reservoir rock & fluid
TRANSCRIPT
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.”
Reservoir Drive Mechanisms
• 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???
Reservoir Drive Mechanisms
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)
DEPLETION DRIVE MECHANISM
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
WATER DRIVE MECHANISM
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
COMBINATION DRIVE MECHANISM
OPERATIVE WHEN BOTH FREE GAS ABOVE THE OIL ZONE AND WATER BELOW ARE PRESENT.
GAS
OIL
WATER
GOC
OWC
COMBINATION DRIVE MECHANISM
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.
GAS-CAP GAS DRIVE MECHANISM
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-CAP GAS DRIVE MECHANISM
•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%.
WATER DRIVE MECHANISM
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.
WATER DRIVE MECHANISM
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.
DEPLETION DRIVE MECHANISM
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