ASPO WORKSHOP UPPSALA

1. ASPO WORKSHOPUPPSALA Technology and Frontier Areas - Can they save the USA? Jeremy Gilbert

2. Natural Bias • All of us interpret data differently, according to our experience, background and perception • A geologist is trained to think differently from an engineer or an economist

3. Basis for my own bias • Degree in Mathematics • 20 years of reservoir engineering worldwide with BP, then many years of general management • After working as the company’s Chief Petroleum Engineer I spent the final years of my career in Alaska

4. Evidence • As every policeman knows, witnesses are likely to describe the same incident in quite different ways • Geologists are generally optimists • Their challenge: find oil against the evidence and despite possible earlier failures • Engineers are naturally cautious • They must develop the geologists’ finds, match investment to expected performance

5. New technology as a panacea • Until a decade or two ago US was source of virtually all new production technology • To determine how technology can influence recovery efficiency where better to look than in the US itself and at a field whose size has meant that funding for new technology has generally been available

6. Alaska - “The Last Frontier” • Not just on auto license plates! • Few parts of US remain unexplored. Alaska is generally accepted as the only area where truly significant volumes of yet-to-find oil may exist • ….. but do they?

7. The path to Prudhoe … • BP has always been recognized as a worldclass explorer, beginning with the first Middle East discovery at MiS in 1908 • BP lost core supply source in Iran in 1951 and began major exploration in other areas, including North America • In 1950s industry had begun development of oil and gas fields in Cook Inlet in SW Alaska

8. The last throw of the dice • BP’s geologists had much experience of ‘foothill’ oil near Iran’s Zagros Mountains • In Alaska BP tested Iranian-type anticlines in foothills of the Brooks Range ; others followed - but the results were disappointing • Patience was running out, interest moved north to new State land on the coastal plain near Colville River • BP and ARCO-Esso acquired most of the available leases

9. Optimism wins the day – just! • In1968 ARCO-Esso discovered oil in what had been planned to be their final Prudhoe Bay well • Shortly afterwards, a BP well drilled on much less costly downflank leases confirms the ARCO-Esso discovery • A huge lease sale takes place in 1969, raising almost $1 billion

10. Prudhoe Bay • In the 1969 lease sale, Arco-Esso made the high bids, winning what proved to be the crest of a giant structure • BP, with lower bids, acquired what turned out to be much of the flank area • The structure had a huge gas cap, about 25 tscf, and so BP had more than half of the oil • In 1969 BP became joint operator of the field with ARCO

11. Operational Extremes • After its discovery and initial appraisal the explorers estimated Prudhoe Bay reserves at 15 billion stb - but we know that they are always optimists! • Development engineers had to deal with huge problems before we could recover even a single barrel

12. Remote and hostile • Huge logistical problems of operating in remote Arctic location • How to travel and work on tundra, deal with permafrost, live in extreme cold? • Bringing in equipment by land impossible; airlift or summer sea-lift only options • Main problem: how to export crude oil?

13. Make or break? • Pipeline to Valdez planned in 1969 – 800 miles of 48” pipe, 600 river crossings, up to 4700 ft. • World’s biggest civil engineering project; cost to be $900 million • Construction delayed by environmental and land ownership problems • Cost of TAPS escalated to over $9 billion • Project would have been economic disaster had oil price not quadrupled in 1973-4

14. Start-up • The pipeline was completed in 1977 • Production began in April 1977 at 3 mbd • Based on the 125 wells drilled, 9 billion stb was a prudent estimate to SEC • Within 32 months production had reached plateau level of 1500 mbd

15. Second Phase • By 1982 field had settled down to routine production, with more than sufficient well capacity to fill the production system • Studies showed that changes to facilities would be required to maintain offtake capacity at 1.5 mmbd • BP began to plan remedial actions – mostly as envisaged in Initial Development Plan

16. ACTION!!! • Well flowline diameter increased; well pads manifolded • Produced-water handling and injection facilities expanded • Low pressure gas separation facilities • Infill drilling begun to reduce well spacing • ‘Horizontal’ wells drilled to reach isolated and secondary reservoirs • Large scale EOR using Miscible Injectant

17. The onset of decline • In 1989 could no longer maintain plateau rate • Even closer infill drilling, additional EOR injection, and flank developments failed to reverse decline • Gas breakthrough to producing wells resulted in unexpectedly high gas production … • … but huge expansions in gas handling capacity in 1991 and 1994 did give short-term respite and allow production to increase • Steep offtake decline rate has continued - but some recent respite with cheaper drilling

18. A win or a loss? • Advances in technology maintained plateau offtake continued longer than anticipated • Over 10.6 billion stb now produced, so engineers’ initial estimate (9.6 billion) far exceeded • Current estimate of 13.5 billion stb is short of explorerers’ promises - despite initially unforseeable technology advances • Some of estimated remaining reserves may prove uneconomic

19. Prudhoe Bay - Reported Reserves

20. Predicting the future 1988 1977

21. What did we learn? • Reservoir geology found to be more complicated and depletion processes more complex than expected • Despite these, the target production plateau length was exceeded through application of technologies developed or refined at Prudhoe Bay • Although the engineers’ reserves estimates were found to be conservative the new technologies were not able to deliver the geologists’ predictions of recovery

22. New Alaskan reserves? • Alaska appears to be a concentrated habitat with most of its oil on the North Slope margins and in or around the super-giant Prudhoe Bay field • Other fields are much smaller than Prudhoe – less than 5 billion stb reserves total - although a few are large by Lower 48 standards • The North Slope has generally been well evaluated (59 exploration wells) but there is still a possibility of oil in ANWR

23. So, what about ANWR? • Environmental concerns exaggerated • Collecting key seismic data and drilling key wildcats would have negligible impact • Limited publicly available data

24. ANWR Reserves Studies • Several published State/Federal agency studies, from 1986 to 1998 • Most recent, by USGS, based on all publicly available data and improved analysis • Study suggests “mean technically recoverable oil” of 7.7 b stb • Sounds impressive at first hearing • … BUT!!! …

25. USGS – Optimists All?

26. ANWR – an engineer’s view • Must discount technically recoverable volume for: risk of not encountering the oil 0.75 oil there but in small pools 0.8 areal restrictions on drilling, facilities 0.9 • Take $24/bbl for ANS crude, to calculate economically recoverable fro m technical volume using USGS data • Risked reserves: 2.7 b stb; aggressive plateau rate: 750 mbd • Plateau could not before achieved before 2020; by then offtake from other Alaskan fields will decline almost 700 mbd

27. The other frontier - Deepwater • Amazing technological achievements make deepwater production feasible … • … but challenges development and operating skills to maximum • Costs likely to be many times greater than for onshore or shallow water • Small accidents, set-backs have huge consequences

28. Deepwater geological environment • Geology very different to that of most onshore fields and usually very complex • Turbidites, “marine avalanches”, act as reservoirs but these often lenticular/entwined • Rich source, below delta front, at upper boundary of maturity: oil often degraded • Larger fields are generally found first

29. Operational Constraints • Floating production equipment brings huge mooring and riser problems • Platform capacity limits constrain peak offtake • Pressure maintenance is difficult - as is control of injected fluids • Economics may rule out development of all but largest accumulations

30. Deepwater reserves • Demanding economics force adoption of aggressive recovery factors for development plans to be approved • Advances in technology likely to be needed to achieve these aggressive initially estimated reserves • Hence little potential for “reserves growth”

31. Farewell to ‘reserves growth’ • ‘Reserves Growth’ in giant fields by as much as 70% (Kuparuk), 40% (Forties) has been common following oil-in-place, recovery factor revisions • In new fields oil-in-place now much better defined by early 3-D seismic, improved down-hole logging in initial wells • With modern technology initially expected recovery factor already close to technical limit set by reservoir physics– little potential for increase

32. Impact of Deepwater • Three production phases likely: First: already underway Second: ultradeep water, beyond 3000 m Third: Mexico • Production expected to peak around 2010 at about 2.5 million b/d, with sharp decline thereafter

33. Deepwater Production Profile

34. Overall US Production

35. Growing Imports * With conservative assumption of flat demand

36. Growing US Dependence on Imports • 1971 peak for US ‘Lower 48’ production • Alaska’s production peaked in 1989, current fields’ declines cannot be significantly reduced • Even optimistic ANWR development will have limited impact on US domestic supply • Deepwater production will peak about 2010 (even if rates doubled impact on supply deficit is small) • Hence, imports are bound to rise unless demand can be cut dramatically

37. Cost of imports With conservative assumption of constant $30/stb

38. Conclusions • The US has been thoroughly explored, new large fields are unlikely • It has state-of-the-art technology and is using it to maximize recovery efficiency, ‘reserves growth’ in existing fields will be insignificant • Domestic production is inexorably declining; imports are set to rise, even with flat demand • Import costs will soon become insupportable for a country already heavily in debt • Demand for nonUS oil will increase to the point where all needs cannot be met • There has to be a solution other than WAR