Definitions of reserves and main difference between conventional and

non-conventional resources

IEA Energy Training Week

Paris, April 4, 2013

Master of Advanced Studies in International Oil and Gas Leadership

Giacomo Luciani

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Exploration Appraisal Development / Production

Estimated ultimate recovery, MMbbl

Range of

uncertainty

High estimate

Best estimate

Low estimate

Cumulated production

Time 0

Decrease with time of uncertainty in reserve estimation

Reserves

• Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward.

• All reserve estimates involve some degree of uncertainty.

• Classification according to the relative degree of uncertainty: Proved reserves

Unproved reserves

• Probable reserves

• Possible reserves

Source: Society of Petroleum Engineers (SPE) Inc., 2000

Proved reserves (P90)

• Quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty (90% probability) to be commercially recoverable…

• Recoverable: From a given date forward,

From known reservoirs, and

Under current economic conditions, operating methods, and government regulations.

• Proved reserves can be categorized as: Developed, or

Undeveloped.

Source: Society of Petroleum Engineers (SPE) Inc., 2000

Unproved reserves

• Based on geologic and/or engineering data similar to that used in estimates of proved reserves;

• But technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved.

• Unproved reserves may be further classified as:

Probable reserves, and

Possible reserves.

Source: Society of Petroleum Engineers (SPE) Inc., 2000

Probable reserves (P50)

• Unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable.

• There should be at least a 50% probability that:

the quantities actually recovered will be ≥

estimated proved reserves + probable

reserves.

Possible reserves (P10)

• Unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves.

• There should be at least a 10% probability that:

the quantities actually recovered will be ≥

estimated proved + probable + possible

reserves.

Source: Society of Petroleum Engineers (SPE) Inc., 2000

Speculative or Undiscovered Resources

• Estimates of petroleum that might exist in a basin based on extrapolation of data on discovered resources, exploration intensity, number of wells drilled etc.

• Based on geological knowledge, but no two basins are the same…

From resource in place to proved reserves

Reserves “growth”

• Reserves are always estimated, they cannot be exactly measured

• The estimate of the reserves in a field changes with time, because our knowledge of the field improves while producing the oil from it

• Normally, the estimate increases, and reserves are said to “grow”: it is not the reserves that grow, it is just our knowledge and consequently our estimate that changes

• But sometimes our estimate is reduced

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Given the current proven reserves base, a 1% increase in the

average recovery rate would add 1 year extra oil production

Source: IEA, World Energy Outlook 2005

Unconventional vs. Conventional

Upside Downside

• Expensive drilling and

completion

• Oil upgrading is capital

intensive

• Low energy return on

investment

• Large greenhouse gas

emissions

• High oil recovery requires large

amounts of water

• High gas recovery requires

high well density

• Potential for groundwater

contamination

• Low exploration risk

• Long-life reserves

• Stable, predictable

production

• Assembly-line development

• Long project life provides: opportunity to improve

recovery

opportunity to improve

efficiency

security of supply

• Gas decline rates decrease

with time

Shale oil and Tight oil

In contrast to shale oil, which remained trapped in the original shale source

rock, the producing area, like the Bakken, contains migrated oil trapped in

siltstone and sandstone between layers of shale. The Eagle Ford’s oil is

trapped in carbonate rocks overlying shale from which it migrated

Tight shale oil: conventional oil extracted by unconventional means

because of lack of porosity and permeability

Horizontal drilling & hydraulic fracturing: « fracking »

The top three producing tight oil plays: Bakken, Eagle Ford, and Niobrara

account for 90% of total US tight oil output, currently about 620,000 b/d

extensive areas, high first-year well decline rates varying from 65% to

90%, and low recovery efficiencies averaged over the entire play: 1-2%

for tight oil. For 'sweet-spots' in the play such as Elm Coulee field, oil

recoveries can reach 5-6%

Potential in China, Australia, Middle East, Central Asia, Russia, Europe,

Argentina and Uruguay

Source: « evaluating production potential of mature US oil shale plays », Rafael Sandrea, IPC Petroleum

Consultants Inc., Dec 2012

Tight Oil Production for selected plays in the US

Source: Oil & Gas Journal, Dec 3, 2012

Heavy, Extra-Heavy Oil and Oil Sands

Essential component of oil resources

OIP estimated between 4,000 and 5,000 Gb

Reserves up to 600 Gb

80% of all heavy oils are in fact extra-heavy

Oil sands are included in this category

Accumulations in all parts of the world: Russia, USA, Middle East, Africa, Cuba,

Mexico, China, Brazil, Madagascar, Europe, Indonesia

The largest are located in Venezuela (The Orinoco Belt) and Canada (Province of

Alberta

Heavy oil is oil that has become extremely viscous as result of biodegradation

Bacteria active at low temperatures associated with shallow deposits consume the

lighter hydrocarbons, leaving behind the more complex compounds such as resins &

asphaltenes

Heavy Oil Classification

Source: F. Cupcic (TOTAL) - ASPO 2003

20,0

d°API: between 7° and 20°

Viscosity: between 100 cPo and 10 000

cPo = mobile at reservoir conditions –

can be recovered using Cold production methods

d°API: 7° << 12°

viscosity: 10 000

cPo<< 8 000 000

cPo) = non mobile.

Mining up to 100 m.

Deeper, Thermal

recovery methods

Canada

Venezuela

Light > 31

°API = 141.5/ density - 131.5

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Orinoco Belt versus Alberta: same order of magnitude for the

reserves

IOIP: 1400 Gb (source: PDVSA)

Reserves: 180 Gb* (source: PDVSA)

IOIP: 1800 Gb (Source: AEUB)

Reserves: 160 Gb (Proven)

* Proven reserves with a mixed cold / thermal technology

Source: PDVSA, AEUB (Alberta Energy and Utilities Board), BeicipFranlab 2012

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Oil Sands: Production Techniques

Source: Total

SA

GD

pro

du

cti

on

Surface Mining

Depth < 100m

20% of deposit

50% of today production

Lower energy intensity

Lower relative GHG

emissions

In situ

Depth > 100m

80% of deposit

50% of today production

Higher energy intensity

Higher relative GHG

emissions

Higher break even point

Surface Mining (1)

5 M$ each – 400 t

Technical cost

40%: mining

37%: separation bitumen from sand

23%: upgrading

In Situ

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In-Situ Exploitation

By Steam water

Recovery rate

20-25% Cycling injection: 1 well alternatively for injection and

production

40-60% Steam Assisted Gravity Drainange (SAGD)

Scale: 50 000 b/d

Usually no upgrading but diluted bitumen

Huge quantity of water required

1 b of water / 1 b of bitumen

to produce the steam water (energy source: natural gas)

Other techniques of injection (R&D)

Solvant injection

Combustion in-situ

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Oil Sands production Technologies: IN SITU (1) (thermal)

Cyclic Steam Stimulation (CSS) since 1985

CSS: better adapted to heterogeneous reservoirs and less viscous fluids of the

Cold Lake Area

Source: Total

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Steam is injected into the oil producing reservoir

As the steam permeates the sand, the oil is heated and becomes less viscous

The oil flows more freely through the wellbore's slotted liner and is pumped to the surface

Better adapted to homogeneous reservoirs and highly viscous fluids of the north & south

Athabasca area

Source: Total

Oil Sands production Technologies: IN SITU (2) (thermal)

Steam Assisted Gravity Drainage (SAGD) since 2001

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Naphta (for

transportation

Mining

Upgrading

Extraction

in-situ

Bitumen

Dilution Diluted Bitumen:

Dilbit (75+ Bit. + 25%

Naphta) / Synbit (50% Bit. + 50% SCO)

Synthetic Crude

Oil (SCO)

Refinery SCO or Naphta

(for commercialization)

50%

50%

Processes from Production to Refining

The bitumen extracted from the oil sands is very heavy and viscous. Once extracted, lighter

hydrocarbons (Naphta) can be added to the bitumen in order to be further processed or upgraded into a

form of synthetic crude oil (SCO) that is less viscous. After that, it can be sold to a traditional oil

refinery, though some bitumen is also sold in raw form for the production of heavy products like tar and

asphalt

Currently 5 operational upgraders in Alberta, 2 of which commenced commercial operation in 2009 –

Horizon & Long Lake

Sand

Water

Bitumen

Tailing Pond

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Production costs