”ZERO DISCHARGE” Opportunities and Challenges Presented by Mr. Stig Svalheim FORCE Seminar Stavanger, 22nd April 2004

Overview NPD-focus: Balance the need to reduce discharges with possible impacts on reserves, safety and costs: Background and status implementation Environmental Impact Factor (EIF) Produced water trends and zero discharge measures Challenges and way forward Conclusions

The Zero Discharge Policy Defined by the Parliament in accordance with the precautionary principle Applies already for new stand-alone developments and by the end of 2005 for existing installations Policy covers production, drilling and pipelines Stricter interpretation will be applied for the vulnerable Lofoten and Barents sea areas.

International obligations (OSPAR) Current requirement: max 40 mg/l OiW New agreed recommendation: Max 30 mg/l OiW 15% total oil discharge reduction from 2000 to 2006 Targets within reach if the operators “zero discharge” plans are implemented, but a challenge beyond 2006 as water production increases (ref. SFT)

The Zero Discharge Target - North Sea and Norwegian Sea areas No discharges of hazardous chemicals (SFT’s black and red categories) No discharges or minimising discharges of naturally-occurring environmental toxins No or minimised discharges of substances which could lead to environmental harm: Oil (dispersed and dissolved) Chemicals in the SFT’s yellow and green categories Other substances which could lead to environmental harm (e.g. drill cutting) Exception: Crucial safety or technical reasons

Status Implementation 1996: “Zero Discharge Goal” launched 1998: “Zero Discharge Work Group” formed 2000: Mandatory operator strategy reporting 2003: Mandatory status reporting on progress and plans to reach the 2005-target SFT-feedback, Dec 2003: In general, pleased with the operators progress and plans (~80% reduction of environmental harmful substances on most fields) Total reduction of 42% of PAH and alkyl-phenol from 2000-2006 Continuing challenge beyond the 2005 milestone as water production is predicted to increase Updated status reporting and committing plans during 2004

EIF – a new tool for setting priorities EIF calculates the risk of environmental harm from produced water (PW) discharges on a field Modelling includes composition and quantity of PW and how the discharge disperses in the sea Management tool applied by both operators and authorities – development spearheaded by Statoil

Source: Statoil

Produced Water Trend on the NCS The NCS contains a relatively large number of small and medium-sized discoveries which have yet to be developed, but which collectively contain a great deal of oil and gas. A number of these finds depend on being tied back to existing infrastructure to achieve acceptable economics. Minimising the expected growth in potential harmful discharges from PW therefore depends on measures on existing platforms. New field developments will normally have PWRI, hence do not make a significant contribution in the forecast shown above. Source: RNB2004

Produced Water Management Reduction Reuse Deposit Treatment - Water shut-off - Downhole separation - Subsea separation - Smart wells etc. - PWRI for pressure maintenance - Produced water injection in deposit reservoir - C-Tour - EPCON - MPPE - Improved deoiling separation - Other methods One principle is to reduce the water production, benefits: reduced energy consumed for lifting water into the platform reduced chemical use and discharges to the sea. Water shut-off implies that zones in the reservoir with high water production or high H2S content is isolated, either mechanical or chemical. Downhole separation: tested onshore, but operators on the NCS have not yet been willing to take the cost and risk to implement the technology offshore. Subsea separation (pilot on Troll C): Separates and reinjects ~ 2500 m3/d, i.e. 10% of total PW at Troll C Total cost ~ $ 70M, i.e very poor cost-efficiency, but a valuable subsea technology experience! Smart wells

Already Implemented Measures Chemical substitution PWRI: Brage (Norsk Hydro) Balder (ExxonMobil) Frigg (Total) Glitne (Statoil) Grane (Norsk Hydro) Heidrun (Statoil) Heimdal (Norsk Hydro) Jotun (ExxonMobil) Oseberg East (Norsk Hydro) Oseberg South (Norsk Hydro) Ringhorne (ExxonMobil) Snorre B (Norsk Hydro) Statfjord C (Statoil) Ula (BP) Valhall (BP) Visund (Statoil) 

EIF-Trends on Major Fields

Each bar represent one specific measure on a platform

Challenges Analysis based on the operators status reports – uncertainty in reporting of costs and effects Key decisions not yet approved in the licenses Field specific solutions requires sufficient time for evaluations and testing Several new technologies and techniques to be installed – how will they work in the long run? Low focus on methods to reduce water production in the operators status reports Long-term risk of reduced injectivity and/or reservoir souring from PWRI

PWRI and Risk of Bacteria Growth PWRI adds nutrients and sulphate from earlier sea water injection  increased population of sulphate reducing bacteria = possible: Reservoir souring (H2S) Reduced injectivity Corrosion Workforce health risk  Potential challenge for the entire upstream value chain (HSE - Resource Management) Export gas specification: max 3 ppm H2S H2S Injecting H2S scavenger and corrosion inhibitor is costly both economic and environmentally (when discharged with produced water).

Conclusions Avoiding potential harmful discharges to sea to operate sustainable and gain acceptance to operate Technologies are developed to meet the zero discharge goal, but cost-effective investment decisions need to be made Focus on minimising/avoiding the water production should not be forgotten!