Chapter 3-rock & Fluid Properties Utm

Fundamentals Of Petroleum Engineering SKPP 1313 CHAPTER 3:

ROCK AND FLUID PROPERTIES Assoc. Prof. Issham Ismail Department of Petroleum Engineering Faculty of Petroleum & Renewable Engineering Universiti Technologi Malaysia

SKPP 1313: FUND. OF PETROLEUM ENGINEERING

COURSE CONTENTS

     

Rock Characteristics Porosity Permeability

Rock and Fluid Interaction Type of Reservoir Type of Reservoir Drive Mechanism

CHAPTER 3: ROCK & FLUID PROPERTIES

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Reservoir Rock Characteristics



To form a commercial reservoir of hydrocarbons, any geological formation must exhibit two essential characteristics.



These are capacity for storage and a transmissibility to the fluids concerned.



Storage capacity requires void spaces within the rock and the transmissibility requires that there should be continuity of those void spaces.

CHAPTER 3: ROCK & FLUID PROPERTIES

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Porosity



Petroleum is not found in underground rivers or caverns, but in pore spaces between the grains of porous sedimentary rocks.

A piece of porous sedimentary rock. The pore spaces are the white areas between the dark grains. It is within such pore spaces that fluids such as oil, natural gas, or water can be found in the subsurface.

CHAPTER 3: ROCK & FLUID PROPERTIES

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Porosity (cont’d)



Porosity () is defined as a percentage or fraction of void to the bulk volume of a material.



Porosity of commercial reservoirs may range from about 5% to about 30% of bulk volume.



Vp Vb

x100% 

Vb  Vg Vb

x100% 

Vp Vp  Vg

x100%

where: Vp = pore or void volume

Vb = bulk volume of rock

Vg = grain volume CHAPTER 3: ROCK & FLUID PROPERTIES

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Factors Affecting Porosity



Grain size: grain size has no effect on porosity. Well rounded sediments that are packed into the same arrangement generally have porosities from 26% to 48% depending on the packing.



Sorting: Well sorted sediments generally have higher porosities than poorly sorted sediments for the simple reason that if a sediment is a range of particle sizes then the smaller particles may fill in the voids between the larger particles.



Grain shape: Irregularly shaped particles tend not to pack as neatly as rounded particles, resulting in higher proportions of void space.

CHAPTER 3: ROCK & FLUID PROPERTIES

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Total and Effective Porosity



Total porosity is defined as the ratio of the volume of all pores to the bulk volume of a material, regardless of whether or not all of the pores are interconnected.



Effective porosity is defined as the ratio of the interconnected pore volume to the bulk volume. Isolated pores

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Primary and Secondary Porosity



Primary porosity is defined as a porosity in a rock due to sedimentation process.



Secondary porosity is defined as a porosity in a rock which happen after sedimentation process, for example fracturing and re-crystallization.

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Porosity Measurement

 

Boyle’s Law porosimeter.



Summation of fluids (also known as Water Saturation method) : pore volume = total volume of water − volume of water left after soaking.



Direct methods (determining the bulk volume of the porous sample, and then determining the volume of the skeletal material with no pores (pore volume = total volume − material volume)).

Wet and dry weight method (also known as Water Evaporation method) : pore volume = (weight of saturated sample − weight of dried sample)/density of water.

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Porosity Measurement



Boyle’s Law porosimeter.



Suppose the rock sample is placed in the sample chamber at zero gauge pressure and the reference chamber is filled with gas at pressure P1, then the valve between the two chambers is open and the system is brought to equilibrium.

CHAPTER 3: ROCK & FLUID PROPERTIES

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Porosity Measurement



Using Boyle’s Law:

PV 1 ref  P2 (Vres  Vsam  Vg ) Vg 

P2Vref  P2Vsam  PV 1 ref P2

where: Vg

= grain volume in the sample

Vref = volume of the reference chamber Vsam = volume of the sample chamber P1

= pressure before opening the valve

P2

= pressure at equilibrium afteropening the valve

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Bulk Volume Measurement



Linear measurement:

 physically measuring the sample with vernier caliper and then applying appropriate formula.  quick and easy, but is subject to human error and measurement error if the sample is irregularly shaped.



Displacement methods: rely on measuring either volumetrically or gravimetrically the fluid displaced by the sample.

 Gravimetric methods observe the loss in weight of the sample when immersed in a fluid, or observe the change in weight of a pycnometer filled with mercury and with mercury and the sample.  Volumetric methods measure the change in volume when the sample is immersed in fluid. CHAPTER 3: ROCK & FLUID PROPERTIES

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Example A clean, dry sample weighed 20 gms. This sample was saturated in water of density 1.0 gm/cc and then reweighed in air, resulting in an increase in weight to 22.5 gms. The saturated sample was immersed in water of the same density and subsequently weighed 12.6 gms. What is the bulk volume of the sample? Weight of water displaced: Wdisplaced = 22.5g – 12.6g = 9.9g Bulk volume: Vb = Wdisplaced/w = 9.9g/1g/cc = 9.9cc

CHAPTER 3: ROCK & FLUID PROPERTIES

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Permeability



The permeability of a rock is a measure of the ease with which fluids can flow through a rock. This depends on how well the pore spaces within that rock are interconnected.

Good Permeability CHAPTER 3: ROCK & FLUID PROPERTIES

Poor Permeability (14)

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Permeability (cont’d)



Permeability is a measure of the ability of a porous material to transmit fluid under a potential gradient.



The unit for permeability (k) is darcy named after a French scientist, Henry Philibert Gaspard Darcy who investigated flow of water through filter beds in 1856.



1 Darcy = 0.987 x 10-12 m2.

CHAPTER 3: ROCK & FLUID PROPERTIES

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Permeability (cont’d)



The general darcy’s equation is: L Q

A P1

Q k  dP     A   dL 

P2

where: Q = flowrate (cm3/sec) k = permeability (darcy) A = cross section area (cm2)

 = fluid viscosity (cp) P = pressure (atm) L = length (cm) CHAPTER 3: ROCK & FLUID PROPERTIES

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Permeability (cont’d) L

Q = 1cm3/sec Q

A = 1cm2

A

 = 1 cp P1

P2

Find k ?

P = 1atm L = 1cm



1 darcy is defined as the permeability that will permit a fluid of 1 centipoise viscosity to flow at a rate of 1 cubic centimeter per second through a cross sectional area of 1 square centimeter when the pressure gradient is 1 atmosphere per centimeter.

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Permeability (cont’d)



There are four conditions that are required for this equation to be valid:  Laminar flow.  No accumulation.  Single-phase liquid flow.  The porous media is not reactive with the flowing fluid.



Plot of Q/A against dP/dL should yield a single straight line as shown below where the slope = k/ = fluid mobility.



Q/A

 

 k/

dP/dL CHAPTER 3: ROCK & FLUID PROPERTIES

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Linear Flow L

kA  P1  P2  Q     L 

Q

P2

P1





CHAPTER 3: ROCK & FLUID PROPERTIES

kA  P1  P2  Q  g sin      L  kA  P1  P2  Q  g sin      L 

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Radial Flow kA  dP  Q    dR   k 2 h  dP  Q R    dR  dR 2 kh  dP R Q

Pe

Pwf

h

re

rw

where: k = permeability (darcy)

h = reservoir thickness (cm)

 = fluid viscosity (cp) P = pressure (atm)

e

e

ln

rw 2 kh  Pwf  Pe re Q

Q

= radius (cm)

CHAPTER 3: ROCK & FLUID PROPERTIES

pwf

dR 2 kh   R   Q dP r p

Q = flowrate (cm3/sec)

r

rw

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



2 kh Pe  Pwf

 ln  re rw 





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Radial Flow (cont’d) Pe

Pwf

In field unit:

h

re

Q

rw



7.08kh Pe  Pwf

 ln  re rw 



where: Q = flowrate (bbl/day)

k = permeability (darcy) h = reservoir thickness (ft)

 = fluid viscosity (cp)

1 bbl

=

159,000 cc

P = pressure (psi)

1 ft

=

30.48 cm

r

1 atm

=

14.7 psi

= radius (ft)

CHAPTER 3: ROCK & FLUID PROPERTIES

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Averaging Permeability (Parallel Sand)

L k1, h1, Q1

Q

A1 A2

k2, h2, Q2

An

kn, hn, Qn

in

Q   Q i  Q1  Q 2  Q n i 1

P P P P k A i  k 1A1  k 2A2  knAn L L L L i 1 in

k A i   k i A i kA  k A i

i

i

CHAPTER 3: ROCK & FLUID PROPERTIES

kh  or h i

Arithmetic averages

i

i

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Averaging Permeability (Series Sand)

in

Q

k1 k2 kn L1 L2 Ln P1 P2 Pn

A

P   Pi  P1  P2  Pn i 1

L

Harmonic averages in

k

L i 1 in

i

Prove it ?

Li  i 1 k i

CHAPTER 3: ROCK & FLUID PROPERTIES

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Example Given: Porosity = Effective horizontal permeability, md = Pay zone thickness, ft = Reservoir pressure (Pavg), psi = Flowing Bottomhole pressure (Pwf), psi = Bubble point pressure, psi = Oil formation volume factor, bbl/STB = Oil viscosity, cp = Drainage area, acres = Wellbore radius, ft = Calculate the flow rate. CHAPTER 3: ROCK & FLUID PROPERTIES

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0.19 8.2 53 5,651 1,000 5,651 1.1 1.7 640 0.328 24 MOHD FAUZI HAMID

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Permeability Measurement



Permeability of core sample can be measured by liquid permeameter and gas permeameter.



Liquid permeameter:





Non reactive liquid (paraffin oil) is forced to flow through a core sample in a core holder.



A flow rate is measured, and permeability is calculated using general Darcy equation.

Gas permeameter:



Non reactive gas (typically helium) is used in the measurement of permeability.



The gas is flow through the sample, and the flow rate of gas is measured.

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Permeability Measurement (cont’d)



Figure below illustrates the schematic diagram of the Hassler-type permeability measurement under steady state flow conditions.

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

The permeability is calculated using following modified form of darcy equation which takes into account the gas compressibility during flow.



Q k g P12  P22  A  2Pa L where:

CHAPTER 3: ROCK & FLUID PROPERTIES



2QPa L kg  A P12  P22



Q kg A  P1 P2 Pa L

= = = = = = = =

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

gas flowrate (cm3/sec) gas permeability (darcy) cross section area (cm2) fluid viscosity (cp) inlet pressure (atm) outlet pressure (atm) atmospheric pressure (atm) length (cm) 27 MOHD FAUZI HAMID

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Slippage Phenomenon during k Measurement liquid

gas

v (wall) = 0

   

finite velocity at wall

Gas permeability dependent on the mean pressure of the gas existing at the time of measurement. At low mean gas pressure, gas permeability exceeds liquid permeability. At high mean gas pressure, gas permeability approaches liquid permeability. Slippage effect is a laboratory phenomenon due to low flowing gas pressure, but negligible for gas flow at reservoir conditions.

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Klinkenberg Correction





Plot of kg versus the inverse of mean flow pressure (1/Pm) yields a straight line with slope k b and an intercept of k. “b” is klinkenberg slippage function. Slope is a function of molecular weight and molecular size.

 b  k g  k  1   P m  

kg 

k

 



P1  P2 Pm  2 1/Pm

CHAPTER 3: ROCK & FLUID PROPERTIES

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kL

The klinkenberg effect plot CHAPTER 3: ROCK & FLUID PROPERTIES

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Rock and Fluid Interaction

    

Interfacial tension. Capillary pressure. Wettability.

Relative permeability. Stock tank oil initially in place (STOIIP).

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Interfacial Tension



Interfacial tension is a force at the interface that acts to decrease the area of the interface.



A drop of water can hang down from the edge of a glass tube using the force at the interface.



However, when the interfacial tension is weaker, only a smaller (lighter) drop can hang down from the edge of the glass.



The interfacial tension can be measured using this phenomenon.

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

The reason why surface tension is decreased when something is adsorbed on the surface.



The attractive force between water molecules is greater than that between other molecules because of the hydrogen bonding.



At the surface, the attractive force works only from inside since there is no water on the outside (air side), so a water molecule on the surface is strongly attracted toward the inside.



This force is called “surface tension”. However, when something is adsorbed on the water surface, interactions between the adsorbed molecules themselves and also the adsorbed molecules and the water occur at the surface, so that the surface tension decreases.

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CHAPTER 3: ROCK & FLUID PROPERTIES

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Wettability



The wettability of a liquid is defined as the contact angle between a droplet of the liquid in thermal equilibrium on a horizontal surface. “Water wet”

“Oil wet”

.

Oil

θ

θ



The wetting angle  is given by the angle between the interface of the droplet and the horizontal surface.



The liquid is seemed wetting when 90<<180 and nonwetting when 0<<90.

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

The wetting phase will tend to spread on the solid surface and a porous solid will tend to imbibe the wetting phase.

 

Rocks can be water wet, oil wet or intermediate wet. The intermediate state between water wet and oil wet can be caused by a mixed-wet system, in which the surfaces are not strongly wet by either water or oil.

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Capillary Pressure



Capillary pressure is the pressure difference existing across the interface separating two immiscible fluids.



It is defined as the difference between the pressures in the non-wetting and wetting phases. That is:

Pc = Pnw - Pw

 

For an oil-water system (water wet): For a gas-oil system (oil-wet):

CHAPTER 3: ROCK & FLUID PROPERTIES

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Pc = Po - Pw Pc = Pg - Po

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

Oil-water system.

Po2  Pw 2 Pw 2  Pw1  hw g Po2  Po1  ho g Since, Pw 2  Po2 Then, Pw1  hw g  Po1  ho g

There fore, Po1  Pw1   w  0  hg That is, Pc   w  o  hg

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Relative Permeability



Relative permeability measurements are made routinely on core samples, to define the relative amounts of fluids that will flow through the rocks when more than one fluid phase is flowing.



Definitions are:

ko k ro  ka where:

k rw o, w, g kr k ka

CHAPTER 3: ROCK & FLUID PROPERTIES

kw  ka

k rg 

kg ka

= oil, water, gas = relative permeability = permeability to a specific fluid, o, w, or g = theoretical “air” permeability (39)

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STOIIP



In place volumes of oil is always quoted at surface conditions.

N 1 STOIIP  7758 x GRV x x  x So x G Bo where: STOIIP GRV N/G  So Bo CHAPTER 3: ROCK & FLUID PROPERTIES

= Stock tank oil initially in place, barrels = Gross volume of rock, acre-ft = Net to gross ratio = Porosity = Oil saturation = Oil formation volume factor, reservoir bbl/STB (40)

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STOIIP



In most cases, it’s convenient to simplify to:

1 STOIIP  7758 x BV x  x So x Bo where: BV = Bulk volume of reservoir, acre-ft

1 acre 1 acre-ft 1 bbl 1 acre-ft CHAPTER 3: ROCK & FLUID PROPERTIES

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= = = =

43,560 ft2 43,560 ft3 42 gal = 5.61 cuft 43,560/5.61 = 7758 bbl 41 MOHD FAUZI HAMID

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Example An oil well has been drilled and completed. The production zone has been encountered at depth 5,220 – 5,354 ft. The log analysis showed that: Average porosity Water saturation Formation volume factor Area

= = = =

21% 24% 1.476 bbl/STB 93 acres

Calculate the STOIIP.

CHAPTER 3: ROCK & FLUID PROPERTIES

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OGIP



OGIP:

OGIP  43,560 x BV x  x S gi

1 x Bgi

where: BV = Bulk volume of reservoir, acre-ft Sgi = Initial gas saturation Bgi = Initial gas formation volume factor, cu.ft/SCF

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Type of Reservoir



Oil Reservoir.

 



Contain mainly oil with or without free gas (gas cap). Can be divided into two:



Undersaturated Oil Reservoir (Pres > Pb) - no free gas exists until the reservoir pressure falls below the bubblepoint pressure.



Saturated Oil Reservoir (Pres < Pb) – free gas (gas cap) exists in the reservoir.

Gas Reservoir

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Recovery Recovery of hydrocarbons from an oil reservoir is commonly recognised to occur in several recovery stages. These are:



Primary Recovery.  the recovery of hydrocarbons from the reservoir using the natural energy of the reservoir as a drive.



Secondary Recovery.



the recovery aided or driven by the injection of water or gas from the surface.

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Recovery (cont’d)



Tertiary Recovery (Enhance Oil Recovery – EOR).  A range of techniques broadly labelled ‘Enhanced Oil Recovery’ that are applied to reservoirs in order to improve flagging production.



Infill Recovery.



Carried out when recovery from the previous three phases have been completed. It involves drilling cheap production holes between existing boreholes to ensure that the whole reservoir has been fully depleted of its oil.

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Drive Mechanism



The natural energy of the reservoir used to transport hydrocarbons towards and out of the production wells.



There are five important drive mechanisms (or combinations).  Solution Gas Drive.  Gas Cap Drive.  Water Drive.  Gravity Drainage.  Combination or Mixed Drive



A combination or mixed drive occurs when any of the first three drives operate together or when any of the first three drives operate with the aid of gravity drainage.

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Solution Gas Drive



This mechanism (also known as depletion drive) depends on the associated gas of the oil.



The virgin reservoir may be entirely liquid, but will be expected to have gaseous hydrocarbons in solution due to the pressure.



As the reservoir depletes (due to production), the pressure falls below the bubble point, and the gas comes out of solution to form a gas cap at the top. This gas cap pushes down on the liquid helping to maintain pressure.



The exsolution and expansion of the dissolved gases in the oil and water provide most of the reservoirs drive energy.

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Solution Gas Drive

Solution Gas Drive Reservoir

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Gas Cap Drive



In reservoirs already having a gas cap (the virgin pressure is already below bubble point), the gas cap expands with the depletion of the reservoir, pushing down on the liquid sections applying extra pressure.



The presence of the expanding gas cap limits the pressure decrease experienced by the reservoir during production.

CHAPTER 3: ROCK & FLUID PROPERTIES

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Gas Cap Drive

Gas Cap Drive Reservoir CHAPTER 3: ROCK & FLUID PROPERTIES

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Water Drive



The drive energy is provided by an aquifer that interfaces with the oil in the reservoir at the oil-water contact (OWC).



As the hydrocarbons depleted (production continues), and oil is extracted from the reservoir, the aquifer expands slightly. If the aquifer is large enough, this will translate into a large increase in volume, which will push up on the hydrocarbons, and thus maintaining the reservoir pressure.



Two types of water drive are commonly recognised: Bottom water drive and Edge water drive.

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Water Drive

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Gravity Drainage



The density differences between oil and gas and water result in their natural segregation in the reservoir. This process can be used as a drive mechanism, but is relatively weak, and in practice is only used in combination with other drive mechanisms.

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Combination



In practice a reservoir usually incorporates at least two main drive mechanisms.

Mixed Drive Reservoir CHAPTER 3: ROCK & FLUID PROPERTIES

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Secondary Recovery



Secondary recovery is the result of human intervention in the reservoir to improve recovery when the natural drives have diminished to unreasonably low efficiencies.



Two techniques are commonly used:



Waterflooding – involve injection of water at the base of a reservoir to:

 



Maintain the reservoir pressure, and Displace oil towards production wells.

Gas Injection - This method is similar to waterflooding in principal, and is used to maintain gas cap pressure even if oil displacement is not required

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Tertiary Recovery (EOR)



Primary and secondary recovery methods usually only extract about 35% of the original oil in place. Clearly it is extremely important to increase this figure.



Many enhanced oil recovery methods have been designed to do this, and a few will be reviewed here. They fall into three broad categories:  Thermal EOR  Chemical EOR  Miscible Gas



All are extremely expensive, are only used when economical.

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Thermal EOR



These processes use heat to improve oil recovery by reducing the viscosity of heavy oils and vaporising lighter oils, and hence improving their mobility.



The techniques include:  Steam Injection.  In-situ combustion (injection of a hot gas that combusts with the oil in place.  Increasing the relative permeability to oil (micellar and alkaline floods).



Thermal EOR is probably the most efficient EOR approach.

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Thermal EOR

Schematic Diagram of Steam Flooding EOR CHAPTER 3: ROCK & FLUID PROPERTIES

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Schematic Diagram of In Situ Combustion EOR CHAPTER 3: ROCK & FLUID PROPERTIES

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Thermal EOR (cont’d)

Schematic Diagram of Microwave EOR CHAPTER 3: ROCK & FLUID PROPERTIES

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Chemical EOR



These processes use chemicals added to water in the injected fluid of a waterflood to alter the flood efficiency in such a way as to improve oil recovery.



This can be done in many ways, examples are listed below:  Increasing water viscosity (polymer floods).  Decreasing the relative permeability to water (cross-linked polymer floods).  Microwave heating downhole.  Hot water injection.

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Chemical EOR (cont’d)

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Miscible Gas Flooding



This method uses a fluid that is miscible with the oil. Such a fluid has a zero interfacial tension with the oil and can in principal flush out all of the oil remaining in place.



In practice a gas is used since gases have high mobilities and can easily enter all the pores in the rock providing the gas is miscible in the oil.



Three types of gas are commonly used:  CO2  N2  Hydrocarbon gases.

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Schematic Diagram of Miscible WAG Flooding EOR CHAPTER 3: ROCK & FLUID PROPERTIES

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 Natural depletion – – – – – –

Fluid expansion Solution gas drive Gas cap drive Water drive Compaction drive Combination drive

 Primary recovery factors – – – –

Solution gas drive Gas cap drive Water drive Compaction drive

CHAPTER 3: ROCK & FLUID PROPERTIES

5% – 20% 20% – 40% 40% – 60% up to +10% (66)

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 Enhanced recovery: – – – – –

Water injection Gas injection Steam injection WAG injection etc.

 Degree of improvement dependent on: – – – – –

Type of scheme implemented Properties of the reservoir rock Properties of the oil Well spacing Economics

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