PetEvalCh2

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CONTENTS

1 INTRODUCTION

2 ROCK CLASSIFICATION SYSTEM

3 POROSITY3.1 Primary Porosity3.2 Secondary Porosity

4 SATURATION

5 PERMEABILITY5.1 Darcy's Law5.2 Effective Permeability5.3 Relative Permeability

6 CAPILLARY PRESSURE

7 FLUID PROPERTIES

8 WATER SALINITY

9 DETERMINATION OF FORMATIONTEMPERATURE

2 2Rock and Fluid Properties

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LEARNING OBJECTIVES

Having worked through this chapter the Student will be able to:

Rock Classification:1. Distinguish between the main relevant rock types: sandstone, shale, carbonate.

Porosity:2. Define the term primary porosity.3. Describe the influence of packing and sorting on primary porosity.4. Define secondary porosity.

Saturation:5. Define the term fluid saturation.

Permeability:6. Define permeability and Darcy’s Law.7. Define the terms effective permeability, and relative permeability.

Capillary Pressure:8. Define what is meant by capillary pressure.

Fluid Properties:9. Distinguish between single phase liquid, single phase gas, and mixed two phase

(liquid and gas) areas on a P,T (pressure, temperature) diagram.

Water Salinity:10. Describe what is meant by water salinity and the factors governing its variability.

Formation Temperature:11. Describe how the formation temperature is measured.

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Institute of Petroleum Engineering, Heriot-Watt University 3


1 INTRODUCTION

The response to measurements made with petrophysical logging tools will depend onthe formation being investigated.

The first step in the interpretation of the logging data is to determine the type of rockwhich is being logged. The next step is to determine the porosity, saturation, andpermeability of the rocks.

Rocks are classified in a very specific way for the purposes of well log interpretation.Evaluation of reservoir rocks or potential reservoir rocks requires basically threepieces of data:

• porosity - the capacity of the rock to contain fluids;• saturation - the relative amounts of these fluids; and• permeability - the ability of the fluids to flow through the rock to the well bore.

Separation of the hydrocarbons into either gas or oil is of lesser significance.

2 ROCK CLASSIFICATION SYSTEM

This classification system uses a pseudo-rock chemistry classification. The methodis very useful since many of the responses from well logging tools reflect physical andchemical properties of the rocks. However the classification system, based onchemistry, must be clearly defined so that it can be related to the geological descriptionof the rocks. This classification is used extensively in the evaluation of logs and inparticular in the charts used for interpretation.

This classification system is based on the following categories of rocks:

• Sandstones - SiO 2;• Limestones - CaCO 3;• Dolomite - CaCO 3Mg CO 3;• NaCl, Anhydrite, Gypsum, Clay

On this rock chemistry basis, sandstones are SiO 2. Therefore, anything that is SiO 2shows up on well logs as sandstone. Since the classification is on a purely chemicalbasis and not on a grain size basis, silt is considered as a very small grained sandstone.Chert is also classified as a sandstone although the crystal structure is different it lookslike sandstone on well logs.

Limestone is calcium carbonate (CaCO 3). Since chalk results in the same responseon logs as calcium carbonate, it is classified as a limestone.

Dolomite (CaCO 3Mg CO 3) differs strongly from limestone on well log readings.Physically, dolomite differs from limestone significantly in density, hardness and

other properties.

NaCl, Anhydrite, Gypsum and Clay are relatively common rocks, but differ significantlyfrom sandstone, limestone and dolomite. Halite is common table salt, (NaCl) and will

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record as NaCl. Anhydrite is calcium sulphate and although gypsum is calciumsulphate plus crystalline water, the water in gypsum creates a large difference betweenthe two log responses.

The only apparent maverick in the system is shale , which in reality is clay, and isclassified as clay. For general usage, there is no need to differentiate between thevarious clay minerals which make up shales as long as clean shales are considered asbeing clay.

A few rock types have been omitted but these omissions are not considered serious.For example, a conglomerate is nothing more than a grain size variation of sandstone,limestones with regular, spherical grains are not classified as sandstones but as

limestone.

3 POROSITY

The porosity of a rock is the percentage of rock gross rock volume that is not made upof matrix material. Porosity can however be subdivided into primary and secondaryporosity.

3.1 Primary PorosityPrimary Porosity, usually related to granular, is the porosity developed by the original

sedimentation process by which the rock was created. For all practical purposes,porosity is the non-solid part of the rock, filled with fluids. Porosity is referred to interms of percentages, while in calculations it is always a number less than one.Porosity, by definition, is the volume of the non-solid part of the rock (that filled withfluids) divided by the bulk volume.

Bulk VolumeRepresentation

Grain VolumeRepresentation

Pore VolumeRepresentation

Figure 1

Diagram and equation of

porosity

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Porosity Void volumeBulk volume

Porosity B volume

Bulk volume

=

=−

=

+

×

x

ulk Grain volumex

Porosity pore volume

void volume grain volume

100

100

100

To acquire a feel for the values of porosity generally encountered, assume somemarbles, all the same size, are stacked on top of each other in columns. Calculationswill show a porosity of 47.6% ( Figure 2 ). Spherical sand grains 1/10 the size of themarbles stacked one on top of the other will have the same porosity, 47.6%. If the samemarbles are packed in the closest possible arrangement in which the upper marble sitsin the valley between the four lower marbles, each touching, the porosity is reducedto 25.9% ( Figure 3 ). Again, changing the size of the marbles will not change theporosity as long as all the marbles are the same size.

The highest porosity normally anticipated is 47.6%. A more probable porosity is inthe mid-twenties. In reality, porosity’s greater than 40% are rare. These may be foundin surface sands that are neither compacted nor consolidate. Porosity reduction occurswith distribution of grain sizes so that smaller grains fit between larger grains(Figure 4 ). Also, non-spherical shapes fit together better. This is closer to the realsituation. The normal range of porosity in granular systems is from 10% - 35% withthe actual complete range being from 3% to 40%.

In general, porosities tend to be lower in deeper and older rocks. This decrease inporosity is due primarily to overburden, time, stresses on the rock, and cementation.

Figure 2

Column stacking of rock

grains - Porosity = 47.6%

Figure 3

Close packing of rock

grains - Porosity = 25.9%

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There are many exceptions to this general trend when normal overburden conditionsdo not prevail. Shales follow very much the same porosity/depth trend as sandstonesexcept that porosities are normally lower in shales. For example, in a recent mud theporosity measures about 40%. It decreases rapidly with depth and overburdenpressure until, at about 10,000 feet depth, normal porosities are less than 5%. This istypical of Tertiary shales, with older shales being considerably more compacted andthus lower in porosity. Shales are essentially plastic and therefore compress moreeasily than sands. These basic trends of porosity versus depth are not really noticeablein carbonates, which tend to be pseudo-plastic and compress considerably more thansands.

3.2 Secondary PorositySecondary Porosity is created by processes which occur after deposition. An exampleof secondary porosity can be found in limestones or dolomites which has beendissolved by ground waters, a process which creates vugs or caverns ( Figure 5 ).

Fracturing and dolomitization also create secondary porosity. Dolomitization is theresult of the shrinking of solid volume as the material transforms from limestone todolomite. In most cases, secondary porosity results in much higher permeability thanprimary granular porosity.

Figure 5

Secondary Porosity in

Limestone

Figure 4

Impact of sorting on

porosity

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4 SATURATION

Saturation of any given fluid in a pore space is the ratio of the volume of the fluid tothe total pore space volume. For example, a water saturation of 10% means that 1/10of the pore space is filled with water.

Where porosity is the capacity to hold fluids, saturation is the percentage or fractionof this total capacity that actually holds any particular fluid. Porosity, hydrocarbonsaturation, the thickness of the reservoir rock and the areal extent of the reservoir rockall contribute to the total hydrocarbons in place ( Figures 6 and 7 ). These establishthe economic potential of any given reservoir.

Oil Water

Oil Water Gas

Of the total volume (barrels or millions of cubic feet) of gas present in a reservoir, thepercentage that is produced depends on the recovery factor. This recovery factor,normally determined by experience, is typically in the 20% - 50% range. Theproduced oil must be able to pay for the cost of drilling and casing the well and other miscellaneous expenses, as well as supply a profit.

5 PERMEABILITY

Permeability refers to the ease with which fluids flow through a formation. It is not

sufficient to have oil or gas in a formation, the hydrocarbons must be able to flow fromthe reservoir into the wellbore in order to be recovered at the surface. Permeabilityis a physical characteristic of any given rock. Generally, permeability is measured byflowing fluids through the rock under known conditions. To determine the permeability

Figure 6

Reservoir rock - saturation

with different fluids (oil and

water)

Figure 7

Reservoir rock - saturation

with different fluids (oil,

water and gas)

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of a rock formation, several factors must be known: the size and shape of the

formation; its fluid properties; pressure exerted on the fluid; and the amount of fluidflow. The greater the pressure exerted on the fluid, the higher the flow rate. The moreviscous the fluid, the more difficult it is to push it through rock. For example, it is alot more difficult to push honey through a rock than to push air through it.

5.1 Darcy's LawPermeability is a measure of the ability of porous material to transmit fluid. The unitof measurement is the Darcy, named after the French hydrologist who investigatedflow of water through filter beds in order to design the public drinking fountains of thecity of Dijon in the year 1856.

However, Henri d'Arcy was using clean water in his experiments. Subsequently, itwas Henri Poiseceuilles, who noted that viscosity was also inversely proportional tothe flow-rate. Hence it was essential to include a term for viscosity, µ in centipoise,in the Darcy equation.

Q

k A P=

∆l µ

One darcy is defined as that permeability that will permit a fluid of one centipoiseviscosity to flow at a rate of one cubic centmetre per second through a cross-sectionalarea of 1 square centimetre when the pressure gradient is one atmosphere per

centimetre.

where:

Q = flow rate of fluid(cm 3 /sec)k = permeability (Darcy)A = cross-sectional area (cm 2)∆ P = pressure change (atmospheres) l = length (cm)

In practical units, one Darcy permeability will yield a flow of approximately one

barrel/day of one centipoise oil through one foot of formation thickness in a well borewhen the pressure differential is about one psi.

Darcy's Law is used to determine permeability, which is a constant when the followingboundary conditions are met:

1 Linear-laminar flow2 No reaction between fluid and rock3 One phase present at 100 percent pore-space saturation4 Incompressible

Because of the relatively high value of the base-unit, the millidarcy mD, (onethousandth, 1/1000, of a Darcy) is commonly in use in reservoir description. TheDarcy has a SI equivalent in the µ m2. Formation permeabilities typically vary from afraction to more than 10,000 millidarcies.

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Permeabilities normally encountered in reservoir rocks are from less than one

millidarcy to about 50,000 millidarcies. The permeability of any rock is governedprimarily by the size of the pores. The larger the pore size, the higher the permeability.For example, one four-inch diameter pipe will have a higher permeability than abundle of quarter-inch diameter pipes with the same flow cross sectional area. Thetortuosity of the path the fluid takes going from one end of the rock to the other alsodetermines permeability. This is due to the fluid flowing around all the sand grainsrather than in a straight line from one end of the core to the other.

Although there may be a correlation between increasing permeability with increasingporosity, this does not necessarily hold for any given situation. An example can befound in the earlier discussions in which the sand grains were stacked one on top of the other and had a porosity of 47.6%. If the sand grains are large, the pore diametersare large and the permeability is very high.

Reduce the size of the sand grains by a factor of 100 and the permeability isconsiderably smaller because the diameters of the pores are considerably smaller.Further, smaller pores mean larger surface areas around them, and therefore moreresistance to flow (lower permeability). Another example is in vuggy type rocks inwhich the pores are often large and permeability’s very high even though the porositymay be only 5% - 10%.

The permeability of fractures has been shown to be almost a pure function of the widthof the fracture. A rough relationship for permeability versus width of fracture can beshown as:

k = 54,000,000 x Width x Width

Therefore, a fracture .001 inches in width has a permeability of 54,000 millidarcies.

The very high permeability created by a very small fracture is the reason that fracturessignificantly affect production capabilities in reservoirs. One small fracture in areservoir will result in the production of most of the fluids from the fracture area asthe fracture acts like a pipeline through the formation. Equivalently, if a formation isfractured while drilling, the high permeability of the fracture results in the high flow

of drilling fluids into the formation.

When only one fluid is present in the pores the permeability of the formation is calledthe absolute permeability .

5.2 Effective PermeabilityThe effective permeability to any given fluid in a rock refers to permeability whenmore than one fluid is present. Effective permeability is less than absolute permeabilitybecause the presence of a second fluid reduces the effective pore diameter availablefor fluid flow.

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In the case of a reservoir where only water is present, the permeability measured will

be absolute. In the case where oil and water are present and the oil is flowing, theeffective permeability of the oil will be less than absolute permeability. This is dueto the water reducing the effective diameters of the pores through which the oil isflowing.

5.3 Relative Permeability Relative permeability is the ratio of effective permeability of a specific fluid toabsolute permeability. Relative permeability curves reflect the capacity of the rockto produce given fluids by showing the permeability of those fluids as a function of saturatio ( Figure 8 ). Thus, in a typical relative permeability curve, it will be seen thatat low water saturations only oil will flow. As the water saturation increases, the

relative permeability of oil decreases until some critical level is reached, at whichpoint both oil and water flow. The oil flow continues to decrease and the water flowto increase as water saturation increases. At some level of water saturation, the oil nolonger flows and only water flows. Beyond this point, as water saturation increases,the flow of water within the core continues to increase.

In either case, the amount of fluid flowing is not a direct effect of the relativepermeability as different fluids have different viscosities. For example, if gas and oilhave equal relative permeabilities, more gas than oil will flow within the rock becauseof the dramatic difference in viscosity.

6 CAPILLARY PRESSURE

Reservoir rocks are composed of many capillaries of varying sizes. Capillary pressure

is the phenomenon by which water or any wetting liquid is drawn up into a capillary.The smaller the capillary, the higher the liquid rises.

Due to the variety of capillary diameters, the water saturation existing within a rock

Figure 8

Diagram of Relative

Permeability

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above the water table varies ( Figure 9 ). The permeability of a rock is determined by

the size of the capillaries in the rock. These capillaries also define the irreduciblewater saturation, which is the water saturation that exists above the transition zone.The transition zone is the zone which displays a change in the water saturation withheight.

Most often it is considered the region in which both water and oil (or gas) flow. Themore small capillaries there are, the higher the water saturation, and the longer thetransition from irreducible water saturation to all water. The larger the pore spaces,the fewer the small capillaries, the transition zone is shorter.

Oil

SandGrain

Pc

Water

WOC

FWL0% Water Saturation 100%

Transition Zone

hp

h

7 FLUID PROPERTIES

Hydrocarbons existing within reservoirs are combinations of compounds such asmethane, propane, butane and pentane. In the oil business, oil and gas are referred toas if they are separate and distinguishable items. They are produced either as liquidor gas at surface temperature and pressure. The cut between liquid and gas oftendepends on the method of separation used at the well site.

In the reservoir, oil and gas are not distinguishable as separate entities but are a system.One way to define this system is with a pressure-temperature (P,T) diagram whichdescribes the conditions of the material in the reservoir at any given pressure or temperature ( Figure 10 ). For example, the hydrocarbons existing under the pressure

and temperature that would put them in the “A” part of the P,T diagram areundersaturated oils, (liquid). Those existing in the “B” area are gases. Thehydrocarbon fluids in the envelope “C” exist as both oil (liquid) and gas. The locationwithin “C” determines the volumetric ratio between gas and oil. Every particular oil

Figure 9

Capillary Pressure and

Saturation

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or hydrocarbon system has its own pressure/temperature phase diagram. The

composition of the hydrocarbon determines the shape and location of the two-phaseenvelope.

X5

P r e s s u r e

Temperature

% Liquid

Gas

(Gas)

BlackOil

VolatileOil

GasCondensate Gas

TM2

75

100

50

25201510

50 Single Phase Region

Single Phase Region(Liquid)Single Phase Region

Two Phase Region

CP

Where:

P b = Bubble point pressure at indicated temperature

P m = Maximum pressure at which two phases can coexist

Tm = Maximum temperature atwhich two phases can coexist

C = Critical conditions

X5 = Cricondentherm

B u b b

l e P o

i n t L

i n e

D e w P o i n

t L i n e

Pm

PbA

BC

Y1

Y2

Where a two phase system exists, a free gas and a free liquid phase, the two are incontact but not necessarily in a dispersed condition. In this state, the oils are calledsaturated. That is, they have in solution all the gas they can hold at that particular pressure and temperature, and often exist as an oilfield with a gas cap. The size of thegas cap is dependent upon its location in the P,T envelope. For example, if it was onthe 75% line, oil volume would be 75% and gas volume 25% of the reservoir. It shouldbe noted that there is no distinct barrier between “A” and “B”. The area that separates“A” and “B” is miscible in the sense that it is impossible to tell when the material goesfrom liquid to gas; within this region are the condensate reservoirs.

Every particular hydrocarbon system has its own P,T phase diagram. What willhappen during the life of the oil or gas field can be determined from the P,T diagram.For example, assume the pressure/temperature is such that the oilfield is produced ata constant temperature condition where just the pressure is reduced. As pressuredrops, the fluid eventually reaches the bubble point line which separates “A” from“C”. Having once crossed the bubble point line, the reservoir then develops larger andlarger amounts of gas or in many cases, develops a gas cap.

A gas cap develops only when the vertical permeability in the reservoir is large enoughto allow the gas to move upward. This presumes the system is closed and there is nowater encroachment. If the reservoir is initially at “Y 1” on this chart and the pressuredrops, as shown going from “Y 1” to “Y 2”, the reservoir fluids change from a singlephase to a two-phase liquid and gas, and then to a single gas phase. This is a retrogradecondensation system in which you first develop the liquids within the reservoir as thepressure drops. As the pressure continues to drop, the reservoir fluid becomes a singlephase gas and ends up a gas field.

Figure 10

Phase Behaviour of Fluid

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An oil being produced from the reservoir to the surface has both pressure and

temperature reduction, and will change from a liquid to a combination of gas andliquid.

The phenomena occurring is very much like the Coke bottle phenomena. As the wellis agitated (the pressure dropped), the gas comes out of solution. A Coke bottle thathas been agitated, when you take the top off, blows Coke everywhere. The gas in theCoke is coming out of solution and represents the driving force that pushed the Cokeout of the bottle. An oilfield is essentially the equivalent with the natural gas forcingthe oil out of the formation.

8 WATER SALINITY

The waters in reservoirs in the earth vary from fresh to salt saturated solutions. Near the surface, waters are generally very fresh with low sodium chloride concentrations.Deeper, the waters tend to become saltier until some maximum concentration occursand the water often becomes fresher.

The salinity of the water is a result not only of its vertical position in the earth, but alsothe age of the rocks and the physical position of the rocks relative to surface outcrops.Salinities used are generally in parts per million by weight. In the logging business,sodium chloride concentrations generally are used. At normal room temperatures,

250,000 ppm (parts per million) is a saturated solution, while at higher temperaturesthe saturation point for waters is higher. For example, at 300 degrees C, a 300,000ppm sodium chloride solution is saturated.

9 DETERMINATION OF FORMATION TEMPERATURE

It is often necessary to know the resistivity of formation waters and the drilling mudat the depth of some formation of interest. The resistivity of aqueous solutions is afunction of temperature. It is thus necessary to be able to determine the approximatetemperature in a well bore at any given depth.

The logic is very straight forward. A mean surface temperature can be obtained or estimated for any given location. A maximum reading thermometer is run with thelogging instrument and the temperature reported on the log heading. This maximumtemperature reading is assumed to be obtained at total depth or the maximum depthat which the logging tool stopped. The temperature between the surface and the depthat which the maximum temperature is recorded is assumed to change linearly. Theassumption that the geothermal gradient (the rate at which temperature increases withincreased depth) is linear is a good approximation.

Sometimes the maximum temperature in the borehole is less than the actual formationtemperature due to the cooling effect of circulating mud while drilling the hole. If thisis a problem, multiple runs with the maximum reading thermometer should be madeto determine a stabilised temperature. The normal approach is to assume bottom holetemperature and formation temperature are equal.

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