ASPO WORKSHOPUPPSALA

Technology and Frontier Areas -

Can they save the USA?

Jeremy Gilbert

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

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

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

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

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?

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

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

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

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

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

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?

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

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

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

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

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

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

Prudhoe Bay - Reported Reserves

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8

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16

Rep

ort

ed R

eser

vesG

b

Predicting the future

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0 2 4 6 8 10 12

Cumulative Production Gb

An

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Gb

/a

1977

1988

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

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

So, what about ANWR?

• Environmental concerns exaggerated

• Collecting key seismic data and drilling key wildcats would have negligible impact

• Limited publicly available data

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!!! …

USGS – Optimists All?  

 

  PAST DISCOVERY & USGS ESTIMATES OF FUTURE DISCOVERY

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40

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1950 1960 1970 1980 1990 2000 2010 2020

Dis

cove

ry G

b

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, facilities0.9

• 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

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

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

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

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”

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

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

Deepwater Production Profile

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1990 2000 2010 2020 2030 2040

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b/a

US-1 US-2 Mexico Total

Overall US Production

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1930 1950 1970 1990 2010 2030 2050

Pro

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b/d

DW

Alaska

US-48

Growing Imports

8000

10000

12000

14000

16000

18000

20000

1990 2000 2010 2020 2030 2040 2050

Imp

ort

s k

b/d

* With conservative assumption of flat demand

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

Cost of imports

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95

115

135

155

175

195

215

1990 2000 2010 2020 2030 2040 2050

Bil

lio

n d

oll

ars

With conservative assumption of constant $30/stb

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