Offshore oil and gas developments in geologically active regions face a number of geohazards, including earthquake shaking, fault rupture, liquefaction, slope failure, and fluid escape. The magnitude and frequency of these hazards are often difficult to quantify; leading to large uncertainties in the risk analyses carried out for engineering development. Traditional deterministic hazard assessments often conclude that such regions are too problematic for development. This paper presents a recently developed probabilistic approach that integrates geohazard evaluation with engineering limit state analysis, which in turn allows a dynamic, streamlined approach to risk assessment. This Failure Modes and Effects Analysis (FMEA) ensures end user focus, with the drilling, subsea and pipeline, infield compression facility, and reservoir teams driving the process through quantification of the consequences of failure. It also enables reality checks and establishes a process for asking the right questions at the right time. This approach has the benefit of rapidly identifying the real geohazard and engineering issues. This, in turn, allows rapid decision making to be undertaken, not just for adjustments to offshore site survey programs, but also, in efficient allocation of engineering resources. It also provides a quantified risk based set of engineering decision tools suitable for life of field appraisal of both HSE and operational issues. The rapid assessment of CAPEX risk allows decisions to be made regarding reassessment of field design and/or identifying defensive measures requiring CAPEX reallocation.This integrated probabilistic approach to geohazard assessment and subsequent risk analysis significantly streamlines the decision processes required for field design. By employing an integrated team of engineering and geoscience experts, potential "project stopper" problems are swiftly identified and solved/avoided by rerouting/resiting facilities or enhancing engineering design. This approach has the potential to lead to significant cost savings and a reduction in time required for field development.

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In recent times, Azerbaijan has seen the development of a significant modern offshore industry. The oil and shipping industries in Azerbaijan bring economic benefits but also give rise to the need for robust oil spill prevention and preparedness measures. Azerbaijan signed the International Convention on Oil Pollution Preparedness, Response and Cooperation (OPRC) in 2004 and continues to develop and refine its national system of oil spill response. This paper discusses how the Azerbaijan government and key players in the oil industry have successfully worked together to achieve alignment in prevention, protection and response to major incidents. The implementation of the OPRC Convention is the responsibility of the Ministry of Emergency Situations (MES) of the Republic of Azerbaijan. Within the national response system a national oil spill contingency plan has been developed. The main offshore developments in the Caspian since the 1990s have been led by BP, as operator of a number of Production Sharing Agreements. BP has implemented comprehensive oil spill response plans and is working in partnership with MES to integrate this planning into the national framework. The oil spill management systems adopted by BP and the government are compatible and commensurate with guidance published by the International Maritime Organization in 2011. These aligned management systems allow for an effective Joint Command and coordination of resources in the case of a major incident. The key to building effective oil spill preparedness are a willing dialogue, integrated command structure, joint training and exercising and upgrade of hardware and information systems' software. The cooperation between government and BP relating to offshore risks strengthens the national capacity to deal with spills risks other than from offshore platforms, including the anticipated increase of oil shipments across the Caspian Sea. Furthermore, these efforts have been supported by international organizations and the regional industry initiative, OSPRI, of which BP is a member. The experience of Azerbaijan provides a model demonstrating how partnership between government and industry can achieve synergy and it confirms the importance of signing and implementing the OPRC Convention.

The Terang, Batur, East and West Sirasun gas reservoirs are located 120 km north of Bali on the Kangean shelf of the North Bali Basin, in water depths ranging from 100 to 300 metres. The reservoirs collectively contain around 1 TCF of recoverable gas. It is proposed to jointly develop the reservoirs by means of a subsea development and associated floating production unit (FPU), with gas being exported to the nearby East Java Gas Pipeline for onward transmission to Java. The North Bali basin lies above a major subduction zone, and is consequently an area of extensive seismic and volcanic activity. The proposed Terang/Sirasun development location is subject to numerous geohazards, including fault rupture, shallow gas, slope instability, liquefaction, and strong earthquake shaking. These geohazards pose risks to safety, the environment and the field facilities, both during construction and during production operations. Consequently, a key element of the early engineering definition phase of the project, prior to undertaking FEED, has been the analysis and quantification of the geohazard risks. A geohazards engineering programme was undertaken during 2000–2001. An integrated multidisciplinary team was assembled, covering the geophysics, geology, drilling, completions, subsea and facilities disciplines. An extensive data acquisition programme was undertaken, comprising some 5,600km of 2D seismic lines, swathe bathymetry, sidescan sonar, sub-bottom profiling and geotechnical sampling. The team used state-of-the-art visualisation technology to map the hazards and plan wellbore trajectories and facility locations to minimise risk. Limit state analyses of the wells and seabed facilities were performed to determine capacity to respond to seismically triggered events. Finally, extensive probabilisitc analysis utilising decision (or logic) trees was undertaken to quantify the safety and economic consequences of geohazard events in terms of environmental impact, asset damage and production interruption. This paper describes the geohazards engineering programme and presents lessons learned. The programme received a commendation in BP's internal Helios Awards scheme during 2001. Development Description Location. The Terang, Batur, East and West Sirasun gas reservoirs are located 120km north of Bali on the Kangean shelf of the North Bali Basin, in water depths ranging from 100 to 300 metres. The area is a relatively benign environment in metocean terms, with a 100-year return significant wave height of 2.5 metres. The climate is monsoonal. Reservoirs. The Terang, East Sirasun, West Sirasun and Batur reservoirs collectively contain around 1TCF of recoverable gas. The reservoirs are extremely shallow (less than 600 metres subsea), and cover a large area (27 km by 5 km). The reservoir fluids are over 98% methane, with no recorded H2S and around 0.1% CO2. Produced water rates vary from 0.3 to 1,000 bbls/mmscf. Reservoir temperatures are moderate, less than 60°C, and reservoir pressures are low (1,100 psi). The reservoir rocks are carbonate sands composed of foraminifera (globigerinids) which pose a potential compaction hazard during production. Location. The Terang, Batur, East and West Sirasun gas reservoirs are located 120km north of Bali on the Kangean shelf of the North Bali Basin, in water depths ranging from 100 to 300 metres. The area is a relatively benign environment in metocean terms, with a 100-year return significant wave height of 2.5 metres. The climate is monsoonal. Reservoirs. The Terang, East Sirasun, West Sirasun and Batur reservoirs collectively contain around 1TCF of recoverable gas. The reservoirs are extremely shallow (less than 600 metres subsea), and cover a large area (27 km by 5 km). The reservoir fluids are over 98% methane, with no recorded H2S and around 0.1% CO2. Produced water rates vary from 0.3 to 1,000 bbls/mmscf. Reservoir temperatures are moderate, less than 60°C, and reservoir pressures are low (1,100 psi). The reservoir rocks are carbonate sands composed of foraminifera (globigerinids) which pose a potential compaction hazard during production.

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