• Responsible for Reserves assessment and reporting for BSP. Ensured compliance with reserves reporting requirements for SEC, Shell and Brunei government. Successfully demonstrated integrity of reserves following audits by Brunei Government and Shell Internal Audit in 2015 and 2017 respectively. • Owner of the corporate production forecast supporting Business Plan and reserves assessment. Consists of 20 fields delivering 330 kboe/d. • Delivered the first fully integrated corporate production forecast tool for BSP. Integrates 90 offshore structures, 2000 wells, planned activity, gas contracts, composition, capacity and pressure constraints. Enhanced visualization and Production System Optimization. Simplified workflows, improved auditability, transparency and vastly reduced cycle time of forecasts. Leading this project required good engagement across subsurface, operations and wells departments. • Lead a multidiscipline team to develop a corporate Opex Model for BSP, now used for long-term Opex forecasts in annual Business Plan and Reserves cycle. • Contributed to a strategy study targeting a reduced offshore footprint. Defined production network dependencies, benchmarked Opex drivers and ran cost/benefit scenarios used by Managing Director for engagements with Brunei Government. • Lead a team of Discipline Heads to provide assurance of reservoir engineering deliverables by participating in technical reviews and model framing events. • Provided reservoir engineering assurance to support a deep-water field unitization. • Maintained focus on pore pressure/fracture gradient prediction as a critical safety risk in BSP environment of mature depleted fields with overpressure zones. • Conducted ad-hoc emergency response readiness of reservoir engineering data. • Ensured gathering of reservoir engineering data and update to the Corporate Data Store in compliance with business requirements. • Responsible for development of reservoir engineering staff capability through training, coaching, succession planning and embedding technology improvements. • Prepared and managed the annual reservoir engineering training budget. • Managed PVT contract tender. Provided recommendations, approved the scope of work, the technical evaluation and input to the commercial evaluation. • Managed non-Shell reservoir engineering consultancy services and contracts. • Deputized for the Chief Petroleum Engineer as needed.

• Responsible for ensuring quality and timely Reservoir Engineering contributions for efficient delivery of hydrocarbon maturation activity which enabled construction of 27 new well pads and 650 wells in pattern waterflood development in 3 fields during a 7-year tenure in which oil production achieved a peak 175 kb/d. Lead a team of 10 REs supporting a peak of 6 drilling rigs. Development wells included ESP lifted producers stimulated with propped hydraulic fracs and water injectors were operated at fracture conditions. • Responsible for waterflood pattern management REs doing the allocation of water (455 kb/d) to injectors, conversion of pre-producers to injection & maintenance of full voidage replacement to optimize volumetric sweep for increased recovery. • Supported input to monthly production system optimization and integrated activity plan for 90-day production forecast. • Responsible for producing the corporate production forecast for annual Business Plan and Work Program & Budget. • Responsible for annual reserves assessment and reporting to shareholders Gazpromneft and Shell • Prepared the WRFM Plan for all 3 waterflood fields ensuring compliance to requirements of Russian Authorities for monitoring and data acquisition, with a specific focus on vertical and areal conformance of the waterflood. • Drove technology trials including ultra-short radius horizontal drilling and single well chemical tracer test of alkali-surfactant-polymer (ASP) flooding. • Contributed to technical concept for multi-well ASP pilot and subsequent phased, full field ASP flood. • Prepared dynamic simulation sector models for development planning and visualization for waterflood patterns in West Salym and for technical assessment of horizontal wells and vertical multifrac wells in low perm Achimov reservoir. • Contributed to the design and interpretation of pressure transient analyses for oil wells and pressure fall off tests on water injectors. Use Shell proprietary software to interpret fracture growth in water injectors. • Contributed to the technical concept of using horizontal multifrac wells to develop the liquid rich Bazhenov shale. Simulated performance for various fracture and well densities. • Delivered the technical and economic analysis to support ongoing conversion of the West Salym waterflood from 50 ha to 25 ha well spacing, including justification for additional injection water pump capacity and construction of the third oil processing train at the Central Processing Facility. Updated the Field Development Plan (FDP) and Asset Reference Plan (ARP) accordingly. • Contributed to documentation required for Tech Schema updates as needed by the Chief Geologist. • Delivered a significant labor productivity improvement, which transformed corporate production forecasting by reducing cycle time, improving auditability, integrity and transparency of corporate forecasts for the business. • Maintained efficient working relationships with technical representatives and study teams from GazPromNeft and Shell. • Supported coaching of 3 Russian graduate & junior reservoir engineers to ensure their competence development.

• Contributed the reservoir engineering aspects of Shell’s tender to develop the very sour gas, condensate rich Shah Field, estimated to contain 15 Tscf of gas with 23% H2S and 10% CO2. The field has a complex subsurface, with 600 m gas column in low permeability, presence of fracture corridors, retrograde condensate and compositional grading. • Prepared compositional & reactive flow reservoir simulation models using CMG software to assess lifecycle reservoir engineering aspects of development concepts based on plateau gas production of up to 1200 MMscf/d. • Evaluated three subsurface concepts including natural depletion (with export of solid Sulphur), natural depletion with sour gas disposal in deep saline aquifers and sour gas recycling with far field peripheral injection of CO2 and H2S. • Assessed impact of subsurface uncertainties including PVT phase behavior, presence of pervasive fracture corridors and formation heterogeneity to develop a continuous data acquisition plan to improve future development for the selected concept of natural depletion with solid sulphur export. • Contributed to tender documents describing development with 70 production wells and late life compression to deliver 1000 MMscf/d of gas for more than 15 yrs. Liaised with Government representatives and Ryder Scott during due-diligence of subsurface aspects of the technical submission by Shell. • Provided operational support for drilling appraisal wells. Designed and interpreted multi-rate gas well tests, coordinated specialized PVT and flow assurance sampling, laboratory analysis program, interpretation of results and inclusion to dynamic models. • Efficiently engaged technical experts in Shell and ADNOC representatives during pre-bid phase. • Supervised and coached 2 reservoir engineers appointed from ADNOC on assignment with Shell Abu Dhabi.

• Lead a multi-discipline subsurface study team of 14 staff in delivery of Nembe Creek field redevelopment FDP that proposed 8 new infill wells to raise oil production by 40,000 b/d. Used 4D seismic and history matched dynamic simulation models to identify unswept areas for development. • Mitigating non-technical risk by regular engagement with community leadership, ensuring support for local school and other community welfare activity was a key enabler for a successful delivery of the redevelopment project. • Updated FDP for Soku gas field for production from 10 reservoirs with oil rims and large gas caps with the overarching requirement to maintain gas deliverability of 1,000 MMscf/d for 5 years. The aim was to secure against a severe delivery shortfall to Nigerian LNG anticipated during 2005-2010 due to the absence of associated gas from other fields. • Engaged shareholders and Nigerian regulator to demonstrate that the Soku development plan yielded limited loss of recovery from oil rims while concurrently producing from selected gas caps to fulfill gas contract commitments.

• Operations reservoir engineering for Barik Deep gas development. All production wells were developed with multiple propped hydraulic fracs. Provided incremental production for individual sands to justify fraccing each new well. • Used Eclipse 300 compositional simulator to estimate feasibility of condensate stripping and dry gas reinjection in Barik Deep Field. Presented study results to Ministry of Oil & Gas demonstrating the concept to be non-viable. • Maintained the history matched dynamic simulation model for the field and several material balance models of exploration prospects for inclusion to Hydrocarbon Field Planning Tool (HFPT, equivalent to PROSPER/MBAL/GAP) to support the Business Plan. • Developed reservoir simulation models used for preparation of FDPs for Barik Gharif and Mabrouk Fields. Prepared dynamic simulation models in support of multi-lateral well development planning of Musalim and Saih Rawl Fields.

• Prepared the Hydrocarbon Field Planning Tool for notional development concepts of the Greater Gorgon area consisting of 9 gas fields. Estimated number of wells, compression timing and export pipeline sizing under multiple gas demand scenarios and offshore/onshore development concepts. • Used the Shell Cost Estimating Tool to develop Level 1 Capex and Opex estimates for the complex integrated developments and assessed economics under a Tax/Royalty system. • Supported exploration department with RE inputs to EMV and VOI assessments for exploration and appraisal wells respectively. • Prepared notional development concepts and economics to identify competitor’s value gaps for divestment of Shell’s assets in the Bass Strait.

• Performed economic evaluations for incremental developments, exploration, appraisal, divestment, tariffing and Capex/Opex trade-off decisions primarily for Central North Sea and Brent Field Units. • Employed Decision Tree Analyses, Value of Information and Estimated Monetary Value concepts to quantify risk in decision-making. Conducted training events to disseminate economics methods and understanding to subsurface staff.

• Worked 1 year as Wellsite Petroleum Engineer on land drilling and workover operations in The Netherlands. • Petrophysical evaluations in support of single string ventures in Papua New Guinea and South Americas. • Homing-in focal point for relief well drilling for blowouts (Rasau-17, Brunei). Authored the Shell Relief Well Homing-in Manual. Focal point for joint industry research into acoustic homing in methods and conducted technology trial with Schlumberger in 2 test wells at the Rogalands Institute, Norway.

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