Res geology

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.


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.


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


Matrix:

Silk,

Mud and

Clay Minerals

Cement:

Silica,

Carbonate

Iron Oxide

Clay Minerals.


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


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.


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


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.


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.


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.


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.


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 .


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


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)


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.


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


Basic Reservoir Rock Properties

Porosity

Permeability

Fluid Saturation

Formation Volume Factor


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.

Documents

Res geology