4. options assessed

AZERI, CHIRAG & GUNASHLI FULL FIELD DEVELOPMENT PHASE 2 ENVIRONMENTAL & SOCIAL IMPACT ASSESSMENT

OPTIONS ASSESSED 4-1

4. OPTIONS ASSESSED

4.1 Introduction This chapter of the ESIA presents a summary of the engineering options evaluated by ACG Phase 2 during the early design stages of the project. It explains briefly both how and why particular options were either adopted or rejected, and thereby seeks to demonstrate that, within the project’s engineering and financial constraints, the current design represents the Best Practicable Environmental Option (BPEO).

The information set out within this chapter summarises the findings of a raft of environmental studies undertaken to date by both Phase 1 and Phase 2. In all cases the studies have been prepared in accordance with “BP Amoco Upstream Environmental Performance Guidelines for New Projects and Developments” with the aim of ensuring that the selection of the final development concept and the chosen technical solutions are made in the most cost-effective manner.

4.1.1 Approach The evaluation of Phase 2’s engineering design options was generally carried out by means of a three-stage process:

i) identification of potential control measures/technology options;

ii) quantification of emissions reduction/reduction in environmental impact which could be achieved by the implementation of each of the feasible options; and,

iii) evaluation of options.

For this last stage each of the options was assessed against a set of evaluation criteria to determine its suitability for incorporation within the project design. The evaluation criteria are listed in Table 4.1 below.

Table 4.1: Evaluation Criteria

Criterion Description

Impact on Safety Would implementation of the option have a significant negative impact on safety? If yes, then the option is not acceptable.

Legislation Does the option breach any current legislation or any legislation anticipated within the next five years? If yes, then it is not acceptable, as it would contravene BP’s Environmental Policy.

Company/Partner Policy

Does the option breach BP’s business policies or any policy requirements of its Partners? If yes, then the proposal is unlikely to be acceptable.

Good Engineering Practice

Does the option breach the principles of good engineering practice? If yes, then the proposal is not acceptable.

Operability and Maintenance

Is the option realistically operable and maintainable? If no, then it is not acceptable.

AZERI, CHIRAG & GUNASHLI FULL FIELD DEVELOPMENT PHASE 2 ENVIRONMENTAL & SOCIAL IMPACT ASSESSEMENT

4-2 OPTIONS ASSESSED

Criterion Description

Cost/Benefit Factors

The costs of the option should be evaluated in the context of the environmental benefits/disbenefits and BACT (Best Available Control Technology). Most of the environmental issues will need to be considered from a local/regional point of view, but would be expected to reference environmental quality standards using established impact assessment procedures. For Carbon Dioxide and Methane emissions covered by the internal BP emissions trading scheme a planning price or price range will apply.

Reputation Issues Are there reputation issues involved with the option? If yes, then it may be unacceptable. In this context, reputation issues include public/NGO/government interest, impact on third parties, etc.

4.1.2 Focus Areas The evaluation of project options focussed on the following key areas;

• Combustion gas emissions and energy efficiency;

• Flaring;

• Venting;

• Fugitive emissions;

• Discharges to sea;

• Ozone depleting chemicals;

• Drilling Discharges; and,

• Pipeline Installation.

The options evaluation is presented in the sections below. For each of the above focus areas a short introduction is provided of the issues involved. The outcome of the evaluation is then presented in a tabulated format, highlighting why an option was adopted or rejected, or where assessment/design work is still on going.

4.2 Options Assessed

4.2.1 Combustion Gas Emissions Combustion gas emissions are the waste products, which result from the burning of fossil fuels (in this case fuel gas and diesel) to generate power or heat. They include carbon dioxide (CO2), carbon monoxide (CO), oxides of nitrogen (NOx), unburned hydrocarbons, particulates, and, if sulphur is present in the fuel, oxides of sulphur (SOx).

With the exception of flaring – which is treated as a separate topic in the section hereafter – the Phase 2 combustion emissions arise principally from gas turbines (used for gas compression, water re-injection, and electrical power generation) and fired heaters at Sangachal Terminal.



There are five principal approaches by which combustion gas emissions (or particular components within the combustion gases) can be eliminated or, at least, minimised.

These are by:

i.) sequestering the CO2 produced by conventional power generation technology in some form of a ‘reservoir’;

ii.) deploying alternative means of power generation which do not result in the production of combustion gases. Such alternative means encompasses renewable energy resources;

iii.) maximising the efficiency of energy usage across the project and thereby minimising the amount of combustion gases produced by MW of power generated (electrical and/or mechanical);

iv.) adopting combustion technology which minimises the generation of atmospheric pollutants. This technique relates principally to the use of Low NOx technology; and,

v.) removing the source of pollution from the fuel gas before combustion or from the products of combustion thereafter. This technique relates principally to SOx.

The options for the abatement of combustion gas emissions are described in Table 4.2.



Table 4.2: Summary of Combustion Emission Abatement Options


Option Potential Advantages of Option Potential Disadvantages of Option Outcome / Basis for Decision

CO2 Recovery and Sequestration

• This technology is based upon the recovery of the CO2 released from gas turbine generators and crude oil heaters (by means of flue gas scrubbing, gas compression and liquefaction), and its subsequent sequestration within a sub-surface reservoir. The technology provides a long-term sink for the disposal of CO2.

• CO2 recovery and sequestration has the potential to abate around 85% of CO2 emissions from turbines and heaters.

• Relatively novel technology and untried on gas turbines in the offshore environment.

• High cost of CO2 disposal ($40 to $60 per te) up to six times BP’s current CO2 budget trading price ($10/te).

• Presence of suitable geological disposal reservoirs within the Caspian is presently unknown.

• Little is known about the behaviour of CO2 injected into a geological disposal reservoir (an aquifer). A development would therefore require geological / geophysical characterisation of an aquifer to quantify its suitability for storage purposes. Detailed geological mapping from core/seismic data would be essential, as would be surveys and monitoring of injection wells.

• There are safety risks associated with CO2 leakage from a disposal reservoir, and associated liabilities.

• The technology reduces the thermal efficiency of a gas turbine from 35% to around 31%. It thus increases fuel gas consumption for the project.

• Potential weight penalty of additional scrubbing and re-injection plant.

Not adopted due to reasons of weight penalty, safety implications, technological novelty, and adverse economics.

Solar Thermal power generation

• Technology based upon the (partial) elimination of combustion gas emissions by the displacement of fossil fuel-derived energy with that derived from renewable (solar) energy.

• In principle a scheme could raise high temperature steam to drive a steam turbine and generate electrical or mechanical power.

• Scheme incapable of making significant contribution to Project energy requirements without necessitating impractically large solar collection areas (approximately 13,000 m2/MW).

• High costs of CO2 abatement (c.$120/te). • Diurnal energy fluctuations would in any case

necessitate back-up gas turbines or significant battery storage capacity.

Not adopted due to technical impracticality/limited contribution to energy requirements, and poor economics.





Solar Photovoltaic power generation.

• Technology based upon the (partial) elimination of combustion gas emissions by the displacement of fossil fuel-derived energy with that derived from renewable (solar) energy.

• Scheme would result in direct generation of electrical power.

• Scheme incapable of making significant contribution to Project energy requirements without necessitating impractically large solar collection areas (see above).

• High capital costs (onshore: $4,000/kWelec to $8,000/kWelec).

• High costs of CO2 abatement (c.$100/te). • Diurnal energy fluctuations would necessitate back-

up gas turbines or significant battery storage capacity. • Possible use in small-scale low power generation

applications, but overall of limited applicability. Typically used for minor duties on unmanned platforms.

Not adopted due to technical impracticality/limited contribution to energy requirements, and poor economics.

Wind power generation.

• Technology based upon the (partial) elimination of combustion gas emissions by the displacement of fossil fuel-derived energy with that derived from renewable (wind) energy.


• Very limited application offshore due to structural and safety considerations (offshore a wind turbine would either need to be located on a purpose-designed platform – at prohibitive cost – or would need to be sited on the Phase 2 production platforms. In this latter case the rotating blades of the wind turbine would represent a significant safety issue). The technology is thus limited to onshore or near-shore applications.

• High capital costs ($1,100/kWelec to $1,500/kWelec). • Marginal economics of CO2 abatement (c.$14/te to

$140/te depending upon ‘capacity factor’). • Diurnal energy fluctuations would necessitate back-

up gas turbines or significant battery storage capacity.

Not adopted due to technical impracticality/limited contribution to energy requirements, safety concerns, and poor economics.





Wave power • Technology based upon the (partial) elimination of combustion gas emissions by the displacement of fossil fuel-derived energy with that derived from renewable (wave) energy.


• Technology not sufficiently mature. There is presently no medium to large-scale industrial application for wave power: the limited number of existing schemes throughout the world are generally aimed at providing power to relatively remote communities.

• Local wave energy in Caspian is relatively low, which would necessitate an unfeasibly large development.

Not adopted due to technical novelty, relatively low energy wave environment, and consequential limited contribution to project energy requirements.

Centralised onshore power generation

• This option involves the generation of power onshore (at Sangachal Terminal) and its transmission via a sub-sea cable to the offshore platforms.

• Onshore power generation does not eliminate combustion gas emissions but offers the opportunity of minimising emissions per MWelec by increasing the efficiency of generation through the use of larger, more efficient turbines and combined cycle.

• Feasibility studies carried out to date (‘Caspian Phase 2 Power from Shore Options’, BP Power & Energy Upstream Technology Group, 15/10/01) have focused on power supply to offshore from an onshore power generation facility at Sangachal. The schemes evaluated included replacement of all offshore generators, and also replacement of the turbine drivers on the offshore injection pumps and compressors on C&WP with electric motors.

• All schemes were found to be economically adverse. Furthermore, the potential CO2 emissions savings are predicted to be very modest due to the high energy losses (c. 10%) associated with electrical power transmission via sub-sea cable over a distance of 180 km.

• There was also a significant technical concern regarding the size and weight of the high voltage DC/AC converter module offshore (40m x 30m x 18m and 1,200 te).

Not adopted due to size and weight concerns, and unfavourable economics.





Combined Heat & Power – Onshore

• This option involves the recovery of waste heat from the gas turbine generators at Sangachal Terminal, and its subsequent use for process heating. The scheme minimises combustion gas emissions per MWheating by reducing the process heating duty of the fuel gas-fired crude oil heaters.

• A detailed study was undertaken of waste heat recovery (WHR) at Sangachal Terminal (‘Review of Phase 2 Process Heating Options at Sangachal Terminal’, BP-2GZZZZ-EV-REP-0004 A1, BP, 12/04/02). A number of heating options were identified, from an independent stand-alone scheme based upon fired heaters – effectively a copy of the ACG Phase 1 design – through to a fully integrated terminal-wide WHR system.

• The most favourable WHR scheme is one, which recovers waste heat from all of the ACG Phase 1 and Phase 2 gas turbine generators, with additional top-up heat being provided, when required, by a 30 MW direct-fired heater. The scheme would enable Phase 2’s entire process heating demand to be met via waste heat recovery for most of the project life, with only a small short-fall being predicted between 2010 and 2015 when the fired heater would be required. The heater would also provide supplementary heat during downturn of the power generation system associated with outage of the BTC crude oil export pumps.

• The scheme would reduce fuel gas usage by 26,400 mmscf over the project lifetime, and reduce total CO2 emissions over the same period by 1,885 kte.

• Notwithstanding that the combined ACG Phase 1 and Phase 2 WHR scheme is the most favourable its overall economics are relatively adverse. For BP, a payback period of nine years (on a capital outlay of $ 4.55 M) is not attractive. From the position of Partners (who would be required between them to fund $8.8 M of the total investment cost of $13.35 M), the prospect is worse as they do not operate GHG trading schemes which would go some way to off-set expenditure on a WHR system. In addition, no value is ascribed to fuel gas the saving of which would otherwise provide a mechanism for economic payback.

Not adopted due to unfavourable economics.

Combined Heat & Power – Offshore

Option not relevant: there is no significant requirement for process heating on the offshore platforms.





Combined Cycle Power Generation (CCPG) – Offshore

• In this scheme waste heat would be recovered from gas turbine exhaust(s) in a heat recovery steam generator (HRSG). It would then be used to raise steam to power a steam turbine (delivering mechanical power or generating electrical power).

• Typically, the steam turbine will produce approximately a third of the power of the gas turbine feeding the unit. For example, two gas turbines operating at 25 MW will produce enough steam to give an additional 17 MW. Combined cycle therefore raises the overall thermal efficiency of a power generation unit to around 50%, thereby reducing combustion gas emissions per MWelec or MWmech.

• A detailed study was made of CCPG on the C&WP (‘Feasibility of Offshore Combined Cycle Power Generation on C&WP’, BP, 26/11/01). The study concluded that from a technological view point, offshore CCPG on the C&WP is feasible: a) field-life electrical power balances indicate that there will always be a power surplus from the moment that combined cycle system comes on stream: the implementation of CCPG would not compromise field-wide power availability, b) feed-back from two operators of offshore CCPG systems indicates that the systems are reliable.

• Depending upon the CCPG option selected, the implementation of this option could save between 134,000 te of CO2 per annum and 180,000 te per annum as an average over the field life.

• Neither of the PDUQs have sufficient available waste heat or power demand to make implementation of CCPG economically feasible. Offshore CCPG is therefore specific to the C&WP.

• The chief impediment to the adoption of combined cycle is the additional weight burdens, which the system would impose upon the C&WP and the consequential impacts upon CAPEX. It is estimated that a scheme comprising one 32 MW steam turbine generator plus HRSGs, bulks, structural strengthening, etc would add 1,500 te to the C&WP topsides dry weight, taking it well over the original float-over weight limit of 14,000 te. The scheme would require an additional CAPEX (when compared with the all-gas turbine Base Case) of between $34.8 and $64.1 million, depending upon the extent of offshore installation required.

Not adopted due to reasons of weight and unfavourable economics.





Gas turbine low NOx – Onshore

• DLN technology is currently capable of achieving a NOx concentration in turbine exhaust gases of around 25 ppmv at reference conditions 15% O2, dry gas basis. This equates to a reduction in NOx emission concentrations of around 90% when compared with conventional machines.

• DLN is considered to be Best Available Control Technology (BACT).

• DLN on RB211 gas turbines is currently only available for single fuel machines. However, the Phase 2 turbines at Sangachal fall within this category.

• Rolls Royce has advised that its knowledge of the ability of DLN generators to accept and reject block loads (loads significant in terms of the overall rating of a unit) is currently incomplete: − Block load acceptance is not expected to present

any problems. − 100% load rejection will cause a ‘flame out’. − For rejections around the 70% load point the

DLN system may not react fast enough to prevent a trip due to over-speed conditions being reached. This is the subject of on going test work.

• Rolls Royce is currently recommending that where a mixture of conventional and DLN turbines exist (which is the case at Sangachal: the Phase 1 gas turbine generators – at least during early field life – will not be of a low NOx design) block load swings should be imposed on the conventional turbines and gradual load increase be applied to the DLN (Phase 2) turbines.

Ongoing. The outcome of this particular evaluation is classified as ‘ongoing’ because there is currently an investigation into the robustness of DLN under conditions of transitory load. Resolution of this issue is anticipated in the medium term future.





Gas turbine low NOx – Offshore

• See above. • The gas turbine generators on the East and West Azeri PDUQs are dual fuel machines. RB211 DLN technology is not currently available for such machines. The PDUQ units will therefore be of a conventional design.

Not adopted. The gas turbines on the C&WP are single fuel-fired units and could therefore be fitted with DLN technology. However, it is not proposed to do so for the following reasons: Air dispersion modelling indicates that the combined offshore Phase 1 & Phase 2 emissions of NOx (from the C&WP and the three PDUQs) are well dispersed and diluted over the distance from the platforms to the mainland (186 km) and consequently have very little impact on air quality around the greater Baku area. Peak onshore annual average contributions of NOx from the platforms are predicted not to exceed 0.05μg/m3 (approximately 0.1% of the air quality standard). The incremental cost for DLN on a new RB211 is approximately $1.25M. At full expansion of the C&WP the adoption of DLN would therefore cost $15M (i.e. there are 12 gas turbines on the platform). The expenditure of this amount of capital to achieve a 0.1% improvement in long-term air quality within Baku is not considered to be a cost-effective allocation of resources.





Other gas turbine NOx reduction options

• Alternative NOx reduction technology is capable of achieving emissions reductions comparable with DLN (see above).

• Alternative technologies for NOx reduction from gas turbines include selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) which involve injecting a reducing agent (typically ammonia) into the exhaust gas stream at elevated temperatures.

• DLN is preferable due to established operating experience.

• Offshore these alternative technologies would impose weight and special penalties.

• Generates waste catalysts. • Some technologies not viable on dual-fuel machines.

Not adopted.

Heater low NOx • Heater low NOx technology is capable of achieving a NOx concentration in the exhaust gases of around 40 ppmv at reference conditions 3% O2, dry gas basis.

Adopted. Low NOx heater technology has been adopted by both Phase 1 and Phase 2 on the basis of BACT.

Offshore fuel gas H2S removal by zinc oxide absorption

• Removal of H2S from fuel gas prevents formation of SO2 within gas turbine combustion gases.

• High cost of SO2 removal ($5,100 to $19,200 per te). • Logistical implications of waste absorbent handling. • Possible absence of absorbent regeneration facilities

leading to disposal in landfill.

Not adopted due to reasons of weight, waste management logistics, and adverse economics. Also, air dispersion modelling indicates little impact of offshore SO2 emissions on air quality around the greater Baku area.





Offshore fuel gas H2S removal by amine sweetening & sulphur recovery

• See above. • The equipment is physically large and heavy. It would require a large deck area and would add a significant weight penalty to a platform design.

• The system results in a waste material, which must be temporarily stored on the platform and subsequently transferred to shore. This issue has significant logistical and cost implications.

• Acid gas from an amine unit is high in H2S and its handling represents significant safety implications for the platform. In addition, the material can be hard to handle due to sulphur crystallisation and corrosion issues: the compressor would require very high levels of maintenance.

• As of the present time no regional market has yet been identified which would enable recovered sulphur to be passed on for re-use. In the absence of a market the sulphur would have to be disposed of in a landfill.

Not adopted for reasons of safety, weight and space penalties, waste management logistics, and adverse economics.

Onshore fuel gas H2S removal by amine sweetening & sulphur recovery

• Removal of H2S from fuel gas prevents formation of SO2 within gas turbine and crude oil heater combustion gases.

• Determination of potential disadvantages is ongoing. Ongoing. Depending upon the concentration of H2S within the gas it may be necessary to install gas sweetening up-stream of the Dew pointing Package (see Chapter 3 Description of Sangachal Terminal). However, information on the sourness of the gas has yet to be confirmed and the requirement for gas sweetening plant has therefore yet to be confirmed.

Low sulphur diesel • SO2 emissions from diesel fired units and dual fuel gas turbines operating on back-up fuel supply (i.e. on black start) can be further reduced by the use of low sulphur diesel fuels

• Determination of potential disadvantages is ongoing. Ongoing. Availability/cost implications of low-sulphur diesel usage are currently under evaluation.



4.2.2 Flaring BP’s Environmental Expectation for Upstream developments is that all routine, non-emergency flaring will be eliminated with the exception of purges and pilots, which should be minimised. The design basis for Phase 2 is that all associated gas will be either re-injected into the reservoir to enhance oil recovery, delivered to SOCAR, or combusted in gas turbines and crude oil heaters to meet the necessary process heat and power requirements of the development.

In terms of ‘normal’ operation the project has focussed principally on the means by which ‘permissible’ flaring, i.e. via purge and pilots, can be minimised or eliminated. Emergency flaring during process-upset conditions will be governed by a Phase 1/2 flaring philosophy, which is still under formulation. The various options evaluated in pursuance of the flaring goal are summarised in Table 4.3. It should be noted a capability to flare under emergency situations is an essential safety requirement.



Table 4.3: Summary of Flaring Abatement Options



Use soft-seat valves • Hydrocarbon releases into the flare system from pressure control valves can be minimised by the use of soft-seat alternatives, which give a tighter shut-off.

• Soft seat valves have relatively higher wear rate than standard valves.

• Potential maintenance implications need to be evaluated.

Ongoing. The issue will be reviewed during the detailed design stage.

Flare gas metering • This technique enables the rate of purge gas flow within the flare systems to be optimised, thereby avoiding the combustion of unnecessarily large volumes of fuel gas.

Adopted. Flare gas metering has been adopted by both Phase 1 and Phase 2 on the basis of BACT. The number of meters and their operational range is an issue for detailed design.

Flare gas recovery & inert gas purging – Onshore

• Flare gas recovery systems enable the recovery of hydrocarbon vapours from the flare system and their return to the upstream process. The systems are commonly designed to handle normal gas leakage rates, with spare capacity to manage minor releases from blow-down/pressure safety valves. During larger releases, a valve in the flare line opens, so isolating the recovery equipment and allowing the vapours to pass through to the flare for combustion.

• Flare gas recovery systems have implications for purge gas systems: in the absence of process gas passing through the flare system it is necessary to purge the system with an inert gas.

Adopted. Flare gas recovery & inert gas purging has been adopted by Phase 1/2 on the basis of BACT.





Flare gas recovery & inert gas purging – Offshore

• See above. • Increased weight and cost implications Ongoing. Flare gas recovery offshore was initially rejected due to space and weight constraints on the platforms, and correspondingly marginal economics. This issue will be revisited during detailed design in light of the increased platform float-over weight conferred by the new transport barge.

Non-continuous pilot ignition systems – Onshore & Offshore

• Non-continuous pilot systems eliminate the requirement for continuous flare pilots.

• Two systems were considered: a) an electronic ignition system, and b) an automatic (Umoe) ignition system.

• The electronic ignition system can be less reliable than conventional pilots.

• The Umoe system has a CO2 abatement cost of $23/te.

Not adopted. The electronic ignition system was rejected on the basis of its reliability, and the consequential implications for maintenance activities, increased purge gas flow rates (to avoid flame out conditions), etc. The Umoe system was rejected on the basis of adverse economics.



4.2.3 Venting The environmental goal for the Phase 2 project is that there will be no venting. Here venting is taken to mean the intentional release of uncombusted hydrocarbons into the atmosphere from point or area sources as distinct from relatively minor leakages from process components such as valves, flanges, seals, etc. Emissions of this latter character are addressed in the section hereafter.

There are two principal potential sources of venting associated with the Project, namely: i) off-gas venting from gas dehydration (both onshore and offshore); and, ii) hydrocarbon emissions from crude oil storage (onshore only). Venting abatement options are described in Table 4.4.



Table 4.4: Summary of Venting Abatement Options



Gas dehydration off-gas recovery – onshore

• Elimination of CH4 and BTEX releases to atmosphere.

Adopted. Onshore, dehydration off-gas is recovered by means of the terminal’s flare gas recovery package (see Table 4.3). This is BACT..

Gas dehydration off-gas recovery – offshore

• See above. Ongoing. Off-gas recovery would be via the offshore flare gas recovery package the feasibility of which is still under evaluation (see Table 4.3).

Gas dehydration off-gas disposal via flaring – offshore

• Reduction of GHG emissions by oxidation of CH4 in off-gas to CO2 and water vapour.

Adopted. Pending the outcome of the offshore flare gas recovery feasibility study, the routing of dehydration off-gas to the LP flare system is considered to be the most environmentally acceptable disposal option.

Crude storage: External floating roof tank with basic fittings.

• Control of hydrocarbon gas releases to atmosphere and reduction in local ambient concentrations of these pollutants.

• Option not Best Available Control Technology. Not adopted.

Crude storage: External floating roof tank with low loss fittings

• See above. • Environmental economics comparable with vapour recovery option.

Adopted.

Crude storage: Internal floating roof tank with primary seal only

• See above. • Option has lower fugitives control performance than EFRT with basic fittings.

Not adopted.

Crude storage: Internal floating roof tank with primary & secondary seal

• See above. • Option has lower fugitives control performance than EFRT with basic fittings.

Not adopted





Crude storage: Internal floating roof tank with primary seal & vapour recovery system

• Improved control performance. • See above.

• Increased CAPEX and OPEX costs due to vapour recovery system.

Not adopted. Improved performance not justified by the extra CAPEX & OPEX required.



4.2.4 Fugitive Emissions

Fugitive hydrocarbon emissions arise from leaking flanges, valves and rotating equipment seals, etc. To achieve the goal of ‘no fugitive emissions’ all of the potential leak sources must therefore be eliminated or the leaking material recovered.

A range of technology options are available to control the release of fugitive hydrocarbon emissions both onshore and offshore. These are summarised in Table 4.5.

Table 4.5: Fugitive Emissions Control Technology Options

Item Options

1 Utilise high non-leakage class valve with low FE gland packing.

2 Maximise use of welded joints.

3 Minimise valves and instrumentation.

4 Use of high efficiency dry gas seals on compressors.

5 Dry gas seal vent recovery.

6 Preventative maintenance to minimise fugitive emissions – Leak Detection and Repair campaigns.

7 Use of flange 'covers' to minimise emissions.

8 Replace safety valves with bursting discs.

9 Closed sample point tundishes.

10 Enclose sources of emission and tie to LP gas recovery system.

11 Use of approved manufacturers for valves.

The evaluation of the above fugitives control measures is a matter for detailed engineering design and will be addressed as Phase 2 passes through to the next design stage.

4.2.5 Discharges to Sea

The options available to the Project to minimise or, where possible eliminate, discharges to sea of oil or chemicals are summarised in Table 4.6. The table does not address discharges from drilling operations. These are covered the Drilling Discharges section.



Table 4.6: Summary of Options to Prevent Discharges to Sea



Offshore produced water disposal – Produced water re-injection

• Minimises produced water discharges to the Caspian by re-injection into the producing reservoir (discharges limited to outage of PWRI system).

• Enhances oil recovery.

Adopted. Project Basis of Design.

Onshore produced water disposal – Produced water re-injection

• Long-term solution to the disposal of produced water arising at Sangachal Terminal.

• Eliminates discharges to the surface environment (land, sea and air)

• Potential risk of re-injection water migrating to contaminate aquifers.

• Potential risk of altering current pressure regimes in disposal reservoir with safety implications.

Ongoing. The base-case for the disposal of produced water on land is currently re-injection at Lokbatan. However, the suitability of this disposal route is the subject of an ongoing study. Issues to be resolved include: − the design of the disposal

well(s) − the characteristics and capacity

of the recipient formation/reservoir

− the potential presence of migration pathways for any re-injection water, so presenting a risk of contamination migrating to any potable aquifers in the area

Alternative sites to Lokbatan are currently under consideration.





Onshore produced water disposal – disposal at Garadagh cement plant.

• Alternative disposal option to the above. • Potential volumes of produced water may exceed disposal routes capacity with operability and emergency storage issues.

Ongoing. This disposal route is currently being implemented by EOP after it was requested to cease disposal of treated produced water to Sangachal Bay. There are a variety of issues surrounding this disposal option which are currently being addressed: does the plant have the capacity to take all of the produced water from both Phase I and Phase II, how would outages at the cement plant be accommodated, etc. Studies are on going.

Onshore produced water disposal – treatment & irrigation.

• Second alternative to the onshore produced water disposal option.

• Increased treatment costs.

• Unknown impacts from irrigation scheme.

Ongoing. The option involves the treatment of produced water to acceptable irrigation water quality standards. The water could then be used for crop irrigation in the general vicinity of the terminal. This option is at an early stage of evaluation and there are presently few specific details available. Further information will be forthcoming as studies progress.

Pigging of Re-injection Water Pipelines: Re-injection of pigging waters

• Pigging from C&WP to East/West Azeri at full pressure with pigging waters being re-injected at platforms.

• Zero discharge of pigging waters to the marine environment.

Adopted. Option considered BACT.





Pigging of Re-injection Water Pipelines: Partial re-injection of pigging waters

• Alternative to the above in the event of a re-injection system blockage.

• Pigging from C&WP to East/West Azeri, and return of pigging waters via Produced Water Transfer line to Water Injection System.

• Option results in the discharge to the marine environment of pigging/produced water flows above the maximum handling capacity of the Produced Water Transfer line.

• Option will be used as a contingency measure to the above.

Ongoing.

Pigging of Produced Water Pipelines: Re-injection of pigging waters

• Minimal discharge of pigging waters to the marine environment.

• Option contingent upon there being sufficient produced water to drive a pig from East/West Azeri to the C&WP. The option will therefore only be adopted in later field life when this condition begins to prevail.

• The operation results in a small discharge to the Caspian during the final stages of pigging.

Adopted. The option is considered BACT.

Pigging of Produced Water Pipelines: Discharge of pigging waters

• Expedient to the above during early field life. • Pigging from C&WP to East/West Azeri. This mode of pigging will only be carried out during early field life when there would be insufficient water on the PDUQs to drive the pig.

• The pigging water and any produced water arising at the platforms during the pigging operation will be discharged to the Caspian.

Adopted. As soon as circumstances allow pigging will revert to the above mode in order to minimise environmental releases.

Cooling water • Offshore, seawater cooling is the project Basis of Design. Air cooling is not possible due to combination of cooling demand, limited availability, and restrictions on weight allowance.

• Offshore cooling will be provided by sea-water lift. Post-cooling, a proportion of this water will be admixed with the produced water and re-injected, whilst the excess will be returned to sea.

Adopted.





Offshore Sewage Treatment: Maceration

• No use of disinfecting agents & no observable floating solids.

• Treatment by natural degradation of sewage in marine environment.

• Not acceptable within Caspian. • Option not BACT.

Not adopted.

Offshore Sewage Treatment: Electro-chemical Treatment

• Alternative to the above. The option involves maceration and chemical addition (sodium hypochlorite) to disinfect the sewage.

• There is no requirement to return sewage sludge to an onshore facility.

• The basic package is certified to meet the US Coastguard specification.

• 1 mg/l chlorine discharge concentration can only be met by means of dilution with grey water and seawater return.

Adopted.

Offshore Sewage Treatment: Biological Treatment

• Alternative to the above. • The system requires a large bio-reactor, resulting in weight and spatial penalties on the platforms.

• The effluent to the bio-reactor must be carefully balanced to avoid shock loads which could otherwise impair or disable biological activity.

• Requirement to return sewage sludge to shore for disposal.

Not adopted.

Offshore Sewage Treatment: Membrane-biological Treatment

• Alternative to the above. This option involves a combination of bio-reaction and ultra-filtration.

• The plant is much smaller (up to ten times) than the biological treatment unit.

• Sewage sludge must be periodically removed and returned to shore for disposal.

Not adopted.

Offshore Sewage Treatment: Ozone Treatment

• Alternative to the above. • The use of ozone does not produce toxic by-products.

• Sewage sludge must be periodically removed and returned to shore for disposal.

• Technology relatively untried in offshore environment.

Not adopted.



4.2.6 Ozone Depleting Chemicals

The project objective of ‘no use of ozone depleting substances’ will be achieved by the use of commercially available substitute chemicals.

Fire-fighting Systems

No halon fire suppressants will be used in fire-fighting systems. The following substances will be used instead;

• Water Mist. This increases the normal surface area of water by more than one thousand times to create an oxygen-depleted atmosphere, thus starving the fire;

• Niagara Foam. Niagara 3-3 is a high fluidity alcohol-resistant film-forming fluoro-protein (AR-FFFP) fire fighting foam concentrate. It is based on natural protein foaming agent and contains no harmful synthetic detergents, glycol ethers, alkyl phenol ethoxylates (APEs), totyltriazoles, or complexing agents. It is biodegradable and virtually non-toxic to aquatic organisms; and,

• Aqueous Film-Forming Foam. This is a mixture of seawater and fire-fighting foam sprayed as a foam on the fire to cool and smother it.

HVAC Systems

No refrigerants are used in offshore HVAC systems: sea water cooling is used instead.

Refrigerants are used onshore only in building split air-conditioning systems. The detail design will be done by local subcontractors who will be made aware of BP’s goal regarding ozone depleting substances.

R407C refrigerant has been used in the past by as an ozone-friendly alternative to R22.

4.2.7 Drilling Discharges

Different disposal strategies are currently proposed for the following hole sections;

i) Top hole section;

ii) 26" hole section; and,

iii) sub-26" hole sections.

These disposal strategies are discussed in Table 4.7 overleaf.



Table 4.7: Summary of Drilling Discharge Options

Table 4.7 – Summary of Drilling Discharge Options Hole Section Disposal Top Hole • It is not technically feasible or safe to return the mud and cuttings from this section to the rig or platform, and therefore in accordance with normal safe

drilling practice this material will be discharged directly to the seabed in accordance with the Production Sharing Agreement (PSA)

26" • Drill cuttings disposal options for the 26 " hole have been the subject of an independent BPEO study (‘BPEO Study for the Disposal of Cuttings from 26" Hole Section for ACG and Shah Deniz’, MC-CDZZZZ-DR-RPT-0001 A1, URS Dames & Moore, 20/7/01). The study evaluated three alternative disposal options, namely: a) discharge overboard, b) cuttings re-injection (CRI), and c) ship-to-shore (for onshore treatment and disposal) in the context of environmental risk, risk to personnel, compliance with legislation, international best practice and BP standards, cost of alternatives, and technology and track record.

• The conclusion is that BPEO for the 26" hole section is discharge to the marine environment. The conclusion is based on the following factors: − there is a paucity of marine fauna around the drill sites; − the drill sites are not located in areas important for fisheries; − the extent of the benthic impact resulting from overboard discharge is thought to be around 100 m; − overboard discharge has the lowest energy demand of all of the options and results in the least atmospheric emissions; − ship-to-shore for ACG Phase I and II will require considerable handling of cuttings and mud which have attendantly high health and safety

risks; − the costs of CRI and ship-to-shore are much greater than overboard discharge; and, − CRI and land-based treatment rely on less proven or reliable technologies than overboard discharge.

Sub-26" • Drilling cuttings and associated fluids from all sections below the 26" hole will be disposed of by CRI. During periods of CRI plant unavailability the cuttings and fluids will be returned to shore for treatment and disposal.



4.2.8 Pipeline Installations There are three principal issues associated with the installation of the Phase 2 pipelines and their potential environmental impacts. These are;

i) the routing of the 30" main oil line from Central Azeri to Sangachal;

ii) the beach-pull of the 30" main oil line; and,

iii) the disposal of hydrotest waters from 30" main oil line and in-field pipelines.

These issues are discussed below.

Routing of 30" Main Oil Line

The Phase 2 30" main oil line will be routed along the existing EOP (and Phase 1) pipeline corridor. Alternative routes were evaluated by Phase 1 (these are described in the Phase 1 ESIA) but the existing corridor was concluded to be the preferred route. From an engineering perspective the EOP corridor is known to be geotechnically sound. It is also the shortest of the routes evaluated: an alternative route landing at the Absheron Peninsula was 43 km longer and had a total onshore length of 120 km. The environmental benefit of using the existing corridor is primarily that it restricts seabed disturbance to an already ‘developed’ area, and thereby does not give rise to additional impacts on a separate and distinct area of sea-bed.

Beach-pull

The Phase 1 and Phase 2 projects combined will require three beach-pull operations at Sangachal Bay: for the Phase 1 30" main oil line, the Phase 1 28" gas line, and the Phase 2 30" main oil line.

The pipeline beach-pulls will require considerable civil works at the shore-line (due to trenching, etc) which will inevitably impact upon the localised ecology within the bay. In order to minimise the overall environmental impact of the beach-pull operations it is the aspiration of Phase 2 to carry out the beach-pull of the 30" main oil line immediately after that of the Phase 1 28" gas line (the gas line in September 2003 and the oil line in October 2003).

Whilst it is acknowledged that this approach could not avoid impacts on the near-shore environment, it would limit disruption to a relatively short period of time, and would avoid further cycles of impact which would otherwise arise from subsequent beach-pulls. It is therefore considered to the Best Practicable Environmental Option.

Disposal of Hydrotest Waters

The disposal of Phase 2’s main oil line hydrotest waters, and the hydrotest waters from the testing of in-field pipelines is the subject of an ongoing BPEO study. Results will be forthcoming in the near future.

4. options assessed

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