Management of competence and training is key to a successful asset management

program and control of technical risk. Staff must be suitably trained and coached as per

their job and function. Basic professional and technical competence should be

supplemented where necessary with training in the management of ageing assets. Training

can be applied in different forms such as via industry work groups, seminars and formal

training courses both within and outside the industry. Resources & manning levels shall be

managed and controlled accordingly.

With respect to contractors and external service providers, their responsibilities and the

competence requirements should be documented in the scope or elsewhere in contracts

document (See 3.5.3 training).

Table 3-10 Organisation Competence and Training

Employee Name

Job Function

Required Qualification for job

Current qualification

Planned Training to close the gap

Task allowed

Employee 1; job title

List training, experience on the job as per job description for the job title or function

List training, experience

Training plan , description to close the gap

As per current skills vs required training list the task allowed

Employee 2

Table 3-11 Organisation Competence and Training – Planning

Employee Name

Course title Planned date Status Completion date

Employee 1; job title

Not started, on-going, competed

Employee 2

Table 3-12 Technical Authority List

Employee Name Subject matter

Employee 1; job title List technical authority subject matter covered by employee

Table 3-13 List of Courses

Course Description Course name, organisation, location Describe the course and qualification it provided DAGO Geothermal Courses

BodemenergieNL, Euroform & Stichting PAO (Netherlands) (ref./ 4)

Basic courses as well as several specialised courses for different target group including drilling companies, advisors/consultants and local authorities

VIA University College, School of Technology and Business (Denmark) (ref./ 4)

Shallow geothermal energy system development and installation focuses on the different aspects related to LEGE systems


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HSE and Emergency Response

ALARP principle shall be observed in day to day AMP activities. As a result, HSE

requirements shall be implemented as per DAGO Zorgsysteem.

The AM plan shall also address a number of emergency plans to cover various emergency,

incident and associated repairs. For a LEGE Asset, the following emergency response plan

should be in place to re-instate the asset integrity in addition to plan for HSE purpose (see

DAGO Zorgsysteem).

Table 3-14 List of Plan

Plan Description and ref

Surface equipment emergency repair plan

Describe the purpose of the plan and give reference to a plan document: Proposed content : leakage repair for piping and pressure vessels, piping blockage; Valves leaks, Exchanger leaks and pressure vessels, piping blockage; Valves leaks, Exchanger leaks; other component, define spare strategy for long lead items, identified supplier and repair supplier

Well emergency repair plan

Describe the purpose of the plan and give reference to a plan document: Xmas tree failure, ESP failure repair/spare plan, identified supplier and repair supplier

Management of Change

The primary objective of a Management of Change (MoC) process is to ensure that

sufficient rigour is applied in terms of planning, assessment, documentation,

implementation and monitoring of changes affecting an installation or operation so that any

potentially adverse effects on Asset Integrity are identified and managed effectively to

mitigate adverse effects.

The AM organisation plays a key role in ensuring that all changes are communicated and

managed in a systematic manner and that all required stake holders are aware of the

changes and approval of changes is known. Changes should be consistently recorded and

assessed in terms of risk for the life cycle of the asset.

Table 3-15 MoC List for all phases

Change description

Component

Project Phase

Who should be consulted & informed

Approver Status Deadline

Describe the change

Relevant component

Exploration development, Construction, Commissioning, Operation and Abandonment

List who is impacted and should be consulted and informed

PM, Technical Authority

Open, ongoing, closed

Deadline to complete or to take decision

Incident, Preventive and Corrective Action Management System

Arrangements should be in place to ensure that all relevant preventive and corrective


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improvement actions arising from monitoring, audit / review are recorded, documented and

tracked to closure.

For incidents; their investigation, root cause identification and the resulting action must also

be recorded for continuous improvement purposes. Other methods exist such as forensic

engineering report (ref./ 17) which complement usual integrity and risk assessment.

Table 3-16 Incident, Preventive and Corrective Action List for all phases

Incident, description

Preventive and Corrective Action Measure

Project Phase

Who should be consulted & informed

Approver Status Deadline

Describe the incident and relevant component

Describe the action

Exploration development, Construction, Commissioning, Operation and Abandonment

List who is impacted and should be consulted and informed

PM, Technical Authority

Open, Ongoing, Closed

Deadline to complete or to take decision

Lessons Learned

Lessons learned from assurance activities or from incidents should be captured and

communicated within the operator's organisation and across the wider industry as

necessary (see section 3.5.5). Learning from problem and exchanging data and information

across developing industries are crucial to the overall long-term viability and efficiency of

the geothermal asset.

Table 3-17 Lessons Learned List for all Phases

Component Lesson Learned description

Recommended Action

Project Phase Distribution list

Status

Relevant component

Describe the change

Describe action Exploration development, Construction, Commissioning, Operation and Abandonment

List who should be informed

Open, ongoing, closed

Storage of Information – Documentation / Database

All assets should have all project life-cycle documentation/data available and associated

change recorded. This activity is often referred to as Life Cycle Information management

systems (LCI). The documentation sets out the design criteria by which the asset meets

safety, operational and other performance requirements.

All changes should be controlled and documented. Operators should demonstrate that

relevant, up-to-date documentation is readily accessible by maintaining an effective

Document Management System (see requirement Table 3-18).


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Operator shall define and list IT information system to store the different data &

documentation related to the life cycle of the asset (see Table 3-19).

Table 3-18 Minimum Documentation Management System Requirements

Item # Requirements & Recommendations Information

1 Maintainable and up-to date documentation and database system

The design documentation will be the primary means by which engineers are informed of key requirements and design assumptions

2 Design and set a documentation format and system easing retrieval and analysis of data & information

Clearly defined criteria to develop and revise documents, to limit documentation and ease access to information in the future

3 Review by Technical Authority The design documentation should be reviewed and endorsed by relevant technical authorities to ensure that the design basis remains aligned with Objectives

4 Identify a document/data Controller Allocated responsibilities and authorities to review and issue documents, to withdraw and retain obsolete documents

4 Documentation data systems account for tracking of changes

Arrangements to ensure that documentation is revised and updated according to MoC section 3.5.6

5 Accessibility to technical personnel and suppliers of relevant information

All engineering activity undertaken throughout the anticipated service life of an asset should properly address AI considerations. Engineers should be kept informed of AM related decisions and plans, and factor those into modifications and other forms of engineering activity to achieve good alignment. Particular areas of focus will be modification interfaces between new and ageing equipment and where inspection has shown some degradation to the existing systems compared to design assumptions

6 Security and back up of the Data Security of the data shall also be considered against ransomware or any other virus; a backup of the information and system shall be set up.

7 Ensure business continuity via a business continuity plan

IT system can be hacked, asset partly damaged (e.g. fire, explosion), key personnel can leave company. As a result, significant knowledge and experience can be lost. Operation can be disrupted for several weeks or months with significant impact. Operator should have a business continuity plan to address such threats.


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Table 3-19 Document& Data Storage System and Content

Item #

Type of Data/Information Description of Content Information/data system

1 Verkenningsfase (Exploration phase and Global Study Phase)

Documentation, plan and changes, including Project management and administration document (doc control, Project control, Minute of meeting etc.

Data/information storage system name, version, server location or archive location, back-up solution, data format, type of data stored, description

2 Haalbaarheidsfase (Detailled Phase)


3 Voorbereidingsfase (Development Phase).


4 Realisatiefase (Drilling & Construction Phase).

Documentation, plan, equipment specification, user manuals and changes, including Project management and administration document (Doc control, Project control, Minute of meeting etc.

5.0 Productiefase work-over (Production and Work-over Phase).

Documentation for operation, procedures, reporting to authorities, Integrity planning and strategies

5.1 Asset Management Document: Minute of meeting, Emails, Contract, Bid and Offers, Invoice recommendation or action internally and externally. Ensure that know-how and information is documented for business continuity

5.2 Operation Documentation

Database and documents register of procedures, analysis report, supplier documentation for equipment, etc. Minute of meeting

5.3 Inspection Data Visual inspection, record, analysis and results

5.4 Inspection Monitoring Data monitored. See also KPI section

5.5 Maintenance Data Predictive and corrective maintenance records A data collection system shall be in place to perform maintenance risk assessment and track maintenance performed e.g. Computerized Maintenance Management System CMMS

6 Abandonneren (Abandonment).

Documentation and plan for abandonment and cessation of activity

7 KPI The organisation shall retain appropriate

documented information as evidence of the

results of monitoring, measurement, analysis

and evaluation.

8 Management of Change Register

Changes for all phases in terms of design

basis, engineering, operation conditions etc.

9 Incident Associated Root Cause and Investigation Register

Incidents for all phase and associated

investigation


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Table 3-20 Typical Master Document Register Content

Document type Document title

Doc. number Revision Status

Procedure, Technical note, Minute of meeting Procedure operation/maintenance , inspection , Monitoring, etc.

As per Numbering procedure, i.e. Categorised by equipment, by system, by supplier or other relevant categorisation approach

As per Numbering procedure

Active, superseded, draft, etc.

Performance Evaluation

Asset performance shall be measured, analysed and evaluated. The KPI provides the basis

to review effectiveness of the asset management system and process and ultimately the

adjustment of mitigation and / or monitoring activities. KPI’s are often used to give a high

level status of an asset when measured against defined criteria.

A set of performance/target level of service measures should be developed to monitor the

effectiveness of implementation of the Asset Management. A minimum list of KPI is listed in

section 3.7.3; some of them are only relevant if equipment is part of the asset. Target and

acceptance criteria are to be defined for each asset.

Monitoring, Audit & Review

Operators should have monitoring, audit and review arrangements in place. This is to

ensure that the AMP is delivering according to objectives and performance. The audits

should be conducted by both internal and external parties.

Audits focus on procedural compliance with respect to objectives, policies and requirement

by stakeholders. Audit plans and procedures shall be developed and maintained by the

Asset Team.

Audit records should be kept and resulting actions should be added to the Action

Management systems to ensure they are tracked, managed, and suitably closed out.

Table 3-21 Minimum Audit and Review Plan

Item # Description Recommended minimum frequency

1 Review and Audit of AMP effectiveness and compliance

Once a year during Operation, Once per project phase

2 Review and Audit of Inspection, Monitoring, Testing and Maintenance plan, records and execution

Once a year, Twice yearly for records

3 Review and Audit of Operation and integrity processes and procedure

Once a year

4 Review and Audit of suppliers Twice for key suppliers during project duration; every year for supplier involved in Operation


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3.6 Reliability Studies

Reliability Prior to Operation/Production

From Exploration until Preparation phase, component systems shall be designed for

reliability, meaning the following principles should be applied: Functional clarity, Simplicity

(minimum parts to provide function), No weak components and remove common cause

failures, Robustness and Materials selection to avoid degradation processes

A FMECA for components and systems is recommended to address reliability and integrity

in design and also to establish Asset Integrity & Maintenance program and associated RBI

and RBM.

FMECA enables Designer and Operators to identify and treat failures that can be

mitigated through design.

Remaining failures will be treated during operation and followed through RBI or

RBM.

It is recommended that if a component/system is ranked as critical for operations during the

risk assessment phase, that testing and evidence of reliability are required from the

Supplier. Reliability of components can be demonstrated by suppliers via field experience

data or testing data.

Reliability Data Collection during Operation/Production

Reliability data related to Equipment’s/Components shall be kept by each Geothermal

Operator. It is recommended that Operator should anonymize and share these data on a

regular basis through a specific Forum/Network.

The data to be collected as a minimum are as per Table 3-22 for each component.

Table 3-22 Reliability Data Collection

Component Name and tag Operation time in service of Components (hrs)

From start to last update of the data in days

Number of failures

Number of failures during time in service

Non production time (hrs)

Any shutdown time during production/ operation

Number of Maintenance order

Number of Maintenance tasks during Operation

Cumulated Maintenance time (hrs)

Cumulated Maintenance time during time in Service in days

Failure type Failure description Repair time Downtime Short description of failure types list : corrosion, mechanical failure, etc.

Describe if failure occur during normal or abnormal operation, describe failure mode, failure cause, failure effect, failure criticality n term of safety or production

Only time to repair. Time from failure to restart; include supply of part time, failure investigation, repair time, time for re-testing and commissioning.

Reliability, Availability and Maintainability (RAM) Analysis

Geothermal plant Availability and Ability to produce is a critical parameter to achieve


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Production Assurance, i.e. Production target toward end-user(s), i.e. minimum, and max

flow rate or number of production days due to planned maintenance/ shutdown (e.g.

300days production yearly).

However, each Geothermal Asset operates under different Business Model/Contract Terms

& Conditions between Operator and end users. A RAM analysis is recommended:

- Whenever no Terms & Conditions have been agreed between Operator and

Users; e.g. operator and energy buyer is the same company, Geothermal asset

is own by a group of buyer, etc.) and,

- User’s requiring a production delivery target (flowrate, temperature,

pressure; etc.)

Reliability is the probability of survival after a unit/system operates for a certain period of

time (e.g. a unit has a 95% probability of survival after 8000 hours). Reliability defines the

failure frequency and determines the uptime patterns. Maintainability describes how soon

the unit/system can be repaired, which determines the downtime patterns. Availability is the

percentage of uptime over the time horizon, and is determined by reliability and

maintainability.

The Reliability and Availability is started by defining the methodology to achieve targets at

concept. That includes designing for reliability. The RAM model is used to demonstrate the

target when design is completed. Reliability Data collected from generic database or from

field data are used in the RAM model.

The goal is mainly to be able to identify cost life cycle impact (CAPEX versus OPEX) of

selected technology, material, Process, need for Spares and Operation philosophy

(shutdowns, maintenance requirements, and retention of spares, etc.) based on production

needs to achieve targets.

Figure 7 Illustration Production Assurance terms (ref./ 24)


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3.7 Technical Integrity Management

The section covers the following deliverable part of the AMP:

System description and Operational parameter;

Generic Threats and Risk assessment to Support RBI and RBM (see section

3.3.5.2)

The “what, how and when” related to Inspection/Monitoring/Testing & Maintenance

technical program; The Inspection tools are further detailed in Appendix D.

Indicative Inspection & Maintenance Frequencies

Long term & Inspection, Testing & Maintenance Frequencies Historical Plan

The Periodic Review content , i.e. compliance and Asset Integrity assessment

This technical information section address LEGE Asset equipment, i.e. surface facilities for

primary loop and wells; the equipment listed and their associated inspection and

maintenance is not exhaustive as it depends on the asset design features and technical

design and operational challenges.

Geothermal System Description

A typical schematic overview of the geothermal asset is underlined in Figure 1. The

wellhead and separators are usually located outside the main/processing building. Note:

gas drying plant (only in some geothermal asset) is located inside of the main processing

building.

Note: additional facilities are sometimes used on some LEGE asset depending of operation

conditions and constraints. These are for instance biocide injection system in production

well, combined Heat and Power Generation (CHP) Boiler, Nitrogen Installation water tank

buffer to deliver temperature. These equipment’s are not discussed hereafter but it is

recommended to add them in the AMP.

The key surface equipment / components have the following functions:

Booster Pump is used to bring the hot degassed formation water to the desired

process pressure;

Filters are used to remove solids from formation water prior to the heat exchanger,

or to prevent particles resulting from heat exchanger degradation from entering the

injection pump;

o Solids may be internal particles entrained in the rock matrix by hydrodynamic

forces or suspended particle precipitates of induced scale (carbonates,

heavy metal sulphides, silica) species.

o Note that particles of infra-micrometric/colloidal sizes (diameters below 0.45

μm) are present in all waters sampled in the Netherlands (ref./ 10).


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Heat exchanger, typically plate – type: where heat transfer takes place from primary

to secondary without mixing.

Injection Pumps, typically centrifugal type.

Water gas/separator: use of a degasser in a geothermal system aids in preventing

the formation of free gas and potential gas clogging further on.

Monitoring and chemical treatment equipment.

The typical geothermal facility has one or more production wells and injection well doublets.

The well is constructed with a conductor casing and surface casing which are usually

cemented to the surface. Liners may be installed to reach reservoir depth with a slotted

liner or wire wrapped screen over the reservoir section. Except for the final production liner

over the reservoir, all liners are cemented from shoe to the liner hanger assembly.

The production well is completed with a tubing and downhole pump, typically an electrical

submersible pump (ESP), with a simple wellhead and Christmas tree assembly of valves.

The tubing and casing materials are carbon and low alloy steel in all existing wells. The

typical injection well is essentially similar but without the downhole pump. The Electrical

Submersible Pump (ESP) consist of a multistage down hole centrifugal pump, a down hole

motor, a seal and a cable going all the way to surface. A variable speed drive can be used

to regulate the flow rate.

Each Production and injection well (i.e. doublet) and Christmas tree shall be operated and

maintained according to design. When a potential defect is identified, additional monitoring

or remedial work required to maintain the well condition shall be planned and carried out as

soon as practicable, depending on the nature and the assessed risk resulting from that

defect. Monitoring shall continue at an appropriate frequency to allow for timely

identification of any change in well condition, until the defect is remedied.

Figure 8 Diagram of Typical Production Low Enthalpy Dutch Geothermal Well


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Design Information Per Equipment

Key Design Information which will be useful for day to day operation shall be collected and

structured in the AMP as per Table 3-23. The information shall be up to date and reflect any

changes and modification occurring after original design & construction as per requirement

3.5.6.

Table 3-23 Design data per equipment

Equipment Description Value and units Name of equipment and associated equipment

Information on key Design Parameter, such as Pressure & temperature, fluid compatibility, voltage, material, geometry & length, etc. In addition key Suppliers information shall be added for the safety and the integrity of the systems

Data itself or reference to database or document

Table 3-24 Typical Design Data For Well

Monitoring Operation Data and Technical and Non-techncial Performance Indicators

Monitoring of Operational parameters and following up the trends of Performance Indicators

(PI) is a key activity of the geothermal Integrity systems. Monitoring can take place through

sensors in the primary process streams, or in bypasses and / or subsurface. Monitoring and

inspection provide essential information on condition and can be continuous or at regular

intervals. It also gives advance warning of possible problems to avoid unexpected failures

and establish relations between operating parameters and threat behaviour. Monitoring

confirms the effectiveness of the mitigation measures and informs the planning of

inspection and maintenance programmes.

The Performance Indicator for LEGE Well and surface facility shall be monitored. PI for

reservoir and well are addressed in Table 3-25. Surface and general additives monitoring,

physical parameter monitoring and non-technical KI are addressed in Table 3-26.

Note that performance indicator and monitoring of parameters shall be adjusted as per Risk

Assessment, i.e. added or removed.

Information Value Information Value

Validation date Well Schematic Attached

Well name Wellhead and Xmas tree rating, dimension, service trim

Well Type (Function)

Identify any leaking or failed barrier components

Reservoir name

Additional Notes:

Original Completion date

Any limitation on acceptable kill and completion fluids?

Latest Completion date

Any special monitoring requirements?

Well design Life

Any other comments?


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Table 3-25 Production and Injection Well Integrity PI

Table 3-26 Production and Injection Surface Integrity Operating Window & Minimum KPI

Performance Indicator Description Acceptance Criteria & Anomaly Limits

Additives Monitoring To be defined as per asset design, i.e. the following shall be defined for each KPI whenever possible.

1) Upper Safe Design limit 2) Upper Safe Operating limit 3) Upper Normal Operating limit 4) Normal Operating Limit 5) Lower Normal Operating limit 6) Lower Safe Operating limit 7) Lower Safe Design limit

Note that beyond 1) or below 6) equipment will operate with Design Margin / known safe then uncertain operating conditions. Between 2/3 and 5/6, this is called the Troubleshooting zone

Corrosion inhibitor content

Corrosion inhibitor availability

H2S Scavenger (Residual H2S Concentration)

Scale inhibitor (continuous/intermittent)

Bactericide / Biocide (continuous/intermittent)

Fluid Parameter Monitoring

Iron Ion content

Oxygen Scavenger (Residual O2 concentration)

Fluid Additives

O2 in Water Injection (ppb Oxygen equivalent)

CO2 (mol% in gas phase)

H2S (ppm in gas phase)

Water Calcium (Ca) content

Water Sodium (Na) content

Water Chloride (Cl) content

Water pH Value

Bubble Point

Methane (CH4) mol%

Physical Parameters Monitoring

Gas/water Ratio

Gas production

Injection pressure

Injection temperature

Production Pressure

Production temperature

Production Flow

Electricity consumption per Phase

Degasser pressure

Degasser, Flow rate

Water/Oil/Gas Separator, pressure

Performance Indicator description Target / Acceptance criteria & Anomaly Limits

Operational Limits

(enter value or NA)

Min / Normal/ Max

Maximum Injection Pressure (psi)

GWR (scf/bbl)

Reservoir Pressure (Bar)

Reservoir Temperature (C)

SITHP (Bar)

Maximum design production rate (m3/hr)

Maximum design injection rate (m3/hr)

ESP design rate (m3/hr)


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Performance Indicator Description Acceptance Criteria & Anomaly Limits

Water/Oil/Gas Separator, Temperature

Usage of Gas - Preferred option - WKK (capacity)

Usage of Gas - Alternative option - Heating (capacity)

Usage of Gas - Alternative option - Flare (capacity)

Heat Exchanger, Flow Capacity

Heat Exchanger, Temperature In

Heat Exchanger, Temperature Out

Non-technical PI

Number of Audit Audit performed during the year

Maintenance back log Maintenance not done as per plan

Corrective maintenance Per equipment per year

Shutdown Number of shutdown

Non Conformances Non Conformance trends

Training Training completed versus training plan

Inspection back log Inspection not done as per plan activities

Generic Threats & Risk Assessment

This section presents Risk Assessment of relevant system Integrity Threats/Risk for LEGE

System. Table 3 -27 provides high level list of Threats to be used to assess the LEGE

asset.


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Table 3-27 Overall Geothermal Asset System Threats

3.7.4.1 Well Specific

Well Integrity (WI) can be defined as the ability of the well(s) to perform its required function

effectively and efficiently whilst protecting Health, Safety and the Environment.

Well Integrity Management encompasses the physical condition of the well(s) as well as the

necessary organization and activities needed to avoid the possibility of failure, which

potentially can result in serious incidents.

Risk Assessment

The WG Corrosion Review and Materials Selection for Geothermal Wells report (ref./ 9)

summarises the most common forms of corrosion and metallurgical degradation


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mechanisms that are potential threats applicable to geothermal wells in the Netherlands.

The Well & Xmas tree risks are driven by corrosion and mechanical stresses. For Instance,

Corrosion can impact ESP (bearing/sleeves) and steel part of the well. When it comes to

material degradation threat, hardening versus corrosion for ESP or tubing is typical issue of

the Material selection phase (ref./ 40).

CO2 is the principal corrodent in many geothermal reservoir fluids. A wide range of CO2

content is possible in any geothermal wells, but probably relatively high, i.e. 5 – 50 mol% in

the gas phase (ref./ 9). Potential “hot-spots” for CO2 corrosion in the well system include:

Pump, pump inlet & outlet in producers;

Perforations and sand screens;

Below (upstream) of corrosion inhibitor injection point in producers (if applicable);

Wellhead and tree (due to bends, flow restrictions);

When the geothermal fluid is brought to the surface and the temperature, pressure and

chemical properties change, the potential for deposition of scale on the casing walls and

within the heat exchanger and topsides facilities exists. Scale can precipitate and coat the

surfaces of plant components which can cause blocking of flow and reduction of heat

transfer capability. Studies (ref./ 11) show that this is the primary suspected cause of

severe injectivity decline on several injector wells.

H2S is not currently present in Dutch geothermal assets (ref./ 9), the potential for the future

presence of H2S should be considered and not be ruled out from Risk Assessment.

High quantities of particles in the geothermal loop as a result of degassing (if any) of the

water, which leads for instance to the precipitation of carbonates.

Review of other LEGE asset operational data and fluid include threats such as presence of

lead and erosion of the systems due to particles cannot be excluded. On some occasions,

scale removal and disposal methods extend the uptime however it may impact operational

cost (e.g. turbine washing).

Radioactivity levels (see LSA norm) are due to be monitored and baseline must be

established to measure evolution. The threat is mandatory by the law to be monitored.

The risk of cement degradation or bad cement may have large consequences whether

pollution of an aquifer or the presence of a gas pocket is identified.

Mechanically, the Risk of a stuck tool is possible and side track is not uncommon while

drilling.


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Table 3-28 Well Threat Risk Assessment

Threats/Risk Mitigation

Material degradation; Material yield

Corrosion program , Calliper inspection to assess deformation

Seal fails Material selection , stop process fluid in seal

Component mechanical stress

Design at Well construction phase

Cement degradation Log and proper cementing job

Corrosion - internal & external

Injection tubing 50m deeper than the free level in the well

Injection of N2 in well annuli to avoid air

Test water each month to detect trend

Scale & deposit

Stuck Tool Drilling plan and corrective action

Material threats Risk mitigation related to annuli behaviour,

Well barriers for drilling and workover operations,

Barriers on completed wells, or

Periodical tests/maintenance of surface wellhead/Xmas tree valves and subsurface safety valves should be addressed

Operational risks

Pressure and temperature are important parameters for all equipment. If brine

boils, releasing gaseous water, then there is a risk of deposition of salt, eventually

causing blockages. If the temperature is lower than the solubility equilibrium, brine

can deposit its salt and cause solid accumulation in low temperature parts. This

can be critical depending on type of process and design (ref./ 10).

Low pumping efficiencies. Optimisation of pumping system design and operation

should be a focus in order to boost efficiencies and control OPEX costs;

3.7.4.2 Surface

Corrosion Risk Assessment

The surface facilities are continuous with the wells; CO2 is the main corrosive species and

forms of CO2 corrosion are the major internal corrosion threat in the surface facilities.

Due to the nature of the surface equipment, preferential weld corrosion and galvanic

corrosion are both more significant than downhole. Enhanced corrosion due to flow

conditions is possible at several locations. The process piping, pumps and valves are

subject to similar external damage mechanisms.

Externally, the systems operate in the temperature range where, if insulated, corrosion

under insulation is a significant threat.

Geothermal waters are often highly saline, and even small leaks will create salt deposits on

the external of equipment. Combined with the temperature, this creates potential conditions

for pitting corrosion and/or chloride stress corrosion cracking of austenitic stainless steels.


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This is particularly an issue with plate heat exchangers due to the thin plate thickness and

the greater potential for leaks. The same situation applies when stainless steel equipment is

opened, for example at filter changes.

Scaling is a threat, especially after separators, and scale could affect the heat exchangers

and filters operation in particular.

Mechanical Risk Assessment

Failures may occur as a result of surface breaking cracks from a pre-existing defect or

incorrect fastener preload on steel part such as piping, valves. There are different causes of

thermal fatigue failure, for instance, general temperature cycling or localised drips of

atmospheric condensation onto hot piping.

This probability is expected to be low (equipment within the buildings, low fluid temperature

variation).

Valves are subject to the same threats as the process piping. However the underlying

cause of the valve problems can be divided into two main groups. The first group is when

there is a design fault or problem with the valve itself. The second group is when the valve

problem is due to ‘other causes’ or to progressive deterioration, such as incorrectly

installed, incorrectly specified, operating conditions have changed from the original

conditions, or a faulty operating procedure.

GRE requires more frequent piping support than steel piping. It has much less ductility than

carbon steel, and therefore is much less tolerant of poor fit-up and of thermal strains that

would be no issue with steel construction.

Separators mechanical threats are expected to be limited with suitable inspection and

design.

Typical heat exchanger risk are the accumulation of debris i.e. foreign material in plate can

lead to under deposit corrosion, leaks/cracks, leaks/seeps at flanged joints. Additional

threats may impact the heat function delivery, i.e. the production availability, without

necessary damage to the equipment. The failure of heat exchange is highly probable on

most of the current LEGE installation.

Pump casing rupture due to thermal fatigue due to frequent restarts, low ambient

temperature, high fluid temperature, insulation, operational procedures has been reported.

Only few vibration cases have been reported on Netherlands LEGE asset. Motor vibration

can occur due to misalignment of pumps (Booster and Injection) and / or dampers. These

can induce vibration in piping/welds inducing leaks. Gas content in fluid may also induce

cavitation and erosion of impellers of pumps.

Process fluid in seal may reduce lubrication, increased temperature of the seal, and

generate fatigue. Probability of fluid in seal is highly probable (several report of white salt

precipitation as a result of fluid leak at seals).

Finally, the filters are a key element of the LEGE Asset process as the debris can lead to

the cause of other threats to the system such as accumulation of debris leading to under


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deposit corrosion, leaks/cracks or leaks at the joints. Maintenance and inspection of the

filters combined with lessons learned should limit the failure of other part of the systems

due to debris.

Table 3-29 contains Threats which shall be reviewed as per above Risk Assessment of

LEGE Asset during RBI and RBM. It also proposes mitigation options than can be used in

RBI and RBM.

Table 3-29 Threats, Risk Assessment and Mitigation for Surface Equipment

Equipment Threats Mitigation Options

Corrosion

All piping and

equipment

Scaling Scale inhibitor;

pH control (controlling outgassing of CO2)

Piping CO2 Corrosion

(including preferential weld corrosion, flow assisted

corrosion)

Steel piping with corrosion allowance +

inhibitor treatment

Or GRE piping

Galvanic corrosion (to major stainless steel

equipment)

Isolation joints or flange isolation kits at key

locations

Or GRE piping ( excellent material to handle

corrosive saline water and eliminates the major

internal and external corrosion threats

Atmospheric corrosion External coating; inspection and maintenance

regime

Or GRE piping

Corrosion under insulation

Dead Leg Corrosion in piping Remove /reduce during design. Planned

access to inspect

Pipe Supports Corrosion caused by the common combination of

water and dirt accumulating in the crevice between

the pipe and support

Preventive Maintenance

All stainless

steel equipment

Internal pitting and/or Cl-SCC Operating procedures for shut-downs to avoid

exposure to hot saline water + oxygen (air)

Vessels

(separator ,

filters)

CO2 corrosion

External coating system breakdown

Stainless steel ( minimum 316 / 316L)

Pumps CO2 corrosion (flow assisted corrosion)¨

Corrosion / erosion

Stainless steel ( minimum 316 / 316L)

Heat

exchangers

(plate type)

CO2 Corrosion

Stainless steel

External pitting and/or Cl-SCC

External coating system breakdown and corrosion

(Plate and nozzles),

Flange corrosion

Higher grade stainless steel, e.g. 22Cr duplex

(e.g. UNS S31803), or 6Mo stainless steel

(e.g. UNS S31254)

Design details to minimise leaks

Instrumentation

tubing and

equipment

CO2 Corrosion

Stainless steel (316 / 316L minimum)

Crevice corrosion Avoid threaded small bore connections in

carbon steel. Use welded or flange


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connections for preference.

Chemical

treatment

equipment

Chemicals (corrosion inhibitor, scale inhibitor,

biocide)

Stainless steel (316 / 316L) and non-metallic

are standard for cleanness. Check Supplier’s

recommendations.

Note that neat chemicals (including corrosion

inhibitors) can be corrosive to carbon steel.

Filters The following are typical damage mechanisms

applying to Filters:

Internal coating breakdown.

Chloride Stress Corrosion Cracking.

Wet CO2 Corrosion.

Crevice Corrosion.

Erosion Corrosion.

External coating system breakdown.

Corrosion under insulation as a result of operating

and environmental conditions.

Leaks at the joints.

Microbiologically Induced Corrosion (MIC).

Inspection and preventive maintenance

Surface valves Atmospheric / External corrosion of uninsulated

carbon steel

Inspection and preventive maintenance

All piping and

equipment

Mechanical Fatigue - internal or external cracking of cyclically-stressed components. Failure may occur as a result of surface breaking cracks from a pre-existing defect or incorrect fastener preload etc.

Thermal Fatigue - caused by general temperature cycling or localised drips of atmospheric condensation onto hot piping,

Vibration induced Fatigue,

Mechanical hazard - pipe hit by car / truck, etc., install appropriate mechanical protection on piping,

Monitor and protect system from thermal,

vibration, and any impact

Mechanical

All piping and

equipment

Mechanical Fatigue - internal or external cracking of cyclically-stressed components : Thermal Fatigue and Vibration induced

Mitigate Mechanical hazard - pipe hit by car /

truck, etc., install appropriate mechanical

protection on piping,

GRE piping Ductility and sensitive Thermal strains The piping layout and supports should be

designed with these characteristics in mind.

Separators will

be treated as

large pressure

vessels

Accumulation of debris i.e. foreign material,

Leaks/cracks,

Structural support failure,

Leaks at the joints.

Filter debris, inspection and set up proper

support , verify

Heat Exchanger Blockage of the tubes, Flow Blockage

Leaks/cracks

Leaks/seeps at flanged joints,

External tube fretting

Daily regulation, repair procedure for failure

mode, select equipment with high reliability


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Loss of thermal power,

Closed loop fluid losses,

Contamination of "clean fluid" (i.e. secondary loop),

External tube fouling,

Reduction of U (heat transfer coefficient) value.

Surface valves Typical damage mechanisms apply to valves:

Erosion and Corrosion-Erosion - occurs

when there are high fluid flow rates, sands

or other solids present. Commonly found in

sand washing operations.

Packing damage / loosening - valves leak

through valve packing gland, damage to the

gland packing area will result, requiring

valve to be replaced or repaired.

Mechanical Fatigue - internal or external

cracking of cyclically-stressed components.

Surface breaking crack from external

surface or from a pre-existing defect

Thermal Fatigue: caused by general

temperature cycling or localised drips onto

hot valve casings.

Filtering of debris,

use the Quench,

monitor potential vibration and limit operation

condition if need

Pumps (Booster

and Injection)

Key damage mechanisms affecting the pumps:

Vibration

Erosion

Gas content in water

Fatigue

Process fluid in seal

Pump casing rupture due to hermal fatigue.

Avoid frequent restarts (usually LEGE practice

Support and operation procedure to avid

thermal change and vibration

Filters Early Damage of filters Remove debris on regularly basis

Christmas-tree and Well: Inspection, Testing & Maintenance Program

3.7.5.1 Inspection and Test

Inspection, Monitoring of operational parameters optimises well management and gives

cost-benefits by proactively identifying issues that can be addressed before they become

serious. A well monitoring and inspection plan shall be established and maintained for both

the downhole and surface components of all wells, taking into account subsurface

conditions, well operating range; well history, changes observed in other wells in the field,

ground subsidence, and well configuration.

The well monitoring plan shall specify the inspection and monitoring frequency for both

downhole and surface components. In addition to the well monitoring plan, each wellhead

shall have a documented annual inspection. Typical information to be recorded are

wellhead pressure, well status (for example, shut-in, bleed, production, injection), operating

condition and leakage of wellhead valves, condition of protective paint systems, condition of


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the anchor casing, condition of the site and cellar drainage or changes in the vertical

position of the wellhead measured relative to other casings. Compilation and upkeep of

detailed records of the above activities in a chronological log shall be kept.

Inspection and Monitoring frequencies will differ from components to component and

integrity level resulting from risk assessment (see section 3.3.5). Recommendation and

indicative frequencies for various threats and equipment items are:

Regular inspection and testing of Xmas Trees / valves to provide confirmation of the

integrity of the outer envelope of the well.

Regular scheduled collection and analysis of data to be used in predictive model

whenever possible to re-define frequencies (e.g. corrosion modelling).

Scheduled (6 or 12 months) sampling of the gas and water or any other determined

frequency based on risk assessment.

Install corrosion coupons of same material as the casing and determine corrosion

rates at set intervals.

Pressure and Temperature recording for producer and injector reinjection wells.

Recovered tubing to be inspected after retrieval to check for corrosion/scaling etc.

Wall thickness or ID measurement of the casing during any well interventions.

Regular in service valve integrity testing should be carried out on all wellhead /

Xmas tree valves at up to yearly intervals.

Frequent inspection of wellheads can give a first indication of potential corrosion

problems in the system as a whole, and an indirect pointer to problems in the well.

Inspection of the Producer and Injection well is practical; a multi-finger calliper tool

can be run in the casing string while the tubing is out. The tubing can be inspected

visually at the surface. A suggested inspection interval is approximately 5-yearly

(ref./ 9). Longer intervals may be appropriate for systems with very low CO2 and

very mildly corrosive conditions. The interval can be adjusted based on experience

or on any indication of corrosion problems from the monitoring data.

Ultrasonic inspection of wellheads at specific datum locations is recommended for

carbon / low alloy wellheads on an annual basis.

Inspection initially on an annual basis is suggested due to the criticality of the wellheads.

This frequency can be modified based on experience using a risk-based approach.

Basic Corrosion monitoring program is described in Table 3-31.

3.7.5.2 Maintenance

The wellhead is considered to be a barrier together with the production casing, the tubing


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hanger seals in the wellhead and the Xmas tree. The integrity of these barriers shall be

maintained at all times by the following means:

Weekly routine visual inspection to detect any signs of leaks or damage.

Routine valve function and pressure testing where feasible.

Routine maintenance (lubrication).

Any valve, which fails to meet the defined test requirements, must be replaced or

repaired as soon as operationally convenient.

Maintenance and testing frequency of the wellhead should reflect changes in the

equipment condition.

Although the recommended frequency is yearly, Operators can carry out a risk

assessment to justify deferring the maintenance if the valves have shown no failures

over a certain period of time.

Testing and maintenance should be carried out in accordance with Manufacturer

instructions (ref./ 9 ).

Surface Facilities : Inspection, Testing & Maintenance Program

3.7.6.1 Inspection and Test

Corrosion Monitoring basic program is discussed in section 3.7.5.1 as per ref./ 9.

Piping

Piping inspection may be divided into two categories:

External Examination: General Visual Examination of all features and Close Visual

Inspection (CVI) of accessible features will be carried out. The inspection will include pipe

supports and hangers and the integrity of flanged connections (for evidence of flange face

corrosion and nut/bolt tightness and deterioration). NDE of selected features will also be

undertaken based on the respective damage mechanism(s) for the section of piping. In

instances where there is deemed to be a threat from discrete random internal damage,

pipework screening tools should be used as large sections may be screened quickly and

where features are detected, these may be sized using more appropriate methods (such as

UT).

Internal Examination (Invasive): CVI of flanges and visible sections of pipe bore will be

carried out. A boroscope may be used to extend the coverage of inspection as appropriate.

NDE of selected pipe bore may be carried out in order to measure remaining wall

thicknesses and to determine the extent of any corrosion which may have occurred. Where

NDE is deployed, specific features such as bends, elbows, tees and welds should be

included as these areas may potentially be more vulnerable especially in high/turbulent flow

conditions.

Inspection Techniques and Frequency


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Pipework inspections should be carried out using the most appropriate inspection

technique(s) that will provide the highest likelihood of detection and quantification of the

prevailing mechanism(s) of deterioration; there are a variety of inspection methods that are

available for use however typical inspections would be expected to include any number of

the following: visual examination, borescope, UT, MPI, DPI or Radiography. The frequency

of inspections should be based on the assessed risk profile of the pipework items or

pipework systems that are in use.

Water & Gas Separator

The inspection of the separator pressure vessel will be defined generally by the RBI and

specifically by the written scheme of examination of the vessel. Particular attention will be

given to following areas: External Shell / Dome Ends, Shell Internals, Nozzles and joint

faces, Bridles, Welds, Bolting, Mounting, Paint system, Insulation and Vortex Breaker.

The inspection may comprise general and/or close visual inspection supplemented with

NDE as appropriate, although the choice of NDE method will depend on the failure threat(s)

that are prevalent in the specific system. A typical risk based scheme would comprise

invasive and non-invasive inspection cycles (where an invasive inspection would warrant

the removal of the separator vessel from service and the breaking of containment to effect

the inspection; non-invasive inspections can be performed whilst the separator is on-line

and relies on the deployment of NDE). The inspection intervals will be dependent upon

prevailing risk profile.

A typical (non-comprehensive) list of test, inspection and monitoring includes:

Corrosion probes, periodic internal inspections,

Monitoring : pressure and level transmitters

Heat Exchanger

Internal Inspection is used to establish the suitability of a heat exchanger for continued

operation. The internal inspection may involve a complete visual inspection, supplemented

by NDE techniques, on all components. Special inspection techniques may be used to

evaluate the mechanical integrity of this type of equipment, specifically the condition of the

plate.

IRIS (Internal Rotary Inspection System)

ET (Eddy Current Testing)

RFT (Remote Field Testing)

MFL (Magnetic Field Leakage)

Callipers

Temperature monitoring and control, periodic inspection (Fouling)

External Inspection – The inspection will be performed on the external surface to determine

if leaks, mechanical or structural damage is present. Generally, much of the inspection will


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be done while the heat exchanger is in service.

A typical risk based scheme would comprise of invasive and non-invasive inspection cycles

(where the terms invasive and non-invasive inspections were defined above). The

inspection intervals will be dependent upon prevailing risk profile. Evaluation of all

inspection data will be performed in strict conformance with the latest editions of API-510

Code - “Pressure Vessel Inspection, Repair, Alteration, and Reconstruction” and API RP-

579 “Fitness for Service”.

Valves on Surface

API 598 provides guidance on inspection and testing of the valves however this is written

for new valves only. There is no specific guidance available for integrity management of

operating valves.

The general practice for process valve integrity management is to set an

inspection/overhaul frequency based on risk; guidance from the OEM should also be

considered, if available. A typical inspection/overhaul will involve the removal from service,

typically during a plant shutdown or process train outage, and the stripping down/

dismantling of the valve(s) in a workshop environment.

Visual inspection and NDE is carried out on the critical components of the valve to look for

any signs of wear or deterioration. The design clearances are recorded during dismantling

and rebuilding of the valve on a workshop bench. If the recorded clearances are within the

tolerance specified by the manufacturer then the valve is rebuilt and put back in to service.

Should there be any component with significant deterioration or metal loss, the decision is

made to replace the component or replace the whole valve.

Alternatively, valves are removed from the process plant and sent to OEM for overhaul and

refurbishment. The inspection of a valve and its components may be carried out using

visual examination, borescope, UT, MPI, DPI or radiography to establish the condition. The

choice of specific technique will be based on the type of suspected damage mechanism

and may also be restricted by the access limitations. The inspection intervals will be

dependent upon prevailing risk profile.

Pumps (Booster and Injection)

The failure modes in pumps cannot all be measured directly without taking the pump out of

service and therefore secondary effects often need to be monitored instead. Once again,

operational experience can provide a useful guide to the early symptoms of failure modes.

This is an important part of Condition Based Monitoring (CBM) and it is important to have

processes in place that ensure small changes can be tracked and used to identify potential

issues in the future. Some of the most useful parameters that can be monitored on a pump

are detailed below.

Vibration e.g. check vibration of pump body, Thermography

Ultrasound, Pressure/Flow, Current, Contamination


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Visual

o Leaks (product, oil, grease), Contamination sources (dirt),

o Loose components Corrosion, Effectiveness of instrumentation, Oil level,

o Abnormal noises, Change in environment, Condition of bolts

ISO10816 Part 7 provides 4 vibration level zones specifically for roto-dynamic pumps,

according to the associated risk of continuous operation.

Filters

The inspection techniques will be similar to piping. Particular attention should be given to

the following areas.

External Shell / Dome Ends, Shell Internals, Nozzles and joint faces

Welds, Bolting, Mounting, Paint system, Insulation.

The inspection shall comprise Visual General Visual Inspection (GVI), Close Visual

Inspection (CVI), supplemented with NDE depending on the failure threat assessment as

deemed necessary. A typical risk based scheme would comprise invasive and non-invasive

inspections. The inspection intervals will be dependent upon prevailing risk profile.

3.7.6.2 Maintenance

Piping

Piping systems and pipework can fail in a number of ways. The most commonly

experienced failures are associated with either internal or external corrosion of the pipe

wall. Other failures may involve alternate metal loss mechanisms, such as erosion, fretting

or gouging. Repairs may be effected on-line using clamps or composite reinforcement

‘wrap’ systems; or alternatively may involve the replacement of the affected section of

pipework. There are a number of proprietary repair components/systems in existence,

involving both metallic and composite materials, but these systems may have certain

limitations regarding their applicability against a range of repair scenarios. There are three

main repair scenarios,

Pipe subject to external metal loss (caused by corrosion or mechanical damage),

Pipe subject to internal metal loss (caused by corrosion, erosion or

erosion/corrosion), and

Pipe components that are leaking.

In addition, the extent of the deterioration or damage (i.e. localised or extensive) will also be

considered when choosing the repair methods and repair components.

Usually the most economical repair solution will involve the replacement of the damaged

section of pipework. This may be straight forward where existing flanged connections are

available to facilitate the replacement of a section of damaged pipework. Alternatively the


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repair could simply involve welding in place a replacement section of pipe. Other repair

methods are also available (e.g. clamp, “self-seal”).

For safety critical piping systems, the adopted repair philosophy will therefore be:

Suitable temporary repair (if feasible) until replacement can be carried out;

Permanent repair where replacement is not practical.

The guidelines above generally apply to the repair of carbon steel pipework. Other metallic

pipework, such as stainless steel, duplex stainless steel, copper, nickel etc., may present

other factors for consideration (e.g. weldability, surface treatment/preparation agents for

composite materials etc.), and may be considered on a case by case basis.

Water & Gas Separator

Maintenance of the separators is mainly related to inspection, and cleaning typically carried

out once a year apart from cycling level control valves, which have a tendency to stick.

Before any repairs are made to a vessel, the applicable codes and standards under which it

is rated will be considered to assure that the method of repair does not violate appropriate

code requirements. API 510 sets forth minimum petroleum and chemical process industry

repair requirements and is recognized by several jurisdictions as the proper code for repair

or alteration of pressure vessels.

If and where defects/anomalies are detected, they will be subject to Fitness for Service

(FFS) assessment in accordance with API 579-1/ASME FFS-1, Part 9. The source of the

problem requiring the repair will also be determined. Treating the source of the condition

causing damage will, in many cases, prevent future reoccurrence. The repair solution will

be dependent on the defect type and location on the vessel.

In the event that a temporary repair is being applied whilst the vessel is in operation (such

as in the installation of composite reinforcement wrap systems), there will be no

requirement for pressure testing, as the pressure containment envelope would not have

been breached. However, if the repairs warrant the removal of the vessel from service and

the breaking of containment, this shall require leak testing to be performed on completion of

the repairs (to 1.1 x design pressure). In the event that the repair solution requires welding

to be done on the vessel, this shall require a ‘strength test’ be performed on completion of

the works (to 1.5 x design pressure); in either case (i.e. leak testing or strength testing) this

shall be performed using treated water as the test medium (i.e. hydro-testing shall be used;

pneumatic testing is permissible but only providing the appropriate additional safety

measures are undertaken).

API 510 provides additional details on pressure test requirements. ASME PTB-2-2009 may

be referred to as an additional guide for lifecycle management of the pressure vessels.

Heat Exchanger

Before any repairs are made to a heat exchanger, the applicable codes and standards

under which it is to be rated will be considered to assure that the method of repair does not


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violate appropriate requirements. API 510 sets forth minimum petroleum and chemical

process industry repair requirements and is recognized by several jurisdictions as the

proper code for repair or alteration of pressure vessels.

If and where defects/anomalies are detected, they will be subject to Fitness for Service

(FFS) assessment in accordance with API 579-1/ASME FFS-1, Part 9. The source of the

problem requiring the repair will be determined. Treating the source of the condition causing

damage will, in many cases, prevent future reoccurrence. The repair solution will be

dependent on the defect type and location on the equipment. Repairs to the heat exchanger

bundles can fall into the following categories:

Minor Repairs:

Minor weld metal build-up of gasket surfaces and machining.

Minor welding

Replacing worn or damaged part.

These minor repairs would be relatively low cost if carried out during a planned

maintenance outage. Often minor damage is not repaired but is subject to periodic

monitoring in order to ensure that the damage does not progressively worsen to the extent

that it compromises the integrity of the heat exchanger.

In the event that a temporary repair is being affected whilst the vessel is in operation, there

will be no requirement for pressure testing, as the containment envelope would not have


the breaking of containment, this shall require leak testing be performed on completion of

the repairs (to 1.1 x design pressure).

In the event that the repair solution requires welding to be done on the vessel, this shall

require a ‘strength test’ be performed on completion of the works (to 1.5 x design pressure);

in either case (i.e. leak testing or strength testing) this shall be performed using treated

water as the test medium (i.e. hydro-testing shall be used; pneumatic testing is permissible

but only providing the appropriate additional safety measures are undertaken). Whereas, if

the type of temporary repair is to be carried out that requires a shut-down of vessel and

breaking of containment, then the pressure test requirements will apply and vessel will be

pressure tested to 1.1 x design pressure.

API 510 provides additional details on pressure test requirements. ASME PTB-2-2009 may

be referred to as an additional guide for lifecycle management of the pressure vessels.

Valves on Surface

Valves should be kept in good condition through routine greasing, cycling and function

testing in alignment with valve type and OEM recommendations. The valve packing glands

(where applicable) should be checked and repacked as necessary.

Pumps (Booster and Injection)


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The general practice for pump integrity management is to set an inspection/overhaul

frequency based on the advice from the manufacturer. The pump is removed from the plant

during a shut down and the individual components are dismantled in a workshop

environment.

Visual inspection and NDE is carried out on the critical components of the pump to look for

any signs of wear or deterioration. The design clearances are recorded during dismantle

and rebuild of the pump on a workshop bench. If the recorded clearances are within the

tolerance specified by the manufacturer then the pump is rebuilt and put back to service.

Should there be any component with significant deterioration or metal loss, the decision is

made to replace the component or replace the whole pump.

The inspection of the pump and its components may be carried out using visual

examination, borescope, UT, MPI, DPI or Radiography to establish the condition. The

choice of specific technique will be based on the type of suspected damage mechanism

and may also be restricted by the access limitations. A typical risk based scheme would

comprise invasive and non-invasive inspections. The inspection intervals will be dependent

upon prevailing risk profile.

Filters

If and where defects/anomalies are detected, they will be subject to FFS assessment in

accordance with API 579-1/ASME FFS-1, Part 9. It is important that the source of the

problem requiring the repair is determined. Treating the source of the condition causing

damage will, in many cases, prevent future problems. The repair solution will be dependent

on the defect type and location on the vessel.

In the event that a temporary repair is being affected whilst the vessel is in operation, there

will be no requirement for pressure testing, as the containment envelope would not have


the breaking of containment, this shall require leak testing be performed on completion of

the repairs (to 1.1 x design pressure). In the event that the repair solution requires welding

to be done on the vessel, this shall require a ‘strength test’ be performed on completion of

the works (to 1.5 x design pressure); in either case (i.e. leak testing or strength testing) this

shall be performed using treated water as the test medium (i.e. hydro-testing shall be used;

pneumatic testing is permissible but only providing the appropriate additional safety

measures are undertaken).

ASME PTB-2-2009 may be referred to as an additional guide for lifecycle management of

the pressure vessels.

Periodic review : Integrity Assessment and Analysis

The data monitored in section 3.7.3 are used to perform daily, monthly, yearly analysis of

the Asset to define its level of integrity, i.e. Integrity Assessment.

The Periodic Review shall provide a yearly overview of the Asset Integrity. It shall assess


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and discuss the following:

Compliance with AMP with:

o Inspection, testing, monitoring & maintenance program requirements;

o Business asset management system requirements (section 3.4).

Address as a minimum, the following assessment or analysis:

o Corrosion assessments covering internal and external corrosion;

o Scale formation assessment by means of fluid composition monitoring and

Well/tubing pressure monitoring;

o Scaling Erosion assessment;

o Mechanical assessments e.g. fatigue, cracks, displacement causing

overstress, third party damage causing extreme strains, etc.

o Other Assessment (e.g. vibration or blockage).

Top 5 Risks and Threats

Recommendation for ITM&M program for the year to come and for the RBI and

RBM

Indicative Inspection, Testing & Maintenance Frequencies

The inspection intervals will be dependent upon prevailing risk profile and this will be

regularly reviewed and update as per the Integrity life Cycle process. Inspection intervals

depend on historical record, analysis of failure, reliability statistic or analysis, or any other

prediction model. Maintenance depends on supplier recommendation and historical record

based on RBM.

With regards to AMP, hereafter indicative Intervals/ Frequency are provided as guidance for

defining Long Term planning for Inspection, Testing and planning accounting for RBI and

RBM outcome (see 3.7.9).


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Table 3-30: Frequencies

Equipment Inspection Frequency Reference/ Source

DAGO Practice

Inspection

Separator Max 12 months for GVI/CVI Max one-half the remaining life of the vessel or 10 years for thickness measurement and on stream inspection

API 510 – May 2014

Pressure relieve design

Max inspection intervals for pressure-relieving devices in typical process services should not exceed: a) 5 years for typical process services, and b) 10 years for clean (non-fouling) and noncorrosive services.

API 510 – May 2014

Piping & Valves 12 months for GVI/CVI Max 48 months for Maintenance Depending

API 570 – February 2016

Wall thickness 2 time year

Booster Pump & Injection Pump

Routinely CVI (read gauges, leak, vibration etc.) Maintenance monthly/annually/by hours of service depending on parts

Typical Manufacturer specification

6 times per year

Heat Exchanger GVI DAGO Daily check

Filters Max 3 months for inspection/Maintenance Typical Manufacturer specification

Every 4 time to take a sample

1 to 4 weeks depending of filter redundancy arrangement

Producer and Injection well

approximately 5-yearly ref./ 9).

Testing

Xmas Trees / valves

6 or 12 months


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Table 3-31 Basic Corrosion Monitoring Regime/Frequencies

Technique Notes

Corrosion Monitoring

LPR corrosion probe

pH monitoring

At a convenient location in the surface piping or on a bypass loops. Ideally, real-time connection to control room. Otherwise, manual reading or download of data daily.

Acts as an alert for problems with the inhibition system.

Corrosion coupon At a convenient location in the surface piping. Typically retrieved 6-monthy.

Process measurements (pressure, flow rates ,

temperature) Standard process measurements

Sampling

Inhibitor residuals (biocide residual, scale inhibitor

residuals etc. if applicable)

Measure at commissioning of the system to set initial dose rates. Review at 6 or 12 monthly intervals.

Sampling point should be as far downstream as practical, e.g. at injection wellhead.

CO2

For systems with Separator, measure the off-gas. May be by on-line monitor or by sampling (e.g. 6-monthly). It is important that a consistent sampling location and technique is used.

LEGE Asset Practice : monthly assessment

Water chemistry

(see Appendix D)

Sampling and laboratory analysis , e.g. 6 or 12 monthly

LEGE Asset Practice : monthly

Bacteriological sampling and analysis

Only required as routine with lower salinity waters able to support microbial activity.

Monitoring of Inhibition systems

Check level of chemical in the storage tank

Record daily, confirms that inhibitor is being used, ensures re-supply on time etc.

Pumps and equipment operational

Check and record daily. On-line alerts may be used, but manual check should still be made.

Chemical dose rate Daily. Check versus target and record.

Adjust or re-set rate if necessary.

Note:

- Reference (ref./ 18) provides practical information on data gathering such as

retaining samples of fluids and contaminants, taking pairs of water samples

upstream of the separator and at the injector wellhead, a pressurized sample

from the producer wellhead, etc.


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- Note that data gathering should be designed to meet study/interpretation needs,

rather than studies having to adapt to whatever is delivered.

Long Term Historical & Planning : Inspection, Testing & Maintenance

Long term and Historical Inspection & Maintenance plan should be kept and maintained.

The document aims to provide an overview of past, present and future activities for each

equipment item. It also provides input to plan resources. Table 3-32 is a template showing

how the plan is built for piping systems. Information is provided in section 3.7.6 to build the

table for other equipment.

This plan is revised a minimum once a year during operation after the Assessment/

Analysis and Risk Assessment are performed (see 3.3.5.1). Indicative frequencies are

provided in section 3.7.8 to build the planning together with Risk Assessment, i.e. RBI and

RBM (as per section 3.3.5.2).

Table 3-32: Inspection & Maintenance Planning template

Inspection

Systems

Component or part

Description Procedure reference

M. 1 M. 2 M. 3 M. 4 M. 5 M. n

Inspection

Piping All piping General GVI Doc number S S F P P P

flanges CVI S P P

As per Assessment

findings

NDE

Piping section, Wels, etc.

Internal Examination

All piping Wall thickness

Corrosion under Isolation

NDE

Testing

Piping Internal Pressure

Maintenance

Piping all Painting

Flanges Seal

Note:

S: Done and successful; F: Done and failed; P: Planned. New Abbreviation to be

added as required.

Time line can be Month, Year, or Week depending on equipment. First two lines for

piping system are an example.

It is suggested to develop an Excel Spreadsheet to keep historical recording and

show planned activities.

Additional equipment to be added as per LEGE Asset.


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4.0 References

ref./ 1 DAGO WIM HAZID Report Final - 20-05812-001-16 –

ref./ 2 NZS 2403:2015 - Code of practice for deep geothermal wells

ref./ 3 NOGEPA, Industry Guideline No.50 Asset Integrity, revision 4.1 ; 31-001-2014

ref./ 4 EU Project REGEOCITIES; Best Practices related to regulation of Shallow

Geothermal Energy; viewed December 2013;

https://ec.europa.eu/energy/intelligent/projects/sites/iee-

projects/files/projects/documents/report_of_the_best_practices_related_to_regulation_of_s

ge_systems.pdf

ref./ 5 DNV RP F-116 Integrity management of submarine pipeline systems

ref./ 6 ISO 55000 - Asset Management - Overview, principles and terminology

ref./ 7 ISO 55001 - Asset Management - Requirements

ref./ 8 ISO 55002 - Asset Management - Guidelines

ref./ 9 DAGO, “Corrosion Review and Materials Selection for Geothermal Wells”; Wood

Group Intetech, June 2017; rev.03

ref./ 10 Report Assessment of Injectivity problems in Geothermal Greenhouses Heating

wells, funded by Kas als Energiebrom program, 5/01/2015

ref./ 11 Lead deposition in Geothermal Installations, TNO, 2014 R11416

ref./ 12 Alaref O. & Co.; Comprehensive Well integrity Solutions in Challenging

Environments using latest Technology innovations, 2016, OTC-26560-MS

ref./ 13 Drilling and Well Construction; Chapter 6, Geo-Heat Center viewed December

2016; http://www.oit.edu/docs/default-source/geoheat-center-

documents/publications/geothermal-resources/tp65.pdf?sfvrsn=2

ref./ 14 Corrosion in Dutch Geothermal Systems, TNO 2015 R10160, 2016

ref./ 15 Review of Current State of the Geothermal Industry with a focus on The

Netherlands, August 2015, MSc Thesis

ref./ 16 Geothermal Investment Guide, project deliverable 3.4; Serjujuk M. & Co; 2013;

www.geolec.eu

ref./ 17 Technology cluster Forensic Engineering; Sponsors: Aardwarmte Vogelaer BV,

AMT International BV, Geopower Holding BV, V.o.f.; Geothermie De Lier, Nature’s Heat BV

TNO reference: 060.17160

ref./ 18 TNO 2012 R10719- BIA Geothermal – TNO Umbrella Report into the Causes and

Solutions to Poor Well Performance in Dutch Geothermal Projects -2012 October

ref./ 19 Chinedu I. Ossai, Brian Boswell*, Ian J. Davies; 2014; Sustainable asset integrity

management: Strategic imperatives for economic renewable energy generation; Renewable

Energy 67 ; p 143-152

https://ec.europa.eu/energy/intelligent/projects/sites/iee-projects/files/projects/documents/report_of_the_best_practices_related_to_regulation_of_sge_systems.pdf



http://www.oit.edu/docs/default-source/geoheat-center-documents/publications/geothermal-resources/tp65.pdf?sfvrsn=2

http://www.oit.edu/docs/default-source/geoheat-center-documents/publications/geothermal-resources/tp65.pdf?sfvrsn=2

http://www.geolec.eu/


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ref./ 20 Lichti K. & Co., 2013, The Application of Risk Based Assessment to Geothermal

Energy Plant, NACE international Corrosion Conference & Expo 2013, paper 2438

ref./ 21 John Finger J., Blankenship D., 2010, Handbook of Best Practices for Geothermal

Drilling, SAND2010-6048

ref./ 22 Loizzo M., Bois, A., Etcheverry P., Linn M.; 2014; An evidence-based Approach to

Well integrity Risk Management, SPE Annual Technical Conference and Exhibition, 27-29

October, Amsterdam, The Netherlands SPE- 170867

ref./ 23 BS EN ISO 17776:2002, Petroleum and natural gas industries. Offshore production

installations. Guidance on tools and techniques for hazard identification and risk

assessment, Edition February 2001.

ref./ 24 ISO 20815:2008, Petroleum, petrochemical and natural gas industries - Production

assurance and reliability management.

ref./ 25 VDI 4640 (parts 1 to 4) in Germany

ref./ 26 VDI 4650 (parts 1 & 2) in Germany

ref./ 27 NORMBRUNN – 07 in Sweden

ref./ 28 “Geothermal heat pump borehole heat exchanger fields : guideline for design and

implementation” (BRGM and ADEME, 2012) in France

ref./ 29 Geothermal energy and heat networks. Guideline for operators (BRGM and

ADEME, 2010) - France

ref./ 30 BRL SIKB 2100: Mechanical drilling - The Netherlands

ref./ 31 BRL SIKB 11000: Design, realisation, management and maintenance of the

subsurface part of SGE systems - The Netherlands

ref./ 32 ISSO-publications 39, 72, 73, 80 en 81: For the technical implementations of the

above ground part of an SGE system - The Netherlands

ref./ 33 NEN 7120: for calculating the EPC of a building - The Netherlands

ref./ 34 API RP14E for calculating erosional velocity limits

ref./ 35 DNV RP G-101 Risk Based Inspection of Offshore Topside Static Mechanical

Equipment

ref./ 36 Data sheet GEO-process ECW , Data sheet GEO-process ECW. 27/10/2016

ref./ 37 QHSEP Risc Matrix (rev02).xlss ; provided by Dio Verbiest, DAGO Operation

Secretary, email 14/02/2018

ref./ 38 Offshore Installations and Wells (Design and Construction, etc.) Regulations 1996,

DCR – regulations 13, 15 and 16

ref./ 39 Report presenting proposals for improving the regulatory framework

for geothermal electricity - Appendix 1; Deliverable 4.1, S Fraser; 2013;


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http://www.geoelec.eu/wp-content/uploads/2011/09/D4.1-A.1-Overview-of-National-Rules-

of-Licencing.pdf

ref./ 40 Recommended Minimum Functional Specification and Standards for geothermal

Wells in the Netherlands V.5, Well Engineering Partners BV, http://wellengineering.nl/wp-

content/uploads/2012/01/Minimum-Functional-Specifications-and-Standards-for-

Geothermal-wells-v5-beveiligd.pdf, viewed January 2018.

ref./ 41 Abandonment Coast Estimation Geothermal Installation, DAGO, May 2016,

D7276R00.5608

-o0o-

http://www.geoelec.eu/wp-content/uploads/2011/09/D4.1-A.1-Overview-of-National-Rules-of-Licencing.pdf

http://www.geoelec.eu/wp-content/uploads/2011/09/D4.1-A.1-Overview-of-National-Rules-of-Licencing.pdf

http://wellengineering.nl/wp-content/uploads/2012/01/Minimum-Functional-Specifications-and-Standards-for-Geothermal-wells-v5-beveiligd.pdf




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J001916-01-PM-REP-001 | Rev 04 | April 2018 Page A-1

Methodology to develop the Asset Management Guideline


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A.1 General

The guideline has been developed on the basis of Oil & Gas standards; good practices,

general asset management standards and a web based literature review, but adapted to

suit the Dutch geothermal industry.

The guideline is aiming to provide guidance on procedures, plan, program, database,

management systems needed to ensure an optimum Asset Management. However, the

guideline is developed to keep the documentation requirements and activities to be

performed to the size of typical Dutch Geothermal Industry asset. The ALARP principle has

been followed to ensure risks are managed to a level that is as low as reasonably

practicable, including HSE risk and Security.

This guideline provides guidance on procedures, plan, program, database, and

management systems needed to ensure optimum Asset Management. The aim has been to

formulate the general requirement and principles of the ISO 55000 series, including other

standards and codes, into a more specific AM guideline.

A.2 Guideline contents rationale

Information relating to regulation are extracted from ref./ 4 . The lack of good practices in

the different European regions/countries has been identified as barriers in the geothermal

asset assessments. As stated in ref./ 18, “the lack of actual industry experience has been

often compounded by lack of understanding of non-geological technical/organisational

risks, absence of minimum or good practice standards, lack of knowledge transfer from

other subsurface knowledge areas (oil and gas industry), in terms of maximizing knowledge

flow and setting minimum standards”. The strand B report focused on making a guideline

so that Dutch Geothermal Industry can create AMP’s for their assets.

Guidance on the economical investment decisions for geothermal wells / plant is not part of

the scope. The geothermal investment guide ref./ 16 indicates that plant availability,

lifetime of the plant, competence and experience of risk mitigation are key requirements to

be addressed in the Plan. (ref./ 16). The GEOLEC Investment Guide on Geothermal

Electricity also provides background about existing technologies and analyses the factors

for the success of geothermal project, the different level of risks involved in the various

phases and the options to finance each of these phases. Though all these recommendation

do not apply to LEGE asset (no electricity, smaller Business) some points were relevant. As

a result, the guideline is including Reliability Maintainability and availability Analysis (RAM)

section. However, RAM is not mandatory when business is small and the operator and the

end user is the same owner.

Existing standards and recommended practices have been used to structure this guideline

(see Section 2.1). These standards / RP’s are typically from the Oil & Gas industries in

Norway and Netherlands. The key references are ref./ 3 , ref./ 5 , ref./ 2 , ref./ 6 , ref./

7 , and ref./ 8 . The general ISO 55000 series have been used to structure and address

the fundamentals content of an Asset Management plan & systems.

The application of the ISO 55000 series requirements has been simplified and adapted to


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Dutch Geothermal Industry business size and LEGE asset Characteristics. The asset

management system requirements described in ISO 55001 are grouped in a way that is

consistent with the fundamentals of asset management:

context of the organisation

leadership

planning

support

operation

performance evaluation

improvement

The Dutch geothermal industry does not adopt a particular ISO, API or NORSOK standard

but rather uses specific elements of these where applicable, such as defining a basis of

Design, performing a hydrocarbon risk assessment and the development of a Risk Register

(as per ISO16530) that carries through the entire well lifecycle (ref./ 9 ).

Asset Management is performed using a risked based approach. During the HAZID

preparation (ref./ 1) risk matrices were proposed based on Hazid Project stakeholders and

various operators across the Dutch Geothermal Industry. The risk matrices developed are

consistent with the guidance provided by EN ISO 17776:2002 (ref./ 23) and comprise a

summary 6x5 consequence versus probability matrix supported by five further matrices in

which consequences are rated more explicitly in terms of People, Environment, Assets,

Reputation and Social impacts. The same matrices are therefore proposed to perform any

risk assessment at different phase of the geothermal asset life and for RBI and RBM. This

is presented in ref./ 37.

Geothermal Asset Operator shall demonstrate their compliance with regulatory bodies

including HSE and demonstrate good Asset Management practice to their various

stakeholder and shareholders. QHSE section referred to QSHE program currently on going

(see Section 3.5.5).

No Information on Dutch regulation has been received at the date of issue of this report

revision from the project. However information has been taken from an EU project (ref./ 4

). Regulation, standards, and relevant EU directives are therefore discussed as they should

apply to Dutch operations.

A specific section on systems / equipment / components is included within Section 3.6 of

this guideline. The aim is to provide practical information regarding degradation threats, and

a general check list for the risk assessment methodology, i.e. risk based scenarios to

support the development of RBI and RBM programs. Based on Wood Group experience

and expertise; typical threats, inspection, testing, monitoring and maintenance requirements

are described. Similarly, specific operational philosophies and asset integrity information

are presented and further developed in the appendices. Finally, AM plan development and


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contents through the asset life cycle is also described based both on Wood Group

experiences, international standards and additional literature listed in Reference section

3.7.7.

A.3 Literature review

A brief literature review was performed related to asset management activities, including

risk document, maintenance, and deep geothermal activity in Iceland and New Zealand.

Note that literature review related to Netherland and Europe are limited.

NZS 2403:2015 - Code of practice for deep geothermal well has been reviewed for well

maintenance (ref./ 2 ) This New Zealand good practice covers the techniques and

procedures to be adopted throughout the life of a well. This includes monitoring, inspecting,

and repairing the well and wellhead components, and the production/injection well.

However, it focuses on high enthalpy geothermal assets and as such not all information are

relevant to LEGE. Wood Group Intetech report (ref./ 9 ) has been manly used to develop

Well and piping equipment IMT&M in section 3.6.

When it comes to Risk Management, Loizzo (ref./ 22) proposed to use “evidence-based

scenario” to screen out threats from check list when evidence can be shown that the threat

is not really relevant to the asset the purpose is to avoid detailed analysis. It screens out

Risk/threats from detailed analysis threats which are rare and focus on relevant possible

threats, while still identifying them. Typical example will be seismic threats.

Litchi (ref./ 20 ) recommends the use of RBI for Geothermal plant, and also refers to

pressure vessel standards for inspection AS/NZS 3788:2006 standard.

Chinedu (ref./ 19) has proposed Asset Integrity Management Framework for Renewable

Energy generation, including geothermal Asset. The procedure for sustainable asset

integrity management broadly comprises of three operations, namely, mitigation, control

and regulatory programmes in his framework as shown in Figure 9.

Figure 9 Hierarchy of elements of sustainable asset integrity management programme.


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(ref./ 19)

The article is providing interaction with stakeholders for feedback mechanism, plant

performance and Interaction of asset integrity indicators and plant management team. This

article AM framework aligns with the overall framework developed in this document. The

article concludes that implementation of the outlined strategies have “the potential to

improve the integrity of assets used in renewable energy plants due to the integrated

organisational function interfaced mitigation approach that makes fault dictation timely.

Mitigation strategies provide a holistic asset integrity performance measurement through a

systematic feedback mechanism and by weighted balancing of social, economic and

environmental KPIs”.

Chinedu further stated that “adoption of sustainable AM improvement performance

principles of control, competence, communication, coordination and compliance will not

only reduce downtime, ageing deterioration, accidents, pollution and incidents but will also

aid in improved lifecycle performance of the assets via a feedback modulated framework.

This conclusion has been used to develop the AM guideline.

Other references used to build up the guideline are listed in Reference section 3.7.7.

A list of remedial and mitigation/ activities to geothermal asset threats have been used (ref./

10 , ref./ 9 and ref./ 11 to be applied both at the design and operational phases.

Guidelines for improving well injectivity presented in ref./ 10 have been reviewed.

A.1 Asset Integrity Management Definitions

Definition related to asset management might differ slightly from standard to standard.

Therefore, for the sake of clarity, definitions are recapped hereafter; the following definitions

are extracted from standard reference in section 3.7.7. ISO 55000 1, 2 & 3 series has

mainly been used whenever relevant and available.

Asset Integrity: Ability of an asset to perform its required function effectively and efficiently

whilst protecting HSE.

Asset life: Period from asset creation to asset end-of-life.

Asset management plan: Documented information that specifies the activities, resources

and timescales required for an individual asset or a grouping of assets, to achieve the

organisation’s asset management objectives

Asset Management System: Management system for asset management which function is

to establish the Asset Management policies and objectives.

Asset Management: Coordinated activity of an organisation to realise value from assets.

Asset: Item or entity that has potential or actual value to an Organisation.

Audit: Systematic, independent and documented process for obtaining audit evidence and

evaluating it objectively to determine the extent to which the audit criteria are fulfilled.


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Incident: Unplanned event or occurrence resulting in damage or other loss.

Inspection: Appraisal involving examination, measurement, testing, gauging, and

comparison of materials or items.

Integrity: State of a system performing its intended functions without being degraded or

impaired by changes or disruptions in its internal or external environments.

Life cycle: Stages involved in the management of an asset.

Maintenance: A combination of all technical, administrative and managerial actions during

the life cycle of an item intended to retain it in, or restore it to, a state in which it can perform

the required function.

Monitoring: Determining the status of a system, a process or an activity.

Performance indicator: Monitoring and measurement of the effectiveness of Asset Integrity

Management as per SMART principle. Performance indicators can be Leading or Lagging.

Policy: Intentions and direction of an organization as formally expressed by its top

management.

Process: Set of interrelated or interacting activities which transform inputs into outputs.

RBI: Process of developing an inspection plan based on knowledge of the risk of failure of

the equipment.

RBM: Prioritizing maintenance resources towards assets carrying the most risk in case of

failure.

Reliability: Ability of a system to consistently perform its intended or required function or

mission, on demand and without degradation or failure.

SMART objectives: Goals that are characterised by being Specific, Measurable,

Assignable, Realistic and Time-related.

Supply Chain Management: Ensures that reliability, integrity, obsolescence risks and

technical risk management goals, requirements, achievements and lessons learned are

communicated between all organisations.


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J001916-01-PM-REP-001 | Rev 04 | April 2018 Page B-6

Risk Assessment Methodology & Risk Matrices


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Risk Assessment - General

A Risk Based Assessment is used to identify component degradation mechanisms,

inspection and maintenance programs. This provides assurance on the operational

integrity of the assets, with rating and review of all systems being the responsibility of the

Asset Integrity Team. Risk Assessment (RA), either qualitative and/or quantitative, are

performed to define threats to the asset and its components with regards to Integrity, HSE,

and business perspective. The objectives of the RA are:

Identify potential risk of failure or degradation for system and components.

Identify the main hazards and operability consequences.

Use relevant standard, models for assessing, which are crosschecked against real

data / experience in other operating units.

Recommend measures suitable to mitigate the threat.

Note that:

1. The RA form the basis of the Project Risk Management prior Production,

2. The RA form the basis of the Risk Based Inspection (RBI) and Risk Based

Maintenance (RBM) scheme during Production.

The risk Matrices are extracted from QHSE Framework ref./ 37.

Risk Methodology

The risk assessment study should involve the input from a multi-disciplined team, with team

members representing, at a minimum, the following groups or disciplines: Reliability

engineer, Integrity engineer, production engineer, maintenance engineer, well / reservoir

engineer.

All Life Cycle phase shall be risk assessed. It is recommended to use an “evidence-based

scenario” to screen out threats from check list when evidence can be shown that the threat

is not really relevant to the asset the purpose is to avoid detailed analysis. It screens out

Risk/threats from detailed analysis threats which are rare and focus on relevant possible

threats, while still identifying them.

Typical example will be seismic threats. This approach is recommended from Concept to

Operation phases. The purpose of the “evidence-based scenario” method is to ensure that

appropriate effort is made on each threat based on the expert judgment and inspection,

monitoring, testing and maintenance information available.

1) At Concept and Design phase, RA shall focus on identifying Risk & Opportunity related

to selection of specific equipment and specific functions required to deliver Asset

Performance. CAPEX cost and OPEX life cycle Cost and HSE Requirement to comply

with Regulation and policies shall be considered.

2) During the Operational phase, RA is performed either through RBI and RBM activities

with the objectives to use a risk based approach to address inspection and


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maintenance priorities account for risk and resource available.

Risk Assessment frequency

Good and time efficient practice is to prepare these RA and review them with relevance in a

workshop. The focus will be on key identified risks, while keeping other risks reviewed by

the risk assessment team.

Risk Assessment frequency should be performed as follows:

1) Prior to Operations, RA should be perform on a regular basis, Prior to any subcontracts

being awarded, prior to key milestones for the project

2) During Operation, RA shall be performed for unplanned anomaly and a yearly workshop

should be planned with all stakeholders as a minimum.

Quarterly / continuous review of anomalies found might be required for Critical Risk

identified for Asset Operation.

Probability of Failure (PoF) & Consequence of Failure (CoF)

Probability of failure is estimated based upon the types of damage expected to occur in a

component and is assessed utilising the design information, operating history, inspection

findings and engineering judgements based on industry experience and any other relevant

literature.

The CoF is dependent on the failure mode and physical location, where the latter is affected

by factors such as Quality, Health, Safety Technical, Environmental and Public Acceptance.

Table 4-1 Risk = CoF x PoF (Quality)


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Table 4-2 Risk = CoF x PoF (Health)

Table 4-3 Risk = CoF x PoF (Safety)


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Table 4-4 Risk = CoF x PoF (Environment)

Table 4-5 Risk = CoF x PoF (Public Acceptance)

Risk Matrix

Risk is defined as: 𝑅𝑖𝑠𝑘=𝑃𝑜𝐹 ×𝐶𝑜𝑓

For both the internal and external threats, the risk will be calculated based on the above

definition, where PoF and CoF shall be combined to give a risk rating.


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Table 4-6 Risk Matrix


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J001916-01-PM-REP-001 | Rev 04 | April 2018 Page C-1

Detailed Information on Standards


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J001916-01-PM-REP-001 | Rev 04 | April 2018 Page C-1

The good practice guidelines identified to the support and development of the LEGE sector

into the mature regions like the Netherlands are included hereafter:

Netherlands

o BRL SIKB 2100: Mechanical drilling - The Netherlands ;

o BRL SIKB 11000: Design, realisation, management and maintenance of the

subsurface part of LEGE systems - The Netherlands ;

o ISSO-publications 39, 72, 73, 80 en 81: For the technical implementations of

the above ground part of an LEGE system - The Netherlands ;

o NEN 7120: for calculating the EPC of a building - The Netherlands

API RP14E for calculating erosional velocity limits

VDI 4640 (parts 1 to 4) in Germany ; VDI 4650 (parts 1 & 2) in Germany

NORMBRUNN – 07 in Sweden

“Geothermal heat pump borehole heat exchanger fields: guideline for design and

implementation” (BRGM and ADEME, 2012) in France; Geothermal energy and

heat networks. Guideline for operators (BRGM and ADEME, 2010) - France

This list is non exhaustive.

Hereafter, general requirements from ISO 55000 series are described:

o data management;

o condition monitoring;

o risk management;

o quality management;

o environmental management;

o systems and software engineering;

o life cycle costing;

o dependability (availability, reliability, maintainability, maintenance support);

o configuration management;

o technology;

o sustainable development;

o inspection;

o non-destructive testing;

o pressure equipment;

o financial management;

o value management;

o shock and vibration;

o acoustics;

o qualification and assessment of personnel;

o project management;

o property and property management;

o facilities management;

o equipment management;

o commissioning process;

o energy management


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J001916-01-PM-REP-001 | Rev 04 | April 2018 Page D-2

Inspection, Testing, Monitoring Techniques


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This appendix describes some of the inspection, Monitoring and testing method available.

The list is non-exhaustive; the list focuses on key methods. List of element to be analysed

in Water & Gas analysis is listed at the end of this section.

Coupons (ref./ 11 and ref./ 9)

Coupons can predict the following types of corrosion when correctly placed to ensure

appropriate exposure: general corrosion, crevice corrosion, pitting, stress corrosion

cracking, embrittlement, galvanic corrosion, and metallurgical structure-related corrosion.

Monitoring with coupons is relatively simple and cheap. Coupons are small pieces of metal,

usually of a rectangular or circular shape, which are inserted in the process stream and

removed after a period of time for assessment. The most common and basic use of

coupons is to determine average corrosion rate over the period of exposure. The average

corrosion rate can easily be calculated from the weight loss, the initial surface area of the

coupon and the time exposed.

However, coupons have several limitations. An extended period of time is required to

produce useful data, and coupons can only be used to determine average corrosion rates.

Corrosion coupons can also be used to investigate the lead deposition rate and/or scaling.

It is advisable to leave a coupon exposed for at least 30 days to obtain valid corrosion rate

information, and a longer period (e.g. 6 months) is typical. There are two reasons for this

recommended practice. First, a clean coupon generally corrodes much faster than one

which has reached equilibrium with its environment. This will cause a higher corrosion rate

to be reported on the coupon than is actually being experienced on the pipe or vessel.

Second, there is an unavoidable potential for error as a result of the cleaning operation.

Another benefit of coupons is to provide information about the type of corrosion. Unlike

electrochemical probes, which only detect the corrosion rate, coupons can be examined for

evidence of scaling, pitting and other localized forms of attack.

Corrosion Probes (ref./ 9)

The major advantage of probes compared to coupons is that measurements can be

obtained on a far more frequent basis - essentially continuous. Also, readings do not

require removal of the probe.

Electrical resistance (ER) systems work by measuring the electrical resistance of a thin

metal probe. As corrosion causes metal to be removed from the probe, its resistance

increases.

Electrochemical probes consist of several individual electrodes and allow one or more

electrochemical methods to be used to measure corrosion rate. Typical methods include

Linear Polarisation Resistance (LPR), Electrochemical Noise and Electrochemical

Impedance. In favourable conditions, electrochemical probes can provide detailed and rapid

information. Electrochemical (LPR) probes are a standard technology for water systems


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generally, and are suitable for geothermal applications.

According to DAGO (2016), several operators use continuous inline measurements in the

brine flow, either in the main flow, or through a bypass with a comparable flow rate.

Measurements techniques include both LPR and ER.

Corrosion loops/bypass (ref./ 11 and ref./ 9)

A corrosion loop is a section of tubing that some of the flow is passed through a pipe

running parallel to the main piping. As the Material and piping size is similar it can more

easily be monitored on corrosion, scale or lead deposits.

Corrosion probes can be installed in the loop to provide facilities for on-line investigation of

the use of new inhibitors or process parameters.

Several Dutch operators have installed corrosion loops in collaboration with chemical

suppliers for the purposes of on-line monitoring of inhibitor performance.

In-situ inspection tools (ref./ 11 )

There is an extensive list of in-situ inspection tools called logs.

Calliper logs, also known as multi-finger callipers, measure the internal radius of the

casing in several directions by using multi-finger feeler arms of the tool. The multi-

finger calliper survey can measure anomalies only on the inner surfaces of the

tubing or casing. Output reports can provide the average wall thickness loss and

also some indication of the maximum local wall thickness loss. The Multi-Finger

Calliper may also be used to measure the build-up of scale, paraffin or other mineral

deposits in the wellbore.

Electromagnetic thickness logs are one of two available electromagnetic measuring

methods for corrosion monitoring. These logs are carried out by electromagnetic

induction tools. Electromagnetic (eddy current) logs can give information on the total

wall thickness of up to three strings, with some indication as to whether loss of

thickness is on the inner or outer strings.

Magnetic flux logs make use of magnetic flux leakage (MFL) technology to

determine the location, extent and severity of corrosion and other metal loss defects

in the inner tubular string.

Near locations of defects such as corrosion or pitting, some of the flux leaks out of

the pipe, and these leaks are detected by the tools sensor arrays.

Ultrasonic corrosion logs employ a very high transducer frequency to measure

anomalies in the tubing or casing. The emitter sends out sound waves and the

detector measures the reflected response. It is able to provide information about

casing thickness, surface condition and small defects on both internal and external

casing surfaces.

Using a gamma-ray (GR) measurement log, it is possible to detect scaling of


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radioactive material.

Corrosion Detection in well

Note that corrosion can be assessed by monitoring the production rate, pressure,

temperature, and fluid corrosivity at the well-head, and their change in time. During

shut down and maintenance of the well equipment, downhole camera and casing

integrity inspection logs can be applied to verify the degree of corrosion. However,

these latter methods are relatively expensive. On technical and financial grounds, it

is unnecessary and undesirable that they are executed on a high frequency basis.

Electrochemical noise measurements (ENM), electrochemical impedance

spectroscopy (EIS) and linear polarization resistance (LPR)

Electromagnetic technology (EM) (ref./ 12 )

The technique used is called Pulsed Eddy Current (PEC) where a short high-energy EM

pulse from a transmitter coil “charges” the surrounding concentric pipes. Immediately after

the excitation pulse, a co-located receiver coil measures the collapsing eddy currents.

Embedded within this received “decay” curve is a complex signature, which is a function of

the surrounding pipe’s geometry and EM properties. The advantage of this technique is that

the source of the problems can be located without the need to “pull the completion” as the

slim PEC tool can be run through tubing. Another application is the evaluation of surface

casing behind the cemented production string.

Cement Evaluation Using Radial Bond Log (RBL) (ref./ 12 )

“The Radial Bond Log (RBL) simultaneously evaluates the quality of cement bonding as

well as the condition and integrity of both the pipe and formation by calculating the

measurements of the cement bond amplitude through near receivers, variable density log,

and far receivers.”

“The primary use of this technology is to guarantee the integrity of the well by ensuring that

the cement is effectively placed between the casing strings and the formation. Poor cement

placement can typically result in unwanted situations such as water or gas production and

fluid migration. With RBL, it is possible to get an accurate insight into the quality of the

cement, which is extremely important, as a correct diagnosis and assessment of the

problem is essential to understanding the remedial work required for gas and water wells.”

Combining Technologies

“In many cases when an operator would like to evaluate the integrity of the well to check if it

is fit for production or injection, multiple sensors are required in order to give a complete

assessment. However, the financial aspect is an important factor when doing so”.


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Water & Gas Analysis Monitoring

Element to be analysed

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