Reservoir rock & fluid

Reservoir Character ist ics , Rock & Fluid Properties and Drive

Mechanism

• To ensure the best possible return, it is important to understand as much as possible about the reservoir.

• This always presents a conceptual problem as we cannot physically see the reservoir in question.

• Techniques, such as; Seismic Data Acquisition, Electric Line Logging, Core Analysis, PVT Analysis, and Well Testing etc produce valuable data which help build the simulated reservoir model and thus help in developing the most cost effective strategy to manage the asset.

Reservoir Characterist ics

ROCKS CLASSIFICATION

SEDIMENTARY

Ro

ck-f

orm

ing

pro

cess

So

urc

e o

fm

ater

ial

IGNEOUS

METAMORPHIC

Molten materials in deep crust andupper mantle

Crystallization(Solidification of melt)

Weathering anderosion of rocks

exposed at surface

Sedimentation, burial and lithification

Rocks under high temperatures

and pressures in deep crust

Recrystallization due toheat, pressure, or

chemically active fluids

To form a commercial reservoir of hydrocarbons, a geological formation must possess three essential characteristics;• Sufficient void space to contain hydrocarbons (porosity).•Adequate connectivity of these pore spaces to allow transportation over large distances (permeability).•A capacity to trap sufficient quantities of hydrocarbon to prevent upward migration from the source beds.

Rock Properties

The void spaces in the reservoir rocks are the inter granular spaces between the sedimentary particles. Porosity is defined as a percentage or fraction of void to the bulk volume of the rock.

Porosity

Porosity = 48%

Measurements of porosity are either done in the laboratory on core samples whereby actual conditions are simulated as closely as possible prior to measurement, or in-situ via suites of electric logs such as Neutron, Density and Sonic Logs.

Porosity

Permeability is a measure of the ease with which fluid flows through a porous rock, and is a function of the degree of interconnection between the pores.

Permeability

A & B have same porosity

Permeability is measured in darcy units or more commonly millidarcy (md - one thousandth of a darcy) after Henry Darcy who carried out some pioneering work on water flow throughunconsolidated sand stones. A practical definition of a darcy is as follows;A rock has a permeability (k) of 1 Darcy if a pressure gradient of 1 atm/cm induces a flow rate of 1 cc/sec/cm2 of cross sectional area with a liquid viscosity 1 cp

Permeability

The grain size has a negligible effect on the porosity of a rock, but this has a predominant effect on permeability. More frictional forces are encountered while passing the same fluid through a fine granular pack than through a coarse granular pack of equal porosity.

Permeability

The apparent permeability is dependent on the type of fluid flowing through the rock and this plays an important part in the interpretation of different hydrocarbon bearing reservoirs. Permeability is denoted in three different ways. 1.Absolute permeability ka is derived in the laboratory by flowing a known quantity of fluid through a core while its pore spaces are 100% saturated with the same fluid. Absolute permeability will not change with varying fluids as long as the pore space configuration remains constant.2.Effective permeability is the permeability of a flowing phase which does not saturate 100% of the rock. The effective permeability is always less than the absolute value of k for the rock.3.Relative permeability is a dimensionless number which is the ratio of effective permeability (to a fluid) to absolute permeability of the same rock.

Permeability

The adhesive force determines which fluid will preferentially wet a solid. As an example, water will spread out on the surface of a sheet of glass whereas mercury will bead up and not adhere to the glass. For water the adhesive forces between liquid and solid are greater than the cohesive forces holding the liquid molecules together, the opposite is true for the mercury. The tendency of one fluid to displace another from a solid surface is determined by the relative wettability of the fluids to the solid.

Wetting

When liquid wets the surface of a fine bore glass capillary tube, surface tension around the circumference of the contact pulls the liquid interface up the tube until an equilibrium is reached with the downward force due to the liquid column height.

In the reservoir, although the pore spaces do not form the uniform capillary tubes, they do interconnect to form a complex capillary systems which in turn gives rise to capillary forces.

These forces can be measured under laboratory conditions for a given rock – fluid(s) system and, in turn, the capillary height can be calculated if the density difference of the fluid system is known.

Capillarity

The minimum saturation that can be induced by displacement is one in which the wetting phase becomes discontinuous. Since the wetting phase will become discontinuous at some finite capillary pressure there will always be some irreducible water saturation, a saturation which cannot be reduced by displacement by a non-wetting phase no matter how great a pressure is applied to the system.

Irreducible Water Saturation

Water tends to displace oil in a piston like fashion, moving first close to the rock surface where it is aided by capillary forces in squeezing oil from the smaller channels. Residual oil is left in the smaller channels when interfacial tension causes the thread of oil to break leaving behind small globules of oil.

Residual Oil (Water Displacement)

The effective permeability of a fluid is a function of the saturation.

Relations between Permeability and Fluid Saturation

Coring

One way to get more detailed samples of a formation is by coring, where formation sample is drilled out by means of special bit.

This sample can provide:Detailed lithological decscription.Porosity, permeability, fluid

saturation and grain density.

These parameters are measured in the laboratory and serve as a basis for calibrating the response of the porosity logging tools and to establish a porosity/permeability relationship.

PDC Cutters

Fluidvent

Drill collarconnection

Inner barrel

Outer barrel

Thrust bearing

Core retainingring

Core bit

CORING ASSEMBLY AND CORE BIT

COMING OUT OF HOLE WITH CORE BARREL

Core Analysis

Core analysis can be divided into two categories:

Conventional Core Analysis. Special Core Analysis.

Conventional Core Analysis.• The core is usually slabbed, cut

lengthwise to make the structure visible.

• Provides information on lithology, residual fluid saturation, ambient porosity, ambient gas permeability and grain density.

Core Analysis

Gas Permeameter

Liquid Permeameter

Core Analysis

Porosimeter

Core Analysis

Special Core Analysis :Provides the following information:

Porosity and permeability at elevated confining stress.

Electrical properties such as formation factor and resistivity index.

Capillary pressure. Wettability and relative permeability. Mechanical rock properties such as

compressibility. Water flood sensitivity for injectivity and well

performance.

Fluid Properties

Naturally occurring petroleum accumulations are made up of large number of organic compounds, primarily hydrocarbons.Seldom are two crude oil samples identical and seldom are two crude oils made up of the same proportions of the various compounds. Reasons to examine the Reservoir fluidsa)A chemical engineer may be interested in a crude oil’s composition as to the amount of commercial products the oil will yield after refining. b)An exploration might have an interest in an oil or water’s composition as it sheds light on the origin, maturation and degradation of the oil for geological interpretation. c)The petroleum engineer is particularly concerned to determine their behavior under varying conditions of pressure and temperature that occur in the reservoir and piping systems during the production process.

Fluid Properties

Products from Petroleum

The distillation of crude oil results in various fractions which boils at different temperatures

If the residue which remains after distillation is a wax like solid consisting of largely of paraffin hydrocarbons the crude is designated as paraffin base

If the residue is a black pitch like solid the crude is called asphalt base

Various fractions of petroleum

Fractions obtained from distillation Temperature Range

Petroleum Ether Upto 160 0f

Gasoline 160-400 0f

Kerosene 400-575 0f

Fuel oil Above 575 0f

Reservoir fluids are generally complex mixtures of hydrocarbons existing as liquid-gas systems under high pressures & temperatures

An important aspect of petroleum engineering is predicting the future behavior of a petroleum reservoir when it is put on production

Therefore, it is necessary to know the behavior of reservoir fluids as a function of temperature and pressure

To understand the behavior of complex systems existing in petroleum reservoir, the derivations from ideal behavior are used.

Requirements to Study the Reservoir Fluid Behavior

A phase is a definite portion of a system which is homogeneous throughout and can be separated from other phases by distinct boundaries.

Solids, liquids and gases are phases of matter which can occur, depending on pressure and temperature. Commonly, two or three different fluid phases exist together in a reservoir.

Any analysis of reservoir fluids depends on the relationships between pressure, volume and temperature of the fluids commonly referred to as the PVT relationship.

It is customary to represent the phase behaviour of hydrocarbon reservoir fluids on the P-T plane showing the limits over which the fluid exists as a single phase and the proportions of oil and gas in equilibrium over the two phase P-T range.

Phase Behavior of Hydrocarbon Systems

Single component hydrocarbons are not found in nature, however it is beneficial to observe the behaviour of a pure hydrocarbon under varying pressures and temperatures to gain insight into more complex systems.As an example, the PVT cell is charged with ethane at 60° F and 1000 psia. Under these conditions, ethane is in a liquid state. If the cell volume is increased while holding the temperature constant, the pressure will fall rapidly and first bubble of gas appears. This is called the bubble point. Further increases of cylinder volume at constant temperature does not reduce the pressure. The gas volume increases until the point is reached where all the liquid is vaporized. This is called the dew point. Further increase of cylinder volume results in a hyperbolic reduction in pressure as the ethane gas expands.

Single Component Systems

Single Component P-V

Consider the phase behavior of a 50:50 mixture of two pure hydrocarbon components on the P-T plane.

The vapor pressure and bubble point lines do not coincide but form an envelope enclosing a broad range of temperatures and pressures at which two phases (gas and oil) exist in equilibrium.

The dew and bubble point curves terminate at that temperature and pressure at which liquid and vapour (gas) phases have identical intensive properties, density, specific volume, Etc.

Phase Behaviour of a Multi-Component System

Phase Behaviour of a Multi-Component System

Reservoir Fluid Types

• Black oil

• Volatile oil

• Retrograde Condensate (gas condensate)

• Wet gas

• Dry gas

Temperature

Pre

ssur

e

Pres , Tres

Dry Gas

GasCondensate

Volatile Oil

Black Oil

P-T Diagram for a Black Oil

P-T Diagram for a Volatile Oil

P-T Diagram for gas condensate

P-Tdiagram for a wet Gas

P-T Diagram for a Dry Gas

Reservoir Fluid Properties

• Oil Compressibility• Saturation Pressure• Live Oil Viscosity• Live Oil Density• Oil Formation Volume Factor• Gas-Oil Ratio• Liberated Gas Formation Volume factor• Incremental Liberated Gas-Gravity• Cumulative liberated Gas-Gravity

Sampling of Reservoir Fluids

• The purpose of sampling is to obtain a representative sample of reservoir fluid identical to the initial reservoir fluid.

• For this reason, sampling operations should ideally be conducted on virgin reservoirs (having not yet produced) or in new wells completed in no depleted zones, containing fluids identical to the initial reservoir fluids.

• If the production fluids are still identical to the initial fluids, the sampling procedure will be very similar to that of new wells.

• If the produced fluid is not identical to the fluid initially in place in the reservoir, one cannot hope to obtain representative samples.

Well Conditioning for Sampling

The objective of well conditioning is to replace the non-representative reservoir fluid located around the wellbore with original reservoir fluid by displacing it into and up the wellbore.

A flowing oil well is conditioned by producing it at successively lower rates until the non representative oil has been produced.

The well is considered to be conditioned when further reductions in flow rate have no effect on the stabilized gas-oil ratio.Stable well conditions: Pressure, Rate, GOR, WGR, Temperature

Types of Sampling

Downhole

DST stringsWireline sample

Surface

Wellhead samplesSeparator samples

Sub-surface sampling for Oil Reservoirs

Subsurface samples are generally taken with the well shut-in.

The sample should be taken under single-phase conditions, Pres > Pb

The well should be fully cleaned up

A static pressure gradient survey should be performed either prior to or during sampling to check for the presence of water at the bottom of the well

Sub-surface sampling for Oil Reservoirs

Sub-surface Sampler

Sample transfer unit

Surface sampling for Oil/gas Reservoirs

Sampling at the wellhead

Valid fluid samples are only likely to be obtained if the fluid is single-phase at the wellhead

Poses safety hazards (high-pressure fluid...)

Sampling at the separator

Easier, safer, cheaper

Only reliable surface method if fluid is two-phase at the wellhead

Wellhead sampling

Sample point should be as near wellhead as possible, and upstream of choke manifold

It is possible to obtain mono phasic wellhead samples for very high pressure gas condensates

Pres = 15,000 psia

Pwh = 11,000 psia

Pdew = 5500 psia

But beware of flashing occurring at sample point

Separator sampling

The most important factor in separator sampling is stability of conditions

Stabilised gas and oil flow rates (and therefore GOR)

Stabilised temperature

Stabilised wellhead pressure

Gas and liquid samples should be taken simultaneously, as they are a matched pair

Oil and gas rates must be measured carefully

Sample points must be as close to the separator as possible

Horizontal Separator

Inlet Gas Outlet

LiquidOutlet

momentumabsorber

SightGlass

Gauge

Sample Transfer

Single-phase sub-surface samples become two-phase as they are brought to surface as a result of a large reduction in pressure due to cooling

The sample chamber must be re-pressured to single-phase conditions prior to transfer to sample bottles

Single-phase positive displacement samplers are now common place, and maintain single-phase conditions in the chamber as it is brought to surface

Gas-Condensate Sampling

Sub-surface sampling is generally not the preferred method in condensate reservoirs

Well-head sampling preferred if single-phase

Separator sampling preferred for other cases

If Pwf < Pdew, the choice of flow-rate during sampling is a balance between the following:

• High rates cause excessive liquid drop-out in the reservoir

•Low rates prevent liquids formed in the wellbore from being produced to surface

Recombination of surface Sample

Separator samples are recombined using the ratio calculated from measured gas and liquid flow-rates

Care must also be taken to preserve consistency between field and laboratory values of separator liquid shrinkage

In what ratio should the oil and gas samples be recombined?

The PVT Cell

Used for examining the behaviour of fluids at reservoir pressures and temperatures

Temperature thermostatically controlled

The volume of the cell can be changed by using a positive displacement pump

Sampling points are provided

Most cells are fitted with an observation window

Basic PVT Experiments

Constant Composition Expansion (CCE)

Constant Volume Depletion (CVD)

Differential Vaporisation (Liberation) (DV)

Multi-stage Separator Tests

Bubble-Point Determination

Bubble-point identified by change in fluid compressibility

Pressure

Volu

me

PbPressure

Volu

me

Pb

Black Oil

Volatile Oil

Isothermal Flash

The Isothermal Flash is the basis for most laboratory PVT experiments

Single-phase fluid is loaded into the PVT cell at temperature T and pressure P1

The temperature is kept constant throughout the experiment (PVT cell is placed in a heat bath)

The fluid is expanded to a new pressure P2 (P2<P1)

The flash results in a change in total volume and may result in phase changes

Constant Composition Expansion (CCE)

A series of isothermal flash expansions at constant temperature (normally Tres).

No fluid is removed from the cell

SinglePhase

SinglePhase

Liquid

Vapour

Liquid

Vapour

Volume

@ Psat

P > Psat P = Psat P < Psat P << Psat

Constant Volume Depletion (CVD)

A series of flash expansions at T At each pressure, vapour is withdrawn to

restore original cell volume at Psat

VapourVapour

Vapour

VapourVapour

VapourVapour

Liquid Liquid Liquid Liquid

Psat P1 P1 P2 P2

A series of flash expansions at T At each pressure stage, all of the vapour

in the cell is removed

Differential Vaporisation (DV)

Vapour

Liquid Liquid

Vapour

Liquid

Vapour

Liquid

Vapour

Liquid

Psat P1 P1 P2 P2

The liquid remaining at the last pressure step is cooled to ambient temperature to give the residual oil

DV Reported Data

Oil volume Oil density Oil formation volume factor, Bo

Gas specific gravity Gas Z-factor Gas formation volume factor, Bg

Evolved gas volumes Solution GOR, Rs

Drive mechanism

Reservoir Drive Mechanisms

What causes oil to flow from reservoirs?Pressure difference between reservoir fluids and the wellbore pressure

If reservoir pressure declines quickly, recovery by natural flow will be small

There are several ways in which oil can be displaced and produced from a reservoir, and these may be termed mechanisms or “drives”.

Where one replacement mechanism is dominant, the reservoir may be said to be operating under a particular “drive.”


• For the proper understanding of reservoir behavior and predicting future performance, it is necessary to have knowledge of the driving mechanism that controls the behavior of fluids within reservoirs.

• Overall performance of the oil reservoir is largely determined by the nature of the energy ( driving mechanism) available for moving the oil to the wellbore

Where does this energy come from???


Possible sources of replacement for produced fluids are:

a)Expansion of under saturated oil above the bubble point.

b)Expansion of rock and of connate water.

c)Expansion of gas released from solution in the oil below the bubble point.

d)Invasion of the original oil bearing reservoir by the expansion of the gas from a free gas cap.

e)Invasion of the original oil bearing reservoir by the expansion of the water from an adjacent or underlying aquifer.

Understanding the Reservoir Drive Mechanism

The recovery of oil by any of the natural drive mechanisms is called primary recovery. During primary recovery, hydrocarbons are produced from reservoir without the use of any process (such as fluid injection) to supplement the natural energy of the reservoir.

Each drive mechanism has certain typical performance in terms of:

Pressure-decline rateGas-oil ratioWater productionUltimate recovery factor

SOURCES OF RESERVOIR ENERGY

GAS DISSOLVED IN OIL

OIL OVERLAIN BY FREE GAS

OIL UNDERLAIN BY COMPRESSED WATER

GRAVITY FORCE, &

COMBINATION OF THE ABOVE

RESERVOIR DRIVE MECHANISM- Types

In oil reservoirs, there are basically six drive mechanisms that provide the natural energy necessary for recovery:

• Depletion drive• Gas cap drive• Water drive• Gravity drainage drive• Combination drive• Liquid expansion and rock compaction drive

DEPLETION DRIVE MECHANISM

In this type of reservoir, the principal source of energy is a result of gas liberation from the crude oil and the subsequent expansion of the solution gas as the reservoir pressure is reduced.

If a reservoir at its bubble point is put on production, the pressure will fall below the bubble point pressure and gas will come out of solution. Initially, this gas may be dispersed, discontinuous phase, but, in any case, gas will be essentially immobile until some minimum saturation or critical gas saturation, is attained.

DIAGNOSTIC FEATURES OF SOLUTION GAS DRIVE

• NO OWC OR GOC ON WELL LOGS• PRESSURE DECLINE ROUGHLY

PROPORTIONAL TO GAS PRODUCTION

• FAST PRESSURE AND PRODUCTION DECLINE

• ULTIMATE RECOVERIES IN 5-30 % RANGE

• LEAST EFFICIENT DRIVE MECHANISM AND HIGHLY UNDESIRABLE

• EVERY ATTEMPT IS MADE TO CHANGE THE DRIVE MECHANISM ( BY GAS AND/OR WATER INJECTION, THE PROCESS BEING CALLED AS ‘PRESSURE MAINTENEANCE)


Wellbore

Gas moves

upstructure

Liberated solution

gas

Secondarygas cap

Wellbore

Gas moves

upstructure

Liberated solution

gasLiberated solution

gas

Secondarygas capSecondarygas cap

FORMATION OF SECONDORY GAS CAP, SIZE KEEPS ON INCREASING WITH PRODUCTIONSTRUCTURALLY HIGHER WELLS SHOW INCREASING GOR AND SOME WELLS START PRODUCING GAS ONLY

DECLINE RESERVOIR PRESSURE GOES BELOW SATURATION PRESSURE, RESULTING IN PHASE SEPARATION WITHIN THE RESERVOIR

DUE TO RAPID PRESSURE

Solution Gas Drive in Oil Reservoir

Time years Typical Production Characteristics

Reservoir pressure behavior

Bubblepointpressure

Initial reservoirpressure

0 5 10Oil recovery, % of OOIP

Rese

rvo

ir p

ress

ure

, p

sig

Solution-Gas Drive in Oil Reservoirs

Typical Production Characteristics

GAS-CAP GAS DRIVE MECHANISM

Gas cap drive reservoirs are identified by the presence of a gas cap with little or no water drive. The gas cap can be present under initial reservoir conditions, or it may be a secondary gas cap formed from gas that evolved from solution as reservoir declined below bubble point due to production of fluids.

GAS-CAP GAS DRIVE; DIAGNOSTIC FEATURES

SLOW DECLINE OF RESERVOIR PRESSURE

STABLE GOR OF WELLS AWAY FROM GOC FOR FAIRLY LONG TIME

HIGH GOR OF THE WELLS CLOSE TO GOC

ULTIMATE RECOVERIES BETWEEN 30-50 %

PREFERENTIAL FLOW OF GAS DUE TO ITS LOWER VISCOSITY

IF PRODUCED TOO RAPIDLY, BY-PASSING OF OIL OCCURS, AND HENCE

LIMITATIONS OF PRODUCTION RATES OTHERWISE LOW RECOVERIES

GAS-CAP GAS DRIVE; DIAGNOSTIC FEATURES

WATER DRIVE MECHANISM

POSSIBLE WHEN OIL ZONE UNDERLAIN BY WATER

TWO TYPES- EDGE WATER AND BOTTOM WATER DRIVE

PRESSURE TRANSMITTED FROM THE SURROUNDING AQUIFER OR WATER AT THE EDGE AND BOTTOM OF THE OIL POOL

ENERGY COMES FROM OUTSIDE THE POOL, WATER MOVES IN, REPLACES PRODUCED OIL OR GAS, AND PRESSURE IS MAINTAINED

IF PRESSURE REMAINS ALMOST CONSTANT WITH PRODUCTION DUE TO ENTERANCE OF NEW WATER- ACTIVE WATER DRIVE

POSSIBILITY OF ACTIVE WATER DRIVE IF EXTENDING TO RECHARGE AREA SUPPLYING ENOUGH WATER

IF LENTICULAR RESERVOIR, OR IF IN A FAULT BLOCK, OR SHARP FACIES VARIATION, CHANCES OF ACTIVE WATER DRIVE HIGHLY REDUCED.

Edge Water Drive

Bottom Water Drive

Oil producing well

Water WaterCross Section

Oil Zone

Oil producing well

Cross Section

Oil Zone

Water

Water Drive in Oil Reservoirs


An efficient water driven

reservoir requires a large

aquifer body with a high

degree of transmissibility

allowing large volumes of

water to move across the

oil-water contact in

response to small

pressure drop.

WATER DRIVE MECHANISM DIAGNOSTIC FEATURES

OCCURRENCE OF OWC ON LOGS

NO APPRICIABLE PRESSURE REDUCTION WITH PRODUCTION

ULTIMATE RECOVERIES REASONABLY HIGH (>50 %)

WATER CUTTING IN STRUCTURALLY LOWER WELLS WITH PRODUCTION DUE TO UPWARD MOVEMENT OF OWC

STABLE GOR VALUES FOR A LONG TIME

DECLINE IN OIL RATE ONLY DUE TO INCREASING WATER CUT

Gravity Drainage in Oil Reservoirs

Gravitational forces:Gravitational segregation is tendency of fluids in

reservoir to segregate, under inference of gravity, to position in reservoir based on fluids' density (gas to move above oil, water below oil).

Reservoir type

•Gravity drainage may occur in any type of reservoir.

•Gravity drainage is particularly important in solution-gas and gas-cap drive oil reservoirs.

Gravity Drainage in Oil Reservoirs

Gravity Drive Mechanism

• GRAVITY ACTS AS A DRIVE MECHANISM THROUGHOUT THE PRODUCING LIFE OF ALL THE POOLS

• SIGNIFICANT IN HIGH RELIEF TRAPS

• SEPARATION OF WATER, OIL AND GAS IS AIDED BY GRAVITY ONLY

• IN SOLUTION GAS DRIVE RESERVOIRS, GRAVITY DRIVE BECOMES IMPORTANT IN LATER STAGES

• IT PROLONGS THE LIFE OF MANY WELLS

COMBINATION DRIVE MECHANISM

Two combinations of driving forces can be present in combination drive reservoirs:

• Depletion drive and a weak water drive •Depletion drive with small gas cap and a weak drive

Gravity segregation plays an important role in any of the above mentioned drives


OPERATIVE WHEN BOTH FREE GAS ABOVE THE OIL ZONE AND WATER BELOW ARE PRESENT.

GAS

OIL

WATER

GOC

OWC


BOTH OWC AND GOC ARE SEEN ON LOGS.

WITH PRODUCTION GOC MOVES DOWNWARD AND OWC MOVES UPWARD

WITH PRODUCTION HIGHER GOR IN STRUCTURALLY HIGHER WELLS AND INCRESED WATER CUT IN STRUCTURALLY LOWER WELLS

REASONABLY HIGH RECOVERY FACTORS ( 50-75 %)

Thank You

COMPACTION DRIVE MECHANISM

The production of fluids from a reservoir will increase the difference between overburden pressure and pore pressure, thereby causing a reduction of pore volume of the reservoir and possible causing subsidence of the surface.

Oil recovery by compaction drive is significant only if formation compressibility is high. Most reservoirs that have a significant compaction drive are shallow and poorly consolidated.


The general behavior of gas drive reservoirs is similar to that of solution gas drives reservoirs, except that the presence of free gas retards the decline in pressure. The characteristics trends of such reservoirs are:

• Reservoir pressure: The reservoir pressure falls slowly and continuously. As compared to depletion drive, pressure tends to be

maintained at a higher level. The gas cap gas volume compared to oil volume determines the degree of

pressure maintenance.

• Water production: Nil or negligible water production


•Gas – Oil ratio

With the advancement of gas cap in the producing intervals of up-structure wells, the gas – oil ratio will increase to high values.

•Ultimate recovery:

Since gas cap expansion is basically a frontal drive displacing mechanism, oil recovery is more efficient as compared to depletion drive reservoirs. The expected oil recoveries range from 20 to 40%.


The replacement mechanism has two particular characteristics – 1.there must be pressure drops in order to have expansion, 2.the aquifer response may lag substantially, particularly if transmissibility deteriorates in the aquifer.

A water drive reservoir is then particularly rate sensitive, and so the reservoir behave almost as a depletion reservoir for a long period if off-take rates are very high, or as an almost complete pressure maintained water drive reservoir if off-take rates are low, for the given aquifer.


The following characteristics can be used for identification of the water-drive mechanism:• Reservoir pressure: The reservoir pressure decline is usually very gradual.

• Water production: Early water production occurs in structurally low wells.

• Gas - Oil Ratio: There is normally little change in the producing gas oil ratio during the life of reservoir.

• Ultimate oil recovery: Ultimate recovery from water-drive reservoirs is usually much larger than recovery under any other mechanism. Recovery is dependent upon the efficiency of the flushing action of the water as it displaces the oil.


In brief, the characteristic trends occurring during the production life of depletion drive reservoirs can be summarized as :

Reservoir pressure: Declines rapidly and continuously

Gas-Oil ratio : Increases to maximum and then declines

Water production: None

Well behavior : Requires pumping at early stage

Oil recovery : 5 to 30%

Capillarity

Tars and Asphalts

These solid and semi solid substances are also known as bitumen, waxes and resins

They are very complex substances and relatively little is known regarding their chemical composition

These materials are formed in nature from petroleum oils by evaporation of the more volatile constituents and oxidation and polymerization of residue

Petroleum deposits obtained from different reservoirs will vary widely in chemical composition and may have entirely different physical and Chemical Properties

They may be present in the reservoir in liquid and/or gas form depending upon the pressure, temperature and composition

In spite of this diversity, the bulk of the chemical compounds found in Petroleum are hydrocarbons:

1.Paraffin hydrocarbons (CnH2n+2)

2.Naphthalene hydrocarbons

3.Aromatic hydrocarbons

Chemical composition of petroleum deposits

Petroleum oil or crude oil is a complex mixture consisting largely of hydrocarbons belonging to various series

In addition, crude usually contain small amounts of combined oxygen, nitrogen and sulfur

No crude oil has ever been entirely separated into its individual components.

Crude oils obtained from various reservoir have different properties because of the presence of different proportions of hydrocarbons constituents

Nearly all crude oils will give ultimate analysis within the following limits

Petroleum oil

Element carbon hydrogen sulfur nitrogen Oxygen

% Weight 84-87 11-14 0.6-2.0 0.1-2.0 0.1-2.0

Natural gas can occur by itself or in combination with liquid petroleum oils

It consists mainly of the more volatile members of the paraffin series containing from one to four carbon atoms

Small amount of higher molecular weight hydrocarbons can also be present

In addition, natural gases may contain varying amount of carbon dioxide, nitrogen, hydrogen sulfide, helium and water vapor Natural gas can be classified as sweet or sour and as wet or dry

Natural Gas

Engineering

Reservoir rock & fluid