2. Development Geology
• Hybrid discipline: geology on the field and
reservoir scale.
• Requires good knowledge of many disciplines.
– Structural Geology.
– Stratigraphy and sedimentology.
– Reservoir engineering.
– Drilling methods and engineering.
– Petrophysics.
– Seismology.
– Petroleum Economics and land management.
– Organic geochemistry……..
3. Why have a development
geologist
• Not all companies do! …this is becoming
less common.
• Engineers, Geologists and Geophysicists
don’t just specialize in different fields, they
think in different ways.
• There is a communication problem: the
development geologist must be able to
bridge the gap.
4. The Energy Crisis
• Size of discoveries decreasing.
• Reserves declining.
• New opportunities must be derived from old
plays and systems.
• Existing reserves must be economically
extracted.
• Modelling and understanding petroleum
systems as a whole is an essential skill.
5. • Importance of the Development Geologist
will progressively increase:
• Additional reserves required from known
occurrences
• Older discounted reserves need to be
reassessed
• Remember, about 60% reserves are left in
the ground.
6. Principal responsibilities of the
Development Geologist
• Estimation of Volumetric Reserves
• Justifying drilling options
• Providing a framework for maximum
financial return for his company
7. • Exploration Group discovers a field
• Responsibility for the field passed to the DG.
• DG must develop the field as economically and
efficiently as possible.
• Input needed from geologists, engineers, drillers,
financial whizzkids….need to be able to talk to all
these experts.
• 4 broad areas of responsibility lie within the title
DG:
8. 1. Predevelopment Evaluation
• After discovery of field.
• Exploratory wells & delineation wells are
drilled
– Evaluate field for reserves and design criteria.
• Very important stage in offshore areas
– Large capital investment: got to get the design
right
– Essential that this phase is done correctly
9. 2. Development Drilling
• DG is responsible for:
– Initiating development well recommendations
– Monitoring these wells during drilling
– Adjusting development plans as wells are
drilled
10. Well Surveillance
• Generally handled by the reservoir engineer
– However, when performance is not as expected
or when remedial work is required (workover)
the DG inputs geological constraint.
• RE & DG work together to evaluate unusual
reservoir performance
• RE & DG then make remedial
recommendations
11. Field Studies
• One of the most important roles of the DG.
• Re-evaluation of old fields and
recognition of new opportunities in these
fields.
– This role will become increasingly important in
the future as reserves decrease.
– The days of wild-catting are long gone.
12. Development Geology in a major Oil
Company
• 5 general subdivisions within a large oil company
(NOC, IOC..). Do not confuse these with the oil
process previously described in this course.
– Exploration
– Production
• E&P generally combined
– Refining
– Transportation
– Marketing
13. Common employment
positions in E&P and the
disciplines hired to fill
them in a large oil company
14. Development Geologist in small or
independent oil companies
• These companies don’t have the resources
to hire specialists in all the areas.
• E&P: generally a geologist/ geophysicist
combination.
• Production: a petroleum engineer
• Otherwise, a single geologist fills E&P and
consultants are used for everything else.
15. The Independent Petroleum
Geologist
• A real fun occupation: exciting career for a
petroleum geologist
• Must develop and produce an attractive
prospect alone and get wells drilled
• Must understand the methods by which a
prospect gets financed: the “third for a
quarter” deal
16. Important definitions
• Overriding Royalty Interest
– An ORI owner gets a percentage off the top (before operating
expenses.
– An ORI owner has no financial obligation
– Can be obtained by writing a book, mineral leases or generating
prospects in the oil business: lucrative.
• Working Interest
– Receives income but has financial obligations
– All costs incurred are the working interest owners responsibility
• Operator
– Individual or company responsible for getting the well drilled,
usually the principal working interest owner in the field
17. The Petroleum “Deal”.
How a petroleum geologist gets a overriding royalty
interest in a well and his/her company gets a working
interest in a well
AS you can see, with no investment on
his part, the prospect generator gets an
Royalty Interest: must, by law, for paid
overriding royalty interest just be
defining and justifying where to drill.
Overriding Royalty Interest: commonly
1/4 2-10% availablethe maths:
Do for the people who make
ORI =deal
the 3%
500 barrels a day production
Investment companies thirdtop a
You get 3% of the oil off the for
3/4
quarter interest
Oil sells at $40 a barrel
You make $600 per day or $18,000 per
month from ONE well
18. In conclusion
• Development geology is not only a rewarding, but a
lucrative field for the small and independent operator.
• In the future, this field (which requires skills in many
fields) will become more important as reserves decline.
• The bottom line in all petroleum exploration is financial,
and economic evaluations require input from many
disciplines: the DG must have these skills.
• The most important ability is RESERVE ESTIMATION
20. • A well will not be drilled just because the geology
is good.
• Wells get drilled because the geology is good and
there is potential for economic gain.
• The most important role os a DG is to:
– estimate the oil and gas reserves that may be discovered
in a particular venture.
– keep track of the reserves in all past ventures.
21. The 4 Basic Reserves Estimation
Methods
1. Educated Guess
2. Comparison with nearby production.
3. Reservoir Simulation – material balance
calculations
4. Volumetric Calculations
22. 1. The Educated Guess
• Historically wells were drilled by wildcat
techniques: some of the largest US discioveries
were made in this way.
• Even today some wells are drilled without an
economic analysis, largely due to contract
obligations.
• Very unlikely these days that you will get to drill a
well because you have a gut feeling about a
particular area.
23. 2. Comparison of nearby production
• Consider a region where production is from a
highly fractured tight formation or where
poroperm heterogeneity is unpredictable.
• Volumetric calculations are largely meaningless.
• A way to estimate potential production from a
well is to consider those nearby.
• Generally, such a wildcat well will not perform
better than the nearest wells: best to estimate
cautiously
24. 3. Reservoir Simulation
• Reservoir Modelling: primarily the reservoir engineer’s
job.
• Commonest simulation model – finite difference model
• Reservoir is modelled in terms of shape and:
– Porosity
– Permeability
– Fluid saturations
– Pressure
– Barriers and baffles….
• Internal reservoir conditions are then modelled: problem-
the best models are built after drilling development wells.
25. 3. Reservoir Simulation: Decline
Curves
• After wells have been producing for a while:
• Decline rate of production is graphed
• Generally 6 months-1year after start of production
• Good reserves estimates can be derived.
• Often compared with volumetric technique results.
• We will look at decline curves in detail later in the
course.
26. 4. Volumetrics
• Most accurate and widely used methods of
reserves estimation.
• Carried out by geologists as they are based on
geological structure and isopach maps.
• Rock volumes are established that are assumed to
contain hydrocarbons (e.g. seismic bright spot).
• Can be a simple volume calculation or a complex
net gas or net oil isopach approach, determined by
structure contours modified by fluid contacts and
net reservoir thickness isopachs.
27. • Most rock volumes established through use
of net gas and net oil isopachs.
• Constructed from structure contour maps
with well defined OWC and/or GOC.
28. Once rock volume is estimated, the in place
oil and/or gas is calculated by:
1. Determination of pore volume
– = rock volume x average porosity
– Average porosity generally from well logs or
engineers
2. By subtraction of water saturation, connate or
free water in the reservoir rocks.
– Water saturation numbers generally calculated by
petrophysicists or engineers
3. Correcting to sales line temperature and pressure
by using Formation Volume Factors
– FVF generally determined by reservoir engineers
29. Points of note
• Not the difference:
– In place volume = total oil/ gas
– Recoverable volume= that percentage that can actually
be produced as estimated by a recovery efficiency
(average 35%)
• All reserves are expressed in surface or pipeline
units
– Gas at reservoir conditions occupies less volume than at
surface.
– All are converted to a common sale pressure base.
– Conversely, oil shrinks on its way to the surface
31. Quantifying uncertainty in reserves
estimates
• ALWAYS uncertainty in estimates, hence we always
construct minimum, most likely and best-case estimates
– If you were putting your money into a venture, which would you
base your financial analyses on?
• In addition, we must always speak the same language:
terminology is essential in understanding what reserves
have been offered to you for investment
– Reserves are anything that can be recovered economically under
current economic and technological conditions.
– Reserves are classified as Proved or Unproved – what do we
mean by this?
– NB. A Reserve is not a Resource: A resource is anything that could
become economic given certain developments in the future. Do not
confuse the two (as many do)
32. Reserves: Proved
• Estimated to reasonable certainty
• Often based on well logs but normally requires
actual production or formation tests.
• Can be:
– Proved developed reserves
• Reserves that are expected to be recovered from existing wells
– Proved undeveloped reserves
• To be recovered by new drilling, deepening wells to a new
reservoir or where additional finance is required to produce
33. Reserves: Unproved
• Based on similar data but contractual, technical or
financial constraints prevent them from being
classified as proved.
• Can be:
– Probable Reserves
• Less certain than proved but can be assessed to some degree of
certainty
• May include logging estimates, improved recovery technique
estimates
– Possible Reserves
• Not as certain as probable reserves and can only be estimated
to a low degree of confidence.
34. Decision Making: protocol
• Despite these defined terms, there is still some
latitude in their application. In general, we use
this:
• Proved Reserves
– = minimum case economics. Financial investment is
based on proved reserves.
• Proved + Probable Reserves
– = most likely case economics. Internal company
decisions usually based on this.
• Proved +Probable + Possible Reserves
– = maximum case economics. This is the best that could
reasonably happe for a venture. Companies try to sell
ventures based on this.
35. Decision Making: projected
income analysis
• Standard diagram for major oil companies
to base their decisions on drilling and
development is a Reserves/ Potential
Income Diagram.
• Best shown with an example:
• Consider a company deciding whether to
spend $50m on the development of a field
by building an offshore platform….
36. Economists then provide estimates of likely oil price on production at:
Max: $40 per barrel
Most Likely: $25 per barrel
Min: $15 per barrel
This allows us to project best and worst case scenarios
for the well development.
200
Projected Income (MM$)
Maximum
160 Profit
120
80
Expected Capital
40 At
Expenditure Costs
Risk
0
1 2 3 4 5 6
MINIMUM MOST LIKELY MAXIMUM
Reserves (Million bbls)
If minimum is true: company will lose $10 – 25 million.
From other wells, geologists estimate recoverable reserves at:
Max: 5,000,000 barrels (provedprofit will be made.
If most likely is true: + probable + possible)
Most Likely: 3,000,000 barrels (proved + probable)
Min: 1,000,000 barrels (proved)
37. • As you can see, accurate estimation of
reserves is essential.
• Moreover, a knowledge of the financial
implications of terminology and your
assessments is critical.
• This is a fun and challenging aspect of the
business IF YOU ARE GOOD AT IT.
39. Isopach Maps
• Graphical representation of the vertical thickness
of a particular unit or feature.
– Vertical thickness of reservoir
– Vertical thickness saturated with oil
– Vertical thickness saturated with gas…
• Not to be confused with Isolith Maps
– True stratigraphic thickness of a lithological horizon.
• In reserves estimation, the Isopach maps are
projected onto the flat map surface. Isolith maps
must be rotated to account for dip.
40. • Overlying a structure contour map with an isopach map
allows determination of the true vertical thickness of a unit
of interest within a particular structure (e.g. trap)
• Designing an isopach map:
– Lot of data and reservoir irregular: make contour intervals small.
– Little data and/or reservoir regular: larger contour intervals
(shortcut)
• Different types of isopach map
– Gross sand thickness isopachs
– Net pay thickness isopachs
– Variable reservoir thickness isopachs
41. Gross Sand Thickness Isopachs
• GST = total thickness of rock saturated with oil or gas
irrespective of
• Tight zones
• Low porosity areas
• Low permeability areas etc..
• Easy to make, especially for gas
• Zero contour = downdip limits of gas (GOC or GWC)
• Gross isopachs should increase updip correspondingly with
the structure contour elevations
42. • E.g. if GWC is at -7,000’ subsea, then the following
isopach lines should overlay the structure contour lines as
shown:
Structure Contour Line Gross Isopach Line
-7000 0
-6980 20
-6960 40
• Until sand becomes full or top of structure is reached.
• For oil, the OWC will plot similarly, although the presence
of gas on top will cause updip wedging (decreasing
thickness) of the gross oil isopach
43. Net Pay thickness isopachs
• Refers to the gross reservoir thickness with
tight zones thrown out.
• If the reservoir is homogeneous we can
simply take the net to gross of the reservoir
and multiply the thickness of the unit by
this reduction.
• Otherwise, heterogeneity can considerably
complicate matters.
44. Variable reservoir thickness isopachs
• Reservoir thickness changes rapidly
– e.g. edge of reef, channel
– Requires a net reservoir thickness isopach map
• GWC or GOC = structure contour (zero gas line)
but this will veer away from the structure contour
where the sand thickness disappears (can’t have
gas where there is no reservoir)
• Basically, the thicknesses are modified so that the
net gas or net oil thickness isopachs do not exceed
the thickness of the reservoir.
45. Calculations from isopachs
• Trapezoidal Rule
– Used to calculate rock volume from an isopach:
BV = (h/2) [A0 + 2A1 + 2A2 + …+ 2An-1 + An] +hnAn/2
Where
BV = bulk volume (acre feet)
h = contour interval
A0 = area enclosed by zero contour line
A1 = area enclosed by first contour line
An-1 = area enclosed by first contour line above top contour
An = top contour line
hn = vertical distance from top contour to top of reservoir
i.e. take the average area between two intervals and multiply that area by
contour interval thickness to get the volume it encloses.
46. GOC or GWC
0’
20’ h = contour interval = 20’
40’
A
54’
B
Illustration of the
Trapezoidal Rule:
Net gas isopach
over the top of a
max h = 54’
dome.
hn = 60 – 54 60’
= 14’
An 40’
A1 20’
A h = 20’ B
A0 0’
GOC or GWC
BV = (h/2) [A0 + 2A1 + 2A2 + …+ 2An-1 + An] +hnAn/2
47. GOC or GWC
0’
20’
40’
A B
54’
Useful Shortcut
Area of the top of a
sphere is remarkably
close to the result of
max h = 54’
multiplying the base
area A0 by ½ the
maximum thickness
60’
i.e. 0.5 x 54 = 27 ft
An 40’
A1 20’
A B
A0 0’
48. Wedge of gas filled sand here
0’ Reservoir is full of gas to the base of the sandstone in this area
Fa
’ ult
20 A
’
’ 54
40 =
h
ax
m
C D
SAND FULL LINE
lt B
Fau
Fault A
60’
Max h = 54’
40’
C 20’
D
0’
Fluid Contact
Sand Full above this point
Well drilled here will find gas
and oil or water Well drilled here will find only gas
