Produced Water & Environmental Conference

Produced Water & Environmental 4.1 Statoil Conference Proceedings 1.1 NEL

5-6 June 2013 1.1 NEL Technical Programme

1.1 DECC

3.2 Enerscope Systems Inc

1.2 Genesis Oil and Gas

3.3 TOTAL

1.3 Veil Environmental, LLC

3.4 PWA Europe Ltd

1.4 Aquateam

3.5 Arjay Engineering Ltd

2.2 IFP Energies nouvelles

4.1 Statoil

2.4 Brilliant Water Solutions

4.3 Advanced Sensors

3.1 Cameron

4.4 LUX Assure Limited

Exhibitor List

NEL Info Brochure

Disclaimer

Produced Water & Environmental Conference 5-6 June 2013 Technical Programme Day 1 – Wednesday 5 June 0900 – 0930

REGISTRATION AND COFFEE

Session 1

Legislation/General Produced Water Management

0930 – 0940

Chairman Introduction Angus Laurie, Nexen - UK

0940 – 0955

An Update on Regulatory Requirements for the Discharge of Produced Water in the UKCS Andrew Taylor, Department of Energy & Climate Change - UK

0955 – 1025

Risk Based Approach - What Does It Mean to the Operators and Service Companies? Safina Jivraj, Genesis Oil and Gas - UK

1025 – 1055

Potential Environmental Impact of Produced Water John Veil, Veil Environmental, LLC - USA

1055 – 1130

COFFEE AND EXHIBITION

1130 – 1200

Produced Water Management - Present and Future Challenges Eilen Arctander Vik, Aquateam - Norway

1200 – 1230

31 Years Experience With Produced Water Treatment Technologies in the North Sea Jon Berntsen, KANFA Mator AS - Norway

1230 – 1240

Open Discussion Period

1240 – 1340

LUNCH AND EXHIBITION

Session 2

Water Reduction/Polymer Flooding

1340 – 1350

Chairman Introduction Paul Hagemeijer, Shell - The Netherlands

1350 – 1420

Environmental Aspects of Polyacrylamide used in Polymer Flooding and Challenges in Produced Water Treatment Dennis Marroni and Jacques Kieffer, SNF SAS - France

1420 – 1450

Management of Produced Water Resulted from Chemical Flooding Operations Jean-Francois Argillier, IFP Energies nouvelles - France

1450 – 1520

Challenges in EOR Produced Water Floods Paul Hagemeijer, Shell - The Netherlands

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Produced Water & Environmental Conference 5-6 June 2013 Technical Programme Day 1 – Wednesday 5 June 1520 – 1550

COFFEE AND EXHIBITION

Session 2 (Cont.) Water Reduction/Polymer Flooding 1550 – 1620

Development of a New Technology for Treating Chemically Stabilised Produced Water Emulsions Paul Schouten and Michiel Arnoldy, Brilliant Water Solutions - The Netherlands

1620 – 1650

Field Experiences of Minimising Water Production Using Advanced Chemicals Glyn Freeman, TIORCO a Nalco Stepan Company - UK

1650 – 1700

Open Discussion Period

1700

Chairman’s Closing Remarks

1710 – 1830

Drinks Reception (Exhibition Area)

Day 2 – Thursday 6 June 0830 – 0900

COFFEE AND EXHIBITION

Session 3

Produced Water Treatment Technologies/Field Experiences

0900 – 0910

Chairman Introduction Keith Robinson, Oil Plus Ltd - UK

0910– 0940

Advances in Compact Flotation Units (CFUs) for the Treatment of Produced Water Mike Bhatnagar, Cameron Custom Process Systems - USA

0940 – 1010

Produced Water Filtration Pilot for Fine Particles Steve Coffee, Enerscope Systems Inc - USA

1010 – 1040

Study of Oxidation Processes for Produced Water Treatment Nicolas Lesage, Pierre Pedenaud, Matthieu Jacob, Julie Savignac, Mohamed Mouzaou and Christine Peyrelasse, TOTAL - France

1040 – 1110

COFFEE AND EXHIBITION

1110 – 1140

Removal of Dispersed, Emulsified, and Soluble Hydrocarbons and Oilfield Chemicals Utilising a Regenerable and Reusable Media Mike Smith, PWA Europe - UK Neil Poxon and Jay Keener, PWA Inc - USA

1140 – 1210

The Hassles & Rewards of Oil in Water Monitoring: Is it Worth it? Greg Reeves, Arjay Engineering Ltd - Canada

1210 – 1220

Open Discussion Period

1220 – 1320

LUNCH AND EXHIBITION

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Produced Water & Environmental Conference 5-6 June 2013 Technical Programme Day 2 – Thursday 6 June Session 4

Oil-in-Water Monitoring

1320 – 1330

Chairman Introduction Ming Yang, NEL - UK

1330 – 1400

Status of Online Oil-in-Water Monitoring in Statoil Ragnvald Soldal, Statoil - Norway

1400 – 1430

Measurement Criteria for Selecting an Online Analyser for Produced Water Russell Hempsey and Khalid Thabeth, Advanced Sensors - UK

1430 – 1500

COFFEE AND EXHIBITION

1500 – 1530

Applying Online Oil-in-Water Sensors for Improved Produced Water Management Gert Folmer, Hobré Instruments bv - The Netherlands

1530 – 1600

A Novel Optical Approach for Produced Water Analysis - A Platform Technology for Monitoring Chemicals, Oil, Solids and Microbes Fiona S. Mackay, Cameron Mackenzie, Catherine Rowley-Williams and Emma Perfect, LUX Assure Limited - UK

1600 – 1610

Open Discussion Period

1610

Chairman’s Closing Remarks

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Produced Water & Environmental Conference 5-6 June 2013 ATTENDING EXHIBITORS NEL is pleased to announce that the following companies are exhibiting within the Pitmedden Room 1 where refreshments will be served during conference intervals. There will also be a drinks reception on Wednesday 5 June from 1710 - 1830 hrs.

Produced Water & Environmental Conference 5-6 June 2013 Abstract

An Update on Regulatory Requirements for the Discharge of Produced Water in the UKCS Andrew Taylor, Department of Energy & Climate Change

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INTRODUCTION

In 2012 OSPAR adopted OSPAR Recommendation 2012/5 for a risk-based approach to the Management of Produced Water Discharges from Offshore Installations and associated Guidance (OSPAR Agreement 2012/7). The Recommendation details the requirements of a risk-based approach (RBA) to the management of produced water (PW) discharges from offshore installations. Full implementation of the recommendation must be achieved by 2018. Each Contracting Party will implement the Recommendation to meet its own national requirements, and this paper outlines the UK’s current thinking on implementation of the Recommendation. In addition to the introduction of the RBA, the application process for produced Water discharge permits will be changing in late 2013, moving from the current paper based system to the PORTAL. In order to capture RBA requirements and discussions since the last revision, the Produced Water Sampling & Analysis Guidance is being reviewed with an aim to provide an update by the end of the year. 2

SCOPE OF THE UK RBA IMPLEMENTATION PLAN

All installations on the UK Continental Shelf (UKCS) that have a permit to discharge produced water, or have a permit for the contingency discharge of produced water in the event of produced water re-injection downtime, will be included in the UK implementation plan. Approximately 100 installations currently fall into those categories, but operators will be able to apply for an exemption for installations that have a confirmed decommissioning date within the period 2013 – 2018. Installations that re-inject all their produced water and halt production in the event of re-injection downtime, i.e. they do not have a permit for the contingency discharge of produced water, will not be included in the UK implementation plan. Affected Installations will require additional toxicity testing to be undertaken at the time of the bi-annual analyses. These requirements will be agreed with the relevant operator in advance. Operators will be advised in which half-yearly period they will be required to undertake the additional sampling and analysis so as to minimise the burden on laboratories and / or those providing assessments. A schedule for undertaking the RBA assessments will be prepared, to spread the assessments over the period 2013 – 2018. The schedule will take a number of factors into consideration, including operators with a number of assets, the scale of the discharges, the availability and capacity of toxicity testing facilities, the existing chemical sampling and analysis schedules, prior participation in the UK

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Produced Water & Environmental Conference 5-6 June 2013 Abstract RBA trial practical programme and installation–specific constraints such as scheduled maintenance shutdowns. The final format of both the RBA assessment process and the implementation schedule will be discussed and agreed with industry during Q2/Q3 2013, with a view to commencing the assessments probably in 2014. While the Recommendation allows for a substance and/or whole effluent analysis approach the UK’s current thinking is that operators should do both for the initial assessment. Substance information is available from the chemical information and natural components are determined bi-annually. The whole effluent toxicity is the additional requirement at the bi-annual stage. 3

RBA PROCESS

The UK RBA methodology involves six steps, covering four assessment tiers, with the potential for installations to be screened out from further assessment at each tier if the PEC:PNEC ratio is ≤1. The UK methodology is based on the UK practical programme carried out in 2010 as part of the study into the RBA. 3.1

Step 1 - Sampling and analysis of produced water

Offshore sampling of the PW stream is required, to collect samples for the determination of the concentrations of naturally occurring substances in the PW and the toxicity of the whole effluent. The samples for both testing programmes must be collected at the same time. It is unnecessary to analyse the sample for any added chemicals, but general information relating to the PW discharge and details of the added chemicals in the PW stream at the time of sampling, including any batch treatments and relevant dosage rates, should be recorded, as this information is required for subsequent steps in the process. 3.2

Step 2, Tier 1 - Screening based on Persistence, Bio-accumulation and Toxicity (PBT)

Tier 1 involves screening out PW discharges that are not Persistent, Bioaccumulative or Toxic, in accordance with the requirements of the relevant Technical Guidance Document (TGD) (ECB, 2003), to demonstrate that the discharge of PW is unlikely to result in significant harm to the marine environment. To be screened out at this stage, Whole Effluent Assay (WEA) would be required to assess PBT parameters, but the proposed UK approach would only require Whole Effluent Testing (WET) to determine toxicity. Tier 2 assessment will therefore be required, unless operators intend to assess all relevant PBT parameters. The UK practical programme was based on toxicity testing and a limited assessment of persistence, but bioaccumulation was not assessed. The produced water discharges were therefore subjected to Tier 2 assessment.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract 3.3

Step 3, Tier 2 - Determination of whole effluent PEC:PNEC ratio at 500 metres using an Average Dilution Factor

Tier 2 involves screening out PW discharges if the whole effluent PEC:PNEC ratio at 500 m from the discharge point is ≤1, based on the use of a PNEC value derived from the toxicity tests and an average dilution factor derived using site specific data. There are a number of ways the dilution factor can be determined, and the UK methodology will allow the operator to select and justify the method used for their assessments. The UK practical programme involved the derivation of dilution factors at four locations 500 m from the discharge point using outputs from the DREAM model, but work is currently underway to determine whether a simpler and more reliable method could be used to determine dilution at 500 m. If, using the selected methodology, the calculated PEC:PNEC ratio at 500 m is ≤1 and DECC confirms that it is content with the assessment, the installation could be screened out and would not require further assessment. Operators will also be able to confirm that a PEC:PNEC ratio of ≤1 would be achieved at a specified distance greater than 500 m, to seek confirmation that this would be acceptable to DECC. If a PEC:PNEC ratio of ≤1 would be achieved within what is considered to be a reasonable distance of the discharge point, Tier 3 assessment would not be required. 3.4

Step 4, Tier 3 - Determination of whole effluent PEC:PNEC ratio using dispersion modelling

Tier 3 involves screening out PW discharges if the whole effluent PEC:PNEC ratio is ≤1 in a specific volume of water within any selected area, based on a PNEC value derived from the toxicity tests and site specific dispersion modelling. This approach is more rigorous than the Tier 2 assessment, and identifies whether the PEC:PNEC ration is >1 within the modelled volume or area. The UK practical programme involved use of the DREAM model, but there are a number of available models and the UK methodology will allow the operator to select and justify the model used for their assessments. If, using the selected model, the calculated PEC:PNEC ratio is ≤1 within an acceptable area and DECC confirms that it is content with the assessment, the installation could be screened out and would not require further assessment. Operators will be able to confirm that a PEC:PNEC ratio of ≤1 would be achieved within a specified volume or area, and to seek confirmation that this is acceptable to DECC. If a PEC:PNEC ratio of ≤1 would be achieved within what is considered to be a reasonable volume or area, Tier 4 assessment would not be required. 3.5

Step 5, Tier 4 - Determination of PEC:PNEC ratio at the substance level

For those installations that require further assessment, dispersion modelling will be required to determine the PEC:PNEC ratio within a specific area or volume of water for the individual naturally occurring substances in the PW, and/or for both the naturally occurring substances in the produced water and the added chemicals discharged with the PW. Whether it is necessary to include the added chemicals will depend upon the nature and quantity of the added chemicals. Assessment of the PEC:PNEC ratio for individual substances should include identification of the contributions of specific components to the overall risk. If the overall assessment indicates that the PEC:PNEC ratios are ≤1 within a reasonable volume or area, there are no substances that are a specific cause for concern, and DECC confirms that it is content with the assessment, further assessment is not required. If the overall assessment indicates that the PEC:PNEC ratio is >1

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Produced Water & Environmental Conference 5-6 June 2013 Abstract within the specified volume or area, or there are specific substances that are a cause for concern, additional measures may be required to reduce the risk, as summarised in Step 6. 3.6

Step 6 - Produced Water Management

DECC will initiate discussions with the operator. Operators may be requested to collect additional samples or undertake additional studies to verify the initial assessment, or to identify measures to reduce the risk. Additional studies could include the commissioning of further toxicity tests for specific substances, to determine whether it is possible to reduce the assessment factor. Measures to reduce the risk could include the substitution of specific chemicals, or modification of the produced water treatment system. Following completion of the additional studies or implementation of the agreed measures, the assessment process would have to be repeated to confirm whether the risk has been reduced. Depending upon the scale of the discharge and the results of the toxicity testing, operators may be required to undertake all four tiers for their initial RBA assessments, in order to establish baseline data. As more installations complete their initial assessments, DECC will be able to better assess the value of individual tiers, and it is anticipated that most installations would be screened out at the Tier 2 or Tier 3 level during subseqent assessments. DECC will also be able to make informed decisions in relation to the frequency of repeat assessments for individual installations 3.7

Demonstration of Best Available Technique and Best Environmental Practice

In addition to implementing the RBA, the demonstration and review of Best Available Technique (BAT) and Best Environmental Practice (BEP) remains a requirement for all PW discharges, as detailed in OSPAR Recommendation 2001/1 (as amended). This would form part of any discussions initiated under Step 6, Produced Water Management. 4

REVIEW OF RBA

In accordance with §6.2 of the Recommendation, progress against the implementation plan will be reported to OIC on an annual basis, commencing in 2014, through an annual report submitted by the Contracting Party to the OIC Expert Assessment Panel. In accordance with §6.3 of the Recommendation, a formal evaluation of the effectiveness of the RBA will be undertaken every five years, commencing in 2018. The outcome of the evaluations will be reported to OIC. 5

OPPC PERMIT CHANGES

The discharge or injection / reinjection of produced water containing hydrocarbons from an offshore installation must be the subject of a permit issued under The Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (as Amended) in accordance with current Guidance.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract Currently this is a paper based application, however during 2013 this process will transfer to the UK OIL PORTAL system and operators will need to apply using a similar system as is currently used for chemical permits. In conjunction with the transfer to the UK OIL PORTAL system, current permit conditions are being reviewed in order to remove some current contradictions, make them more streamlined and strengthen some areas. Permits will contain relevant permitted discharge, sampling, analysis and reporting information in a tabular format to make it easier to understand. The bulk of permit conditions, which apply to all particular discharges, such as sampling & analysis, will sit as a set of ‘Standard Industry Conditions’ (SIC) which are linked to but separate from the permit itself. Therefore if we need to change these SIC’s we can do so without having to reissue all OPPC permits. Permit conditions specific to an installation and discharge will be captured in the relevant tables and as bespoke conditions. A small stakeholder engagement to discuss the new proposals was undertaken at the start of the year with a few operators and UK Oil & Gas, and was well received. A wider roll out to industry will take place in due course. 6

PRODUCED WATER SAMPLING & ANALYSIS GUIDANCE REVISION

The current Guidance Notes were issued in August 2010. Since then numerous discussions have occurred with various parts of Industry resulting in agreement on how some aspects should be interpreted or exceptions to the Guidance due to particular circumstances. Some of the identified changes being considered for review are: Sampling and analysis frequency for manned installations discharging 20% on 6 monthly correlation graphs, Clarification on how to manage expiry of calibration graphs due to extended shutdowns, Review of correlation of online analysers to determine if this can be simplified, Review of Section 12 regarding hydrocarbon analysis of non-produced water streams, Clarification on analysis requirements for hammermill operations. Until the scale of any changes are identified it has not yet been determined if a consultation with Industry will be required prior to reissue. 7

REFERENCES

[1]

D. SAWARD, I. STEWART. OSPAR Recommendation 2012/5: Implementation Plan, OIC 2013. (Paper not publicly available)

[2]

VARIOUS. OSPAR Recommendation 2012/5, For a Risk-based Approach to the Management of Produced Water Discharges from Offshore Installations, OSPAR.

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UK

Produced Water & Environmental Conference 5-6 June 2013 Abstract [3]

VARIOUS. OSPAR Agreement 2012/7, OSPAR Guidelines in support of Recommendation 2012/5 for a Risk-based Approach to the Management of Produced Water Discharges from Offshore Installations, OSPAR

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Produced Water & Environmental Conference 5-6 June 2013 Abstract Risk Based Approach - What Does it Mean to the Operators and Service Companies? Safina Jivraj, Genesis

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INTRODUCTION

The fate and biological effects associated with the marine discharge of produced water from offshore installations are of growing environmental concern. This coupled with a number of worldwide oil and gas fields entering their “end of life”, means an increasing volume of produced water is generated, leading regulators to increase vigilance over safeguards and controls. In order to protect the marine environment of the North East Atlantic, OSPAR (the Oslo-Paris convention) has already set a target of ‘zero harmful discharge’ from produced water by 2020. With this deadline fast approaching and likely to be adopted by UK regulators, accepted engineering practices may need to be adapted for future produced water management. One widely accepted means of assessing environmental impact associated with produced water is to employ a Risk-Based Approach (RBA). This paper aims to provide a perspective on how UK Operators and Service providers can prepare themselves for changes against the OSPAR Recommendations 2012/5. It will look at the Norwegian example as Norway has made the most progress in this field and concludes by looking at how RBA can be used to better inform operators and engineering service providers during the design stage of project development. 2

ENVIRONMENTAL CHALLENGE

Produced water is an inseparable part of the hydrocarbon recovery process. It is a term used to describe water that is produced when oil and gas are extracted from the ground. Primarily, produced water is made up of formation water (water in the reservoir) and injection water used to enhance oil and gas recovery, which assists in driving oil and gas to the surface. As operating fields mature, they tend to produce increasing amounts of water. In 2010, the global produced water rate exceeded hydrocarbon production by 50% [1] and in the UK Continental Shelf, this figure reached over 130% between 2011 and 2012 [2]. Three routes are commonly used to dispose of produced water: discharge overboard into the sea, injection back to the source reservoir or injection to other sub-surface formation. Due to cost and operational factors, discharge overboard into the sea has been the main route across offshore operations worldwide and as a result, regulators worldwide have shown increasing interest in understanding the risks to the marine environment from produced water discharges. Produced water contains a variety of components, both naturally occurring and those added for production purposes. Although produced water varies significantly among wells and fields, typically it would include dispersed and dissolved hydrocarbons, production chemicals, metals, suspended solids and naturally occurring radioactive material. Regulators worldwide have put much emphasis on managing levels of dispersed oils, i.e. oils that will separate from water, but the

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Produced Water & Environmental Conference 5-6 June 2013 Abstract dissolved fractions such as production chemicals and hydrocarbons which can include BTEX, phenols and PAHs can be toxic in certain concentrations. When these are released to the marine environment, they have the potential to cause harm to marine organisms. 2.1 Perception of Risks for Marine Discharge The process of understanding harm caused by marine discharge of produced water is extremely complex and involves processes with combined considerations. Firstly the component in the produced water must be “bioavailable”, which means that it is capable of being taken up by a living organism, thereby has the potential to cause harm. Secondly, the component has to be “toxic” - that is, the substance has the capacity to cause harm once it has been taken up by a living organism, at concentrations relevant to the situation being considered. Then the “harmful effect” relates to a change in a biological process, organism, population, community or ecosystem, in this context as a result or consequence of a produced water discharge. A component of produced water has to possess the inherent qualities of being “bioavailable” and “toxic” for it to have a “harmful effect”. To establish whether a component has caused an observed effect is a difficult process, typically requiring a plausible biological mechanism and a dose related relationship to be established. Beyond this, some stakeholders would need an effect to be demonstrably adverse for it to be considered as harm. For others applying the precautionary principle, any plausible risk of harm from produced water would be considered undesirable and therefore constitutes harm. 3

LEGISLATIVE SAFEGUARDS

The OSPAR Convention for Protection of the Marine Environment of the North-East Atlantic is the current legislative instrument regulating international cooperation on environmental protection in the region. The Convention has been signed and ratified by 15 signatory nations, and representatives of the European Commission (EC), representing the European Union. The Contracting Parties including Belgium, Denmark, the EC, Finland, France, Germany, Iceland, Ireland, the Netherlands, Norway, Portugal, Spain, Sweden and the UK. Luxembourg and Switzerland also are signatory due to their location within the catchments of the River Rhine [3]. OSPAR, formed in 1992, and its predecessor Conventions formed in 1972 and 1974, has been pushing the agenda to protect the marine environment since its formation and has continually driven the evolution of the regulatory regime in the signatory nations. Over the past five years, OSPAR has been formulating a recommendation for a RBA which takes a more holistic view to protecting the marine environment rather than solely focussing on levels of dispersed oil in produced water. Currently, OSPAR has two key mechanisms to regulate produced water discharges: Performance standards: these are prescribed limits on allowable levels of hazardous substance discharged. The current OSPAR limit is 30 mg dispersed oil/l of produced water as a monthly average. But produced water contains many pollutants, other than dispersed oil, hence a limit on dispersed oil does not adequately inform on environmental harm. In addition, the use and discharge of production chemicals are controlled by the Harmonised Mandatory

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Produced Water & Environmental Conference 5-6 June 2013 Abstract Control Scheme (HMCS), which requires substance level toxicity pre-screening and site specific environmental risk analysis. Guiding principles: These principles underline the approach to achieve performance standards, with the most significant and far-reaching ones being the application of Best Available Techniques (BAT) and Best Environmental Practice (BEP), fundamental OSPAR principles. In 2008, in support of the EC Technical Guidance Note (TGN) on Risk Assessment for new substances [4], OSPAR in its meeting of the Offshore Industry Committee (OIC) decided to evaluate the possibility of implementing a RBA in produced water management. This decision was made in light of the overall goal of the OSPAR recommendation 2001/01 for management of Produced Water from Offshore Installations [5], which was to: “reduce the input of oil and other substances into the sea resulting from produced water from offshore installations, with the ultimate aim of eliminating pollution from those sources. ensure that an integrated approach is adopted, so that reduction in oil discharge is not achieved in a way that causes pollution in other areas and/or other environmental compartments. ensure that effort is made to give priority to actions related to the most harmful components of produced water”. OSPAR Recommendation 2001/01 also has a ‘zero harmful discharge’ target from produced water by 2020. OSPAR’s description of the target is: ‘near background concentrations in the marine environment for naturally occurring substances and close to zero concentrations of synthetic substances’ but does not provide a clear picture of what constitutes ‘harmful’. Operators need clear rules to decide how to assess the risk of harm so that they can identify and prioritise actions to make stepwise progress. While the implication is that the UK will adopt the RBA for produced water management, with its enabling regulations, the UK regulator (the Department of Environment and Climate Change, DECC) already has powers to request reasonable information under the Regulations for EIA, Offshore Chemicals and Oil Pollution Prevention and Control. Moving forward, DECC is in the process of formulating its proposals with UK operators on the subject of RBA procedures however these are not yet agreed and finalised. 4

WHAT IS THE RISK BASED APPROACH

The RBA for Produced Water Management has been developed following a harmonised, structured procedure [6] presented below (Figure 1). This framework follows principles of environmental risk assessment already in use e.g. the EU (ECTechnical Guidance Document on the risk assessment of chemicals) and US (USEPA guidance on risk assessment). The RBA approach has as far as possible been aligned with these guidelines in developing the environmental risk assessment of single components and assessment of mixtures has also been developed according to best scientific practice, (in simple terms, the summation of effects delivered by each single component). Although detailed definition of risk may differ amongst users of the risk assessment methodologies, the basis is universal. The goal is to reach a level of “zero harmful discharge”. To more clearly define this goal in Norway, the Environmental Impact Factor (EIF) was developed as an indicator of potential

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Produced Water & Environmental Conference 5-6 June 2013 Abstract impacts from produced water. A reduction in EIF is used as a measure of benefits achieved when alternative measures are considered for reducing potential environmental risks and is therefore also a measure of the degree of movement toward the goal of zero harmful discharge and demonstrating BAT and BEP. In the UK, it is expected that whole effluent toxicity assessment will also form part of the process and direct effort towards potential effluents of concern, and sitespecific modelling of WET dispersion can inform risk-reduction decisions.

Fig. 1 -Risk Based Approach

It should be noted that the development of the EIF has been guided by the principle that areas of uncertainty should be resolved in favour of protecting the environment i.e. conservative environmental assumptions are invoked. The methodology is therefore conservative in the sense of over-protecting rather than under-protecting the environment. The method is not designed to serve as an estimator of impact, rather a measure of environmental risk that is intended to be used to quantify the comparative benefit to the environment of alternate management strategies [7].

The EIF is expressed by comparing the “predicted environmental concentrations” (PECs- exposure concentrations) to “predicted no effect concentrations” (PNECs – threshold concentrations that produce no adverse effects). EIF is therefore defined as being proportional to the water volume in which the ratio PEC/PNEC > 1 presenting a 5% risk of harm (which is widely accepted as a tolerable effect - see Figure 2).

Probability of Environmental Injury (%)

So when the predicted (modelled) environmental concentration (PEC) is larger than the predicted noeffect concentration (PNEC), there may be a risk for ecological harm. When the PEC is lower than the PNEC threshold, the risk for harm from that single substance is considered to be acceptably near zero. By computing the environmental risk resulting from each component and adding the risks as independent Ratio of PEC/PNEC probabilities, the total risk at any given spatial point, Fig. 2 - PEC/PNEC Ratio verses at any given time can be Environmental Risk calculated [8]. 4.1

The Predicted No-Effect Concentration (PNEC)

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Produced Water & Environmental Conference 5-6 June 2013 Abstract The PNEC is the estimated lower limit of effect on the biota in the receiving marine environment for a single chemical component or component group. A PNEC level is given for each component in the produced water. A massive data collection effort has been undertaken to obtain data of sufficient reliability for use in determining PNEC values. Different procedures have been selected for determination of PNEC values for natural constituents in produced water and for added production chemicals. For naturally occurring components in produced water, PNEC is determined using acute toxicity testing. The PNEC value is derived from Effective Concentrations (EC50), Lethal Concentrations (LC50), or where better data is not available the No Observed Effect Concentration (NOEC) values from laboratory testing can be used. The EC50, LC50, or NOEC value determined are divided by an assessment factor (defined below) in order to arrive at the expected PNEC. In EU countries (including the UK) PNEC values for additive production chemical components are usually derived from information found in the Harmonized Offshore Chemical Notification Format (HOCNF) scheme which includes properties such as: Density Molecular weight Biodegradation (BOD28) Bioaccumulation (log Pow), and Toxicity (tested on a limited species given as EC50 and/or LC50) It should be noted that PNEC is based on toxicity tested on the same species rendering the PNECs comparable between components. The distribution of these species may not be uniform in the marine environment, and they may not be fully representative of all the species present, and therefore an assessment factor is applied to express confidence in that PNEC. Uncertainties can also arise from location relevance, representation of taxonomic groups and use of acute or chronic toxicity data. In Figure 3 where EC50, LC50 or NOEC toxicity data has been limited, the EU TGDs recommend the application of an assessment factor which takes account of the uncertainties mentioned. 4.2 Predicted Environmental Concentrations (PEC) The purpose of exposure estimation (Step 3 in the RBA framework) is to derive the PECs for the Fig. 3 - EU-TGD requirements for PNEC derivation receiving environment around an offshore installation. The PEC can be determined by modelling concentrations in the receiving environment. OPSAR recommends that as a

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Produced Water & Environmental Conference 5-6 June 2013 Abstract minimum, the PEC should be determined within the water column, with a radius defined by the distance from the installation e.g. 500m zone, specified by the Contracting Parties or within the volume of water directly impacted by the discharge as determined by hydrographic dispersion modelling of the discharge, taking into account local environmental conditions and sensitivities [6]. The concentration field for discharge PEC may be predicted by use of a 2D or 3D dilution/dispersion model. The model must demonstrate that dilution is not overestimated and therefore use of field validation study(s) may be necessary [6]. Furthermore, the model chosen should be well documented and its users should be well trained. A model that takes account of different fate processes can provide a more accurate PEC. Figure 4 shows an example of PEC for a modelled produced water stream and the corresponding EIF using the DREAM (Dose related Risk and Effect Assessment Model) software development and maintained by SINTEF, Norway.

Calculation of PEC

Calculation of EIF (PEC/PNEC)

Fig. 4 - Example of PEC calculated using DREAM Software 5

IMPLICATION OF RBA ON INDUSTRY

UK offshore regulator, DECC has been formulating a proposal on a four-tiered assessment method involving a stepwise process with the possibility to screen installations by risk. To provide Operators an overview of how the process can be applied, examples have been worked using data from OSPAR practical program on sampling of chemical and toxicity properties of produced water. The final output of the process is a produced water management plan based on the risk profile generated from the assessment. Such screening of installations by its environmental risk is something that is already being undertaken by the Norwegian Regulators, a pioneer in adopting the RBA for produced water management and can be seen in Figure 5. Norwegian Operators are required to report their annual EIF, this way allowing regulators to assess where improvements can be made. More recent papers have been published to show newer post-reduction numbers [11], which demonstrate that EIF reduction projects and improvements in knowledge have reduced these values considerably.

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Produced Water & Environmental Conference 5-6 June 2013 Maximum Environmental Impact Factor (annually)

Abstract

18 000 16 000 14 000 12 000

EIF

10 000 8 000 6 000 4 000 2 000

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Va G rg ul fa ks B Br a Ås ge ga rd Ås B ga rd A

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0

Field

Fig. 5 - Maximum EIF of Norwegian Installation 5.1

Operator Obligation

The adoption of RBA will become increasingly important within an Operators’ strategic planning. Change may force industry to consider different practices in engineering and in the way it manages risk. Some considerations include: Project lender may require ventures to demonstrate zero environmental harm as a measure of risk. Re-negotiating arrangements with leased FPSO’s providers to accommodate change toward RBA. Optimisation of deck space to accommodate additional produce water abatement kit, adding topside weight and capex to new developments. Substituting production chemicals which may be more costly or which the operator has limited prior experience. Operators may also believe adoption of RBA will bring the need for additional capital expenditure due to earlier consideration within field development. Modifications to an operating facility in a step wise manner may therefore also be a viable route to prepare for 2020. Clear guidance is therefore needed by Regulators to ensure Operators can successful align with the changing requirements. 5.2

Service Provider Offering

As a Service Provider, Genesis has long supported offshore oil & gas operators with field development planning consultancy and engineering design services, incorporating environmental considerations early into financial decision making on both small and major development projects. Investigating fate and potential for harm from produced water marine discharge is becoming a key early design consideration. In certain scenarios no additional considerations beyond modelling may be necessary. This could be a result when produced water discharges are low and the environmental risks rapidly disperse to 90 % of the production is water. A large number of installations on the NCS were installed in the seventies and the eighties. During the last five years a significant number of life extension projects have accepted by the Petroleum Safety Authority (PSA). Among these are Åsgard C (until 2019), Ula (2028), Ekofisk 2/4 B (2015), Statfjord A (2028), Valhall (2015) and many others. The challenges with respect to produced water management issues include [2]: Afterlife of facility typically involving extension beyond original design criteria typically has water and gas processing limitations Compatibility issues are raised due to a mix of new and existing streams that will change the composition of the fluids to be treated Produced water treatment technology development over the last 30 years will be summarised and discussed. Some examples of the challenges and the possible solutions will be given. The challenges associated with PWRI will be discussed and a couple of examples of obstacles seen and selected solutions for some fields will also be provided.

Produced Water & Environmental Conference 5-6 June 2013 Abstract 2.2

New Discoveries

For new discoveries, prefeasibility, feasibility and concept studies are performed, and different options for produced water management are evaluated. Expected influent water quality and discharge permits along with design PW flow rates are input parameters. The available information of influent quality is normally limited, but the plans and the experiences gained from similar fields are used. To make decision on which kind PW treatment technology to select, a set of selection criteria are agreed upon with the operators. Typically the criteria for selecting PW treatment technology include parameters such as: 1. 2. 3. 4. 5. 6.

Experience Robustness of technology Environmental performance Treatment costs Technology complexity Technology flexibility

The weighting of the different parameters and the subcategories of issues to be included will vary from project to project. Typically the treatment technology must perform according to the needs, but experience and robustness are parameters of significant importance and bringing new solutions into projects in the planning stage is not easy. In several new projects on the planning stage on the NCS, a holistic approach has been taken for water management. This means including water treatment needs for injection water and for produced water, where the objective is to achieve 95 % PWRI over the field lifetime. Examples will be given. 2.3

EOR Activities and Consequences for PW Management

EOR technologies have a promising, but unproven technical and economic recovery potential on reservoir and field levels and include: in situ water diverting gels, silica, LPS, Bright water; CO2; polymers; surfactants; salinity designed injection water; salinity designed polymer assisted surfactant (SDPASF) “cocktails”. EOR activities will change the composition of produced water significantly. According to [3], the average planned recovery of Norwegian Oil fields is 46 % as of 2010, but an increase of 1 % in average will result in a value creation of 270 billion NOK (assuming 70 USD/bbl). The fundamental relationship dictating the effectiveness of EOR methods is that between the oil, the water and the rock within the reservoir, and the key concept linking those three elements is ‘wettability’. Two examples of EOR methods presently discussed and planned are: LowSal injection (or designer water): Low-salinity enhanced oil recovery involves flooding a sandstone reservoir using water with a specially engineered salinity and ionic composition. This method is to be applied in combination with polymers and/or surfactants which are efficient in injection water with reduced salinity. Polymer flooding (with or without the use of surfactants). The most common approach worldwide is application of HPAM; a hydrolyzed polyacrylamide which increases the viscosity of the fluid injected. The salinity of the water is less important. The produced water from polymer or surfactant flooded reservoirs will get increased concentrations of the chemicals in produced water. The produced water will also have a high viscosity which is likely to be a major problem with respect to re-injection. Polymer flooding is presently mainly applied on onshore fields, and longest history of experience is from China. The first offshore field implementing polymer flooding is also in China (from ~2012). PW treatment of polymer flooded produced water (PFPW) holds numerous challenges and the qualified PW treatment technologies are likely to be far too costly

Produced Water & Environmental Conference 5-6 June 2013 Abstract (size and weight and operational costs) and could limit the implementation of polymer flooding. Examples of possible solutions will be discussed. 3

REFERENCES

[1]

OG21 (2012): http://www.og21.org.

[2]

OG21 TTA4 (2012): Future Technologies for Production, Processing and Transportation. http://www.og21.org.

[3]

Åm, K. et al (2010): Increased recovery on the Norwegian Continental Shelf. A report from the Recovery-Committee. Oil- and Energy Department (OED) Report Sept. (in Norwegian).

Produced Water & Environmental Conference 5-6 June 2013 Abstract

Management of Produced Water Resulted from Chemical Flooding Operations Jean-Francois Argillier, IFP Energies nouvelles

As a result of the recent increases in crude oil prices, a number of chemicallybased enhanced recovery methods are being reconsidered by companies around the globe. The entire design and production chain required to bring these technologies from the bench to the field has been the focus of research for several decades. But one important aspect that is generally neglected in chemically-based enhanced recovery technology concerns the impact of the EOR chemicals on the produced water cycle. This includes the compatibility of EOR chemicals with the additives used to pretreat the injected water (e.g. biocides, etc.) and to process the produced oil/water mixture after EOR chemical breakthrough (e.g. demulsifiers, flocculants, etc). The chemicals used in polymer flooding, surfactant flooding and their combinations may react with the usual additives, causing problems like loss of activity of those additives, EOR underperformance, permeability impairment at injectors, inability to separate oil from water or to treat the produced water to get the specification of oil content depending on the usage of the produced water (discharge or preferentially produced water reinjection). Some chemicals themselves, like surfactants and mechanically degraded polymers, may as well produce stable W/O or O/W emulsions and induce strong impact of produced water treatments, that ask for specific additives and equipment in order to keep the topside processing efficient. All these problems may seriously impact the forecasted economical performance of EOR projects.

In this presentation we will describe in more detail what are the specific constraints in terms of water management linked to chemical EOR and what are the challenges associated with backproduced chemicals (polymers & surfactants) on topside processes (separation, water treatment) and produced water

1

Produced Water & Environmental Conference 5-6 June 2013 Abstract reinjection, using a specific laboratory methodology designed to study the impact of ASP-type chemicals on produced fluids treatment efficiency. As the present trend is to increase the use of enhanced recovery methods, among them the chemically-based ones, the industry urges for viable solutions to implement those methods while accomplishing the strict process and environmental constraints that nowadays exist. Water management is an important challenge for chemical EOR that needs an integrated approach and should be studied upfront. As the technical hurdles involved are numerous and challenging, IFP Energies nouvelles is developing R&D projects in collaboration with oil companies that aim to investigate the impact of chemical EOR on the production system as a whole, and, more specifically, to assess the compatibility of EOR chemicals with treatment additives and to evaluate the impact of EOR chemicals on well, surface and reinjection processes.

2

Produced Water & Environmental Conference 5-6 June 2013 Abstract Development of a New Technology for Treating Chemically Stabilised Produced Water Emulsions Paul Schouten and Michiel Arnoldy, Brilliant Water Investments

1

INTRODUCTION

The increasing watercut in mature fields and tightening regulations are the main drivers for the growing challenge of treating emulsified water. In addition, the industry is creating more emulsified water in applications such as fraccing and Alkali Surfactant Polymer water as used in EOR. Installed solutions often rely on time and gravity as the main forces for separation of water and hydrocarbons. For chemically stable emulsions these forces are not enough. Demulsifiers can present a solution but bring a risk of overtreatment and in any case demand specialist attention to keep the process in a narrow operating window. Various membrane filtration processes have been tried and found not able to cope with the various upsets and changes in chemistry in the water. Any solution needs to conform to offshore and standard oilfield preconditions. In a nutshell these revolve around safety, user friendliness and robustness in more way than one. This paper relays the implementation and test results of the first full size, automated application of this new technology.

Fig -1, full size 5 m3 / hr DNV skid in a Zone 2 area

2

GENERAL

Produced water, slop water and frac flow back water can have very stable oil in water (O/W) emulsions. Surfactants present in the water are causing this problem. A surfactant is a substance that, when dissolved in water, lowers the surface tension of the water and increases the solubility of organic compounds. Surfactants will occur naturally in the reservoir and are used in a wide variety of applications in the oil and gas industry, such as: wetting agent in drilling muds. corrosion inhibitor to protect carbon steel piping

1

Produced Water & Environmental Conference 5-6 June 2013 Abstract cleaning agent. during foam jobs They need to be considered an indispensable part of the producers toolkit with all subsequent consequences. Generally speaking the cost of disposing produced- or other waste water is lowest when treated at the source. The application at hand is in a gas producing field in the North Sea and represents the produced water arriving from various satellites onto a hub installation with a ‘standard’ skimmer treatment facility followed by a disk stack centrifuge. In an offshore environment, the alternatives to re-injection are: the water is sent as part of wet-gas through the pipe line, or, the water –in the case of extended non-compliance- may be collected and shipped to shore. The first alternative increases maintenance cost due to corrosion and increased pigging runs; the second alternative increases direct operating cost.

3

THE TECHNOLOGY

The technology consists of a four step process : Step 1 Electrical Oxidation: Electrical demulsification cartridges consist of multiple pairs of electrodes separated by a few millimeters and arranged so that the water flows along the plates at a moderate rate. A direct current voltage is applied across the plates. A number of processes take place simultaneously:

·

·

·

Step 2: Compact Flotation Unit

2

Electronic charge destabilisation of suspended colloids and emulsions. Release of reactive oxygen, hydroxyl and other radicals which react with dissolved organic compounds, oxidising them and causing heavy metals to separate from solution as oxides/hydroxides. Large amounts of fine gas bubbles promote the flotation of coagulated solids and coalesced hydrocarbons.

Produced Water & Environmental Conference 5-6 June 2013 Abstract Now that the emulsion is broken the free oil will float to the top where it is skimmed off. Step 3: Fibra filtration Fibra technology operates by a simple concept. The filter bed is formed from a bundle of fine fibre, potted at one end. The bundle is mounted vertically in a vessel and compression is achieved through a patented insert quite close to the free end to form a fine filtration bed. Feed enters the filter vessel and flows through the cartridge to provide a clarified filtrate downstream of the compression point. The design is such that the pressure drop over the cartridge in the opposite direction, during back- flushing, is far less.

• Feed enters the filter vessel and permeates the bundle, flowing through the bed to provide a clarified filtrate downstream of the compression point.

• The bed density close to connection of the fibre to the top plate is

relatively low, becoming progressively tighter towards the compression point, thus providing an effective gradation of pore size. This ensures that reasonably high solids loadings can be achieved, before the filter bed becomes fully loaded.

• On a time based or dP signal, the direction of flow reverses and the filterbed is flushed indirectly to the starting point of the process, thereby minimising total reject volume.

Step 4: polishing In a final filtration step consumable cartridges are used as a guard filter primarily. The lifetime of the cartridges is strongly enhanced with the Fibra pre-filtration.

4

FIELD TESTING

After numerous lab tests and small scale tests offshore on freshly produced water, a full scale unit was produced which was subjected to a 6 to 8 month testing programme on the Dutch Continental Shelf. Oil in water results from the tests were analysed at an accredited third party lab using the normal OSPAR procedures. Considerable downtime was incurred in the first two months as teething problems were resolved. From then on the unit was ran continuously. The test was started in January 2013 and consists of several steps and smaller projects with intake water from various sources: downstream of the disk stack centrifuge from the pressurised skimmer from pipe line pigging operations from well testing operations flow back from frac operations

3

Produced Water & Environmental Conference 5-6 June 2013 Abstract

Advances in Compact Flotation Units (CFUs) for the Treatment of Produced Water Author: Mr. Mike Bhatnagar, Cameron Custom Process Systems, USA

1

INTRODUCTION TM

The Cameron TST-CFU (Patent Pending) is the next generation compact flotation unit that uses gas flotation and additional centrifugal forces to separate and remove hydrocarbons, aromatic compounds, hydrophobic substances and fine solid particles from produced water. The technology uses special internals for mixing of gas and oil. The process can be repeated through several stages within one vessel depending on the inlet conditions. Following extensive lab and field testing several full scale units have now been deployed. This next generation compact flotation unit is capable of handling higher inlet oil concentrations (over 1,000 mg/l) and providing lower outlet OIW concentrations (less than 10mg/l) through one single multi stage vessel. TM The TST-CFU system requires less equipment, has a lower weight, smaller footprint, is less dependent on chemicals and can potentially replace multiple produced water treatment technologies.

Fig. 1 - TST-CFUTM Compact Flotation Unit 2

This presentation will outline the technology and present test data from one of the fields in the North Sea where TM the TST-CFU has been tested against existing hydrocyclone and conventional compact flotation systems. It will address the OIW removal performance TM of the TST-CFU under high OIW concentrations and small oil droplet size distributions.

BACKGROUND

Produced water is water that is returned to the surface through the lifespan of an oil or gas well. It is made up of natural formation water as well as the return of water injected into the formation (flowback water) that was sent downhole as part of a fracture stimulation (frac) process or an enhanced recovery operation. Globally water production associated with the oil & gas production is three times higher than the oil production. This gives an average water fraction of about 75% of what is produced from the wells and it continues to increase over the lifespan of the well. The water fraction increases in proportion to the oil fields being older and decreases in proportion to better methods being

Produced Water & Environmental Conference 5-6 June 2013 Abstract developed to handle the reservoir. Most onshore produced water is re-injected to underground formations, either to provide additional oil and gas recovery or for disposal, under permits issued by state agencies or regional offices. Most offshore produced water is diposed as discharge to the ocean following treatment as permitted by the regional offices. Produced water is an inescapable fact of life for oil and gas producers that offers both opportunities and challenges for sustainable recovery of hydrocarbon resources. Oilfield operating companies continue moving to ever-increasing water depths to produce oil and gas reserves. Due to the high cost of constructing floating platforms required for these deep water fields, it is imperative that the size and weight of processing equipment on the platform be kept as low as possible. In addition, fluid processing equipment that is installed on the topsides of these floating structures is subject to more severe wave-induced motions. These issues must be taken into consideration when designing topsides equipment in order to minimize any adverse impacts to capacity and performance. The challenges for the operators are increasing and the need for better, diminished and more cost effective technologies exists. In the past, many offshore operators have adopted a trend toward the use of liquid-liquid hydrocyclones followed by conventional vertical column flotation vessels to treat produced water prior to overboard disposal. TM

The TST-CFU is the next generation compact flotation technology that offers a more compact solution for produced water treatment replacing hydrocyclones and vertical column flotation TM vessels. The TST-CFU compact flotation technology, is specially designed to handle higher inlet oil concentrations and incorporates many new features which enhance equipment performance, and reduce - foot print, weight of equipment, capital costs, operating costs, and maintenance costs.

3

TST-CFUTM COMPACT FLOTATION DESIGN CHARACTERISTICS

Conventional vertical column flotation technology was originally developed for offshore produced water treatment applications. The use of floating platforms has led to many challenges for oilfield equipment operators. Some of the primary issues that need to be addressed are: • • •

Compact size Reduced weight Wave-induced motion

Offshore applications of the flotation equipment have led to improvements in the original geometry. The design of the vertical column gas flotation units was intended to address offshore TM needs. The next generation design of the TST-CFU compact flotation unit combines several technologies into one single vessel and addresses the need for enhanced equipment performance at higher inlet oil concentrations along with the need for reduced foot print and weight. TM

Design of the TST-CFU takes into account the effects of major parameters on the process hydrodynamics including fluid velocity, gas bubble size, mixing efficiency, fluid circulation, internal flow paths, gas bubble re-mixing capability as well as cell residence time, skimming rate, downward velocity, and gas induction rates. TM

The TST-CFU design consists of special internals that include a static mixture, a riser pipe, distribution arms and guide vanes that prevent produced water from short circuiting as observed in conventional flotation vessels. Improved produced water circulation and re-mixing is crucial to TM the design of TST-CFU system that enhances the oil separation efficiency.

Produced Water & Environmental Conference 5-6 June 2013 Abstract CFD analysis was used to improve the efficeincy of the internal guidevanes by retiaining more of the swirling oil water mixture and providing an upward flow pattern to the rising gas bubbles attached to the oil. The proper distribution of gas bubbles over the entire cross-sectional area of the vessel, the re-mixing of the gas bubbles, the size of the bubbles induced into the produced water are all critical to promote good oil separation that leads to: • • •

Much shorter retention times per stage that results in a more compact vertical pressure vessel. Typically around 20 seconds per stage. Enhanced design with a multiple stage vessel instead of the single stage conventional design of the vertical IGF and conventional Compact Flotation Units. Smaller reject volumes. Typically around 0.5% per stage.

The cylindrical vessel design allows for implementation of ASME pressure vessel code guidelines for high internal pressure applications. Adaptation of special internals to the cylindrical geometry allows for higher inlet OIW levels. Attenuation of wave-induced motion, or sloshing, is a critical aspect of the design of vertical TM column flotation units on floating platforms. The TST-CFU is 100% liquid filled and avoids the negative impact of these effects. Additional stages can be addeed as needed and the treated water is released from the outlet at TM the bottom of the vessel. The TST-CFU can be also used for land-based applications for refinery waste water and oilfield produced water treatment.

4

FUNCTIONAL DESCRIPTION - TWO STAGE TST-CFUTM

The following description outlines a TSTTM CFU MS2 (multi stage 2) which is one vessel with 2 internal stages separated from each other as shown in Figure 2. Each stage has separate gas injection and oil reject lines. The numbers of internal stages required are dependent on the produced water quality with respect to the OIW concentration, oil droplet size distribution, solid particles and use of chemicals and are not limited to 3 stages. The units can operate at 0.5barg pressure drop per stage, and at 0.5 barg above the downstream reject system pressure in the final stage. 4.1

First Stage TM

The TST-CFU units use a vertically oriented cylindrical vessel to contain the produced water for treatment. The produced water enters the vessel at the bottom and flows upward. Simultaneously, gas bubbles are introduced to the vessel at the inlet through a gas mixer located in the

Fig. 2 – Two Stage TST-CFU

Produced Water & Environmental Conference 5-6 June 2013 Abstract pipe at the inlet of the vessel. This helps in mixing the induced gas (N2 or fuel gas) with the produced water or for mixing the recycled gas from the top of the vessel when an eductor is used. The primary objective of gas flotation is to populate a produced water stream containing oily contaminants (dispersed oil droplets and/or oil-coated solids) with gas bubbles such that as the bubbles rise to the surface, they collide with, cling to, drag along, and float the oily contaminants to the surface. As the mixture of gas and oily water rises to top of the riser pipe it is distributed into the first stage of the vessel through several tangential distribution pipes which create an internal spin. Additional tangential distribution pipes may be added to maintain effective swirling motion and re-mixing for larger size vessels. The mixture of gas and oily water from each distribution pipe is forced upwards over an inclined guide vane that overlaps the next distribution pipe. Large gas bubbles float to the surface and the remaining gas bubbles and produced water are remixed with new incoming gas-oily water mixture released from the next distribution pipe. In this way the required gas bubble size is maintained to create a good contact with the oily contaminants entering with the new incoming water. The continuous mixing also creates a coalescence of the small gas bubbles and the oil connected with these gas bubbles floats to the surface. Gas from the first stage can be recirculated by using an external eductor. When the inlet produced water flow enters the eductor, a low pressure zone is created in the eductor. Gas from the top of the vessel is routed to the eductor. Gas is pulled into the eductor by the vacuum and mixed with the water prior to entering the vessel. This gas/water mixture is used to introduce the bubbles needed for the flotation process. Gas bubbles that disengage at the gas-liquid interface are recycled to throught the eductor to the bottom of the vessel for flotation. Oftentimes it is necessary to inject a chemical agent to promote gas bubble-oily contaminant interaction in induced gas flotation. Many times these chemicals are long-chain polymers that impart an electrical charge to the oily contaminants or render them hydrophobic. This phenomenon increases the possibility that the contaminants will cling to the bubbles and float to the surface. Once at the surface, the separated hydrocarbons along with the gas and some water are extracted in a common reject pipe at top of the vessel. The amount of reject is less than 0.5% of the liquid feed and is adjusted by a manual valve that can be fixed and set during start up. An actuated valve that has a self cleaning function can also be used. Treated produced water exits nd from the bottom of the first stage and is directed via a vortex breaker to the 2 stage. 4.2

Second Stage nd

st

nd

The treated water enters the 2 stage via an annulus chamber inbetween the 1 and 2 stages. External gas is added to the produced water via an internal gas mixer in this annulus before entering the distribution manifold. The produced water/gas mixture is distributed in the same way as in the first stage. The numbers and size of the distribution pipes and vanes is the same as for st st the 1 stage and the amount of gas needed will be the same as that for the 1 stage. There will st nd be a pressure drop of apr. 0.5bar across the 1 and 2 stages. The separated oil together with gas, and some water are extracted in a reject pipe at the top of the second stage. The normal amount of reject is less than 0.5% of the feed per stage and is adjusted by a manual valve that can be fixed and set during start up. An actuated valve with a self cleaning function can also be used. The oily reject from this stage enters the common reject line. Additional stages can be added depending upon the inlet oil concentration, oil droplet size

Produced Water & Environmental Conference 5-6 June 2013 Abstract and desired outlet oil concentratio centrations. The TST-CFU configurations in a single vessel.

TM

is currently available lable in 1, 2, 3, or 4 stage

The foregoing descriptions highlights the primary design considerations used to enhance the TM performance of the TST-CFU flotation units:

• • • • • • 5

Oil droplet size Quantity and size of gas bubbles formed Proper distribution and re-mixing mixing of gas bubbles across the cross-sectional sectional area Proper distribution of produced water across the cross cross-sectional area Downward velocity (flux) of the produced water Proper water chemistry to promote gas bubble-oil droplet interaction

NORTH SEA - PILOT TEST RESULTS

The test performed with the TST TST-CFU at the tie in points shown in the schematic (Fig. 3) showed promising results. Table 1 summarises the TST-CFU CFU performance and shows the results observed at the different tie in points with respect to oil in water, environmental analyses and oil droplet size as three separate issues.

Fig. 3 – North Sea Field - Process Schematic

Produced Water & Environmental Conference 5-6 June 2013 Abstract Table 1 - Results obtained during testing at different tie-in points

5.1

Tests DS of the degasser

The test performed DS of the degassing vessel showed that one stage of the TST-CFU treated the water from a OIW concentration in average of 20 mg/l down to 2 mg/l, which is a 90 % reduction of OIW (Table 9). The existing CFU had an OIW outlet of ~7.8 mg/l, which gave an average of approximately 61% OIW removal by the existing CFU. 5.2

Tests DS of the first stage separator

During the test performed after the 1st stage separator, the single stage TST-CFU treated the water to a lower OIW concentration than what was being achieved from the flocculation vessel and hydrocyclones combined. By using a three stage single vessel TST-CFU unit, same or better results were achieved than having several single stage vessels in series. The three stage single vessel unit treated the produced water to the same level as the combined treatment with three separate exisiting produced water technologies (hydrocyclones, degasser and exisiting CFU). The result was 98% OIW removal. 5.3

Tests DS of the 1st stage hydrocyclones

In the test DS of the 1st stage hydrocyclones, the single stage TST-CFU treated the water to an OIW concentration below the concentration measured by the treatment of the degasser and the existing CFU. By subsequent treatment over a second stage TST-CFU or by application of flocculant upstream of the one stage TST-CFU, the effluent OIW concentration was further reduced by 1-2 mg/l. 5.4

Tests DS of the 2nd stage hydrocyclones

The test DS of the 2nd stage hydrocyclones showed that the single stage TST-CFU treated the water to a level far below the level reached by the treatment from the existing degasser and the existing CFU. A concentration down to 2 mg/l OIW was reached, and a treatment efficiency of 90% OIW removal was obtained.

Produced Water & Environmental Conference 5-6 June 2013 Abstract 5.5

Oil droplet size

The most promising overall result was that the TST-CFU was more effective in removal of small oil droplets than the existing conventional CFU installed on the platform. 50 % of the oil droplets > 2 µm (d0.5) were removed during operation DS of the degasser. For comparison, a sample was taken DS of the existing CFU which exhibited a d0.5 of 6.6µm. OIW measurement from the outlet of the TST-CFU was 2.4 mg/l compared to 7.8 mg/l from the existing conventional CFU at the same time. The results showed that the TST-CFU was capable of removing >90 % of oil droplets >3 µm. 5.6

Oil-in-water (OIW) analyses

The samples were analysed using the Arjay Fluorecheck Instrument. The instrument was directly calibrated with the existing GC method for discharge compliance monitoring. Produced water samples were extracted with pentane. Control samples were frequently run to control the instrument. 5.7

Oil droplet- and particle size distribution analyses

The particles (oil droplets and solids) in different samples were characterized by measuring the size distribution using Malvern Mastersizer S. The measuring principle of the Mastersizer is laser diffraction, i.e. each oil droplet or particle with a specific diameter changes the laser with a unique angle. Particle size distribution between 0.5 and 878 µm was performed using a 300 RF lens and a cell fitted with a magnetic stirrer. Clean, particle free deionized water was utilised as a blank for the Mastersizer, for sample dilution and as the cleaning fluid. The percentage distribution was recorded, as well as the total concentration of particles and the d0.1, d0.5 and d0.9 (cumulative particulate diameter (µm) under which 10, 50 and 90 vol% particles analyzed are classified).

6

CONCLUSION AND FUTURE WORK TM

The multi stage single vessel design of the TST-CFU Compact Flotation technology is very effective in treating produced waters with high oil concentrations and reducing the outlet OIW to very low discharge levels. The technology has been proven to handle small oil droplets. The TM vertically oriented multi stage compact flotation vessel design of the TST-CFU offers significant weight and space reductions. The 100% liquid filled compact flotation design is well suited for high oil separation efficiencies on floating platforms. Computational fluid dynamics (CFD) is a powerful diagnostics and design tool that allows equipment designers to understand the system performance. The CFD analysis helped in upgrading the existing design and improve performance for larger flow rates. TM

Thus far the next generation TST-CFU compact flotation technology has been installed at several platforms and is performing satisfactorily. Other operating companies in the GoM and TM other deepwater regions have also shown an interest in applying the TST-CFU design in their produced water treatment systems. As feedbacks from existing and new field installations is TM received, additional enhancements will be made to the TST-CFU design.

7

NOTATION

ASME American Society of Mechanical Engineers

Produced Water & Environmental Conference 5-6 June 2013 Abstract BTEX CFD CFU DS EOR GC GoM MS2 NPD OIW PAH µm

Benzene, Toulene, Xylene Computational fluid dynamics Compact Flotation Unit Downstream Enhanced Oil Recovery Gas Chromatograpfy Gulf of Mexico Multi Stage 2 Norwegian Petroleum Directorate Oil in Water Polycyclic aromatic hydrocarbons Micro meter

8

REFERENCES

[1]

TS-Technology AS Presentation, Jorn Folkvang, Terje Kornberg, December, 2010.

[2]

Advantages with the flotation technology of TS – Technology, Per Gramme, 2011.

[3]

Results from tests with TS Technology CFU for produced water treatment offshore, Aquateam – Norwegian Water Technology Centre A/S, Eilen Arctander Vik, February 2009

[4]

Compact Induced Gas Flotation As An Effective Water Treatment Technology On Deep Water Platforms, OTC, T. Frankiewicz, C.-M. Lee, and K. Juniel, NATCO Group Inc., May 2005, Houston, Texas

[5]

J. Veil, Produced Water Management training course, TUV NEL, Aberdeen, April 2009

[6]

Developing Vertical Column Induced Gas Flotation for Floating Platforms using Computational Fluid Dynamics, Chang-Ming Lee, Ted Frankiewicz, NATCO Group Inc., September 2004

Produced Water & Environmental Conference 5-6 June 2013

Produced Water Filration Pilot for Fine Particles Stephen Coffee, Enerscope Systems Inc.

1

ABSTRACT

Enerscope Systems and a major oil & gas production company conducted an extensive 90-day test on an automatic self-cleaning filter at three (3) site locations in Azerbaijan 2012. Three test locations were chosen and tests where conducted on produced water representative of the operator’s three different fluid compositions for onshore and offshore oil production. The tests were conducted with an ESS self-cleaning screen test unit and allowed for solids particle removal down to 1 micron. The tests were executed on 10, 25 and 50 micron filtration degrees, and at various oil & solids concentrations, mixtures and temperatures. The goal of the test was to evaluate the reduction of the Total Suspended Solids (TSS) levels and to get a better understanding of the ability of the cleaning mechanism to achieve effective cleaning of the filter element during the automatic cleaning cycle. It was concluded that the filtration technology proved to be successful by reducing the solids content significantly as well as not creating large backwash volumes for retreatment. 2

INTRODUCTION

High TSS continues to be a major issue in the treatment of produced water prior to reinjection into the oil fields. A major initiative supported by our customer’s Operation Groups is on the way to solve this issue. Solutions are being sought for several processing locations onshore and offshore but new equipment trials are more easily carried out onshore. Self cleaning or back washable filters continue to be of particular interest to this major oil production company since they will require little manual work thereby reducing operating costs and minimizing personnel risks. Failure in consistently achieving required water specifications could potentially require cuts in oil production. A trial filter skid and new tie-in spools were designed and equipment procured. Tie-ins are covered under MoC 15321 and trials are covered under MoC 15323. Three tie-in locations were identified for the trials so the self-cleaning screens could be tested against different levels of produced water quality. These are: 1- Between Produced Water (PW) storage tanks and Hydrocyclones 2- Downstream of Dissolved Gas Floatation (DGF) 3- Downstream of Granular Media Filtration (GMF) The specific tie-in points were selected ensuring that enough pressure was provided at the filters inlet and for the return to go back to the PW storage tanks to minimize operations disturbances. The produced water contained solids (in this case, fine colloidal solids and sand particles), which needed to be removed prior to the fluid continuing downstream.

1

Produced Water & Environmental Conference 5-6 June 2013 The produced water also contained various hydrocarbons and waxes and a variety of chemicals. This mixture, often called “Schmoo” can have a negative impact the performance of any type of solid and oil removal filtration system. Even without the presence so of Schmoo many operators have experienced problems with other self-cleaning filters that were unable to keep themselves clean while filtering produced water. In 2012, Enerscope Systems tested the ESS Self-Cleaning Screen to see how this unit compared to others on the market with reducing solids content in produced water in our customer’s production streams. The goal of the testing was to confirm how much of a reduction in solids content was achieved with the tested filtration systems and equally important, to examine the ability to maintain reliable self-cleaning characteristics. Since the filters are regenerative, each cleaning cycle should result in a “clean condition” or a return back to the starting point of pressure loss. Tests were conducted on three (3) produced water streams for which solid particles were to be removed down to a filtration degree of 1 micron. This paper will provide some details of the test, the results, and the recommendations for installations on various fluid streams. 3

HOW THE ESS SELF-CLEANING SCREEN WORKS

Enerscope’s ESS filters are automatic self-cleaning screens that operate continuously without interrupting the system flow or requiring duplicate equipment. They are designed for very high efficiency solids removal- even light and floatable debris. These units are heavy-duty, automatic, self-cleaning screens that are designed for 5,000 to 400,000 bbld per unit and filtering down to 1 micron using various sized screens (down to a 10 micron screen). The cleaning mechanism, a focused, suction-scanning technology, keeps the units in operation and cleans without interrupting system flow. Self-cleaning is performed only when needed based on differential pressure (dP). This improved technology results in minimal usage of liquids (a fraction of a percentage) and therefore, significant energy savings. The ESS is ideal for a final polishing filter for most produced water, sea water and pipeline flushing applications. It is also used for pretreatment for UV and membranes for potable water systems on platforms and FPSOs as well as boiler feed water for SAGD.

4

TECHNOLOGY

One of the most important criteria for any self-cleaning filtration technology is the ability to clean the filter element completely after each backwash interval. The goal is to return the screen to its original “clean” condition after each cleaning cycle.

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Produced Water & Environmental Conference 5-6 June 2013 If (backwash) cleaning is not sufficient, then the screen has not been cleaned to its original state and a new cycle starts with a dirty screen, meaning it will plug even more rapidly. Testing proved that for any automatic self-cleaning filter design, a focused cleaning system is the most efficient cleaning method. For this produced water test, Enerscope Systems utilized a “focused scanning” technology and a spring loaded cleaning nozzle to keep the filter screen clean. The technology uses a suction-scanner which releases flush water at atmospheric pressure through an exhaust valve. The reversed flow of high velocity water is created by the differential pressure between the positive working pressure of the vessel and the atmospheric pressure at the exhaust valve. This high velocity water stream pulls the debris layer, called a “filter cake” off the screen and out the exhaust valve. The suction-scanner is a hollow stainless steel pipe with tubular nozzles evenly spaced along its length. A combination of a threaded drive shaft and motor creates a spiralling motion of the suction scanner nozzles, which sweep across 100% of the screen in a single 16 second stroke. Newly designed spring loaded suction nozzles have been implemented in order to achieve efficient cleaning of sticky solids from extra fine screens (10 and 25 microns). 5

ADVANTAGES Self-cleaning technology saves maintenance time and cost. Low fluid loss reduces downstream treatment. Low and steady pressure loss saves energy and provides a more predictable operating system. Real-time self-cleaning filters: cleans automatically when head-loss reaches pre-set value for easy system design. Uninterrupted water supply: cleans in seconds without interrupting downstream flow eliminating the need for duplication of equipment. Flexibility of control options: hydraulic or electronic control for more design flexibility. In-line inlet and outlet configuration for simplified piping.

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TESTING

Although the tested self-cleaning filtration technology has been successfully installed for almost a decade on produced water and sea water applications, Enerscope Systems and our customer decided further testing was necessary due to the specific nature of the customer’s produced water and the specific region’s requirements. Testing concluded that the ESS filtration technology proved to be successful and fully capable in handling produced water and in reducing the solids content necessary to improve the performance of their produced water streams in various locations.

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Produced Water & Environmental Conference 5-6 June 2013 Additionally, the testing proved the filter’s capability to be completely regenerative and to return to its initial “clean” condition after each cleaning cycle. The test set-up incorporated accurate and controlled flow and pressure allowing for steady testing conditions. With these parameters, various tests were conducted to learn from each of its contributions. Planned pilot conditions: - 5 to 30 m3/h - 2.5 to 10 bar inlet pressure - 20 to 90 C - 20 to 80 mg/l of solids - 1 to 100 mg/l of oil - Solids to be clays, fine silica, FeS - Oil to be 30-35 API - PSD to be (0-2 micron @ 20%, 2-5 micron @ 30%, 5-10 micron @ 30%, 10-100 micron @ 20%) Water temperature was between 20-68 degrees Celsius and the working pressure was above 2.5 bar during the self-cleaning cycle. A low water temperature and low working pressures allowed testing the filter under very difficult conditions. Ideally, more pressure (5 bar) and higher temperatures (20-50 C) would have been offered a more efficient backwash. The filter piloted was the smallest filter in the Enerscope Systems product range of self-cleaning filters: Model ESS 15-4 (effective filtration area: 1500 cm2. Open area: approximately 40%, depending on type of filter screen), generating approximately 15-23 liters of back flush water per cycle. Filter Skid Description: A transportable skid has being designed for these trials. It contains the following: - Enerscope self cleaning filter - Hose connections (Inlet, Outlet and Flush Outlet) - Skid isolation valves - Drain connections - Sample connections - Inlet and flush line pressure gages - Inlet to outlet differential pressure gage - Outlet flow meter. The skid is steel framed and has been built in compliance with offshore transport requirements. Lifting lugs and forklift channels are provided for easy movements. The overall weight is estimated at less than 2 tons. Also provided with the skid package is a motor; instrumentation and control panel that are Zone 2 compliance. All skid added instrumentation and electrical works are Zone 2 compliant. The slurry produced will be collected in a cuttings collection bin located next to the filter skid.

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Produced Water & Environmental Conference 5-6 June 2013 Tie-in Locations: Three tie-in locations were identified for the trials so it could be tested against different levels of produced water quality. These are: 1- Between PW storage tanks and Hydrocyclones 2- Downstream of DGF’s 3- Downstream of GMF’s The specific tie-in points were selected ensuring that enough pressure was provided (2.5 barg min) at the filters inlet and for the return to go back to the PW storage tanks to minimize operations disturbances. Trial Run Procedures: 1- Set filter in differential pressure self cleaning mode (0.5 Bar). 2- Open the 3”globe valve on filter skid slowly until the flow meter reaches 30 m3/hr. 3- Wait for flushing cycles and adjust ball valve so pressure gauge in flush line reads approximately 4 bar lower than in the inlet line and flushed slurry has the right consistency (not too watery). 4- Take inlet and outlet samples once an hour for the length of the trial run. Record inlet pressure, filter dp and flow rate readings while sampling. Each trial is to last approximately one week (less if collected data is deemed sufficient). 5- Take slurry sample from slurry line before end of run. 6- Stop run by closing globe valve. 7- In an emergency situation if safe to do so close the valve at the respective pump discharge TIP.

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TRIAL SKID ARRANGMENT

8

SAMPLE TEST RESULTS

Testing was conducted at 3 locations with all 3 size screen elements (10, 25, and 50 micron) for the duration of a week or more for each location and screen. In addition, various flows and dPs where explored.

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Produced Water & Environmental Conference 5-6 June 2013 Here are the overall averages of the 12 weeks of tests, based on the planned flow and dP conditions: 50 micron The 50 micron element ran for 1 week at a 0.5 bar maximum differential setting and a flow rate of 30 m3/hr. The samples were taken at regular sampling time (02:00, 8:00, 14:00 and 20:00). Here is a summary of the preliminary data analysis: - Average 43 ppm OIW at the inlet and 42 ppm at the outlet (locations 1, 2, 3 ranged from 40-110 ppm) - Average 106 mg/l TSS at the inlet and 87 mg/l at the outlet (location 1, 2, 3 ranged from 70-140 mg/l) 25 micron The 25 micron element ran for 1 week at a 0.5 bar maximum differential setting and a flow rate of 30 m3/hr. The samples were taken at regular sampling time (02:00, 8:00, 14:00 and 20:00). Here is a summary of the preliminary data analysis: - Average 43 ppm OIW at the inlet and 42 ppm at the outlet (locations 1, 2, 3 ranged from 40-110 ppm) - Average 93 mg/l TSS at the inlet and 85 mg/l at the outlet (location 1, 2, 3 ranged from 70-140 mg/l) 10 micron The 10 micron element ran for 1 week at a 0.5 bar maximum differential setting and a flow rate of 30 m3/hr. The samples were taken at regular sampling time (02:00, 8:00, 14:00 and 20:00). Here is a summary of the preliminary data analysis: - Average 44 ppm OIW at the inlet and 41 ppm at the outlet (locations 1, 2, 3 ranged from 40-110 ppm) - Average 83 mg/l TSS at the inlet and 78 mg/l at the outlet (location 1, 2, 3 ranged from 70-140 mg/l) 9

COMMENTS FROM TEST

A highly accurate differential pressure (dP) measurement was used during the trial for checking on the state of the filter screen. Oil by itself does not influence cleaning interval times: all oil will go through the filter screen, even at 10 micron filtration degree No significant improvement was observed at the high (0.9 bar) dP The generated waste water (typically up to 1% of filtered flowrate) is a function of how many times the filter will enter its self-cleaning cycle As in all locations, the flushing proved to be effective in cleaning the screen throughout the trial Coagulant injections upstream of the screen appear to assist in solids removal

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Produced Water & Environmental Conference 5-6 June 2013 Actually Particle Size Distribution (PSD) was much smaller than expected resulting in little change in screen outlet conditions at location 2 and location 3 and with the 50 micron screen (one test suggested 98% were under 10 micron) Lower pressure differentials increase removal efficiencies when particles were fragile or more easily fractured or extruded 10

LESSONS LEARNED The higher the solid concentration and the finer the filtration degree, the larger the filter area is required. Hydrocarbons, by themselves, do not influence the build-up of differential pressure over the filter. The combination of oil and solids will result in a faster buildup of differential pressure; it is believed that the oil sticks to the solids, making the particles slightly larger, thus more particles will be stopped by the filter. Focused scanning self-cleaning technology is able to filter produced water and will assist in providing cleaner screens, even when filtration degree is 10 micron with oil-wetted solids.

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CONSIDERATIONS FOR FUTURE PW INSTALLATIONS Minimum 5 bar working pressure to allow for optimal selfcleaning performance when using 10 or 25 micron screens Finer filtration degrees will require more filtration area for the same flow rates Total filtration area will largely depend on solids load to be removed and flow rate. Therefore, requirements and given conditions must be clearly defined and studied. More accurate PSD aide in proper sizing. Higher temperatures (over 35 C) aid in solids removal When using the 10 and 25 micron screen elements, units work better when oil & solids concentrations are under 80 mg/l.

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Produced Water & Environmental Conference 5-6 June 2013 12

CONCLUSIONS

The performance of the Enerscope ESS Self-cleaning Screen has been demonstrated by in-house testing and by extensive field trials, such as this pilot, to be effective in a variety of produced water and sea water applications. The objective of this pilot evaluation was to reduce the TSS levels to meet the customer’s and regions requirements. Tests were conducted on produced water representative of the three fluid streams for the operator’s fluids at their location in Azerbaijan. The tests were conducted with an ESS self-cleaning screen test unit and allowed for solids particle removal down to 1 micron. The tests were executed on 10, 25 and 50 micron filtration degrees, and at various concentrations, mixtures and temperatures. Testing concluded that the filtration technology proved to be successful of reducing the solids content enabling downstream equipment to be used at the operator’s location(s). The testing also proved that the filter could clean itself back to its original clean state and starting pressure differential. Oil & Gas production companies continue to collaborate with Enerscope to expand the scale of test programs to improve filtration methods to replace conventional barrier and media methods, particularly in the treatment of produced water. There are many economic advantages for the use of self-cleaning screen filters, such as their low operating costs, making it a viable filtration method. This new technology offers new solutions to increasing production while reducing production costs and meeting environmental responsibilities for production companies globally.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract

Study of Oxidation Processes for Produced Water Treatment Nicolas LESAGE, Pierre PEDENAUD, Matthieu JACOB, Julie SAVIGNAC, Mohamed MOUZAOU and Christine PEYRELASSE, TOTAL

1

INTRODUCTION

Treatment of produced water is an essential obligation associated with production of crud oil regardless of final use of produced water. This is vital in case of disposal of the wastewater into the surrounding environment as high quantity of the water and its non natural pollutants can cause severe environmental effects on biodiversity and natural life of species and therefore indirectly affect life of the peoples. The environmental and social concerns have resulted in series of legislation approved by national and international law making bodies. These govern norms and regulations regarding level of different pollutions in produced water. Development of new wastewater treatment technologies is accordingly an essential task for oil and gas producing companies to achieve obligated levels urged by legislation. The framework of this project is also defined based on this necessity. Present study proposes to compare advanced oxidation processes to remove dissolved compounds from produced water [1, 2, 3]. Catalytic ozonation and electro-oxidation processes are compared to treat a synthetic produced water. 2

MATERIAL & METHODS

2.1 Produced Water The following table presents the composition of the produced water. Table 1 – Composition of synthetic produced water Chemical Phenol Acetic acid Naphthenic acid Pyrene Naphtalene

Concentration (mg/L) 200 200 25 0,05 0,95

COD (mg/L)

TOC (mg/L)

750

250

The salt content is adjusted with NaCl to obtain a salinity in a range from 0 to 100 g/L.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract 2.2 Anayltical Procedures The following table introduces the analytical methods used. Table 1 – Analytical procedures Parameter

Unit

Method

Chemical Oxygen Demand

mgO2/L

ISO 15705

Total Organic Carbon

mgC/L

NF EN 1484

Ozone (gas)

mg/L

ISO 10523 BMT 964 BT analyser

Dissolved Ozone

mg/L

Indigo method

pH

2.3

Catalytic Ozonation

Experiments were carried out with a semi-batch ozonation process at controlled temerature in the 1.2 L reactor. The liquid flow was in batch mode whereas the gas flow was in continuous mode. A global ozone balance was performed for eah experiment.

Fig. 1 – Ozonation pilot scheme Hydrophilic zeolite was used as catalyst. 2.4

Electro-Oxidation

Experiments were carried out with a batch electro-oxydatrion process (600 ml). The temperature is adjusted using a thermostatic bath, the solution is stirred using a magnetic stirrer, oxidation is performed using Boron Diamond Doped electrodes. The current density is adjusted during the tests. An polarity invesrion was applied in order to limit electrode plugging.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract

Fig. 2 – Electro-oxidation pilot scheme 3

RESULTS

3.1

Catalytic Ozonation

The following figures present the evolution of TOC, COD and pH as function of time. Experiments were performed at 2g/L of catalysts, and 35°C.

Fig. 3 – Evolution of TOC versus time on a synthetic produced water.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract

Fig. 4 – Evolution of COD versus time on a synthetic produced water

Fig. 5 – Evolution of pH during oxidation Results show a decrease of TOC and COD content as function of time whatever the trials. However addition of catalysts enhances the oxidation processus. Even with catalysts addition, the total mineralisation of the effluent is not achieved. In

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Produced Water & Environmental Conference 5-6 June 2013 Abstract those operating conditions, hydrophilic zeolite seems to lead to a better mineralization (62% of TOC removal vs. 50% with Al2O3). Fig 5. points out first a pH decrease before a stabilisation (O3 or O3/Al2O3). The first decrease could be due to the formation of organic acids, whereas the increase could be attributed to the consumption of the organic acids. The hydrophilic zeolite has a buffer effect on the pH. This buffer effect (at pH > 7) could play on hydroxyle radicals formation. Further investigations are ongoing to assess the impact of buffer effect vs. O3 decomposition. 3.2

Electro-Oxidation

The following figures present the evolution of TOC and pH as function of time for electroxidation tests.

Fig. 6 – Evolution of TOC vs. Time on synthetic produced water with applied CD of 8 mA/cm² for BDD and 78 mA/cm² for BDD+50g/L NaCl.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract

Fig. 7 –pH evolution during produced water electro-oxidation with applied CD of 8 mA/cm² for BDD and 78 mA/cm² for BDD+50g/L NaCl. Fig. 6 shows the decrease of TOC as function of time during electro-oxidation (with and without salts). Results point out that without salt there is no oxidation. Indeed Fig.6 does not show any varaiation of the TOC content during 140 min, whereas when 50g/L NaCl is added, 44% of TOC is removed. Aliphatic compounds are also produced, and for long time electrolysis all organic intermediates are oxidized to CO2 and H2O [4]. Fig.7 shows that pH strongly increases during oxidation process (especially when salt is added). Indeed pH passes from 4.5 to 9.1. The hydroxile radicals formation is promoted as such pH (>8). 4

CONCLUSIONS

This study aims to compare 2 oxidation process to remove organic subtsances within produced water. Results point out that when the salt content is low, electro-oxidation does not have any impact on the organics, whereas catalytic ozonation could remove more than 60%. In the tested operating conditions, hydrophilic zeolite leads to a better oxidation than Al2O3. Further tests are ongoing in order to assess the impact of salts and pH on catalytic ozonation. Other type of electrodes are also testing.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract 5

REFERENCES

[1]

Matthieu Jacob, Nicolas Lesage, Pierre Pedenaud, Patrick Gajowka, and Christine Peyrelasse, Hybrid Oxidation Process for the Treatment of Produced Water, 9th Produced Water Workshop, Aberdeen,18th - 19th May 2011

[2]

Julie Bergraser, Julie Savignac, Matthieu Jacob, Pierre Pedenaud, Nicolas Lesage, Effect of carbonates and NaCl on ozonation of naphthenic acids in oil sands process water, Ozone and Related Oxidants in: Safe Water along its Cycle, April 23 – 24, 2013, Berlin, Germany Rodgers, J.D., W.J. Jedral, and N.J. Bunce, Electrochemical oxidation of chlorinated phenols. Environ. Sci. Technol, 1999(33): p. 1453-1457. Iniesta, J., et al., Electrochemical oxidation of phenol at boron-doped diamond electrode. Electrochimica Acta 2001(46): p. 3573-3578.

[3] [4]

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Produced Water & Environmental Conference 5-6 June 2013 Abstract Removal of Dispersed, Emulsified, and Soluble Hydrocarbons and Oilfield Chemicals Utilising a Regenerable and Reusable Media Mike Smith, PWA Europe Neil Poxon and Jay Keener, PWA Inc.

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INTRODUCTION

PWA Inc. provides novel waste treatment solutions and services to the oil and gas industry. The foundation of the company’s technology offering is Osorb ® – a patented, regenerable media that removes dispersed, emulsified, and dissolved hydrocarbons and oilfield chemicals from produced water. The primary market for the Osorb technology is the treatment of produced water to meet environmental and legislative discharge limits and water reinjection specifications. PWA was founded in Wooster, Ohio, USA, where its headquarters are currently located and has opened a European office in Aberdeen, Scotland, UK.

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TECHNOLOGY

Osorb® is a regenerable, absorbent media capable of removing dispersed, emulsified, and soluble hydrocarbons and organic oilfield chemicals from produced water. With an extensive pore structure, internal surface area of over 550 m2 per gram, and the ability to increase absorption capacity by volumetrically swelling, the media has the capacity to capture over 100% w/w dispersed hydrocarbons before the treatment efficiency begins to gradually decline from as high as 99.9% hydrocarbon removal. The media also captures dissolved organics and can capture up to 800% of the media’s own weight in neat organics. Two onshore field trials have been completed in 2013 in the Far East using Osorb feasibility test columns. During these two trials, Osorb respectively reduced an average 85 ppm oil-in-water (OIW) to 2.9 ppm and an average 155 ppm OIW to 8.5 ppm OIW. In addition to dispersed and dissolved hydrocarbons, Osorb has exhibited significant promise for removing a range of organic oilfield chemicals to reduce the Environmental Impact Factor (EIF) of discharges and reduce loading on downstream processing equipment. The chemicals include some corrosion inhibitors and surfactants, such as those used in Alkaline Surfactant Polymer (ASP) chemical EOR applications. Beyond water treatment capabilities, the Osorb technology offers small footprint, flexible application methods including bulk media, cartridges, or injection dosing and coalescence system. There is additionally a range of flexible processes for regeneration of the Osorb media, and the process can be designed for full self-containment or utilization of existing onsite resources. No consumible waste is generated during the process of regenerating the Osorb for reuse, which reduces the needs to handle, transport, and dispose of hazardous waste in comparison to alternative adsorption / absorption medias.

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Produced Water & Environmental Conference 5-6 June 2013 Abstract

The Hassles and Rewards of Oil in Water Monitoring: Is it Worth it ? Greg Reeves, Arjay Engineering Ltd

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INTRODUCTION

The focus of attention in an upstream or downstream oil operation is, understandably, the economics of producing and refining of oil. To help keep operations running smoothly and efficiently, there are many process variables and sensors that are routinely monitored. Some of these are continuous in-situ devices such as pressure, temperature and flow while others are discrete samples drawn for quality control analysis or other parameter testing. Regulatory authorities have traditionally been the driving force behind monitoring for oil content in water but advancements in field instrumentation design has shown industry that there can be many other benefits to the routine effluent monitoring of oil in produced water. This paper will look into the many facets of the oil in water monitoring regimen and discuss the pros and cons that can contribute to rewarding results. Oil in water monitoring can be looked at from a regulation view or from a process optimization view. Techniques and policies that affect both views will be considered with the intent to debunk, or least alleviate, the hassles while showing the rewards. Offshore oil developments have been commercialized for little over 100 years. The collection and interpretation of environmental impact data even less, and the use of instrumentation offshore for oil in water monitoring even less than that. The environmental and instrumentation segment of the oil industry is on a constant learning curve. Changes and improvements are routinely being made to adapt to the actions and reactions of the various governments and industries involved. This is a positive evolution, but when it comes to understanding oil in monitoring policies and procedures, this can be a major contributor to confusion. 2

REGULATION

Regulation is usually one of the first introductions an operator has to the oil in water monitoring world but this doesn't have to be a stressful one. Regulation constantly evolves as industry intensifies and environmental knowledge and instrumentation advances. Ecosystems differ all over the world and as new regions are explored and different oil retrieval techniques are introduced, such as unconventional fracturing, regulation needs may change. The hassle is keeping on top of it.

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REGULATORY AUTHORITIES

Various countries or groups of countries throughout the world have their own regulatory authorities. These authorities will be the source for discharge limits and analytical methods. Most authorities rely on the guidance and recommendations of non-enforcing organisations. The United States has the authority of the USEPA to enforce regulations through various channels such as the Clean Water Act and its NPDES (National Pollutant Discharge Elimination System). Canada's National Energy Board enacts federal legislation to give regional authority to bodies such as the Canada-Newfoundland Labrador Oil Petroleum Board (C-NLOPB). In the North Sea area, the OSPAR Commission is responsible for encouraging responsible environmental activity by setting standards and guidelines for it's member countries; which include Norway, the UK and the Netherlands. These activities include matters pertaining to the concentration of oil discharge produced water. In the UK the Department of Energy and Climate Change enforce the OSPAR recommendations. In Norway, the KLIF is the enforcing body. 4

STANDARDS AND GUIDELINES

To help enforce guidelines, standard measurement methods are used so that similar industries reporting to an authority are on an equal playing field. Various organisations around the world can be approached to write a standard. Usually, an unbiased organisation that is recognized with a high degree of integrity is approached by an interested committee, but in reality, any one of us could write a standard. However, without solid third party support, it would be difficult to convince a local authority to adopt it. A change to an approved method can take many years and due to the costs involved, it usually meets with resistance. Oil in water monitoring practices in the North Sea follow standards that have been developed through the International Standards Organization. Specifically, ISO 9377-2 has been adopted. In other regions of the world, other standards may be referenced. For instance, in the USA, the USEPA refers to ASTM D7066 for TPH in wastewater and the EPA 1664 for oil and grease . ASTM (originally the American Society for Testing and Materials) is an organization focused on verifying and writing standards. Both ISO and ASTM do not write or enforce laws and methods for testing oil in water. They only help to develop and document them. There is a shift toward international harmonization of standards but it is slow. Country needs and attitudes are unique and even if a base harmonized standard is accepted, each country or region will usually add a few twists that localize the standard.

2

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OIL DEFINITION

Coming to terms with the definition of oil presents another hassle. Like most industries, acronyms are common place and similar terms can often have different meanings. Units of measurement for oil content concentrations in discharge water is typically recorded as a mg/l (milligram per liter) but often described as ppm (parts per million). These values do not actually correlate. For example, the mg weight of 30 parts per million of API 25 oil is not the same mg weight as 30 parts per million of API 65 because they have different specific gravities. However, for the sake of general discussions, these two are mostly interchangeable. Other terms include FOG - fats oil and grease TOG - total oil and grease TPH - total petroleum hydrocarbons fats)) Dispersed oil Free oil Emulsified oil Dissolved oil BTEX aliphatic aromatics PAH - poly aromatic hydrocarbons

(polar organics removed (animal & vegetable

A common first question from the field is 'What type of oil should I measure and what instrument should I use to measure it ? Another hassle now presents itself because there is no definition of oil. Oil in water measurement definitions are Method Dependent. This means that the analytical method is determined first and whatever is in the presented sample that causes a response defines what is being measured. Historically, two reportable analytical methods have been predominant for oil in water; infrared absorption and gravimetric. Both used Freon solvents to extract the oils out of the water prior to analysis which provided a common method to pre-qualify the oils to be measured. The gravimetric approach heats the extracted sample to evaporate the solvent and weighs the residual oil. The infrared approach measures the amount of infrared absorption in the solvent at a targeted wavelength and correlates this to a pre-calibrated curve of absorption vs. ppm (mg/l). Due to the Montreal Protocol restrictions on the production of freons in the late 90's, alternative solvents were introduced and the playing field became less clear as new methods were introduced and others superseded. In the early 2,000's in the North Sea area, the OSPAR Commission adopted a technique called GCFID (Gas Chromatograph - Flame Ionization Detection). ISO 9377-2 uses a pentane solvent extraction for preliminary sample qualification. Here is an example of two regulated discharge limits. For produced water discharge from platforms, most countries follow one of these guidelines.

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Ospar: 30 mg/l daily composite average USEPA: 29 mg/l monthly average, 42 mg/l maximum For oil content reporting to the responsible authority, an accredited third party lab is typically required to perform the actual test using the locally approved analytical method for that particular industry. When sending a sample to an accredited lab, be sure to advise the intent and purpose of your sample. The lab will be able to assist with the analytical method required for the authority you are reporting to. 6

SAMPLE TAKING PROCEDURES

The next hassle is actually taking a sample and sending it to the lab. There are no common or formal rules on how to take a sample, although there are plenty of guidelines. The hassle is knowing what guidelines to follow. The lab will recommend procedures for sample preparation. Some methods may require the pH of the sample to be lowered to