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RESERVOIR GEOLOGY
INTRODUCTION
RESERVOIR GEOLOGY
Definition:
Reservoir geology is an integrative science that incorporates:
Basic geologic principles and
Some engineering application in describing a reservoir
Reservoir geology could be seen as a spectrum extending
between the end-members of geology and some aspects of
reservoir engineering such as fluid dynamics and pressure
systems
RESERVOIR GEOLOGY CONTD.
Reservoir geology thus relates the fundamental principles of
geology and engineering in accurately:
Describing,
Delineating,
Or Monitoring
of a reservoir in terms of its geometry and rock properties,
with a view of modelling it and eventual recovery of
hydrocarbon in place.
RESERVOIR GEOLOGY CONTD
The Geology of a Reservoir Involves:
Reservoir Thickness,
Lithology,
Composition,
Size,
Roundness and Sorting of Grains,
Cement,
Depositional Geometry,
Structure,
Diagenetic
Depositional History.
RESERVOIR GEOLOGY CONTD
These factors permit not only the definition of rock
properties but can ultimately control well spacing and
production programs
They also relate to the physical and chemical condition of
the reservoir and promote an understanding of its engineering
condition
RESERVOIR DEFINITION
For any subsurface body to be called a reservoir the following
criteria must be fulfilled:
The Ability for Such a Body to Store Fluids
The Ability to Transmit the Fluid
Hence, an in-depth knowledge of geology is necessary in
describing a reservoir and its subsequent modelling.
DATA REQUIRED FOR RESERVOIR
GEOLOGY
Well logs,
Core data,
Test data,
Fossils,
Maps
Seismic data.
DATA REQUIRED FOR RESERVOIR
GEOLOGY CONTD..
The well logs, core data, test data are used to define the
vertical and lateral reservoir characteristics.
From the analysis of these data, stratigraphic and structural
cross- sections are produced, which show the composition and
shape of the reservoir.
DATA REQUIRED FOR RESERVOIR
GEOLOGY CONTD..
The variations in reservoir group are shown by structure,
lithologic, facies and Isopach maps.
Fossils identification permits the precise age determination of
reservoir rocks and is an aid in establishing the depositional
histories
Figure 1.1 The interrelationship between reservoir geology and other
sciences
Reservoir
Geology
Geophysics
Fluid
Mechanics
Mineralogy
Structural
geology
Descriptive
geometry
Paleontology StratigraphyPetrophysics
Petrology
RESERVOIR TYPES
TYPES OF RESERVOIR ROCKS
A reservoir rock is one capable of accumulating a quantity of petroleum if entrapment conditions are met and liberating it during drilling and production. This attribute of a reservoir rock is a function of its porosity and permeability.
Reservoir rocks for petroleum are mainly: Sandstones,
Conglomerates
Carbonates
SANDSTONES RESERVOIRS
Sandstones which are compacted sands, are detrital silicate rocks composed essentially of:
Framework Minerals:
Quartz,
Chert,
Feldspar and
Rock Fragments
SANDSTONES RESERVOIRS
Matrix:
Silk,
Mud and
Clay Minerals
Cement:
Silica,
Carbonate
Iron Oxide
Clay Minerals.
SANDSTONES RESERVOIRS
They form in:
Ocean basins (turbidities),
Shelf areas (tidal and storm ridges)
Shore zones
-Barrier Islands
-Deltas
-Intertidal flats
Fluvial settings such as meander, braided and alluvial fans as well as desert areas.
CLASSIFICATION OF SANDSTONES RESERVOIRS
They are classified into:
Quartz Arenites
Lithic Arenites
Arkosic Arenites
QUARTZ ARENITES:
Contain 95% quartz,
Generally supermature mineralogically and texturally,
Matrix made up of predominantlyclay minerals such as illite and kaolinite,
CLASSIFICATION OF SANDSTONES RESERVOIRS CONTD.
Cement mainly calcite and or silica,
Porosity and permeability very high because of the
compositional nature,
They are the best reservoirs,
Production of petroleum from them is predictable,
They are associated with barrier islands, beaches,
deltas and tidal channels
CLASSIFICATION OF SANDSTONES RESERVOIRS CONTD.
Arkosic Arenites:
Quartz percentage less than 90%
Felsdpars usually greater than rock fragments
Percentage of feldspar more than 25%,
Generally mineralogically and texturally not matured.
Matrix is dominantly clay minerals such as illite,
kaolinite and montmorillonite.
CLASSIFICATION OF SANDSTONES RESERVOIRS CONTD.
Arkosic Arenites Contd.:
Cement usually calcite and silica but calcite is
dominant.
They are moderate reservoirs
Porosity and permeability high because of much
matrix
They form in deltas and turbidites
CLASSIFICATION OF SANDSTONES RESERVOIRS CONTD.
Lithic Arenites:
Quartz percentage less than 90%
Rock fragments exceed feldspar content.
Rock fragments content exceed 25%.
Usually contain igneous and metamorphic rock
fragments.
Matrix made up of clay minerals such as illite,
kaolinite and montmorillonite.
CLASSIFICATION OF SANDSTONES RESERVOIRS CONTD.
Lithic Arenites Contd:
Have lower porosity and permeability when compared
with quartz and arkosic arenites.
The are moderately good reservoirs.
They are associated with fluvial sequences
CARBONATES RESERVOIRS CONTD.
Limestones are carbonate rocks composed mainly of calcite.
Their framework materials are mostly carbonate particles such as:
Fossil Fragments,
Oolites Pellets, and
Pelletoids.
These are usually bound with lime mud (micrite) and cemented by calcite/dolomite
CONGLOMERATE RESERVOIRS
Conglomerate Reservoirs are classified into:Orthoconglomerates:
-grains in mutual contact with one another-mostly monomineralic-made of pebbles and cobbles of silica-usually associated with well sorted sediments like quartz arenites
-coarse to very coarse-cementing material is silica-have good porosity and permeability-they are good reservoirs
CONGLOMERATE RESERVOIRS CONTD.
Paraconglomerates:-have matrix support fabric-charts and phenocrysts not in mutual contact-matrix minerals are poorly sorted shaly sandstone, silt, mudstone or even shales
-they are polymodal -cementing material is commonly calcite-have low porosity and permeability-they are poor reservoirs because of the abundance of clay minerals
CARBONATES RESERVOIRS
Carbonates Reservoirs are made up of mainly:
limestone-CaCO3 ;
dolomites CaMg( CO3)2
They are rocks composed dominantly of:
- calcite,
- aragonite
- dolomite.
LOCATION OF RESERVOIRS IN
THE SUBSURFACE
HOW TO LOCATE RESERVOIRS
Reservoirs are located using Geophysical Exploration Methods
Definition:
Methods which involve the application of the
principles of physics in search of hydrocarbon
deposits within the subsurface earth.
BRANCHES OF GEOPHYSICSPure Geophysics
Aims at obtaining the physical properties of the earth as well as its internal constitution from an analysis of the physical phenomena associated with it such as –geomagnetic field, thermal field, force of gravity and the propagation of seismic waves.
Applied Geophysics (or Exploration Geophysics)
Attempts to investigate and measure specific and relatively small scale features that exist within the earth, such as – salt domes, synclines and anticlines, faults, dykes and undulation of the crystalline bedrock.
. MAIN EXPLORATION METHODS
•Gravity Method
•Magnetic Method
Seismic method
DATA REQUIREMENT
Signal:
• Is that we wish to measure
• In Gravity work signal is the field of the mass
distribution produced by some feature
• In seismic work, it is the reflections from
interfaces in the subsurface.
Noise:
• Is anything which obscures signal
• Is always present in greater or lesser
extent.
DATA REQUIREMENT
Filter
• A discriminator of Signal from Noise
•Enhances Signal to Noise ratio
•This can be done by strengthening the signal or
by attenuating the noise.
DATA INTEGRATION
All types of information in geophysical exploration must be tied together in order to make a worthwhile interpretation. These include:
• Given set of geophysical data
• Surface geology
• Regional Tectonics concepts
• Information from Boreholes
A worthwhile geophysical interpretation can not be done in isolation
INFERENTIAL REASONING
Exploration for hydrocarbon reservoirs has to rely on this, a typical line of reasoning is:
A is often related to B,
B is often related to C,
C is often related to D, etc.
Therefore, if A is observed, perhaps D can be inferred.
GRAVITY METHODIn the gravity method, measurements are made of minute
variations in the pull of gravity from rocks within the first few miles
of the earth’s surface. The measurements are made with a gravity
meter, which is capable of detecting minute variations in the pull of
gravity with an accuracy of one part in ten million.
Theoretical
gravity graphs
over various
buried structural
hydrocarbon
traps.
PRINCIPLE OF OPERATION
Gravity exploration is based on Newton’s Law of Universal Gravitation:
221
d
MGMF
•F = Gravitational force between two point
masses M1 and M2
•d = Distance between M1 and M2
•G = Universal gravitational constant
FACTORS AFFECTING THE MAGNITUDE OF
THE EARTHS GRAVITY FIELD
• Variation of gravity with latitude
• Elevation above sea level
• Nearby topographic features
• Tidal deformation of the earth’s crust due to the
attraction of the sun and moon
• Variation in the nature and density of rocks
underground
APPLICATION OF GRAVITY METHOD
• Definition of Basin Shape and Extent
•Structural Trends
•Fault Locations
•Prospect Leads
MAGNETIC METHOD
This method is aimed at determining and interpreting anomalies which arise from local variations in the magnetic field.
These variations are as a result of changes in the magnetic properties of rocks such as susceptibility.
The magnetic method uses the magnetometer which indicates deviations from the earth’s normal magnetic field.
MAGNETIC METHOD
Granite ridges, igneous intrusive rocks and structures containing highly magnetic rock layers produce such deviations.
Whenever petroleum is expected to be trapped by or associated with rocks such as these, the magnetometer is a valuable exploration tool.
Theoretical magnetometer graph over a buried igneous
intrusive containing many magnetic minerals. The upwarping
caused by the intrusion has created an anticlinal oil trap.
APPLICATION OF MAGNETIC METHOD
Limits of basins
Depth to basement
Basement lineation
MAGNETIC AND GRAVITY SURVEYS
Cost-effective methods of reconnoitering large areas of the earth's surface onshore and onshore before lease acquisition.
Define the limits and scale of sedimentary basins and the internal distribution of structural highs and lows
Magnetic and gravity surveys are now being run concurrent with offshore seismic surveys.
SEISMIC METHOD
Seismic methods are the most important geophysical
method. These miniature earthquakes are created at or
near the surface of the earth by exploding a charge of
dynamite.
The seismic wave created by the dynamite explosion
travels downward through the rock layers.
SEISMIC METHOD CONTD.
When the seismic wave encounters a particularly hard,
dense layer (for example, a limestone underlying a soft
shale), a small portion of the energy of the seismic wave
is reflected back to the surface.
Lower reflecting horizons are detected by sets of
wiggles farther along on the seismic record.
SEISMIC METHOD CONTD.
Seismographic field operation.
(After Finley, 1975)
TRAVEL TIME
Magnitude of the Travel Time Depends On:
Travel path
Elastic properties of the materials along the path of the waves.
TYPES OF SEISMIC METHODS
Refraction Seismic
Reflection seismic
GENERAL PRINCIPLE IN SEISMOLOGY
Reflection and Refraction of seismic waves occurs when there is a difference in acoustic impedance(product of velocity and density) between two media.
Usually, the density variation is so small compared with velocity variation, so velocity variation is usually what is considered,
Hence we often automatically think in terms of velocity discontinuities when we consider seismic exploration
Discontinuities may be caused by subsurface reservoirs
.
REFRACTION METHOD
This utilizes seismic energy that returns to the surface after traveling through the ground along refracted ray paths.
This method is normally used to locate refracting horizons that separate layers of different seismic velocity.
Source point
Receivers
Field Arrangement
Intercept time
Offset distance
Layer 1, V1
Layer 2, V2Depth
Crossover distance
t – x curve and geometry of the refracted ray path through a 2-layer model
APPLICATION OF REFRACTION METHODDepth of layers
Engineering;
Identification of subsurface materials- hard or
soft soils
Mapping of shallow structures to depth of 5000ft
Outline salt domes
Velocity determinations
REFLECTION METHOD
The measurement of the arrival time of wave energy reflected from the subsurface between two media of different acoustic impedance
Here the travel time of wave energy depend on the velocity of the medium(rock).
The variation of velocity is a function of depth, due to differing physical physical properties of layers than horizontally.
The horizontal variation is due to lateral facies changes.
Source point Receivers
Field Configuration of Seismic Reflections
SEISMIC ENERGY SOURCES
Sources Land Marine
Explosives Yes Yes
Air Gun No Yes
Vibroseis Yes No
Gas Exploder Yes Yes
Weight Droppers Yes No
Seismic Cross-section
OBJECTIVES OF SEISMIC INTERPRETATION
To Determine The Geological Structure
To Determine The Nature Of The Rocks
The Nature Of Fluids In The Pore Spaces Of the Rocks
APPLICATION OF REFLECTION METHOD
Identify Structural Types
Structural Character
Sediment Velocities
Unconformities
Inferences From Reflection Character
Inferences Of Depositional Environment
Direct Hydrocarbon Indicator
HYDROCARBON MOVEMENT
TO AND WITHIN THE
RESERVOIRS
During and after generation, the hydrocarbon is in a
dispersed state within the fine grained source rock.
To produce a pool therefore, the hydrocarbon must
migrate to the reservoir rock.
HYDROCARBON MOVEMENT TO AND WITHIN THE
RESERVOIRS
This Is Called Migration
MIGRATION is responsible for moving the petroleum
hydrocarbon from the fine grained clays, shales, micrite,
lime mud in which they are formed to the coarse grained
reservoir rocks where they accumulate and are trapped.
There are three types of migration:
Primary Migration
Secondary Migration
Tertiary Migration.
HYDROCARBON MOVEMENT TO AND WITHIN THE
RESERVOIRS CONTD.
PRIMARY MIGRATION
Compaction is the main cause of primary migration
After the deposition and preservation of kerogenous clay and lime mud source beds progressive compaction sets.
As the depth of burial increases with concomitant increase in temperature and pressure, clay dehydration begins at a depth greater than that at which the hydrocarbons were generated.
PRIMARY MIGRATION CONTD.
At shallow depths clay/water saturation is about 80% at 2000 it reduces to 25% and 10% at about 6000depth.
As compaction takes place, porosity is decreased and the liquid contained in the pores is squeezed out.
SECONDARY MIGRATION
Secondary migration takes place within the porous strata or from one reservoir rock to another.
It is determined by gravity and hydrodynamic fluid gradients as the hydrocarbon seek areas of less potential energy.
It is essentially lateral.
This is the migration that finally gathers the oil into the pool that we find today in reservoirs.
.
TERTIARY MIGRATION
This takes place due to the flow of fluids from high to low pressure areas.
This is the movement or flow of petroleum from the reservoir rocks into a well bore when the formation is drilled.
ENTRAPMENT OF HYDROCARBON
IN RESERVOIRS
ENTRAPMENT OF HYDROCARBON IN
RESERVOIRSThe migration of hydrocarbon within reservoir rocks would continue indefinitely due to the effects of:
Buoyancy,
Capillary Forces
Hydrodynamic Forces
The migration can only be stopped by one form of trap or another.
These traps then impede the movement and get the hydrocarbon to accumulate into pools.
TYPES OF RESERVOIR TRAPS
There Are Three Main Types of Traps
Structural Traps
Stratigraphic Traps
Combination Traps
STRUCTURAL TRAPS
These are petroleum traps formed by flexures and fractures of the rock strata including the reservoir beds.
They result from the elastic or otherwise behaviour of strata when subjected to stresses (usually horizontal).
The two most important types of structural traps are:
Anticlinal Traps and
Fault Traps.
STRUCTURAL TRAPS CONTD.
Anticlinal Traps:
They are basically upfolds of rock layers and are produced by lateral pressure acting in a horizontal plane.
Anticlines are by far the most abundant structural traps in the Niger delta.
Fault Traps:
A fault is a rock fracture which results in the relative displacement of the strata on either side of the fault plane.
It is formed by sheering forces associated with earth movement or rapid deposition.
FAULT TRAPS CONTD..
The trapping of hydrocarbon by fault is dependent on the availability or presence of:
An inclined reservoir
A caprock
A barrier in the reservoir along the fault to
prevent lateral migration
Structural Traps
Faults
Piercements
Oil
Oil
Oil
Gas
SaltSalt
Water
Oil
StructuralUnconformities
Anticlines
Salt Water
Oil
STRATIGRAPHIC TRAPS
Stratigraphic traps are not dependent on folding or
faulting of the rock layers
They are formed by primary changes in porosity and
permeability related to deposition.
COMBINATION TRAPS
These are combination of structural and stratigraphic traps.
Stratigraphic Traps
Isolated Sand or
Limestone Bodies
Fluvial bars and
channels
Deep water channels
Reefs
Oil
OilOil
Water
WaterWater
Exercise No. 1Name the hydrocarbon traps shown in the figure:
AAA
B
C
F
ED
Solution to Exercise No. 1
A. Anticline
B. Pinchout
C. Unconformity
D. Reef
E. Salt dome related
F. Fault
HYDROCARBON OCCURRENCE IN RESERVOIRS
Hydrocarbon can occur near the surface or subsurface. Crude oil and natural gas mostly occur in the subsurface reservoirs whereas the semi-solid gas mostly occur at or near the surface reservoirs.
Surface Occurrences:
Petroleum may occur as springs or seepages from fractured reservoirs.
The semi-solid/solid petroleum are usually regarded as fossil petroleum (petroleum that has lost its liquid and gaseous components).
HYDROCARBON OCCURRENCE IN RESERVOIRS CONTD.
Fossil occurrence may be wax, asphalt or bitumen.
In Nigeria, the Okitipupa Tar Sand Deposits which extends over much of Ondo, Ogun, Ekiti arose from seepage of hydrocarbon from the subsurface along the geologic boundary between the sedimentary basin of the Niger delta and the basement rocks of the West.
SUBSURFACE OCCURRENCES
Subsurface occurrences of petroleum are restricted to gaseous and liquid hydrocarbons. Based on their economic viability, the following classes are distinguished:
Minor Oil Shows in Reservoirs:
These are uneconomic oil and gas accumulations in reservoirs based on the current pricing system for oil.
Reservoir Pool:
This is the simplest unit of commercial occurrence of petroleum in a reservoir. It is a body of oil and /or gas which occurs in a separate reservoir and under a single pressure system.
SUBSURFACE OCCURRENCES CONTD
Field:
This term is applied:
A group of oil and /or gas reservoir pools related to a single geologic feature such as structural or stratigraphic.
The individual pools may occur at different depths, one above the other or they may be distributed laterally throughout the geologic features.
Very large fields are called giants fields.
SUBSURFACE OCCURRENCES CONTD
Province:
A petroleum province is a region which contains:
A number of oil and /or gas reservoir pools and fields
In a similar or related geologic environment
Example the Niger Delta Petroleum Province.
\
HYDROCARBON IN RESERVOIR
RESERVE ESTIMATE
DEFINITION OF RESERVE
Amount of crude oil, natural gas, and associated substances that can be produced profitably in the future from subsurface reservoirs
Reserves are that portion of an identified resource (in this case, hydrocarbon) that is available now by being economically recoverable under existing technological conditions (F. K. North, 1985).
CLASSIFICATION OF RESERVES
Reserves Are Classified Into:
Proved Reserves (> 80% Probability)
Drilled
Not drilled
Probable Reserves (40 to 80% Probability)
Undeveloped part of pool
Secondary recovery
Behind pipe
CLASSIFICATION OF RESERVES CONTD.
Possible Reserves (10 to 40% Probability)
Shallower or deeper pools within field limits
Pools outside field limits
Areas not now producing but which are
geologically similar to producing areas in the
region
RESERVE
Why Estimate Reserves?
For exploration, development & production
Evaluation of profit/interest.
Govt. regulatory & taxation
Planning & development of national energy
policies
Investment in oil/gas sector
Reconcile dispute or arbitration involving reserves
PROVED RESERVES
Proved reserves of crude oil, natural gas, or natural gas liquids
are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in
future from reservoirs under existing economic conditions.
Proved reserves in terms of recovery are estimates of
hydrocarbons to be recovered from a given data forward. They
are expected to be revised as hydrocarbons are produced and
additional data become available
PROVED RESERVES CONTD.
Reservoirs are considered proved if economic
producibility is supported by actual production or
formation tests OR
If core analysis and or log interpretation demonstrates
economic producibility with reasonable certainty.
PROVED RESERVES CONTD.
The Area of a Reservoir Considered Proved Includes:
That portion delineated by drilling and defined by fluid
contacts, if any.
The adjoining portions not yet drilled that can be reasonably
judged as economically productive on the basis of available
geological and engineering data.
In the absence of data on fluid contacts, the lowest known
structural occurrence of hydrocarbon controls the lower
proved limit of the reservoir.
PROVED RESERVES CONTD.
Estimates of proved reserves do not include crude oil,
natural gas, or natural gas liquids being held in
underground storage (that is though they are there, but
have not been ascertained)
Other Categories of Proved
Reserves (Sub-category)Proved Developed Reserves:
They are those reserves that can be expected to be recovered
through existing wells (including reserves behind pipe) with
proved equipment and operating methods. Improved recovery
reserves can be considered developed only after an improved
recovery project has been installed.
Other Categories of Proved
Reserves (Sub-category)
Proved Undeveloped Reserves:They are those additional proved reserves that are expected to
be recovered from:
1. Future drilling of wells
2. Deepening of existing wells to a different reservoir
3. The installation of an improved recovery project.
PROBABLE RESERVES
Probable Reserves of crude oil, natural gas, or
natural gas liquids are:
Estimated quantities that geological and engineering
data indicate are reasonably probable to be recovered
in the future from known reservoirs under existing
economic conditions.
Probable reserves have a higher degree of uncertainty
with regards to extent, recoverability, or economic
viability than do proved reserves.
POSSIBLE RESERVES
These are estimated quantities that geological and engineering
data indicate are reasonably possible to be recovered in the
future from known reservoirs under existing conditions.
Possible reserves have a higher degree of uncertainty than do
proved or probable reserves
CATEGORY OF RESERVES BY WORLD
PETROLEUM CONGRESS
Proved Reserves, both developed and undeveloped
Unproved Reserves, available only from deposits already
discovered. This category embraces the probable and possible
reserves of American system
Speculative Reserves: All volumes expected from deposits
not yet discovered
The Ultimate Potential Recovery: The ultimate potential
recovery is the sum of the volumes in these three categories
plus the cumulative production
THE COMPUTATION OF RESERVOIR
VOLUME
Reserves are calculated using two major methods:
Planimetering
Volumetrics.
PLANIMETERING
The volume of the reservoir rock between the highest point in
the trap and the level of the bottom water (OWC or GWC) or
stratigraphic bottom of hydrocarbon sand (HDT) is simply the
accessible area times the average thickness of the saturated
rock especially within the structural closure.
PLANIMETERING CONTD.
The area is obtained from geologic map (structural top maps,
net pay maps).
Using Simpson’s rule or Trapezoidal rule the area enclosed by
the contour is planimetered and plotted as abscissa on an acre-
feet diagram versus the corresponding sub-sea depth as the
ordinate.
PLANIMETERING CONTD.
After the observed points are connected, the combined gross
volume of oil-and gas – bearing sand may be determined by
the following method:
If the sand is of uniform thickness, it will often times suffice
to multiply the average gross pay thickness by the area
enclosed by the contour .
PLANIMETERING CONTD.
If the area within the top contour is circular, then the top
volume if treated as a segment of a sphere is given by:
And ⅓Az if treated as a cone
AzZ21
61
PLANIMETERING CONTD.
Multiplication of the net-pay fraction by gross sand volume
yields (V) the net pay volume.
For example, if it is found that 15% of the gross section is
consisted of evenly distributed shale, the net bearing pay
volumes may be computed as:
0.85 x V = Net hydrocarbon bearing pay volumes
Geologic softwares like petrel could be used for this purpose,
if the input data are available.
Volumetric Method
Used
At early life of the reservoir
In principle, to
Estimate O/GIIP
RF and recovery efficiency
In practice,
Assumes V = A * h
Assumes RF from drive mechanism
Estimates reserve as R = V * RF
VOLUMETRIC METHOD CONTD.
Requires
Subsurface data
Appropriately calibrated seismic data
Maps
OIL INITIALLY IN PLACE
For oil reservoirs or oil column of an oil reservoir with gas
gap (no free gas present in oil saturated portion) ,OIIP may be
estimated as:
N = 7758Ah(1-Sw)/ Boi
Where,
N = Oil initially in place
7758 = barrels in an acre-foot
= average porosity in the oil zone, fraction
Sw = average water saturation in the oil zone, fraction.
A = area of the oil zone, acres
h = average net oil pay, feet
Boi = average initial oil formation volume factor.
GAS INITIALLY IN PLACE
For a non associated gas reservoir or for a gas cap in
associated reservoirs (no residual oil present), free gas
initially in place may be estimated as:
G = 43560Ah( 1- Sw ) / Bgi
Where,
43560 = cubic feet in an acre-foot
= average porosity in the free gas zone, fraction
A = area of gas gap or gas reservoir acres
h = average net thickness of gas cap reservoir, feet.
Bgi = average initial gas formation volume factor, rcf/scf
RF = Gas recovery factor
SOLUTION GAS
Solution Gas in oil Reservoir (no free gas present) For
standard cubic feet of solution gas in place is given by:
o
ss
B
RG
)S-(1 V 7,758 iwo
Where:
Gs = Solution gas in place, SCF
Rs = The solution GOR, SCF/STB
CONDENSATE INITIALLY IN PLACE
C = G R ci
Where,
C = condensate initially in place, STB
G = free gas initially in place, MMSCF
Rci = Initial condensate / gas ratio,
stbconde/mmscf
ESTIMATES OF PROBABLE OR POSSIBLE
RESERVES
Probable additional supply, from enlargements of known
fields within, beyond, or below their currently productive
limits, may be assessed by:
Considering the historical appreciation of the discovered
reserves in such fields.
The reserves of a field may appreciate:
Within its original area
Depth limits,
Because of:
Excessively conservative early assessments,
Improved recovery technologies ( such enhanced recovery,
or denser development drilling)
ESTIMATES OF PROBABLE OR POSSIBLE
RESERVES CONTD.
This form of appreciation constitutes revisions of the reserves.
Revisions may move the reserves downwards instead of
upwards, of course; not all early estimates are excessively
conservative..
Possible additions to supply may be gained by extrapolating
historical discovery rates in the single basin, or in clearly
comparable basins elsewhere, but the exercise is largely
nugatory for a simple operational reason.
ESTIMATES OF PROBABLE OR POSSIBLE
RESERVES CONTD.
Possible Reserves Can Only Exist:
Within regions already productive
Areas having few exploratory wells.
Areas having few wells penetrating the entire potentially
productive section
HYDROCARBON IN RESERVOIR
RECOVERY TECHNIQUES
RECOVERY TECHNIQUES
The procedure and method designed to produce the maximum
petroleum from the reservoir at the lowest cost is referred to as
recovery techniques.
The maximum petroleum produced is a function of:
The reservoir
Reservoir characteristics.
OIL AND GAS RECOVERY IN A RESERVOIR
•Oil and gas found in reservoirs can be utilized only when recovered at the surface. Three classifications used to describe the methods of recovering fluids from oil and gas reservoirs are:
•Primary recovery.
•Secondary recovery.
•Tertiary recovery.
The secondary and tertiary recovery methods are also called:
•Enhanced recovery methods.
PRIMARY RECOVERY.Primary recovery is the initial production of fluids from the reservoir using only available natural sources of energy to recover the oil and gas. The main sources of energy for primary recovery are:
(a) Energy from expansion of under-saturated oil above the bubble point.
(b) Energy from expansion of rock and connate water.
(c) Energy from expansion of gas released from solution in the oil below the bubble.
(d) Energy from invasion of the original oil bearing reservoir by the expansion of the gas from a free gas cap.
(e) Energy from invasion of the original oil bearing reservoir by the expansion of the water from an adjacent or underlying aquifer.
(f Energy from gravity effects.
DRIVE MECHANISM
•Oil reservoirs are now classified on basis of dominant energy responsible for primary production. In the classification, the energy responsible for primary production is termed the drive mechanisms. The main types of drive mechanisms are
•Water Drive,
•Gas Cap Drive,
•Solution Gas Drive, And
•Combination Drive.
To optimize oil recovery required knowledge of the reservoir drive mechanism is essential.
DRIVE MECHANISM CONTD.)
The basic data needed to determine which drive mechanism is at work in a given reservoir are:
(a) Reservoir pressure and rate of decline of reservoir pressure over a period of time.
(b) The character of the reservoir fluids.
(c) The production rate
(d) The gas-oil ratio
(e) The water-oil ratio.
(f) The cumulative production of oil, gas and water.
SECONDARY RECOVERY
•After the natural energy of a reservoir is used up, substantial amount of oil is still left unrecovered.
•With increasing demand for petroleum, it is necessary to find ways to recover the oil left in the reservoir.
•Secondary recovery methods are applied for this purpose.
•Secondary recovery methods, also called fluid injection process, involve injection of fluid to displace the oil. such as:
•Water Injection.
•Gas Injection
TERTIARY RECOVERY
•Even with a well-engineered secondary recovery process, about one-third of the original oil is unrecovered.
•Tertiary recovery methods are used to recover residual oil left behind by increasing the volume of the reservoir contacted. In general, these tertiary recovery methods fall into three categories.
•Miscible Fluid Displacement.
•Thermal Recovery.
•Chemical Recovery
RECOVERY IN GAS RESERVOIRS
•Gas reservoirs differ from oil reservoirs in that they generally contain no oil, but produce mainly gas or, sometimes, gas with varying amounts of condensate or water.
•Unlike some oil reservoirs, which have poor recovery efficiencies in primary production, gas reservoirs generally produce well without addition of supplementary energy.
RECOVERY IN GAS RESERVOIRS
•Primary recovery methods are usually sufficient because a sizeable amount of stored energy is contained in the compressed gas in reservoir. In addition, gas is highly mobile, which enables it to travel easily through the rock. Gas recovery efficiencies in excess of 80 percent are not uncommon.
RESERVOIR ROCK PROPERTIES
Applications Of Reservoir Rock Properties
Determination of Hydrocarbon Content of Reservoir
Determination of Reservoir Content That Can be
Recovered
Designing the Most Effective and Recovery Efficient
Method
Determining the Reservoir and Individual Well
Production Potential
Possible Production Rate
Potential Production Profile
RESERVOIR ROCK PROPERTIES
Basic Reservoir Rock Properties
Porosity
Permeability
Fluid Saturation
Formation Volume Factor
RESERVOIR ROCK PROPERTIES
POROSITY
Definition:
Porosity, , is defined as the ratio of the void space in a rock formation to the bulk volume of the rock.
It is a Measure of the space in a rock not occupied by the solid framework of the rock
It is a measure of how much fluid a formation can store
= Porosity
Vp = Pore Volume = Vb - Vg
Vb = Bulk Volume
Vg = Grain Volume
Unit = % or Fraction
BV
pV
bV
gV
bV
gV
bV
bV
pV
1
POROSITYCONTD.
Types Of Porosity:
Absolute Porosity:
Measure of the Total Pore Spaces in a Rock as a Function of the Bulk Volume
Effective Porosity:
Measure of Interconnected Pore Spaces as a Function of Bulk Volume.
Porosity Responsible for Migration of Oil to Wellbore
Measured by Porosimeter
PERMEABILITY
Definition:
The Permeability of a porous rock is a measure of its ability to transmit fluids
The magnitude of this fluid passing property is related to the number, size, shape and continuity of the pores within the rock
A medium of high permeability will pass fluids with relative ease, while one of low permeability will pass fluids with difficulty.
Darcy’s Law:
q = Production rate
k = Permeability
= Viscosity
A = Cross-Sectional Area
P/L = Pressure Gradient
Unit = Darcies or Milidarcies
Measuring Device = Permeameter
qkA p
L
*
PERMEABILITY CONTD.
Definition of Darcy:
A Darcy of permeability is defined as one that 1 cubic
centimetre of fluid of 1 centipoise (cp) (i.e. the
viscosity of water at 68oF) would flow each second,
through a portion of sand 1 centimetre in length and
having 1 square centimetre of area through which to
move if the pressure drop across the sand is 1
atmosphere.
qkA p
L
*
PERMEABILITY CONTD.
Absolute Permeability:
Measure of the Ease of Flow of a Single Fluid Through the Porous Medium, k
Effective Permeability:
Permeability of a rock to a particular fluid in the Presence of Other Fluids
ko = Effective Permeability to Oil
kw = Effective Permeability to Water
kg = Effective Permeability to Gas
PERMEABILITY TYPES.
Relative Permeability:
Ratio of Effective Permeability to the Absolute Permeability
kro = ko/k
k = Absolute Permeability
PERMEABILITY TYPES CONTD.
Average k-value (md) Quantitative Description
< 10.5 Poor to fair
15.50 Moderate
50.250 Good
250-1000 Very Good
>1000 Excellent
QUALITATIVE EVALUATION OF PERMEABILITY
FLUID SATURATION
Percentage of reservoir pore volume occupied by a particular fluid
VW = Water Volume
VO = Oil Volume
Vg = Gas Volume
VP = Total Pore Volume
v
P
WW
V
VS
1 gOW SSS
P
OO
V
VS
P
g
gV
VS
FORMATION VOLUME FACTOR
Definition:
This is the volume of fluid at reservoir conditions as a measure of the volume at standard conditions of temperature and pressure
Oil Formation Volume Factor (measured in reservoir barrels per stock tank barrel, RB/STB), is the volume occupied at reservoir conditions by one stock tank barrel (STB) of oil plus all the gas originally dissolved in it.
conditions standard at tank stock entering oil of Volume
conditions reservoir at gas dissolved oil of Volume
V
V B
OS
ORo
FORMATION VOLUME FACTOR
WS
WRw
V
VB
•Units: Reservoir barrels/Stock Tank barrels - RB/STB
Water Formation Volume Factor:
GAS FORMATION VOLUME FACTOR
GS
GRg
V
V B
Units: Cu. ft./SCF
The Volume that one Standard Cubic Feet of Gas will occupy in the Reservoir at the Reservoir temperature and pressure
IDENTIFICATION AND CHARACTERIZATION OF
RESERVOIR ROCKS
This can be archieved by means of logs
A log is a continuous record of any particular physical
property (geological and or petrophysical) along the well bore.
They are obtained by lowering a sonde or tool attached to a
cable or wire to the bottom of a well bore filled with drilling
mud.
The interpretation involves, determining the petrophysical
and or geological property of any rock via the wire line logs.
PARAMETERS INTERPRETED FROM LOGS
These include:
Lithology,
Porosity,
Permeability,
Saturation,
Nature and Type of Fluid(hydrocarbon),
Resistivity ( Formation Water Resistivity)
LITHOLOGY
• Natural Gamma ray
• Spontaneous Potential
• Density –Photo – electric factor (PEF)
Gamma Ray
• Detects the clay or shale content in reservoirs due to their radioactivity
• The shales give a high GR log reading and low reading in clean sandstones or
carbonates except in cases of radioactive sands due to zircon, glauconite etc.
Interpretation Steps
• Identify the average GR reading in a thick shale section of the reservoir This
value read-off is assumed to represent 100% shale and is called shale – line.
• Identify the average GR reading in a thick sand section of the reservoir This
value read-off is assumed to represent 100% sand and is called sand – line.
• A near vertical line in the middle between the shale line and sand line (cut –
off line) is also constructed
• All intervals where the GR log is on the left of this cut – off line are sands.
Spontaneous Potential (SP)
• The curves usually defines a more or less straight
line on the log
• In sands and more permeable formations, the
curves show excursion from straight line.
• Currents are developed from the interactions which
are electrochemical or electrokinetic in nature.
• The direction of this deflection depends primarily
on the relative salinities of the formation water and
of the mud filtrate.
• There will be a deflection to the left in the sand
compared to the shale when the resistivity of the
mud filtrate (Rmf) is greater than the resistivity of the
formation water (Rw) and will deflect to the right
when Rmf < Rw.
Density – Photo Electric Factor (PEF)
• It is a Litho-density tool. The parameter links the number of
gamma rays (r-ray) that are absorbed by photo-electric
absorption to Lithology.
• Photo- electric absorption is the disappearance of a low –
energy r-ray as it collides with an atom, causing the ejection of
an orbital electron.
• The PEF is a good matrix indicator.
• Low PEF factor corresponds to sandstone lithology.
1 2 3 4 5 6 7 8 9 10
SST SDSH SH
Identification of Lithology from PEF
Porosity Tools
These include
• Sonic log
• Density log
• Neutron log
Note: Porosity calculated from these tools might not
be equal to one another
Sonic Log
• It is usually inferior to neutron or density log calculated values.
• The formula commonly used for this is Wyllie et al., 1958
Where
Sonic = Sonic derived porosity
tma = interval transit time of matrix (given)
t log = Interval transit time of formation
tF = Interval transit time of fluid in the well bore (Fresh
mud = 189, salty mud = 185)
maF
masonic
t - t
t - logt
• Where a sonic log is used to determine porosity in
unconsolidated sands, an empirical compaction factor
or Cp. should be added to Wyllie et al., (1958) equation
Where:
Cp = compaction factor
tsh = Interval transit time of adjacent shale
C = a constant, normally 1.0 (Hilchie, 1978)
•
100
c x t C sh
p
Interval transit time (t) of a formation is
increased due to the presence of hydrocarbons
(i.e. hydrocarbon effect).
Hilchie, (1978) suggests that
= sonic x 0.7 gas
= sonic x 0.9 oil
Density log
Porosity from the density log is calculated using the
equation
where
D = Apparent density porosity
ma= Matrix density
b = Bulk density log reading
f = Fluid density
fma
bmaD
Note:
Fracture Identification
When the density – derived porosity is much less than
the sonic porosity the difference is due to fracture
porosity (Schafner, 1980). The two logs should be
normalized to prime this comparison. This may be done
with the logs themselves or by cross-plotting core-
verified values to define fracture fields.
Permeability
• This is the ability of a
rock to transmit fluids. It is
related to porosity but it is
not always dependent
upon it.
Log-derived permeability formulas are only
valid for estimating permeability in formation at
irreducible water saturation (Swirr),
(Schlumberger, 1977) e.g. Coates and
Dumanoir or Wyllie and Rose
For an indication of permeability of the
reservoir rock, the SP and resistivity logs
are used.
Spontaneous Potential logs
• Primarily a “permeability log” which is a response to
permeability to ion flow, rather than permeability to
fluid movement. If there is a slight deflection on the SP;
the bed opposite the deflection is permeable (see
illustration above)
Resistivity logs
Does not provide the absolute permeability value, only used as an indicator of permeable formations.
Basically, two curves, deep and shallow, separation between the two curves, with the deep reading higher indicates mudcake and therefore permeability.
When there is no separation between the two curves, it indicates an impermeable stratum
When there is a negative separation, it might indicative of a change in lithology type.
Hydrocarbon Saturations
Resistivity logs are used to calculate water saturation
from which the hydrocarbon saturation is calculated.
When water saturation (Sw) is not 100% , the reservoir
rock contains hydrocarbon.
(1-Sw) = Shc; (Shc = hydrocarbon saturation)
Saturation model are used for this calculation. A typical
model is the Archie model.
t
w
R x
R x a
mSw
Where,
a = tortuosity factor
m = cementation factor
Rw = Water Resistivity
Rt = True Resistivity
Formation Water Resistivity (Rw)
The resistivity of the formation water is
determined from the following sources
Mathematically
• SP logs. This is done using a series of charts
or.
• Apparent Water Resistivity
Charts
• Salinity Charts form measured data
Hydrocarbon Type
• Neutron – Density logs are used
to discriminate between gas and
oil in a formation.
• A separation of the Neutron and
Density log with the Neutron
deflecting to the right and
Density log to the left indicates
gas.
• A balloon shape typifies gas
while in an oil reservoirs the two
curves normally track together.
Fluid Contact
The deep resistivity log (LLd, ILd) is used to
determine the extent of hydrocarbon thickness in a
formation.
A combination of the Neutron – Density log further
confirms the contact point.
In resistivity logs fluids contacts is inferred where
there is a sharp contrast in resistivity values at the
hydrocarbon zone. (see illustration)
Some of the drilling terminologies used in this chapter
are explained below.
Drilling Mud (Rm) – Fluid used to drill a borehole and
which lubricates the bit, and maintains borehole over
formation pressure. Removes cuttings and maintains the
walls of the borehole.
Mud Cake (Rme) – The mineral residue formed by
accumulation of drilling mud constituents on the
wellbore wells as the fluids invade the formations
penetrated by the borehole.
Mud Filtrate (Rmf) – Mud fluid that penetrates the
formation while leaving the mud cake on the walls of
the borehole.
Flushed Zone (Rxo) – The portion of the invaded zone immediately adjacent to the borehole in which mud filtrate has removed most or all the formation water and /or petroleum.
Invaded zone – That part of the formation between the borehole and unaltered formation rock penetrated by mud filtrate.
Annulus (Ri) – The portion of the invaded zone where mud filtrate mixes with formation water and/or petroleum. It is the portion of the invaded zone farthest from the wellbore.
Uninvaded zone (Ri) – Formation rock materials away from and unaltered by mud filtrate and containing uncontaminated formation fluids.
SOFTWARE APPLICATION
IN RESERVOIR GEOLOGY
INTRODUCTION
• An understanding of the reservoir stratigraphy and
structure is crucial to evaluating the producibility of a
reservoir. Integrating various datasets to provide a
geologically relevant subsurface image which aids
interpretation
• Models for visualization, mapping and static reservoir
modelling are all available in various software
packages.
• Modelling involves the use of statistical techniques or
analogy data to infill the inter- well volume.
INTRODUCTION cont’d
The use of software is mostly applicable in the development of solutions explaining the structural complexities of fields, especially the along strike relationship among thrust related structures. This helps to explain how folds and faults are connected along strike.
The trapping mechanism of the reservoir can be better understood and this provides useful information for better reconstruction of the possible migration path and improving the evaluation of hydrocarbon reservoirs.
Reservoir model requires:
• Seismic interpretation and structural mapping
• Petrophysical analysis via wireline logs which are used to
determine petrophysical properties of different sedimentary
facies. These are incorporated into the static reservoir
model
• Core analysis and description: Where core data are
available the analysis is integrated with the wireline logs
for petrophysical evaluations.
All these technical activities are now done via suitable
software packages. If any of these are incomplete, models
can still be made to meet the requirements for early
decisive information.
Types of Model
1. Sequence based Models: These assume that the
subsurface is a composite of smooth and continuous
variables and that these variables can be interpolated
between control points.
2. Object based Models: These assume the subsurface
to consist of a mosaic of discrete bodies (objects) with
specific spatial locations and dimensions.
Variables are therefore to be modelled within the context
of geological objects. In reality, however, a mixture of
the two is used because geological processes can produce
both discrete and gradational boundaries.
Illustration of a structural reservoir model
Mapping
• This involves plotting geologic data on map. The
geologist measures and describes the rock sections and
plots the surface structure on the geologic map or
structure maps using relevant software packages. Other
useful subsurface maps include thickness maps,
lithologic maps, porosity, and saturation maps.
• The software allows the geologist to input as much
knowledge as is appropriate in the reservoir model.
Where well values are not available processes like
kriging, moving average, and other methods are used to
interpolate the unknown.