l2-geology and resourceunconventionals

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L2- Geology and resource

1



Geology

• Conventional: Discrete fields or

pools localized in structural or

stratigraphic traps by buoyancyof oil or gas in water

• They have trap, seal, reservoir

with defined thickness & lateral

• USGS defines Continuous

petroleum accumulations are

those oil or gas accumulations thathave large spatial dimensions and

indistinctly defined boundaries,

and which exist more or less

continuity.

2



Geology

Continuous accumulations

– Two key geologic characteristics: (1) they consist of large volumes

of rock pervasively charged with oil or gas, and (2) they do notappear to depend upon the buoyancy of oil or gas in water for

their existence

– Because they may cover hundreds, or even thousands, of square

miles, they may occur across a wide range of stratigraphicenvironments, each of which may have widely varying reservoir

properties. Or They may exist in their source rock, never having

migrated in to a carrier bed or reservoir

– This all means that it is very difficult to obtain even a properlyframed stochastic view of how big or small these resources might

be because it is not always clear how big an individual

“accumulation” might be

3



Characteristics

Conventional

– Relatively high matrix permeability

– Obvious seals and traps

– High recovery factors

– The assessment of conventional resources focuses on the number of remaining

undrilled prospects (discrete potential structural or stratigraphic traps, often a

number in the tens, or possibly hundreds) and expected future field size

.

Unconventional

– Regional in extent, Diffuse boundaries, Low matrix permeability, No obvious

seals or traps, No hydrocarbon/water contacts, Abnormally close to source rocks,

Low recovery factors

– Includes tight sandstones, coal bed gas, oil and gas in fractured shale and chalkWhen originated by source rock, crude oils not heavy. Oil becomes heavy after

degradation

– For continuous resource assessments, the basic unit of assessment becomes the

number of wells that will ultimately be needed to develop the entire play area

(often a number in the thousands), and the expected recovery per well 4



Unconventional Oil Resources

5




Natural bitumen and extra-heavy oil resources (billion barrels)

6Source: WEO, 2010




Oil Shale resource (billion barrels)

7Source: WEO, 2010



Technically Recoverable Resources

8Source: PRMS Guidelines, 2011



PRMS - Resources classification framework

“A deterministic estimate is a single

discrete scenario within a range of

outcomes that could be derived by

probabilistic analysis.”

“Uncertainty in resource estimates is

best communicated by reporting a

range of potential results.However, if it is required to report a

single representative result,

the “best estimate” is considered

the most realistic assessment of

recoverable quantities. It is generallyconsidered to represent the sum of

Proved and Probable estimates (2P)

when using the deterministic

scenario or the probabilisticassessment methods.” 9Source: PRMS Guidelines, 2011



Subclasses based on project maturity





Change in uncertainty and assessment methods over the

Project’s E&P life cycle





Timeline for example oil project maturity stages and assessment

methods used





Volumetric and Analogous Methods

Volumetric equation for the volumetric equation for the PIIP PIIP

Estimated Ultimate Recovery (EUR)


Area ( A), net pay (h), porosity ( φ ), initial water saturation (Swi) and hydrocarbon

formation volume factor (FVF) (Bhi) for oil (RB/STB) or gas (Rcf/scf)




Material Balance Methods pi, p = average reservoir pressure (psia)

at reservoir datum and “i” stands for

initial,

T = average reservoir temperature at

reservoir datum (oR),


zi and z = gas compressibility factorsevaluated at pi and T and any p and

T, respectively,

G = GIIP (scf), and

Gp = cumulative gas production (scf) at any reservoir pressure (p).




Reservior Simulation Methods (RSM)

– The static geological, geophysical,

petrophysical, and engineering datacharacterizing the subsurface

reservoir structure in 3D

– The degree of uncertainty in the


estimates (or the range of outcomes)is expected to decrease as the

amount and quality of geoscience,

engineering and production

performance data increase. – Compare the estimates obtained

using several different methods




Production Performance Trend (PPT) Analyses





Unconventional Resources Estimation

USGS Methodology

– Resource assessments should be fundamentally based on

geology.

– Probabilistic methods should be used.

– Assessment methodology is a means of quantifying geologic

ypo eses an uncer a n es

17Source: USGS, Open File Report, 2011 - 1167



USGS Old Methodology

In-place Methods

– Volumetric calculation–Area * thickness * porosity * hydrocarbon

saturation * temperature/pressure corrections – Recovery factors generally conjectural

– Primary method used by the assessment community prior to 1995

–

Productivity - based Methods

– Based on productivities of cells–Cells are roughly the size of the

drainage area of a well

–

Well productivities determined by decline-curve analysis• Estimated ultimate recovery (EUR)




USGS Methodology

Productivity based methods

– Estimates of numbers of cells based on:

•

Area of assessment unit (AU)• Percent of area already tested

• Area of a cell

– n me o o ogy, a o ese are es ma e as pro a y

distributions

Advantages

– Well productivities (EURs) make assessments more realistic

– Much more production data available compared to 30 years ago• Many more wells with longer producing histories

• Many more plays




Revised USGS Methodology

Disadvantages

– Assessments are tied to current engineering practice

–

No estimate of volumes recoverable by future technologies – Large data requirements

Features of Revised USGS Methodology

– e s nstea o ce s

– Risk more explicit–AU risk, area risk, well risk

– Option to have mixture of two populations–Sweet spots and

nonsweet spots

– Direct estimation of uncertainty of mean EUR





Robustness

– The revised methodology works for both data-rich and data-poor

areas.• Analogs used for data-poor areas

– The revised methodology is not tied to a specific geologic model.

•

develops, this can be accommodated in the assessments.





Minimum Requirement

– Based on current USGS thinking of what is needed to have a

successful shale-gas AU – Could change in the future with increases geological

understanding

–

– Biogenic gas would have different minimum requirement

Defining Assessment Unit (AU)

– TOC>2 wt%

– Kerogen type I, II, or IIS – Ro>1.1%

– Net thickness>15 m

– Gas is thermogenic22

Source: USGS, Open File Report, 2011 - 1167




Desirable

– High gamma-ray values in shale

–

Hydrogen index of kerogen greater than 250mg/g – Depth more than 1500m

– Not intensely structured

– ver pressure

Analysis

– AU risk: Based on 5 Minimum requirement, what is possibilities

that all requirement are met at some place within the AU

– Productive Area: How large the are that meet requirements – Drainage Area: What is avg. drainage area of production well in

AU

– Untested Area: What is untested are in production area?23

Source: USGS, Open File Report, 2011 - 1167




Analysis

– Sweet vs Non-Sweet : Within the untested area, what percent

area falls within sweet spots?

– Success Ratio: Within the untested sweet spots, what percent of

wells will have productivity greater than the minimum?

– EUR distribution: Within the untested sweet s ots what is the

average EUR? – Coproduct Ratios: What are the average ratios? For oil AU: Gas to

oil and NGL to gas ratios, for Gas AU, liquid to gas ratio


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