Extension of Field Life & Prevention of Premature COP

1. Extension of Field Life & Prevention of Premature COP UKCS Total Remaining Reserves Total Remaining plus est. max. Potential Additional & Undiscovered Recoverable Reserves (BBOE) Benefits Maintain cash flow / employment. Defer abandonment liabilities. Keep window of opportunity open for additional technologies and/or use of existing infrastructure. It is estimated that around 65% of Undiscovered Recoverabe reserves lie within 50 km. of existing infrastructure. Producing Fields Challenges Currently-estimated Dates of Gas field COP Currently-estimated Dates of Oil field COP Reduce well side-track costs. Combat corrosion and deterioration. Environmental / flaring / discharge limits. Uncertainty in oil price affects the ability to pursue infill projects and develop discovered accumulations; and thereby affects COP. Uncertainties when applying novel technologies. DTI Role Responsible for developing and implementing Government policy. Will challenge all aspects of Cessation of Production: Instigate operator-independent contractor studies. Prioritise DTI research funds. Check well remediation possibilities. Check for untapped reachable reservoirs. Check hosting opportunities. Prepared to accept reduced monitoring at very tail-end of life. Possible Gas Reserves potentially left at COP Possible Liquid Reserves potentially left at COP DTI Involvement O&G Industry Task force (PILOT). LIFT – web-site for licence trading. Currently involved in industry discussions with Inland Revenue to attempt to make existing reliefs for decommissioning spend more effective. Regular formal reviews with oil companies. Encourage new operators. Fallow block and fallow discovery initiatives. Reduce regulatory burden. Facilitate change of operator on request. Promote exploration. Support advancement of latest technology. Support to hardware developments. Seed-corn for R&D / JIP’s / technology transfer / best practice workshops. Investigate GoM late-field strategies. Field Extension Examples Field Before After NNS (small) Field had produced over 90% of ultimate recovery and was producing at 85% watercut. Development drilling had ceased and COP was expected within 3-4 years. Development based on maximising developed reserves associated with existing wells. Minimum multi-skilled offshore mode adopted. Portfolio of development opportunities prepared, in case of economic up-turn. Strategies aligned with neighbours; possibility of providing route for 3rd party export. Field life extended. USA land (medium) Waterflood of oil field in Permian basin on 40 acre spacing, with low secondary-to-primary ratio (i.e. < 0.75). Poorly filtered injection water; most interior wells had not responded to peripheral injection. Low RF. Field study was conducted and two unsolicited offers were made. Operator put property up for competitive bid. Property was bought for same price as 2nd offer. New geological interpretation made. Successful pilot waterflood led to field-wide 20 acre, 5-spot. Injection water was mixed and filtered; sweep efficiency was improved, by perforating low resistivity pays and shutting off thief zones. RF increased to > 42%. Actions to defer COP CNS (large) Increasing lifting cost, decreasing production, high lost time incident frequency, RF 40%. Net income held flat despite production decline, by: rota system/downsizing; reduced hierarchical layers; outsourcing. New 3D seismic led to infill well programme. Vast improvement in production efficiency/better water management. Access secured to shallow hydrocarbon resource. Eventual aspiration for RF > 60%. Discuss early-on with DTI. Talk to other operators. Revisit geological model. Thoroughly review well histories and data base. Take a fresh look. Evaluate all options: infill drilling; satellite development; EOR; de-bottlenecking; shallower and deeper geological horizons. Cross-plot well performance, scrutinise outliers, examine voidage / material balance trends. Consider techniques such as through-tubing rotary and coiled tubing drilling to access by-passed reserves and/or isolated compartments. Examine possible alignments with neighbouring licensees. Resolve co-venturer misalignments. Consider application of latest: seismic technologies; advanced history-matching and reservoir target optimisation models; decision / risk management tools. Adopt stimulation and low cost preventative maintenance strategy. Re-perforate existing zones; perforate missed zones; perform injectivity studies; change existing sweep patterns. Provide incentives for onshore and offshore teams to optimise production. Consider outsourcing or selling asset to specialist mature field operator. Investigate options for non-licensee investment and/or involvement. FPU / FPSO contractual flexibility at end of field life, to achieve win-win. NNS (large) Under-performing asset, < 25% RF, questionable early seismic, short life expectancy. Focus on opex control and decommissioning. Risk-reward alliance created. Remedial operations and hydraulic fracturing attempted. Seismic acquired and dynamic model rebuilt. Pressure compartments redefined. Attic targets identified. Field life extended. Efforts to identify best decommissioning method continued SNS Potential for satellite developments, but need for upgrade to existing systems and requirement for new satellite platforms. Historically, increasing cost and complexity of satellite platforms. Lump sum engineering, procurement, installation and commissioning contract. Breakthrough in platform design by removing traditional design constraints. Platform capex reduced to 50% less than predecessor fields. Enabled exploitation of > 450 BCF reserves. Key Lessons • Innovate • Discuss at early-stage with DTI • Think ‘renewal’ rather than ‘end-game’ • Prepare for opportunities / economic up-turn Colin Cranfield Field Development and Approvals Tel. +44 (0) 1224 254066 colin.cranfield@dti.gsi.gov.uk United Kingdom Department of Trade and Industry