dep-39.10.40.31

DEP SPECIFICATION

PRODUCED WATER TREATMENT AND INJECTION FACILITIES

DEP 39.01.40.31-Gen.

February 2014

ECCN EAR99

DESIGN AND ENGINEERING PRACTICE

DEM1

© 2014 Shell Group of companies All rights reserved. No part of this document may be reproduced, stored in a retrieval system, published or transmitted, in any form or by any means, without the prior

written permission of the copyright owner or Shell Global Solutions International BV.

This document contains information that is classified as EAR99 and, as a consequence, can neither be exported nor re-exported to any country which is under an embargo of the U.S. government pursuant to Part 746 of the Export Administration Regulations (15 C.F R. Part 746) nor can be made available to any national of such country. In addition, the information in this document cannot be exported nor re-exported to an end-user or for an end-use that is prohibited by Part 744 of the Export

Administration Regulations (15 C.F.R. Part 744).

Co

pyr

igh

t S

hel

l Gro

up

of

Co

mp

anie

s. N

o r

epro

du

ctio

n o

r n

etw

ork

ing

per

mit

ted

wit

ho

ut

licen

se f

rom

Sh

ell.

No

t fo

r re

sale

This document has been supplied under license by Shell to:Galfar Engineering and Contracting SAOG [email protected] 21/12/2015 06:02:19

ECCN EAR99 DEP 39.01.40.31-Gen. February 2014

PREFACE

DEP (Design and Engineering Practice) publications reflect the views, at the time of publication, of Shell Global Solutions International B.V. (Shell GSI) and, in some cases, of other Shell Companies.

These views are based on the experience acquired during involvement with the design, construction, operation and maintenance of processing units and facilities. Where deemed appropriate DEPs are based on, or reference international, regional, national and industry standards.

The objective is to set the standard for good design and engineering practice to be applied by Shell companies in oil and gas production, oil refining, gas handling, gasification, chemical processing, or any other such facility, and thereby to help achieve maximum technical and economic benefit from standardization.

The information set forth in these publications is provided to Shell companies for their consideration and decision to implement. This is of particular importance where DEPs may not cover every requirement or diversity of condition at each locality. The system of DEPs is expected to be sufficiently flexible to allow individual Operating Units to adapt the information set forth in DEPs to their own environment and requirements.

When Contractors or Manufacturers/Suppliers use DEPs, they shall be solely responsible for such use, including the quality of their work and the attainment of the required design and engineering standards. In particular, for those requirements not specifically covered, the Principal will typically expect them to follow those design and engineering practices that will achieve at least the same level of integrity as reflected in the DEPs. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from his own respons bility, consult the Principal.

The right to obtain and to use DEPs is restricted, and is typically granted by Shell GSI (and in some cases by other Shell Companies) under a Service Agreement or a License Agreement. This right is granted primarily to Shell companies and other companies receiving technical advice and services from Shell GSI or another Shell Company. Consequently, three categories of users of DEPs can be distinguished:

1) Operating Units having a Service Agreement with Shell GSI or another Shell Company. The use of DEPs by these Operating Units is subject in all respects to the terms and conditions of the relevant Service Agreement.

2) Other parties who are authorised to use DEPs subject to appropriate contractual arrangements (whether as part of a Service Agreement or otherwise).

3) Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) or 2) which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said users comply with the relevant standards.

Subject to any particular terms and conditions as may be set forth in specific agreements with users, Shell GSI disclaims any liability of whatsoever nature for any damage (including injury or death) suffered by any company or person whomsoever as a result of or in connection with the use, application or implementation of any DEP, combination of DEPs or any part thereof, even if it is wholly or partly caused by negligence on the part of Shell GSI or other Shell Company. The benefit of this disclaimer shall inure in all respects to Shell GSI and/or any Shell Company, or companies affiliated to these companies, that may issue DEPs or advise or require the use of DEPs.

Without prejudice to any specific terms in respect of confidentiality under relevant contractual arrangements, DEPs shall not, without the prior written consent of Shell GSI, be disclosed by users to any company or person whomsoever and the DEPs shall be used exclusively for the purpose for which they have been provided to the user. They shall be returned after use, including any copies which shall only be made by users with the express prior written consent of Shell GSI. The copyright of DEPs vests in Shell Group of companies. Users shall arrange for DEPs to be held in safe custody and Shell GSI may at any time require information satisfactory to them in order to ascertain how users implement this requirement.

All administrative queries should be directed to the DEP Administrator in Shell GSI.



TABLE OF CONTENTS

1. INTRODUCTION ........................................................................................................ 4 1.1 SCOPE ........................................................................................................................ 4 1.2 DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS ......... 5 1.3 DEFINITIONS ............................................................................................................. 5 1.4 CROSS-REFERENCES ............................................................................................. 6 1.5 SUMMARY OF MAIN CHANGES ............................................................................... 6 1.6 COMMENTS ON THIS DEP ....................................................................................... 6 1.7 NON NORMATIVE TEXT (COMMENTARY) .............................................................. 6

2. RESERVOIR REQUIREMENTS FOR PRODUCED WATER BASED WATERFLOOD AND WELL DISPOSAL ................................................................... 7

2.1 BACKGROUND .......................................................................................................... 7 2.2 INJECTIVITY IMPAIRMENT AND FORMATION INTEGRITY ................................... 7 2.3 SCALING .................................................................................................................... 7 2.4 RESERVOIR SOURING ............................................................................................. 7

3. BASIS FOR WATERFLOOD, WATER DISPOSAL AND SURFACE DISCHARGE TO SEA DESIGN ................................................................................. 8

3.1 GENERAL ................................................................................................................... 8 3.2 WATER INJECTION VOLUME ................................................................................... 9 3.3 PRODUCED WATER FORECAST ............................................................................. 9 3.4 NUMBER AND GEOGRAPHICAL LOCATION OF INJECTION WELLS ................... 9 3.5 INJECTION PRESSURE .......................................................................................... 10 3.6 PRODUCT WATER QUALITY .................................................................................. 10 3.7 CHARACTERISTICS OF FEED WATER ................................................................. 11 3.8 EXPANDABILITY ...................................................................................................... 13

4. SURFACE FACILTIES FOR CONVENTIONAL PRODUCED WATER TREATMENT ............................................................................................................ 13

4.1 GENERAL ................................................................................................................. 13 4.2 DESIGN CONSIDERATIONS FOR SURFACE DISCHARGE TO SEA ................... 15 4.3 DESIGN CONSIDERATIONS FOR PWRI AND WELL DISPOSAL ......................... 22 4.4 GENERIC DESIGN CONSIDERATIONS ................................................................. 27

5. REFERENCES ......................................................................................................... 35

APPENDICES

APPENDIX A OPTIONS TABLE GAS/CONDENSATE FIELD PRODUCED WATER TREATMENT PROCESSING ......................................................................... 36

APPENDIX B OPTIONS TABLE OIL ONSHORE FIELD PRODUCED WATER TREATMENT PROCESSING ......................................................................... 37

APPENDIX C OPTIONS TABLE OIL OFFSHORE FIELD PRODUCED WATER TREATMENT PROCESSING ......................................................................... 38



1. INTRODUCTION

1.1 SCOPE

This new DEP specifies requirements and gives recommendations for the design of produced water treatment system (surface facilities) for:

Produced water re-injection • Waterflood projects where produced water is used as the water source

• For both onshore and offshore application

Well disposal • Produced water well disposal in non-producing reservoir or aquifer

• Both onshore and offshore

Surface discharge to sea • Surface disposal to sea of produced water

The produced water treatment system boundary starts at the produced water outlet of the bulk separation equipment and stops at last treatment step in the produced water system, including associated water quality monitoring.

The scope of this DEP also covers:

• The impact of bulk separation of the well fluids on the produced water treatment system

• Discharge to sea and produced water injection pumps design aspects.

The scope of this DEP does not cover well design.

This DEP relates to conventional produced water treatment, well fluids (oil and water) from oil operations with use of conventional chemicals within normal limits, i.e. excludes EOR chemicals.

The scope of equipment covered includes produced water treatment facilities for:

• solids removal from the produced water

• dispersed oil removal from the produced water

• degassing of the produced water

• dissolved hydrocarbon removal from the produced water

This DEP consolidates the applicable content of the following documents, which are replaced in part by this DEP and other documents:

• EP 2007-5475, Waterflood Manual, Chapter 6: Surface Facilities

• Deoiling manual

The DEP scope excludes:

• Disposal of produced water inshore (rivers, reed beds and evaporation ponds)

• Subsea produced water treatment

For seawater based waterflood reference is made to DEP 39.01.40.30-Gen.

The DEP addresses the selection of technology alternatives within the produced water system configuration. It also specifies the minimum technical requirements for the technology selected within the configuration. Detailed mechanical and process equipment design requirements to meet the functional requirements herein are beyond the scope of this DEP.



This DEP contains mandatory requirements to mitigate process safety risks in accordance with Design Engineering Manual (DEM) 1 – Application of Technical Standards.

1.2 DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS

Unless otherwise authorised by Shell GSI, the distribution of this DEP is confined to Shell companies and, where necessary, to Contractors and Manufacturers/Suppliers nominated by them. Any authorised access to DEPs does not for that reason constitute an authorisation to any documents, data or information to which the DEPs may refer.

This DEP is intended for use in facilities related to exploration and production facilities. This DEP may also be applied in other similar facilities.

When DEPs are applied, a Management of Change (MOC) process shall be implemented; this is of particular importance when existing facilities are to be modified.

If national and/or local regulations exist in which some of the requirements could be more stringent than in this DEP, the Contractor shall determine by careful scrutiny which of the requirements are the more stringent and which combination of requirements will be acceptable with regards to the safety, environmental, economic and legal aspects. In all cases, the Contractor shall inform the Principal of any deviation from the requirements of this DEP which is considered to be necessary in order to comply with national and/or local regulations. The Principal may then negotiate with the Authorities concerned, the objective being to obtain agreement to follow this DEP as closely as possible.

1.3 DEFINITIONS

1.3.1 General definitions

The Contractor is the party that carries out all or part of the design, engineering, procurement, construction, commissioning or management of a project or operation of a facility. The Principal may undertake all or part of the duties of the Contractor.

The Manufacturer/Supplier is the party that manufactures or supplies equipment and services to perform the duties specified by the Contractor.

The Principal is the party that initiates the project and ultimately pays for it. The Principal may also include an agent or consultant authorised to act for, and on behalf of, the Principal.

The word shall indicates a requirement.

The capitalised term SHALL [PS] indicates a process safety requirement.

The word should indicates a recommendation.

1.3.2 Specific definitions

Term Definition

Waterflood Waterflood is a method of recovery in which water is injected into the reservoir to displace additional oil and/or to help maintain reservoir pressure.

Well disposal

Well disposal is a method in which produced water is injected into a non-producing reservoir or aquifer with the aim to dispose produced water

1.3.3 Abbreviations

Term Definition

BTEX Benzene, Toluene, Ethylbenzene, Xylene

EOR Enhanced Oil Recovery

IGF Induced Gas Flotation

IOR Improved Oil Recovery



Term Definition

LAT Lowest Astronomical Tide

MPPE Macro Porous Polymer Extraction

NPD Naphthalene, Phenanthrene, Dibenzothiophene

NPSH Net Positive Suction Head

OIW Oil in Water

PAH Polyaromatic Hydrocarbons

PW Produced Water

PWRI Produced Water Re-injection

RAM Reliability, Availability and Maintenance

SRB Sulphate Reducing Bacteria

1.4 CROSS-REFERENCES

Where cross-references to other parts of this DEP are made, the referenced section or clause number is shown in brackets ( ). Other documents referenced by this DEP are listed in (5).

1.5 SUMMARY OF MAIN CHANGES

This is a new DEP.

1.6 COMMENTS ON THIS DEP

Comments on this DEP may be submitted to the Administrator using one of the following options:

Shell DEPs Online

(Users with access to Shell DEPs Online)

Enter the Shell DEPs Online system at https://www.shelldeps.com

Select a DEP and then go to the details screen for that DEP.

Click on the “Give feedback” link, fill in the online form and submit.

DEP Feedback System (Users with access to Shell Wide Web)

Enter comments directly in the DEP Feedback System which is accessible from the Technical Standards Portal http://sww.shell.com/standards.

Select “Submit DEP Feedback”, fill in the online form and submit.

DEP Standard Form (Other users)

Use DEP Standard Form 00.00.05.80-Gen. to record feedback and email the form to the Administrator at [email protected].

Feedback that has been registered in the DEP Feedback System by using one of the above options will be reviewed by the DEP Custodian for potential improvements to the DEP.

1.7 NON NORMATIVE TEXT (COMMENTARY)

Text shown in italic style in this DEP indicates text that is non-normative and is provided as explanation or background information only.

Non-normative text is normally indented slightly to the right of the relevant DEP clause.


https://www.shelldeps.com/

http://sww.shell.com/standards

mailto:[email protected]


2. RESERVOIR REQUIREMENTS FOR PRODUCED WATER BASED WATERFLOOD AND WELL DISPOSAL

2.1 BACKGROUND

When defining the design basis for produced water waterflood and produced water well disposal, a number of aspects need to be addressed by specific studies; impairment and formation integrity, compatibility (scaling) and reservoir souring.

Produced water discharge to sea does not result in any reservoir impact and is not covered by this section. Scaling assessments related to a produced water discharge to sea scheme are conducted as part of mandatory flow assurance assessments without any specific considerations due to produced water re-injection or well disposal.

These general assessments will have a direct impact on the system design, specifically equipment selection and production chemicals.

2.2 INJECTIVITY IMPAIRMENT AND FORMATION INTEGRITY

The sustainable reservoir injectivity is not only dependent on reservoir properties, but also on the specific characteristics of the injected produced water.

1. As a minimum, definition shall be provided on the following injected water characteristics:

a. Suspended solids levels and size distribution in the injected water

b. Dispersed oil-in-water levels in the injected water

c. Type of solids (Scale, sand, silt and/or schmoo)

d. Temperature of the injected water at the injection well

e. Rock fluid compatibility resulting in scaling (2.3), clay swelling and fines migration.

2. The Reservoir Engineer shall determine sustainable well injectivity flow rates into a reservoir as a function of the characteristics of the injected water.

2.3 SCALING

Produced water reinjection and well disposal related scaling issues are:

• Self scaling potential of the injected water

• Scaling due to incompatibility of the injected water with the formation water

• Self scaling potential of the produced fluids following water breakthrough

• Scaling potential due to incompatibility of produced water with other water sources for water flood (seawater, aquifer water, etc.)

1. The Production Chemist/Flow Assurance Engineer shall conduct a standard scaling assessment to identify scaling potential and severity of scaling.

2. Options to mitigate and/or control scaling shall be defined.

3. The scaling control strategy shall be decided upon by the project team, based on a lifecycle cost and risk evaluation for the applicable project conditions.

2.4 RESERVOIR SOURING

Produced water based water flood and well disposal can result in reservoir souring.

1. The Souring Potential Assessment, see DEP 25.80.10.18-Gen., shall be executed to identify if any reservoir souring is expected.



2. When the Souring Potential Assessment concludes that there is a risk of reservoir souring, the Production Chemist (Souring Expert) shall predict the H2S concentration in the reservoir and the produced well fluids as a function of time.

3. Options to mitigate and/or control reservoir souring shall be defined.

4. In case nitrate injection into the injected water is selected for souring control, the corrosion assessment shall consider the increased corrosion risk of the injection system.

5. The souring control strategy shall be decided upon by the project team, based on a lifecycle cost evaluation for the applicable project conditions.

3. BASIS FOR WATERFLOOD, WATER DISPOSAL AND SURFACE DISCHARGE TO SEA DESIGN

3.1 GENERAL

1. The basic input data listed in Table 1 shall be specified as a function of the produced water destination.

This data is required for the design for the produced water system.

For some projects a mix of produced water destinations may be appropriate resulting in multiple design cases.

Table 1 Basic input data required for design of produced water system

Design requirement

Produced water destination

Produced water re-injection

Well disposal Surface discharge to sea

Water injection volume

√ √ Note 2

Not applicable

Produced water forecast

√ √ √

Number and location of injection wells

√ √ Not applicable

Injection pressure √ √ Not applicable

Water quality (Note 1)

√ √ √

Design life/ Expandability

√ √ √

NOTES: 1. Including disposal temperature

2. Water injection volume for disposal may be limited by non-producing reservoir or aquifer maximum pressure

Produced water re-injection and well disposal

2. The basic input data shall be specified by the Reservoir Engineer and Production Technologist.

3. The Environmental Engineer shall specify additional produced water quality requirements as applicable.

Legislation may set additional quality requirements for produced water re-injection or well disposal.

4. In case the basic input data does not provide a limit for dispersed oil-in-water content, the oil-in-water specification on which the produced water treatment system is



designed shall be defined by the Concept Engineer based on cost/benefit analysis of additional oil recovered.

5. When multiple cases are defined by the Reservoir Engineer, which may include (sea) water as source water, an integrated subsurface-surface-wells assessment shall compare these cases and select the optimum concept. The integrated assessment shall as a minimum address economic parameters (cost, production and schedule), operability and quantified risks.

Produced water surface discharge to sea

6. Basic data related to water quality for produced water surface discharged to sea, shall be specified by the Environmental Engineer.

This is generally covered by legislation and/or Specification for Discharge to Water Minimum Requirements) as defined in the Shell HSSE & SP Control Framework HSSE Environment Manual.

3.2 WATER INJECTION VOLUME

1. The required system availability, on an annual basis, and the contribution of other streams such as alternative water sources for water flood (e.g., seawater, aquifer water, etc., and reject streams), shall be taken into account in the waterflood design basis.

2. A RAM study, taking into account the specific availability issues associated with all elements in the produced water treatment and alternative water source treatment and injection system including the sparing of critical elements, shall be documented to assess the availability for a given injection system. The RAM study shall:

a. utilize specific analogue data where available;

b. consider constraints imposed on the water injection volume due to incompatibility of the various produced water streams and/or alternative water streams in the injection systems as well as the reservoir.

3.3 PRODUCED WATER FORECAST

The produced water forecast for a reservoir, or field is dependent on specific reservoir characteristics that at the onset of a design are uncertain. The uncertainty associated with these parameters could result in large variations in the produced water forecast, particularly in terms of the onset and rate of increase of produced water.

The produced water forecast in case of produced water re-injection is directly affected by the selected recovery mechanism which is directly impacted by the water quality of the injected water.

1. The produced water forecast(s) shall consider the impact of these uncertainties, the selected recovery mechanism and the water quality.

3.4 NUMBER AND GEOGRAPHICAL LOCATION OF INJECTION WELLS

The number and geographical location of injection wells, in combination with the injection pressure, is relevant for the design of the injection pumps and the distribution piping network.

1. Special consideration shall be given to ensure a good balance in the injected volumes over the different injection wells, especially for water flood operations.

2. The injected water flow rate in each well shall be controlled. The allocated volume of water injected into a well shall be recorded by appropriate metering.



3.5 INJECTION PRESSURE

The injection pressure is defined by the injection regime, and in case of fractured injected, by the maximum allowable fracture growth.

1. The minimum required injection pressure over the design life, as well as the maximum allowable injection pressure, shall be defined by the Production Technologist.

3.6 PRODUCT WATER QUALITY

1. Specification of the injected or discharged produced water quality shall, as a minimum, include the parameters listed in Table 2.

Table 2 Produced water quality specification parameters

Parameter Specification Produced water destination


Well disposal Surface discharge to sea

Suspended Solids

Maximum level √ M(ppmv) √ M (ppmv) √ P (mg/l)

Size distribution

√ M Not applicable Note 4

Not applicable

Dispersed oil-in- water

Maximum level √ M (ppmv) √ M (ppmv) √ M (mg/l)

Dissolved HC Maximum level Not applicable Not applicable √ P Note 2

Temperature Maximum Not applicable Not applicable √ P

Minimum √ √ Not applicable

Chemicals Maximum level √ P Note 1

√ P Note 1

√ P

Ionic composition Note 3

Maximum level √ P Not applicable Note 4

√ P

Minimum level √ P Not applicable Note 4

Not applicable

√ P = possible requirement

√ M= mandatory requirement

NOTES: 1. Legislation may set requirements for maximum level of production chemicals injected into reservoirs and aquifers.

2: For surface discharge to sea, the requirement for specification of dissolved hydrocarbon content depends on the legislation. Typically, methods described by the legislation for OIW analysis do not discriminate between dispersed and dissolved hydrocarbons.

3. For specific ions

4. Assumes well disposal is under fracture conditions.

2. The water quality requirements shall be defined including tolerable excursions (including duration) of specific parameters.

The water quality specification for produced water re-injection and well disposal of produced water is defined by the Production Technologist at the entrance of the reservoir.

3. The Concept Engineer shall assess impact of distribution and injection system downstream of the last treatment step on the water quality.



3.7 CHARACTERISTICS OF FEED WATER

The design of the produced water treatment system is determined by the characterisation of the produced water feed streams, well fluids and the process flow scheme.

Over the field life, the well fluids characteristics and more specifically the produced water characteristics may change as a result of:

• injected water breakthrough

• injected gas breakthrough

• change in reservoir pressure

• change in reservoir temperature

In addition certain non-routine operations, such as well clean-up, may result in temporary excursions of the “normal” produced water characteristics.

1. An appropriate water quality characterisation shall be done prior to selection of any equipment.

2. The Concept Engineer shall define the characteristics of the various produced water streams.

3. The Production Chemistry discipline shall be involved in defining the sampling, analysis and interpretation of the analysis.

4. Droplet size distribution analysis prepared and analysed in laboratory based on mimicking the actual operating conditions should only be used for relative comparison between the various cases analyzed and should not be interpreted as the actual droplet size distribution for a specific condition evaluated. Creating a representative droplet size distribution in the laboratory is very hard, if not impossible.

5. At a minimum, the characteristics listed in Table 3 shall be defined.

6. The potential variation as a result of the chosen recovery scheme shall be taken into account in the characterisation of produced water streams.

7. The uncertainty associated with key produced water characteristics shall be considered to ensure that robust produced water treatment system is selected.

Table 3 Minimum characteristics of produced water feed streams to design produced water treatment

Category Characteristics Produced water destination Comment


Well disposal

Surface discharge to sea

Well fluids Dispersed oil density and viscosity

√ √ √ Direct impact on bulk separation and hydrocarbon dehydration equipment performance

Produced water

Dispersed oil-in-water concentration

√ √ √ Defined as a range. For Greenfield calculated based on equipment performance, or analogues.



Category Characteristics Produced water destination Comment


Well disposal


Dispersed oil droplet size distribution

√ √ √ For Greenfield calculated droplet size distribution based on system performance

Dispersed oil density and viscosity

√ √ √ Direct impact on bulk separation and hydrocarbon dehydration equipment performance

Dissolved hydrocarbon-in-water concentration

Not a minimum requirement

Not a minimum requirement

√ Note 1

Anions and cations concentration

√ √ √ Including density, hardness and alkalinity Note 2

Dissolved gases √ √ √ O2, H2S, CO2. Based on process conditions

Suspended solids concentration

√ √ √ For Greenfield Development analogue data. Other developments actual measurement, including particle size distribution

Particle size distribution

√ √ √

Operations and design

Treatment chemicals and dosage rate

√ √ √ Hydrate inhibitor, corrosion inhibitor, scale inhibitor, demulsifiers, etc.

Processing scheme

√ √ √ Overview of complete process flow scheme, including flow rate, operating pressure and temperature

NOTES: 1. When required by legislation

2: Produced water properties can make a step change upon injected water breakthrough, when the injected water is considerably different in salinity than formation water.



3.8 EXPANDABILITY

There are many uncertainties in the reservoir and the processing of the well fluids that have an impact on produced water forecast, the characterisation of produced water streams and/or the achieved water quality.

These uncertainties include:

• Subsurface uncertainties affecting produced water forecast, well fluids/produced water streams characterisation and injected water quality specifications

• Performance of processing equipment

• Changed legislation resulting in more stringent water quality specifications

1. The design of the produced water systems shall consider the above uncertainties.

2. The requirement for future capacity expansion and additional treatment equipment shall be considered as part of the initial design. See also see DEP 00.00.07.10-Gen.

3. Special attention shall be given to the impact of potential future EOR and IOR strategies.

4. Active interaction between subsurface disciplines and the Concept Engineer is required to understand the possible future EOR and IOR strategies.

5. The impact of these strategies on the system design shall be considered. The outcome of such an assessment may be to:

a. Design the produced water facilities such that facilities are designed for future EOR or IOR strategies,

b. Design the produced water system that produced water system can be easily expanded for EOR and IOR strategies,

c. Discard the impact of the potential EOR and IOR strategies.

4. SURFACE FACILTIES FOR CONVENTIONAL PRODUCED WATER TREATMENT

4.1 GENERAL

1. The produced water treatment system shall be designed according to the following principles:

a. Meet the required water quality

b. Consider all produced water streams, including secondary streams

c. Consider the impact of start-up, maintenance, non-routine operations and possible process upsets.

d. Based on equipment that is classified as proven for the specific application.

e. The surface facilities for treating produced water shall be considered as part of an overall production process to ensure that performance of the water treatment system has been optimised and is effectively integrated.

f. Specific focus shall be given to:

i. Bulk separation of liquid hydrocarbon and water phase at highest possible pressure

ii. Maximise oil droplet size

iii. Minimise remaining hydrocarbons in water in production separators

iv. Design for constant and stable feed streams to produced water treatment equipment



v. Careful consideration of the effect of recycle streams and minimise recycle streams

vi. Segregate treatment for different water streams

vii. Impact of production chemicals injected on water treatment systems

viii. Achieve water quality with minimum use of chemicals

g. Robust against equipment not performing according to theoretical performance.

2. The Concept Engineer shall provide justification for the selected process line-up, which shall include evaluation of alternative equipment as identified in the option tables in the appendices and consideration of the above listed principles.

a. The process line-ups presented in (4.2) and (4.3) serve as a starting point.

b. In the Assess Phase these line-ups should be tailored (i.e. number of treatment steps) to the water specification and the expected difficulty of the produced water to be treated.

i. These tailored line-ups, without detailed evaluation of alternatives, may provide sufficient definition in the Assess Phase of an opportunity.

ii. For specific opportunities where technical feasibility related to the achievable produced water specification has to assessed, more analysis may be required.

The process line-ups present in general the most comprehensive line-up, i.e. maximum number of treatment steps and equipment that would normally be required for the treatment of produced water to achieve a stringent specification in most fields.

Optional equipment that should be deleted when the specification is less stringent, or when feed water characteristics are favourable, is identified with the dotted bypasses in the process line-ups.

Optional equipment that should be included when the produced water characterisation results in complicated water treatment or the specification is more stringent is also indicated with dotted lines in the process line-ups.

The process line-ups and associated option tables included in the appendices are based on deployable, or proven, technologies/equipment according to the Shell definition.

3. Equipment classed as new technology shall be managed through the Principal’s development release procedures. In Shell, the Water Management group in IRD (PTI/WF) shall be consulted.

4. For some fields, sand production from the reservoir(s) may be such that desanding equipment is required on the total well fluid upstream. Desanding equipment shall be specified where required.

This may be the case when sand screens are not installed downhole to allow higher well rates.

5. Sand production shall be discussed and evaluated between subsurface and surface discipline engineers to ensure that all have an appreciation of the system as a whole and the overall advantages/disadvantages are determined and agreed. Installation of sand removal equipment at or near the wellheads or as part of the bulk separation may be justified.

The consequences of large amounts of sand production will be deposition in equipment and possibly flow lines, decreasing capacity and necessitating regular removal operations (water flushing of separators, shutdown of dehydration tanks to dig out the sand) that will affect the quality of the water to be treated.



Table 4 provides an overview of the process line-ups presented in (4.2) and (4.3).

Table 4 Overview of line-ups presented and criteria used to discriminate line-ups

Hydrocarbon type

Location Produced water destination

Process line-up number

Section

Gas/condensate Onshore and Offshore

Well disposal 4 4.3.1


1 4.2.1

Oil Onshore PWRI and well disposal

5 4.3.2


2 4.2.2

Offshore PWRI and well disposal

6 4.3.3


3 4.2.3

4.2 DESIGN CONSIDERATIONS FOR SURFACE DISCHARGE TO SEA

4.2.1 Gas/condensate on- and offshore process line-up

The process line-up for a gas/condensate field where the produced water is discharged to sea is shown in Figure 1.

Figure 1 Process line-up for a gas/condensate field produced water surface discharge to sea (line-up #1)

NOTE 1: Destination of liquid/liquid hydrocyclones reject and skimmed-off condensate in degasser to be decided on a case-by-case basis.

Condensate & Residual Emulsion

Gas/liquid separator

Liquid/liquid separator

Surface Disposal (WOB)

Condensate Treatment to Export Specs

MPPELiquid/liquid

hydro -cyclones

Degasser (skimmer)

Gas

Solid and Oily Waste Handling

Reverse demulsifier(if required)

Demulsifier(if required)

Biocide

Note 1 Note 1

Well fluids or condensate/water stream

Gas

Condensate

Produced water

Solids and oily waste

Chemical

Induced Gas

Flotation

Flocculant &Coagulant

(if required)



An options table, that provides an overview of alternative solutions for the processing steps of a gas/condensate field, is presented in (Appendix A) for general reference.

4.2.1.1 Gas/liquid separator

1. The well fluids shall be separated into gas and liquid (condensate/water streams).

2. For most gas/condensate fields the well fluid separation requires a vertical Gas/Liquid Separator in combination with a horizontal Liquid/Liquid Separator.

3. At relatively low gas/liquid ratios, the functionality of the Gas/Liquid Separator and Liquid/Liquid Separator may be integrated into a Gas/Liquid/Liquid Separator. For selection criteria, reference is made to DEP 31.22.05.12-Gen.

4. The Gas/Liquid Separator shall be designed in accordance with DEP 31.22.05.11-Gen.

5. The liquids separated in the Gas/Liquid Separator shall flow under gravity to the Liquid/Liquid Separator.

6. The level control valves at the condensate and water outlet of the Liquid/Liquid Separator shall control the level in the Gas/Liquid Separator.

7. The level control design in combination with the slug allowance in the Gas/Liquid Separator shall ensure that the maximum liquid flow rate into the Liquid/Liquid Separator is within the nameplate capacity.

4.2.1.2 Liquid/liquid separator

The Liquid/Liquid Separator separates the liquid stream of the Gas/Liquid Separator in a condensate and a water stream.

1. The Liquid/liquid Separator shall be designed as a horizontal two phase settler with plate pack provided the fouling tendency of the well fluids is acceptable.

2. The Liquid/Liquid Separator shall be designed in accordance with DEP 31.22.05.12-Gen., which also defines the selection criteria between an open two phase settler and horizontal two phase settler with plate pack.

4.2.1.3 Liquid/liquid hydrocyclones

1. Liquid/Liquid Hydrocylones shall be included in the produced water treatment scheme when normal gravity separation does not achieve the required inlet specification for the Degasser/Induced Gas Flotation.

An example is when the Liquid/Liquid Separator is designed as a horizontal open two phase settler or when the water stream is difficult to treat (heavily emulsified). Preference is to design the Liquid/Liquid Separator as horizontal two-phase settler with plate pack.

2. When the produced water stream mean volume droplet size is less than 10 microns even a Liquid/Liquid Hydrocyclone will not function and alternatives shall be considered.

3. When hydrocyclones are required to meet the treated water specification, the feed to the hydrocyclones shall be taken directly from the Liquid/liquid Separator.

4. The level control valve on the water outlet of the Liquid/Liquid Separator shall be downstream of the hydrocyclones. A dedicated hydrocylcone shall be deployed on the produced water stream of each separator.

5. The system design shall consider the reduction in operating pressure in the Gas/Liquid Separator as a result of the implementation of depletion compression.

The hydrocyclones reject streams are generally routed back to the process.

6. The optimum location for routing the reject stream shall be selected based on the project specifics for condensate treatment.



7. Consideration shall be given to:

a. Route reject stream to a dedicated collection vessel, or the closed drains system, and pump liquids back to upstream the gas/liquid separator

b. Route reject stream to a dedicated collection vessel, or the closed drains system, and pump liquids back to the condensate treatment system

c. Free-flow the reject stream to the condensate treatment system.

8. Specific treatment of the reject stream, by means of a disc stack centrifuge should be considered.

4.2.1.4 Degasser (skimmer)

1. A Degasser (skimmer) shall be included in the produced water treatment system to flash-off any dissolved gas that is remaining in the produced water before the produced water is disposed to surface and to protect the downstream IGF from excess oil and/or surges in the produced water stream.

The off-gas from the degasser is typically routed to the LP vent/flare system, hence operating slightly above atmospheric pressure.

2. The Degasser (skimmer) shall be designed to enhance skimming of dispersed condensate by means of the floatation effect of the dissolved gas.

3. The Degasser (skimmer) shall be equipped with internals enhancing the deoiling of the produced water, i.e. sparger system inlet device and plate pack.

4. The degasser shall be designed to allow skimming of free condensate separated in the degasser.

5. The skimmed condensate shall be routed to the closed drains system or slops tank from where the skimmed condensate shall be pumped into the process again, either upstream the gas/liquid separator, or to the condensate treatment system.

4.2.1.5 Horizontal multistage induced gas flotation

1. A Horizontal Multistage Induced Gas Flotation Vessel shall be included in the line-up.

For a specific project, when the produced water contains little or no fine solids and condensate droplets are large, the IGF may not be required.

2. The froth, skimmed condensate and solids, from the flotation unit shall be routed to the solids and oily waste treatment system.

3. Recycling of the froth into the process should be prevented.

Besides condensate, the flotation froth usually carries polyelectrolyte and solids that accumulate into a “jelly like” compounds. The presence of ferrous sulphide further complicates treatment.

4.2.1.6 Macro Porous Polymer Extraction (MPPE)

1. MPPE shall be included in the produced water treatment system when dissolved hydrocarbons are required to be removed from the produced water stream.

Dissolved hydrocarbons removed by MPPE are BTEX, PAH and NPD.

2. The dissolved hydrocarbons removed from the produced water shall be routed to the condensate treatment system.

3. The Concept Engineer shall verify is the dispersed oil-in-water concentration in the produced water stream towards the MPPE meets feed water quality specification.

It is expected that for a gas/condensate field that the produced water stream from the Induced Gas Flotation Vessel meets the feed water quality specification for MPPE.



4.2.1.7 Surface discharge to sea

1. Surface discharge of produced water shall occur below the sea level (LAT).

2. Recycling of overboarded produced water discharged to sea back into the seawater intake shall be prevented.

3. Assessment shall be conducted to confirm that PW disposal pipe is self-venting at the maximum PW disposal flow rate.

If the disposal pipe is not self venting at maximum PW disposal flow rate pressure, surges will occur in the overboard system.

4. To prevent pressure surges consideration shall be given to atmospheric vent at the top of the overboard pipe to break vacuum by sucking in air.

5. Hydraulic assessment shall be completed to determine overboard and atmospheric vent line sizes, which shall include the full range of flow rates between the design produced water flow rate and the maximum flow rate at which the overboard pipe is self-venting.

6. For an onshore facility the disposal of produced water to sea requires a pipeline. The disposal location shall comply with legislative requirements, which generally prohibits near shore disposal.

4.2.2 Oil onshore process line-up

The process line-up for an onshore oilfield where the produced water is discharged to sea is shown in Figure 2.

Figure 2 Process line-up for onshore oil field produced water surface discharge

to sea (line-up #2)

An options table, that provides an overview of alternative solutions for the processing steps of an onshore oil field, is presented in (Appendix B) for general reference.

4.2.2.1 Gas/oil/water separator

1. The well fluids shall be separated in a gas, oil and water stream.

2. For most oil fields the well fluid separation requires a three-phase Gas/Oil/Water Separator that shall be designed according to DEP 31.22.05.12-Gen.

Oil & Residual EmulsionGas/oil/ water

separator


Oil Treatment to Export Specs

Plate interceptor

Induced gas flotation

vessel

Gas


Nutshell Filter


(if required) BiocideReverse demulsifier

(if required)Biocide

Skim tanks


Well fluids

Gas

Oil

Produced water


Chemical



4.2.2.2 Skim tank and plate interceptor

1. The bulk water of the primary separation phase shall be treated in a Skim Tank, a Plate Interceptor, or both.

2. A system with both Skim Tank and Plate Interceptor shall be considered for difficult produced water characteristics where the bulk water stream of the primary and secondary phase separation has high residual oil-in-water content.

A system with both Skim Tank and Plate Interceptor offers robustness in the treatment of the produced water stream.

For fields where the well fluid and produced water stream characteristics are easier, only a Skim Tank or a Plate Interceptor is normally sufficient.

3. A skim tank shall be considered if the bulk water flow rate and composition have significant and rapid variation. The skim tank would also provide produced water degassing.

4. Successful implementation of a Plate Interceptor requires the upstream system design to prevent variations in bulk water flow rates and composition, i.e. hydrocarbon slugs.

5. The plate interceptor could be designed to include degassing, but it may also be designed to operate at elevated pressure resulting in produced water being degassed as part of the induced gas flotation unit.


1. A Horizontal Multistage Induced Gas Flotation Vessel shall be selected for onshore produced water processing.

In most fields, the water quality achievable with horizontal multistage induced gas flotation is sufficient to meet disposal to sea specification.

2. The froth, skimmed oil and solids, from the flotation unit shall be routed to the solids and oily waste treatment system.


Besides oil, the flotation froth usually carries polyelectrolyte and solids that accumulate into a “jelly like” compounds. The presence of ferrous sulphide in the froth would even further complicate the processing when recycled into the process.

4.2.2.4 Nutshell filter

1. For difficult produced water streams, or stringent OIW specification, it may be necessary to include a nutshell filter as a tertiary produced water treatment step.

2. The backwash from the nutshell filter shall be routed to the solids and oily waste treatment system.

3. Recycling of the back wash into the process should be eliminated.


1. Surface discharge of produced water shall occur below the sea level (LAT).

2. The discharge of produced water from an onshore field to sea requires a pipeline.

3. The discharge location shall comply with legislative requirements, which in general prohibits near shore discharge.



4.2.3 Oil offshore process line-up

The process line-up for an offshore oil field where the produced water is discharged to sea is shown in Figure 3.

Figure 3 Process line-up for offshore oil field produced water surface discharge

to sea (line-up #3) NOTE 1 Destination of liquid/liquid hydrocyclones reject and skimmed-off oil in degasser to be decided on a

case-by-case basis.

An options table, that provides an overview of alternative solutions for the processing steps of an offshore oil field, is presented in (Appendix C) for general reference.


See (4.2.2.1).

4.2.3.2 Liquid/liquid hydrocyclones

1. Liquid/Liquid Hydrocylones shall be included as the primary produced water treatment step.

2. The feed to the hydrocyclones shall be taken directly from the Gas/Oil/Water Separator and the level control valve on the water outlet of this separator shall be located downstream of the hydrocyclones.

3. Consequently, the system design shall include separate hydrocyclones for the various separators.

4. When the separator pressure is too low for the application of hydrocyclones consideration shall be given to:

a. Pump the low pressure water streams of later separation stages to the primary phase separation step, Gas/Oil/Water Separator.

b. Increase operating pressure of water stream by a low shear pump and route to a dedicated hydrocyclone.

5. The hydrocyclones reject streams shall be routed back to the process.

6. The optimum location for routing the reject stream shall be selected based on the project specifics for oil treatment.


separator



Liquid/liquid hydro -

cyclones

Degasser (skimmer)

Gas


Induced Gas flotation

vessel


Biocide


(if required)


Well fluids

Gas

Oil

Produced water


Chemical

Note 1 Note 1




a. Route reject stream to a dedicated collection vessel, or the closed drains system, and pump liquids back to upstream the Gas/Oil/Water Separator,

b. Route reject stream to a dedicated collection vessel, or the closed drains system, and pump liquids back to the oil treatment system,

c. Free-flow the reject stream to the oil treatment system.


1. A Degasser (skimmer) shall be included in the produced water treatment system to flash-off any dissolved gas that is remaining in the produced water before the produced water is disposed to sea.

The degasser also protects the downstream IGF from excess oil and/or surges in the produced water stream.

2. The off-gas form the degasser is typically routed to the LP vent/flare system, hence operating slightly above atmospheric pressure.

3. The Degasser shall be designed to allow skimming of free oil separated in the degasser.

4. The skimmed oil shall be routed to the closed drains system or slops tank from where the skimmed condensate shall be pumped into the process again, into the primary or secondary phase separation, or into the oil treatment system.

5. The Degasser (Skimmer) shall be designed to enhance skimming of dispersed oil by means of the floatation effect of the dissolved gas.

6. The Degasser (Skimmer) shall be equipped with internals enhancing the deoiling of the produced water, i.e. sparger system inlet device and plate pack.


1. A Horizontal Multistage Induced Gas Flotation Vessel shall be included in the line-up to treat the produced water stream to the specification.

For a specific project, when the produced water contains little or no fine solids and oil droplets are large, the IGF may not be required to meet the specification





1. Surface disposal of produced water shall occur below the sea level (LAT).

2. Recycling of overboarded produced water discharged to sea back into the seawater intake shall be prevented. Assessment shall be conducted to confirm that the PW discharge pipe is self-venting at the maximum PW discharge flow rate.

If the discharge pipe is not self venting, pressure surges will occur in the overboard system.

3. To prevent pressure surges consideration shall be given to atmospheric vent at the top of the overboard pipe to break vacuum by sucking in air.

4. Hydraulic assessment shall be completed to determine overboard and atmospheric vent line sizes, which shall include the full range of flow rates between the design



produced water flow rate and the maximum flow rate at which the overboard pipe is self-venting.

4.3 DESIGN CONSIDERATIONS FOR PWRI AND WELL DISPOSAL

4.3.1 Gas/condensate on and offshore process line-up

The process line-up for a gas/condensate field where the produced water is disposed in a well is shown in Figure 4. Produced water re-injection into the producing reservoir for increased recovery is not considered to be appropriate for a gas/condensate field.

Figure 4 Process line-up for gas/condensate field produced water well disposal

(line-up #4)

NOTE 1: Destination of liquid/liquid hydrocyclones reject and skimmed-off condensate in degasser to be decided on a case-by-case basis.

An options table that provides an overview of alternative solutions for the various elements for a gas/condensate field is presented in (Appendix A) for general reference.

4.3.1.1 Gas/liquid separator

See (4.2.1.1).

4.3.1.2 Liquid/liquid separator

See (4.2.1.2).

4.3.1.3 Solid/liquid and liquid/liquid hydrocyclones

1. Solid/Liquid Hydrocyclones shall be included in the produced water treatment scheme when the water stream of the Liquid/Liquid Separator contains a substantial amount of solids (more than 100 mg/l).

2. Liquid/liquid Hydrocylones shall be included in the produced water treatment scheme when normal gravity separation does not achieve the required inlet specification for the Degasser.

An instance is when the Liquid/liquid Separator is designed as a horizontal open two phase settler or when the water stream is difficult to treat (heavily emulsified).

3. Preference should be given to design the Liquid/Liquid Separator as horizontal two-phase settler with plate pack.

Condensate & Residual Emulsion

Gas/liquid separator

Liquid/Liquid separator

Subsurface Disposal & Recycling

Condensate Treatment to Export Specs

Media filter


cyclones

Degasser (skimmer)

Gas


Solid/liquid hydro -

cyclones

Cartridge filter



Surfactant (in back wash water)



Biocide

Note 1 Note 1

Well fluids or condensate/water stream

Gas

Condensate

Produced water


Chemical

Induced Gas

Flotation


(if required)



4. When the produced water stream mean volume droplet size is less than 10 microns even a Liquid/liquid Hydrocyclone will not function and alternatives shall be considered.

5. In case hydrocyclones are required to meet the specification, the feed to the hydrocyclones shall be taken directly of the Liquid/Liquid Separator and the level control valve on the water outlet of the Liquid/Liquid Separator shall be downstream the hydrocyclones.

6. The hydrocyclones system design shall consider the reduction in operating pressure in the Gas/Liquid separator as a result of the implementation of depletion compression.

7. The reject stream of the Solid/Liquid Hydrocyclone shall be treated by the solids and oily waste handling system.

8. The Liquid/Liquid Hydrocyclones reject streams shall be routed back to the process.

9. The optimum location shall be selected based on the specifics for condensate treatment.


a. Route reject stream to a dedicated collection vessel, or the closed drains system, and pump liquids back to upstream the gas/liquid separator

b. Route reject stream to a dedicated collection vessel, or the closed drains system, and pump liquids back to the condensate treatment system

c. Free-flow the reject stream to the condensate treatment system.


1. A Degasser (skimmer) shall be included in the produced water treatment system to flash-off any dissolved gas that is remaining in the produced water prior to the downstream treatment and to protect the downstream IGF from excess oil and/or surges in the produced water stream.

The off-gas from the degasser is typically routed to the LP vent/flare system, hence operating slightly above atmospheric pressure.

2. The Degasser (skimmer) shall be designed to enhance skimming of dispersed condensate by means of the floatation effect of the dissolved gas.

3. The Degasser (skimmer) shall be equipped with internals enhancing the deoiling of the produced water, i.e. sparger system inlet device and plate pack.

4. The degasser shall be designed to allow skimming of free condensate separated in the degasser.

5. The skimmed condensate shall be routed to the closed drains system or slops tank from where the skimmed condensate shall be pumped into the process again, either upstream the gas/liquid separator, or to the condensate treatment system.


1. A Horizontal Multistage Induced Gas Flotation Vessel should be included in the line-up when a media filter is required to meet the well disposal specification or when the oil-in-water specification cannot be achieved with a degasser (skimmer).

2. The froth, skimmed condensate and solids, from the flotation unit shall be routed to the solids and oily waste treatment system.


Besides condensate, the flotation froth usually carries polyelectrolyte and solids that accumulate into a “jelly like” compounds. The presence of ferrous sulphide in the froth would even further complicate the processing when recycled into the process.



4.3.1.6 Media filter

1. A media filter shall be included in the produced water treatment line-up when the solids specification for well disposal is stringent.

2. Due to the condensate characteristics, the specification for dispersed oil-in-water is not so strict that tertiary treatment, for instance nutshell filter for dispersed oil-in-water shall be included in the line-up.

Normally, a nutshell filter has to be included upstream of the media filter to reduce the dispersed oil-in-water content to acceptable limits for the media filter. However, in case of condensate the dispersed oil-in-water content in the water stream of the degasser usually meets the media filter inlet requirements, less than 30 mg/l OIW.

4.3.1.7 Cartridge filter

1. A cartridge filter as guard to prevent incidental excursion of the solids specification should be included in the line-up when these excursions are not acceptable to the reservoir and/or the injection pumps.

4.3.1.8 Produced water injection pumps

1. Type, selection, and design of centrifugal pumps shall be according to DEP 31.29.02.11-Gen and DEP 31.29.02.30-Gen.

2. The pump characteristics should be matched to the reservoir requirements and control systems should be put in to prevent the wellhead pressure exceeding the specified maximum value.

3. Booster pumps shall be installed upstream of the injection pumps upstream of the injection pumps to provide adequate NPSH – net positive suction head for injection pumps.

4. Numerous failures have occurred in produced water applications in the past and as with injection pumps, detailed produced water analysis and solids content may dictate the necessity for special materials.

5. Designs should not allow solids to settle out in pumps during operation.



4.3.2 Oil onshore process line-up

The process line-up for an onshore oil field where the produced water is re-injected or disposed into a well is shown in Figure 5.

Figure 5 Process line-up for onshore oil field produced water re-injection and

well disposal (line-up #5)

An options table, that provides an overview of alternative solutions for the processing steps of an onshore oil field, is presented in (Appendix B) for general reference.


See (4.2.2.1).

4.3.2.2 Skim tank and plate interceptor

See (4.2.2.2).


1. A Horizontal Multistage Induced Gas Flotation Vessel shall be selected for onshore produced water processing prior to final treatment, if required.





See (4.2.2.4).


See (4.3.1.6).

Oil& Residual EmulsionGas/oil/ water

separator

Skim tanksSubsurface Disposal & Recycling


Nutshell filter

Induced gas flotation vessel

Gas


Plate interceptor

Cartridge filter

Media filter


(if required)

Biocide





Biocide


Well fluids

Gas

Oil

Produced water


Chemical




See (4.3.1.7).


See (4.3.1.8).

4.3.3 Oil offshore process line-up

The process line-up for an offshore oil field where the produced water is re-injected or disposed into a well is shown in Figure 6.

Figure 6 Process line-up for offshore oil field produced water re-injection and

well disposal (line-up #6) NOTE 1 Destination of liquid/liquid hydrocyclones reject to be decided on a case-by-case basis.

An options table, that provides an overview of alternative solutions for the processing steps of an offshore oil field, is presented in (Appendix C) for general reference.


See (4.2.2.1)

4.3.3.2 Solid/liquid and liquid/liquid hydrocyclones

1. Solid/Liquid Hydrocyclones shall be included in the produced water treatment scheme when the water stream of the Liquid/Liquid Separator contains a substantial amount of solids (more than 100 mg/l).

2. Liquid/Liquid Hydrocylones shall be included as the primary produced water treatment step.

3. The feed to the hydrocyclones shall be taken directly from the Gas/Oil/Water Separator and the level control valve on the water outlet of this separator shall be located downstream of the hydrocyclones. Consequently, the system design shall include separate hydrocyclones for the various separators.

4. When the separator pressure is too low for the application of hydrocyclones consideration shall be given to:

a. Pump separate low pressure water streams of later separation stages to the primary bulk separation step, Gas/Oil/Water Separator.

Solid/liquidhydro -

cyclones


separation

Subsurface Disposal & Recycling


Nutshell Filter


cyclones

Induced Gas

Flotation

Gas


Cartridge filter

Media Filter

Biocide



Biocide





(if required)Note 1

Well fluids

Gas

Oil

Produced water


Chemical

Degasser (skimmer)



b. Increase operating pressure of water stream by a low shear pump and route to a dedicated hydrocyclone.

5. The reject stream of the Solid/Liquid Hydrocyclone shall be treated by the solids and oily waste handling system.

6. The Liquid/Liquid Hydrocyclones reject streams shall be routed back to the process.

7. The optimum location for routing the reject stream shall be selected based on the project specifics for oil treatment.


a. Route reject stream to a dedicated collection vessel, or the closed drains system, and pump liquids back to upstream the Gas/Oil/Water Separator,

b. Route reject stream to a dedicated collection vessel, or the closed drains system, and pump liquids back to the oil treatment system,

c. Free-flow the reject stream to the oil treatment system.

4.3.3.3 Degasser

See (4.2.3.3).

4.3.3.4 Horizontal Multistage Induced Gas Flotation

1. A Horizontal Multistage Induced Gas Flotation Vessel shall be selected for onshore produced water processing upstream of nutshell and media filters.





See (4.2.2.4).


See (4.3.1.6).


See (4.3.1.7).


See (4.3.1.8).

4.4 GENERIC DESIGN CONSIDERATIONS

4.4.1 Operability

1. The Operations Philosophy shall specifically address the produced water treatment and injection facilities, i.e., need to clearly outline how these will be managed operationally.

2. Specific requirements to be addressed or specified as part of the Operations Philosophy are:

a. Water quality requirements.

b. Water treatment requirements.

c. Metering, testing and monitoring requirements, see (4.4.2).



d. Uptime requirements, load shedding and sparing philosophy.

e. Maintenance and inspection philosophy.

f. Commissioning and start-up.

g. Organisational and staffing requirements.

h. KPIs to be recorded.

i. Accounting methods, reconciliation structure and deferment recording.

3. Any design requirements resulting from the Operations Philosophy shall be included in the design.

4.4.2 Monitoring and control

1. A monitoring programme shall be established and the structure of the monitoring programme shall be tailored to the specifics of the project and include consideration of:

a. The nature of the source water.

b. The reservoir properties.

c. The treatment process used (equipment and chemicals).

d. The plant location

e. Organisational capability

f. Project status – commissioning, normal operations, pilot testing, etc

2. The programme shall specify the following data:

a. Monitoring parameters.

b. Monitoring locations.

c. Monitoring frequency.

d. Monitoring techniques.

e. Manpower requirements – compatible with the appropriate (normally high) degree of automation.

On-line continuous analysers allow reductions in manning and improved process control (manual sampling will not detect short term variations and any problems with operation of the plant is likely to go un-noticed). A need will remain for manual calibration, instrument and plant troubleshooting, and quality control.

3. The monitoring programme shall be included in the maintenance plan.

4. Facilities for manual testing and calibration shall be provided.

4.4.3 Commingling produced water and seawater

1. If injection of both produced water and seawater is to be employed then separate injection wells and headers should be considered.

2. Commingling of seawater and produced water at surface conditions is not normally advisable due to increased scaling and souring potential, which shall be addressed by compatibility studies, see (2.3) and (2.4).

Nevertheless, there may be major cost savings to be made if mixing is possible. For example, if a seawater injection system could gradually blend in more and more production water as it becomes available this would save on injection pumps and piping.

3. The extent of any potential incompatibility (particularly with respect to scaling shall be assessed, see (2.3).



4. As a minimum, commingling should only be considered prior to the injection pumps after each stream has been treated.

4.4.4 Conversion from seawater to produced water treatment

1. As the volume of produced water increases, wells and equipment originally used for seawater treatment and injection may be used for produced water treatment.

2. If this change over from seawater to produced water is applicable, the seawater and produced water system design shall consider this conversion.

4.4.5 Secondary waste streams

1. Secondary waste streams from the production facilities, such as process water, drains water and ballast water, shall not be mixed with the produced water in the produced water treatment and injection facilities.

2. In these circumstances, even though the bulk of the waste water may be disposed of through water injection, separate waste water treatment facilities shall be provided for the disposal of secondary waste water streams.

4.4.6 Gas dissolved in produced water

4.4.6.1 General

Produced water contains dissolved hydrocarbons, H2S, and CO2 if present in the well fluids. The presence of these dissolved components in the produced water affects material selection (H2S, CO2) and has safety implications (H2S, hydrocarbon components).

The H2S present in well fluids partitions between the oil, water and gas phase. At low pressure, the majority of H2S partitions into the gas phase. A relatively small amount dissolves in the produced water stream. H2S is a weak acid and the total H2S present in produced water dissociates in S--, HS- or as H2S, depending on the pH of the produced water stream. Acidizing of the produced water results in shifting the equilibrium and H2S being released to the gas phase.

A change in operating conditions (pressure, temperature and/or pH) may result in gas and/or H2S release from the produced water stream.

1. An assessment of produced water being discharged SHALL [PS] be conducted to:

a. Estimate the released gas quantity and composition as a result of the changed operating conditions (temperature, pressure and pH).

b. Produce gas dispersion modelling to determine the extent of the explosive and/or toxic gas cloud.

2. If the results of the above assessment indicate the potential for a gas cloud, produced water SHALL [PS] be sufficiently degassed and/or treated before being discharged to sea to prevent an explosive and/or toxic gas cloud.

3. An assessment SHALL [PS] be conducted to identify processing, operational and maintenance activities that could result in a shift in pH and thereby result in unexpected H2S release or increased H2S content. The design (e.g. material selection study) and operating procedures SHALL [PS] specifically address these activities.

Typical activities are well acidisation and acid injection to dissolve scale in equipment.

4. For fields where the well fluids contain significant H2S, consideration shall be given to treat the produced water stream to remove the H2S before discharging the produced water overboard.

Potential treatment options are:

• Injection of H2S scavenger.

• Removal of H2S by steam stripping



• Removal of H2S by sweet gas stripping.

5. Injection of H2S scavenger should be considered when the H2S concentration in the produced water stream is low and/or the produced water flow rate is small.

6. At higher H2S concentrations and larger produced water flow rates the water stripping should be considered.

The process injection point for H2S scavenger injection into the produced water stream is downstream of the final degassing step in the produced water treatment system.

7. The produced water system downstream of the injection point shall provide sufficient mixing and retention time for scavenging of the H2S.

The process line-up for H2S stripping by means of steam and sweet gas are shown in Figure 7 and

Figure 8, respectively.

8. A sour water stripper feed stream shall:

a. Have a stable flow rate and composition

b. Have a low dispersed oil-in-water content

c. Have a low suspended solids content

d. Be degassed

Figure 7 Sour water steam stripper line-up



Figure 8 Sour water sweet gas stripper line-up

9. The following aspects shall be considered in the evaluation of steam versus sweet gas stripping:

a. Availability of steam or sweet gas

b. Requirement to acidize the produced water stream

c. pH sensitivity of stripping column performance

d. Scaling due to sour water stripping process

e. Sensitivity to fouling of stripping column

f. Sensitivity to produced water flow rate/stripping medium flow rate variations

g. Off gas flow rate and composition and possibility for further processing

10. In addition to the equipment presented in the line-ups (see Figure 7 and Figure 8) the following equipment/functionality should be considered:

a. Depending on the operating pressure of the stripping columns a bottom pump may be required to boost the pressure of the sweet water stream.

b. A recycle line or pump to recycle sweet water to the inlet of the stripping column for start-up and turndown operations

c. For hot produced water streams where sweet ags stripping operates at elevated temperatures include an overhead condenser, reflux vessel and pump to condense evaporated water in the sour off gas of the stripping column (like for steam stripping).

11. An N+1 sparing of the sour water stripping system should be provided.

4.4.6.2 Dissolved oxygen

1. The introduction of oxygen into a produced water treatment and injection system shall be prevented.

2. Nevertheless, oxygen may ingress into the produced water system though for instance pump seals.



3. The produced water shall be monitored for oxygen ingress.

4. Upon detection of oxygen ingress above 10 ppb, the Materials Engineer shall be consulted to determine appropriate material selection and/or mitigations against material failures. Generally, oxygen scavenger shall be injected into the produced water to control the oxygen content below 10 ppb.

5. The Materials Engineer shall be consulted for sour produced water when any oxygen is detected to determine appropriate material selection and/or mitigations against material failures.

For sour produced water, H2S dissolved in the produced water, a dissolved oxygen concentration less than 10 ppb could be detrimental to materials

4.4.7 Turndown

1. The produced water treatment system shall take into account the impact of prolonged operation of the produced water system at flow rates significantly less than the design flow rate.

2. The performance of the produced water system and specific equipment shall be assessed to confirm the robustness of the produced water system against turndown operation, specifically hydrocyclones, control valves and pumps.

4.4.8 Off specification water

A number of routine operations may give rise to altered produced water characteristics.

1. Each operation shall be analysed on the water quality impact.

2. If the resultant water quality excursion is unacceptable to equipment, reservoir or disposal those operations shall be changed to eliminate or minimise excursions.

3. An alternative disposal route, disposal well or surface discharge to sea, or produced water storage shall be available as back-up to prevent off-specification water being injected, or production downtime.

4.4.9 Produced water storage

1. Preferably, a produced water system should be designed without storage.

2. Alternative disposal routes with less stringent water quality requirements for off-specification water are preferred.

3. Produced water storage volume, if required, shall be assessed based on evaluation of the various start-up and downstream system down-time scenarios.

4. Produced water storage tank shall be blanketed to prevent oxygen ingress into the produced water.

4.4.10 Reject handling

The main focus of most produced water system designs is the quality of the effluent water stream. The contaminants removed from the produced water streams are simply moved to some secondary waste streams.

1. The design of a water treatment facility shall consider the treatment and potential disposal requirements of secondary waste streams that may be generated.

2. Recycling of reject streams has an impact on the treating performance and shall be given specific attention.

4.4.11 Chemical treatment and injection points

4.4.11.1 General

1. Chemical injection system shall be designed in accordance to DEP 31.01.10.10-Gen.

2. The chemical treatment requirements, chemical selection, chemical concentration, injection point location, sampling points, etc., shall be specified by the Production Chemist.



3. Main equipment for the system shall include:

a. Bulk transfer to storage

b. Storage tanks

c. Injection pumps

d. Injection points

e. Umbilicals (offshore)

4. Overdosing of chemicals should be avoided as this may stabilise emulsions.

5. Injection rates should be automatically varied with the appropriate production rate (bulk, oil or water).

Chemicals specific to produced water treatment are discussed in this DEP. For oxygen scavenger, see DEP 39.01.40.30-Gen.

4.4.11.2 Injection points locations

1. As a minimum, the injection points for chemicals as indicated in the advised line ups of Figure 1, Figure 2, Figure 3, Figure 4, Figure 5 and Figure 6 shall be provided.

2. Injection points shall also be into a part of the process where mixing readily takes place so that the dosed chemical can be fully effective

3. Injection points for different chemicals in close proximity to each other shall be avoided.

Although water treatment chemicals may be compatible at in-stream concentrations (typically a few mg/l each) they may not be compatible at higher concentrations.

4.4.11.3 Demulsifier

Demulsifiers are injected into the well fluids to enhance the bulk separation of the well fluids.

1. The demulsifier shall be injected as far upstream as practical, well flow line or even downhole.

2. When selecting a demulsifier, consideration shall be given to not only obtain a low water-in-oil concentration but also the best oil-in-water concentration.

A possible benefit may be that there is not a requirement for water clarifier injection.

4.4.11.4 Water clarifier

1. Although, in principle, demulsifier selection may eliminate the need for water clarifier injection, the produced water system shall still include all the required water clarifier injection points.

These points will allow for water clarifier injection, when the required water quality cannot be achieved without water clarifier injection.

4.4.11.5 Biocide

Microbial activity is generally stimulated by the accumulation of solids and debris in stagnant areas, like tank bottoms.

1. During the design of the produced water treatment facilities, stagnant areas shall be avoided.

2. In case this requirement cannot be fulfilled, suitable facilities shall be included in the design to flush the solids out of the process.

3. The requirement to inject biocide shall be based on evaluation of sessile bacteria in the process.



4. If this assessment identifies that biocide injection is required, Biocide shall be applied in the bulk separation and produced water treatment system following a conservative approach.

5. Best microbiological control is achieved by shock dosing of biocide for certain limited time (typically once or twice a week for 3 hours each treatment) at a high enough injection rate (typically 300 ppmv active component).

6. The selection of the biocide shall be based on actual produced water and with the development of sessile bacteria.

7. The frequency of biocide shock dosing shall be modified based on regular monitoring of the occurring bacterial growth in the system.

Biocide injection is intended to prevent biological activity in the surface facilities, for instance SRB, and therefore, the injection of biocide indirectly impacts reservoir souring. Reservoir souring is discussed in (2.3).

4.4.11.6 Coagulants and flocculants

1. Coagulation/flocculating agents shall be applied with care, both location and dosage rate.

The function of coagulant/flocculant agents is “binding” solids and/or oil droplets, but the resulting floc is not stable.

2. Additional shear/mixing destroys the formed flocs again. Injection of these chemicals needs to be designed properly and once added any shear shall be avoided.

4.4.11.7 Surfactant

1. Surfactants may be dosed into the filter backwash inlet header in order to assist in the removal of the oil from the filter media.

2. The backwash water containing surfactant shall not be mixed with the produced water stream.

4.4.11.8 Scale inhibitor

The scale control strategy could specify scale inhibitor injection in the produced water treatment and injection system.

1. Scale inhibitor dosing shall always be applied upstream of any location anticipated to be susceptible to scale deposition.

4.4.11.9 Corrosion inhibitor

1. The produced water system preferably is designed such that material selected is not prone to corrosion. In case this is not practical, economical or for other reasons, corrosion inhibitor may be required. Selection of the corrosion inhibitor shall consider the emulsifying behaviour.

4.4.12 Sample points

1. Sufficient sampling points, as defined by the Production Chemist, shall be included in various locations to be able to monitor the effectiveness of the chemical injection systems and to evaluate equipment performance.

4.4.13 Materials of construction

1. Material selection of the produced water treatment and injection system shall be in accordance with DEP 31.01.10.11-Gen., DEP 39.01.10.11-Gen. and DEP 39.01.10.12-Gen.



5. REFERENCES

In this DEP, reference is made to the following publications: NOTES: 1. Unless specifically designated by date, the latest edition of each publication shall be used,

together with any amendments/supplements/revisions thereto.

2. The DEPs and most referenced external standards are available to Shell staff on the SWW (Shell Wide Web) at http://sww.shell.com/standards/.

SHELL STANDARDS

DEP feedback form DEP 00.00.05.80-Gen.

Design Class Tables DEP 00.00.07.10-Gen.

Hydrogen sulphide prediction for produced fluids from new and existing wells in oil and gas fields

DEP 25.80.10.18-Gen.

Chemical injection systems for upstream production facilities DEP 31.01.10.10-Gen.

Corrosion prevention and control of water injection systems (EP) DEP 31.01.10.11-Gen.

Gas/liquid separators - Type selection and design rules DEP 31.22.05.11-Gen.

Liquid/liquid and gas/liquid/liquid separator - Type selection and design rules

DEP 31.22.05.12-Gen.

Pumps – Selection, testing and installation DEP 31.29.02.11-Gen.

Centrifugal pumps (amendments/supplements to ISO 13709) DEP 31.29.02.30-Gen.

Selection of materials for life cycle performance (upstream facilities) - Materials selection process

DEP 39.01.10.11-Gen.

Selection of materials for life cycle performance (Upstream facilities) – Equipment

DEP 39.01.10.12-Gen.

Seawater injection facilities DEP 39.01.40.30-Gen.

Shell HSSE & SP Control Framework, Design Engineering Manual (DEM) 1 – Application of Technical Standards http://sww.manuals.shell.com/HSSE/

DEM1

Shell HSSE & SP Control Framework HSSE Environment Manual http://sww.manuals.shell.com/HSSE/

HSSE Environment Manual


http://sww.shell.com/standards/

http://sww.manuals.shell.com/HSSE/

http://sww.manuals.shell.com/HSSE/


APPENDIX A OPTIONS TABLE GAS/CONDENSATE FIELD PRODUCED WATER TREATMENT PROCESSING

TSS Dispersed Degassing Dispersed OIW (TSS) Dispersed OIW TSS TSS / Dispersed - Guard Dissolved & dispersed OIW

Vertical 2 phase (gas/liquid)

None None None None Degasser (skimmer) None None None None

Horizontal 3 phase -gas/condensate/water

(with plate pack)

Liquid/liquid separator (with plate pack)

Solid/Liquid Hydrocyclones Liquid/Liquid Hydrocyclones Produced water flash drum Skim tank (offshore) Centrifuge (+ solids pre-treatment)

Multi-media Filter Cartridge filter GAC

Horizontal 3 phase -gas/condensate/water

(without plate pack)

Liquid/liquid separator (without plate pack)

Plate interceptor Coalescence polymer filter Nutshell filter Coalescence polymer filter

Organic clay

Horizontal Multistage Induced Gas Flotation

Coalescence polymer filter MPPE

Vertical Gas Flotation

Remarks Required when Vertical gas/liquid separator is selected as primary separator

Gas/condensate field generally has separators operating at sufficient high pressure to enable selection of hydrocyclones

No primary treatment required when dispersed oil-in-water meets feed specification of secondary treatment.

Gas/condensate field generally has separators operating at sufficient high pressure.

Skip primary treatment for dispersed OIW when feed stream mean (volume) condensate droplet size is <10 µm.

To be considered:1. Protect downstream low design pressure equipment against high upstream pressure2. Flash off gas from PW stream when primary treatment is at high pressure.

Required treatment step. Combination of two may be required. For instance Degasser (skimmer) + Horizontal Multistage Induced Gas Flotation

Tertiary water treatment to be included when dispersed oil-in-water from secondary treatment exceeds specification, or when dissolved oil-in-water treatment is required. Dispersed OIW treatment also required when feed stream exceeds maximum allowable dispersed OIW for tertiary TSS PW treatment equipment

Include multi-media filter when TSS in produced water stream does not meet specification. Alternative for streams with limited amount of solids in produced water stream is cartridge filter

Include to prevent excursions due to off-specification water of tertiary PW treatment, or to protect downstream equipment (MPPE, injection pumps, etc)

Selection criteria

Selection criteria: gas/liquid ratio (CAPEX) and fouling tendency

Selection criteria: Fouling tendency

Selection criteria: feed stream pressure, solids content, stable feed stream, specification on product water TSS, liquid/liquid hydrocyclones deployed

Selection criteria: feed stream pressure, mean (volume) condensate droplet size, solids content, stable feed stream

Selection criteria: fine solids content, solids content, mean (volume) condensate droplet size, plot size limitations, feed stream fluctuations in oil content or flow rate, CAPEX, OPEX

Selection criteria: operability, footprint, weight, reliability, CAPEX, OPEX, solids content and particle size, oil droplet size to be removed

Selection criteria: CAPEX/OPEX on basis of TSS loading

Selection criteria: TSS - cartridge filter, OIW - coalescence polymer filter

Selection criteria: flowrate, particle size, solids content, type of dissolved to be removed

Bulk separation Produced water treatment

Options

Tertiary water treatmentPrimary separation Primary water treatmentTertiary separation Secondary water treatment



APPENDIX B OPTIONS TABLE OIL ONSHORE FIELD PRODUCED WATER TREATMENT PROCESSING

Secondary

TSS Dispersed Dispersed OIW (TSS) Dispersed OIW TSS TSS / Dispersed OIW - Guard

Dispersed & dissolved OIW

3 phase -gas/oil/water (with plate pack)

None None None Degasser (skimmer) None None None None

3 phase -gas/oil/water (without plate pack)

Skim tank Solid/Liquid Hydrocyclones Liquid/Liquid Hydrocyclones Horizontal multistage induced gas flotation

Nutshell filter Multi-media filter Cartridge filter

Plate interceptor Plate interceptor Dissolved gas flotation Coalescence polymer filter Coalescence polymer filter

Coalescence polymer filter Nutshell filter

Remarks Required when water quality out of 3 phase separator does not meet feed water quality of primary water treatment or surges in feed water can be expected.


Skip secondary treatment for dispersed OIW when feed stream mean (volume) oil droplet size is <15 µm.


Tertiary water treatment to be included when dispersed oil-in-water from secondary treatment exceeds specification. Dispersed OIW treatment also required when feed stream exceeds maximum allowable dispersed OIW for tertiary TSS PW treatment equipment


Include to prevent excursions due to off-specification water of tertiary PW treatment, or to protect downstream equipment (injection pumps, etc)

Selection criteria

Selection criteria: fouling tendency

Selection criteria: Surges in produced water flow rate and composition, solids content and mean (volume) oil droplet size


Selection criteria: feed stream pressure, mean (volume) oil droplet size, solids content, stable feed stream

Selection criteria: fine solids content, solids content, mean (volume) oil droplet size, plot size limitations, CAPEX, OPEX

Selection criteria: operability, reliability, CAPEX, OPEX, solids content and particle size, oil droplet size to be removed



Produced water treatment

Options

Bulk separation

Primary separation Tertiary separation (incl degassing functionality)

Primary water treatment Tertiary water treatment



APPENDIX C OPTIONS TABLE OIL OFFSHORE FIELD PRODUCED WATER TREATMENT PROCESSING

Secondary water treatment

TSS Dispersed Dispersed OIW/(TSS) Dispersed OIW TSS TSS / Dispersed - Guard Dispersed & dissolved OIW

3 phase -gas/oil/water (with

plate pack)

None None None Degasser (skimmer) None None None None

3 phase -gas/oil/water

(without plate pack)

Skim vessel Solid/Liquid Hydrocyclones Liquid/Liquid Hydrocyclones Horizontal multistage induced gas flotation Nutshell filter Multi-media filter Cartridge filter

Plate interceptor Plate interceptor Dissolved gas flotation Coalescence polymer filter Coalescence polymer filter

Vertical gas flotation Nutshell filter

Coalescence polymer filter

Remarks Required when water quality out of 3 phase separator does not meet feed water quality of primary water treatment or surges in feed water can be expected.


Skip secondary treatment for dispersed OIW when feed stream mean (volume) oil droplet size is <15 µm.


Tertiary water treatment to be included when dispersed oil-in-water from secondary treatment exceeds specification. Dispersed OIW treatment also required when feed stream exceeds maximum allowable dispersed OIW for tertiary TSS PW treatment equipment


Include to prevent excursions due to off-specification water of tertiary PW treatment, or to protect downstream equipment (injection pumps, etc)

Selection criteria

Selection criteria: fouling tendency

Selection criteria: Surges in produced water flow rate and composition, solids content and mean (volume) oil droplet size


Selection criteria: feed stream pressure, mean (volume) oil droplet size, solids content, stable feed stream

Selection criteria: fine solids content, solids content, mean (volume) oil droplet size, plot size limitations, CAPEX, OPEX

Selection criteria: operability, reliability, CAPEX, OPEX, solids content and particle size, oil droplet size to be removed



Produced water treatment

Tertiary water treatment

Options

Bulk separation

Primary separation Tertiary separation (incl degassing functionality)

Primary water treatment


dep-39.10.40.31

Documents

shell companies

shell gsi

system of deps

engineering standards

appropriate deps

preface dep design

eccn ear99 design

galfar engineering