FORMATION EVALUATION AND INTEGRATION

1. An Overview of Well Logging

Introduction

Col. Edwin Drake gets the credit for drilling the first well in 1859 in Pennsylvania. He

found oil at a depth of 69 ft (21m). On January 10th,1901 Anthony Lucas and Patitto

huggins drilled a well at Sprindletop which blew at a phenomenol rate, some say

100,000 bbl/day, raining oil down on the country side. Thus the oil hunts began.

On a fine September day in 1927, Henri Doll lowered an experimental resistivity

sonde at a well Dienfenbach 2905, Tower 7 and attached it by wire to a winch. The

sonde was lowered to the bottom of the hole and resistivity measurements were

made at 1m intervals. Doll plotted the resistivity readings against depth on a piece of

graph paper and, by joining successive readings with lines, drew the first electrical

well log.

Thus a log records the characteristics of rock formations (together with the fluid it

contains), versus depth, by a measurement device in a well bore. The formation

characteristics may be electrical, nuclear or acoustic, etc. The initial uses of well

logging were for correlating similar patterns of electrical conductivity from one well to

another, sometimes over large distances.( In fact, the first experiment, that Doll

carried out, was aimed at to locate the top of a bed of marls which was often missed

in drilling). No doubt, at that time the electrical log was aptly called “electrical coring”.

As the measuring techniques improved and multiplied, applications began to be

directed to the quantitative evaluation of hydrocarbon formations. New

measurements have been continuously evolved which have found applications in all

the areas of hydrocarbon explorations.

1.1 Evolution of well logging

First Phase

From 1927-1945, saw the introduction and wide use of so called ES (Electrical

surveys). These logs, which were quite repeatable, were often difficult to interpret.

Others log available in this period were SP and GR. The sidewall core gun was first

introduced in 1942. The temperature log, used to detect the entry of gas into well

bore, was made available in 1936.

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G. E. Archie, in 1943, published his famous work on the relationship among

porosity, resistivity and the water saturation, which is better known as Archie‟s

Equation.

Second Phase

The second phase, from 1945-1970, was a major tool development era. With the

progress made in electronics to withstand the rigours of downhole environment

numerous tools were designed and tested successfully. Focused electrical devices

were introduced having good bed resolution and various depth of investigation. The

induction log, which can measure formation resistivity in a hole drilled with air oil-

based/fresh water mud, was introduced in 1949. A variety of acoustic and nuclear

tools were developed to provide porosity and lithology information. The formation

tester was introduced 1957

With the wealth of data acquired from these newly developed tools much

laboratory and theoretical works were done to place log interpretation on a sound

footing. M.J. Wyllie published his time average equation in 1956.

Third Phase

The third phase, from 1970-1990, may be called the log processing era. With

progress made in computer technology it has become possible to analyze the wealth

of data sent uphole by the logging tools in much greater detail. Computer became

an integral part of a logging truck and a number of logging tools could be combined

and recording could be done in a single run.

Fourth Phase

The fourth and current phase, which began in mid 90‟s, can be termed as imaging

era. The tremendous improvement in data handling capacity “a full array of data” is

brought uphole in digital form and processed to obtain an image log, which can be

an electrical or acoustic one. Another important development during the present

phase is in the field of nuclear magnetic resonance domain and the successful

launch of a log which can predict permeability, fluid typing, and irreducible water

saturation.

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1.2 The role of a log analyst

Most of the information we need from logs must be gained by data analysis, since

few logs measures directly any of the things we really want to know. Thus the role of

the log analyst was born. A log analyst is a scientist, a magician, and a diplomat. He

is a scientist because he has to have good knowledge of geology, geophysics,

mechanics, atomic physics, sedimentology, petrophysics, mathematics, chemistry,

electrical and electronic engineering. He is a magician because with all the scientific

reasoning often he has to depend on his imagination, inspiration and inventiveness.

The numerical figures he gets out of his computer/calculators still need his

interpretation or judgments to arrive at meaningful results. The job is not just to do

the algebra but to decide what the numbers really mean.

G.E. Dawson-Grove, a well known consulting petrophysicist, likens the role of

the log analyst to that of the “spider in the web.” He claims that the petrophysicist

(log analyst) plays a “vital central, potentially controlling position.” The range of his

or her influence is wider than any other discipline within the oil industry, with the

possible exception of the financial wizard. To be successful in this role, however, the

analyst has to realize the importance and potentially powerful position he or she is in

and be able to sell ideas to management.

Because of the multidiscipline approach required, the analyst must maintain a

web of communication with many seemingly unrelated functions within the

organization. The analyst must be sensitive to the vibrations coming along each

strand of the network and respond accordingly. That response might be in the realm

of geophysics, geology, reservoir engineering, petroleum economics or corporate

managements.

Dawson-Grove goes on to explain that there is no short cut to a log evaluation

and a log analyst can contribute maximum to the organization by doing a “full

evaluation.”

1.3 Applications of information derived from logging surveys.

The information obtained from logging surveys can be used in three broad areas.

Petrophysical and geological investigations of sub-surface rock strata with reference to its lithology, rock texture, stratigraphy, sedimentology,

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diagnesis, compaction studies, paleo-environments, tectonics, basin

evolution, geochemical studies etc.

Identification of reservoirs, reservoir fluid type determination, locating fluid contacts, estimation of inplace and recoverable hydrocarbons and

descriptions of reservoirs rocks.

Conceptual and mathematical modeling of reservoir for simulation of

reservoir volumetric and reservoir fluid flow behaviour.

Over and above a well log helps 1) a geophysicist to tie well with seismic 2) a drilling

engineer to calculate hole volume for cementing purpose and to know the quality of

hole.

2.Fundamental Properties of Reservoir Rocks.

Great G.E.Archie, whose understanding of rocks helped to start the quantification of

log analysis and formation evaluation enunciated, “ A term to express the physics of

rocks.. Should be related to petrology much as geophysics is related to geology.

Petrophysics is suggested as a term pertaining to the physics of particular rock

types.. This subject is a study of the physical properties of rock which are related to

the pore and fluid distribution.”

Introduction

Formation evaluation of a petroleum reservoir is the practice of finding out the

amount of hydrocarbon and its producibility. The volume of hydrocarbon can be

found out by determining reservoir parameters such as porosity, hydrocarbon

saturation, reservoir thickness etc. Lithology of the reservoir should be known

precisely to determine above mentioned parameters as well as permeability to

predict its producibility. These parameters can be known indirectly from well logs.

Most of the petroleum reservoirs are found in sedimentary rock. Any sedimentary

rock, which is a reservoir, has two components: solids and pore space. The major

task of a log analyst is to know rock pore system and type of fluid it contains. A

logging tool receives combined response from solid as well as pore space. The

fundamental problem, hence, is to separate response into the two components.

Therefore, formation evaluation requires a clear understanding of both rock solids

and pore-space properties. The physical character of the solid part is called lithology.

A lithology is characterized by its mineral composition and texture.

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2.1 Clastic rocks

These are generally defined as those created by physical sedimentations. Debris

arising from the alternation and decomposition of pre existing rocks and may be

transported often a considerable distance by wind, water, or ice from the site of

erosion to the site of deposition.Table-1 shows the major classes of detritel

/clastics rocks of the sandstone type with respect to grain size (Wentworth-Lane

class limits).

TABLE-1: Classification of Sandstone reservoir according to grain size (After

Pettijohn)

Grain size Grain Component Aggregateμm size

(mm)boulder boulder conglomerate

256,000 256

cobble cobble conglomerate

64,000 64

pebble pebble conglomerate

4,000 4

granule granule conglomerate

2,000 2

Sand Sandstone

62.50 1/16

Silt Siltstone Mudstone(nonlaminated)

mud or3.906 1/256

Shale (laminated, fissile)clay Claystone

Sandstone:

Sandstone is composed of at least 50% sand-size particles. Three mineral

components used to classify sandstone reservoirs are 1) quartz 2) feldspar and 3)

rock or lithic fragments (igneous rocks, chert, limestone, slate etc). Table 2 outlines

the classification of sandstone based on above components.

Siltstone:

Siltstone is composed of at least 50% silt-size particles that are generally less rich in

quartz than is sandstone. The most common minerals are quartz, mica, feldspar and

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heavy minerals. Siltstone can be a petroleum reservoir but is difficult to coax for

production.

Table 2: Classification of clastic rocks according to composition

Nomenclature Framework Fractions Properties

1. Arenites- Less than 15% “interstitial material” less than 30 μm size

A. quartz arenites More than 95% quartz

B. I. Arkoses More than 25% feldspar; percent feldspar greater

than percent rock fragments.

II. Subarkoses 2.5% to 25% feldspar; percent feldspar greater than

percent rock fragments.

C. I. Lithic arenites More than 25% rock fragments; percent rock

fragments greater than percent feldspar.

II.Sublithic arenites 2.5% to 25% rock fragments; percent rock

fragments greater than percent feldspar.

2. Wackes- More than 15% “interstitial material” less than 30 μm size

A. Quartz wackes More than 95% quartz.

B. Feldspathic Percent feldspar greater than percent rock

graywacke fragments.

C. Lithic graywacke Percent rock fragments greater than percent

feldspar.

Claystone:

Claystone is composed of at least 50% clay size particles, generally clay minerals

(hydrous aluminum silicates). Claystones are generally not considered as reservoir

rock.

Shale / mudstone:

Shale or mudstone is a mixture of clay-size particles (mainly clay minerals), silt-size

particles (mainly quartz, occasionally feldspar or calcite), and perhaps some sand-

size particles (mainly quartz, occasionally feldspar or calcite). Shale or mudstones

are generally not considered as reservoir rock.

Clay:

Minor amount of clay minerals (or shale) often have a major influence on reservoir-

rock properties, such as, porosity, permeability (hence producibility) and also on

logging tool response. Knowledge of type clay mineral as well as their distribution is

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important for formation evaluation. Hence 1) its mode of distribution 2) its effect on

logs have been discussed in detail below.

Table-3 outlines a classification scheme based on the structure of clay crystal unit

layers.

2.2 Distribution of clays in sandstone

The clay minerals contained in sandstones can have two distinct origins. They may

have formed at some point outside of the sandstone framework (detrital origin or

allogenic), or they may have formed locally within sandstone framework (digenetic

origin or authigenic).

Detrital clays:

Detrital clay minerals are usually incorporated into sandstone at the time of

deposition and range in size from discrete clay size particle to sand size aggregates.

Detrital clays may be of two types- laminated and structural. In laminated clay type

Individual clay size particles deposited as intercalated lamina separated by thin bed

of sandstones. This shale lamina affects vertical permeability while leaving the

permeability unaffected in the horizontal direction. As far as porosity is concerned,

presence of laminated clay will not effect the porosities of sandstone lamina but there

is an overall reduction of the bulk porosity of the total rock. The structural type of

clays are also deposited as sand-size or larger particles in the sand fraction and do

not have affect on porosity and permeability(Fig-1)

Diagenetic clays:

Diagenetic clays are developed subsequent to sediment deposition by precipitation

of clay crystals from pore fluids or by the interaction between pore fluid and the

mineral component of the rock.

Three types of diagenetic clays have been identified.(Fig-2)

i) Discrete particle

ii) Pore lining

iii) Pore bridging

i) Discrete particle or pore-filling: Formation of kaolinite in sandstone is a such

type of example. It usually develops as platy crystal attached as discrete particles to

pore walls or occupying intergranular pores. The crystal platelets may be stacked

face-to-face forming long “Book-like” crystal aggregates. Kaolinite crystals may be

scattered (patchy) throughout the pore system and don‟t form intergrown crystal

framework. (Fig-2a)

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ii) Pore lining: Pore-lining clay minerals, essentially illite, chlorite and

montmorillonite, coat (≤12 microns) the pore walls with a thin layer of flakes that are

parallel or perpendicular the pore wall, but growth does not reach far into the pore

space. A large amount of microporosity can be present between flakes. This type of

authigenic clay greatly reduces permeability and also influences electrical properties

because it can considerably increase surface area.(Fig-2b)

iii) Pore bridging: Formation of illite fibers in sandstone is such type of example. In

addition to being attached to pore wall surfaces, the illite fibers intergrown far into

the pore space or extend across a pore to create a bridging effect. This type causes

major reductions in permeability (due to tortuous fluid flow pathways) but porosity is

less affected because microporosity is preserved between the very fine fibers.

Fig-1: Distributions of clays in sandstone

From the discussion it is obvious that the knowledge of the type of distribution

(laminated, structural or dispersed), and of the nature of the clay minerals is of the

utmost importance to predict the porosity & permeability range and the existence

and distribution of permeability barriers. Presence of diagenetic dispersed clay

deteriorate the petrophysical characteristics of the formation. Severe reduction in

permeability and porosity occurs in the presence of montmorillonite clay. Similarly

illite and chlorite tend to significantly reduce effective porosity and permeability,

although to a lesser degree than montmorillonite. Kaolinite reduces porosity and

permeability to a significantly lesser degree than other clay minerals. Detrital

kaolinite crystals frequently are of angular form and substantial size, which is

favorable for the creation of large interconnected pores.

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Fig-2: Three types of diagenetic clays

Fig-2a: “Book-like” crystal aggregates of kaolinite. (Tipam sand)

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Fig-2b: Pore bridging illite (Tipam sand)

Fig-2c: Pore bridging montmorillonite (Tipam sand)

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TABLE 3-CLASSIFICATION OF CLAY MINERALS (after Grim)

2.3 Effect of clays on log responses

Resistivity log: The electrical properties of clays are of particular interest in well log

interpretation.

Cation Exchange Capacity (CEC)

In the crystal lattice of many clay minerals, atoms of lower positive valence often

replace ones of similar size but higher positive valence. This results in a net

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negative charge at the substitution site. Broken bonds around the edges of the

silica-alumina units also contribute to

net negative charge. The excess

negative charge is countered by

surface adsorption of hydrated

cations too large to fit into the

interior of the crystal lattice.

These counter ions can

exchange with other ions in the

solution and is responsible for

the so called clay surface

conductivity.

The “cation exchange

capacity” (CEC) is a measure of

the amount of such

exchangeable cations on the

surface of any clay. So, CEC,

expressed in meq/100gm of dry

clay, is defined as the amount of

positive ion substitution that

takes place per unit weight of dry

rock.

In case of kaolinite substitution of

cations does not occur within a

single layer and so theoretically it

has a CEC of zero. But some broken bonds around the edges give rise to

unsatisfied negative charges and which must be balanced by cations. As a result,

kaolinite has a very low CEC of 0.03 to 0.10 meq/gm. Substitution within the lattice

as well as broken bonds account for most of the CEC observed in illite. Illite

commonly has a CEC range of 0.10 to 0.40 meq/gm. A very high CEC is measured

on montmorillonite with values ranging from 0.8 to 1.5 meq/gm. About 80% of the

CEC is the result of lattice substitution, while rest is attributed to broken bonds. In

case of chlorite the CEC value reported to be almost negligible (Table-4))

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Fig-3

The net negative charge on many clay mineral surfaces attracts positive counterions

from the surrounding ionic solutions, establishing a nonuniform distribution of net

positive charge (modeled as an electrical double layer). Fig-3a is a simple

representation (the Guoy model) of this double layer. For the first few molecular

layers away from the clay surface the cations are concentrated and relatively

immobile. Their concentration decreases with distance from the clay surface (the

diffuse layer) finally equaling the number of anions. A more sophisticated model

(The Stern model), Fig-3b considers that the counterions are kept a bit away by 1)

adsorbed water on the clay surface and 2) hydrated water around the cations.

Clay Type CEC ØCNL ρ (av) K% (av) U (av) Th (av)meq/g g/cc ppm ppm

Montmorillonite 0.8-1.5 0.24 2.45 0.16 2-5 14-24

Illite 0.1-0.4 0.24 2.65 4.5 1.5 < 2

Chlorite 0-0.1 0.51 2.8 - - -

Kaolinite 0.03-0.06 0.36 2.65 0.42 1.5-3 6-19

Table-4: Clay properties of concern in logging.

Surface Area

To evaluate the volume occupied by the salt free water, one needs to know the area

of the surface of contact between clays and water. It is expected that there should

be a relationship between CEC and the specific surface area (area per unit weight).

Moreover, the finer is the clay, the higher will be the specific surface area. Hence

CEC will be more for finer clay than coarser clay. The higher CEC value of illite and

montmorillonite as compared to kaolinite or chlorite can be explained on the basis of

their higher specific area or finer than the latter. So montmorillonite and illite have a

pronounced effect on resistivity of the formation, while, kaolinite and chlorite have a

negligible effect. The conclusion is that clay typing is very important in the log

interpretation.

Neutron-Density log :

In a limestone compatible scale, discounting the effect of basic Lithology, i.e.

sandstone, limestone or dolomite, the variations in the separation between density

and neutron log responses are mainly due to two factors: the volume and the type of

clay presents.

Basically, clay minerals fall into two categories differentiated by significantly

different HI (Hydrogen Index)-values. Chlorite and kaolinite have a HI of 0.36 to 0.38,

whereas, both illite and montmorillonite have a HI of 0.12 to 0.13. Clay minerals with

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low index of HI of dry clay, particularly montmorillonite, usually have a substantially

greater amount of bound water than clays with high HI. As a result of the low content

of bound water in chlorite and kaolinite, the neutron log can measure similar

„porosity‟ in all the above three types of clay, while density porosity will be higher in

montmorillonite. In contrast, neutron porosity readings in illite are lower than that of

other three types of clay, while the density porosity should be lower than in

montmorillonite but higher than in chlorite and kaolinite.

Gamma ray log

All the clays, except chlorite, show high gamma ray activity. High gamma ray value

of illite is attributed to the presence of radioactive potassium in its structure and it is

much higher than the potassium content in kaolinite and montmorillonite. The

thorium content of illite is less than that of kaolinite and montmorillonite.

SP log

When the thickness of a clean sand is large enough the deflection of SP log reaches

a limiting value which is called „static SP‟. Against shaly sand the deflection of SP

log is smaller than the „static SP‟ and is termed as „Pseudo-static SP‟. The „static

SP‟ against a shale is taken as „base-line‟.

The static SP of a clean sand basically depends on the salinity of its connate

water with respect to that of mud, but it does not depend on the resistivity of the

sand. On the contrary, the pseudo-static SP of a shaly sand depends not only on the

salinity of its connate water with respect to that of the mud, but also on the

percentage of clay and on the resistivities of 1) the clay 2) uncontaminated part of

the sand and 3) the zone invaded by the mud filtrate.

If the three resistivities above were equal, the pseudo-static SP would be

proportional to the percentage of the sand in the shaly sand; its departure from the

static SP of a clean sand having the same connate water would be proportional to

the percentage of clay.

When, however, the sand is on the average substantially more resistive than the

clay, the amount of departure of the pseudo-static SP from the static SP of clean

sand is much larger than the percentage of clay. For this reason, the magnitude of

the SP log opposite shaly sands are systematically smaller when the sands are oil

bearing than when they are water bearing, provided all the other conditions

remaining same.

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3. Texture & its influence on reservoir characteristics

Texture deals with the size, sorting, shape, roundness, and packing of the rock

solids. Porosity and permeability are the main petrophysical characteristics of a

reservoir. Therefore, the influence of different component of texture on these

parameters will be discussed.

Textural Parameters Porosity Permeability

Grain size (sphere) - Increases Does not effect Increases

Grain sorting – Increases Increases Increases

Grain shape – sphericity increases, angularity Decreases Decreases

decreases

Sphere grain-packing- Open (less compacted) Maximum maximum

effect of compaction Closed( compacted) Minimum Minimum

Orientation–non-spherical grain Does not effect Effects

Cementation – Increases Decreases Decreases

Table5: Effects of textural parameters on porosity & permeability

3.1 Grain size

It measures the approximate diameter. For nonspherical grains the diameter of the

minimum cross-sectional area is taken.

Porosity is theoretically independent of grain size. Sphere (representing grain)

with uniform size will have the same porosity regardless of size. The situations arise

in case of sands with maximum sorting, such as, washed or winnowed sand or oolitic

sand. (Fig-4).

A few studies showed that porosity decreased slightly with increase with grain

size. (Fig-5 & 6). This can be explained on the fact that finer sands tend to be more

angular and are likely to be organized according to a less dense arrangement.

Permeability increases when the size of the grain increases. This is easily

understood because the size of pores and the canals (throats) which connect the

pores to one another are governed by grain size (Fig-7).

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Fig-4 : Relationship between porosity and mean grain size (Paluxy Formation,Texas) (from Dodge et

Fig-5: Relationship between porosity and median diameter of grains (Bentheimer sandstone) (from Von Engehardt,1960)

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Fig-6: Relationship between porosity and median diameter of sand grains for different sorting coefficients. A: So=2.086;B: So=1.625; C: so=1.279; D: So=1.128; E: so=1.061 ( Rogers & Head, 1961)

Fig-7: Relationship between permeability and mean grain size,(Dodge et al, 1971)

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3.2 Grain sorting

It measures how nearly a collection of grains approaches a single size. Porosity and

permeability increase when sorting increases. (Fig-8). In poorly sorted sand, the

small grains fill up the interstices of coarser grains thereby reducing the porosity as

well as permeability

Fig-8: Relationship between porosity and sorting coefficient of sands for different grain sizes. A: median diameter md = 0.106mm; B: md = 0.151mm; C: md = 0.213mm; D : md = 0.335mm. (from Rogers & Head, 1961)

Fig-9: Thin section showing deteriorating sorting (left to right)

3.3 Grain shape (sphericity) & Grain roundness (angularity)

Grain shape measures how nearly a particular grain approaches the shape of a

perfect sphere as opposite to grain roundness, which measures the sharpness of the

edges or corners of a grain. Sediments composed of spherical grains have lower

porosity than those formed by grains of less sphericity. This is due to the fact that in

the first type, the grains tend to settle down to a denser arrangement and the second

type can pack together in a way that creates wider volumes between them.

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Permeability also follows the porosity changes due to variations in shape &

roundness.

3.4 Grain packing

It describes the spacing (or density) of the spherical grains grains. Porosity depends

on packing type, 47.64% (cubic packing of equal grain size) for the most „open‟

arrangement to 25.95% (rhombohedral of equal grain size) for the most „closed‟.

Naturally the most „open‟ arrangements are not found and is generally packing is of

random or haphazard kinds. Compactions also lead to the most „closed‟

arrangements.

3.5 Orientations of grains

For non-spherical grains it is generally observed that the orientation of grains is the

same as the orientation of their axis of maximum elongation and is parallel to the

direction of current. Generally the orientation of the grains does not have any

influence on porosity but has a strong influence on permeability or more precisely on

the permeability anisotropy. For example, in channel sands, the direction of

maximum permeability is parallel to the axis of the elongation of sand bodies and in

bar sands it is perpendicular to sand elongation.

3.6 Cement

It is also have an important influence on the petrophysical characteristics of detrital

reservoirs. When the percentage of cement increases, the porosity and permeability

decreases, since the cement tend to occupy the pore space between the coarser

elements. Cement is developed after deposition either by chemical interaction

between unstable grains and formation water, or by circulation in the pore space of

solutions under hydrodynamic forces.

3.7 Mineralogical composition of grains

A) Grains composed of heavy and denser minerals will be deposited with the

minerals of the same weight, i.e. with less density, but with bigger size. This

situation leads to a poorer sorting and hence, lesser porosity and permeability.

B) Grains composed of unstable or chemically immature minerals, such as, mica,

feldspar etc, will affect porosity and permeability. They alter to authigenic clay

minerals (kaolinite, montmorillonite, illite, chlorite, etc), which will surround the grains

or invade the pore space, thus causing major reductions in porosity and permeability.

Formation & distribution of authigenic clay have already been discussed.

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3.8 Information on texture from well log

In a poorly consolidated sandstone formation, where cement is minor, well log gives

some textural information of the formation. In contrast , in a well cemented or

consolidated formation, it mask other textural attributes thereby making it difficult to

get any information on them. The discussion below pertains to poorly consolidated

sandstone formation.

Grain size:

There is no general universal relation between the grain size and a log

measurement. But often in a number of cases a clear relationship could be found

between grain size and logging measurement. Coarsening and finning upward

sequences (and hence depositional environment) can often be identified from a

number of logs.

Gamma Ray: Fig-10 shows that a correlation exists between gamma ray & grain

size measured on core samples. Gamma ray increases when grain size decreases because radioactivity is linked with finer grains, i.e. clay minerals. It can also be concluded that these clay minerals are mainly detrital (allogenic) as it is not possible to have more authigenic clay in an environment of finer grain size deposition than

the coarser grain size. GR

GR

Grain size from cores

Grain size from cores

Fig-10: Correlation between natural radioactivity and grain size (from Serra & Sulpice,1975)

The relationship between radioactivity & grain size is not always straightforward. It

may so happen that silty levels are more radioactive than shales Fig-11. In such

case, using of two logs, such as, SP and GR in the form of cross-plot may help to

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know the present of silts against very high GR zone , which otherwise would have

been interpreted as still finer grain i.e. clay . The density-neutron crossplot with SP,

GR, Th or K as „Z‟ parameters may also help to resolve the problem.

Fig-11: Silty sand more radioactive than shale

SP curve : Fig-12 shows the relationship between SP curve and grain size.

Resistivity : Fig-13 shows the grain size evolution detected on dipmeter resistivity curves. These evolutions are confirmed by the core descriptions reproduced

alongside.

Irreducible water saturation : A relationship can be observed between irreducible water saturations and grain size (Fig-14) .

NMR log provides information which can be related to grain size. (NMR log will be discussed in detail in a later chapter).

Sorting: Fig-15, gives an example of the change in sorting. Levels 9 & 10 present

an average porosity of about 35%. Taking into account the depth of occurrence

(7000 ft) this high porosity is certainly due to a good sorting. Level 11 shows a lower

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porosity of about 25% with identical SP & slightly less radioactivity as in level 9 & 10.

This drop in porosity seems to be result of a poor sorting.

Fig-12: Relationship between SP & Grain size

Fig-13: Evolution of grain size detected by resistivity

Fig-14: Relationship between Swir

with grain size

The problem can also be analyzed

by using neutron-density crossplot

with gamma ray

(or Th or K), SP as „z‟ parameters.

On such a crossplot ,(will be

discussed later), from the point

defining the maximum porosity for

a given interval (representing the

best sorting) a drop in porosity

along

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the sand line may represent decrease in the sorting.

To arrive at a meaningful interpretation in the above example it was assumed

that other textural properties (which affect porosity) remain constant and which is a

reasonable assumption at given depth interval.

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10

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Fig-15: Logs showing change of sorting.

Grain orientations : Qualitatively an idea of grain orientations may be obtained from

the azimuth of blue pattern seen on dipmeter tadpole plot as it is synonymous to floe

direction (foreset beddings).

Grain packing : This parameter cannot be obtained from log at a particular depth or

short depth interval. But the evolution of porosity on a long interval will explain the

modification of packing under the effect of compaction as well as diagenesis.

Grain shape: If the density as well as GR log (high potassium content) indicates the

formation to contain feldspar, mica it means that the formation is chemically

immature. A chemically immature formation is also texturally immature and

consequently has angular grain. On the other hand, if the sand appears to be very

clean, with a very low radioactivity level and high porosity the formation must be

chemically as well as texturally mature to have grain of round shape (spherical).

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3.9 Diagenetic processes

Compaction: This is a mechanical rearrangement of grains under the sediments

above during burial process. The rearrangement of grains results into reduction of

initial porosity. The amount of compaction depends on the initial porosity and on the

size, shape & sorting of the grains. It also depends on the rate of sedimentations &

passage of time.

Cementation : It is the deposition of minerals within the pore space. The minerals

may be derived from the sediment itself or from the salts dissolved in interstitial or

circulating water.

The most common cements are calcite, dolomite, silica, clay minerals. Cementation

results in a reduction of porosity and the quantity of cement cannot exceed the initial

porosity.

Pressure Controlled Solution: High pressure developed between points of contact

of the grains due to burial depth result in increased solubility and reappear as crystal

growth, causing loss of porosity.

Authigenesis /Clay Filling: The formation of authigenic minerals in detrital

sequence will depend on the textural & chemical maturity, the type of fluids,

hydrodynamic conditions & on compaction (simultaneous action of temperature &

pressure). The formation of authigenic minerals in orthoquartzites is usually limited

to the precipitation of „books‟ of kaolinite. In immature sequence (Arkoses &

graywackes) the most common authigenic minerals are illite, montmorillonite, and

chlorite.

3.10 Detection of Diagenetic Changes using Well Logs

Wireline log cannot give diagenetic history of a rock but can give information at the

present/final state – the state which depends on the initial state. So from the

present /final state one can infer some information of initial state.

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4.Pore-Space Properties

In formation evaluation, the most important characteristics of rocks are their pore-

space properties. A pore-space system can be considered as containing both pores

and pore throats. Pores are local enlargements in a pore space

Fig-16: Pores and pore throats in a pore-space system

system (Fig-16) giving storage space to fluid. Pore throats are the small connecting

spaces that link pores and provide restrictions to fluid flow. The pore- (and pore-

throat-) size distribution controls the reservoirs characteristics of porosity,

permeability, and fluid distribution.

4.1 Pore-size Distribution: The mercury / air capillary-pressure curve gives insight

to the pore-size distribution. Thomeer characterizes this curve with three

parameters (Fig-17):

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(Vb) p∞ is the fractional bulk volume occupied at infinite mercury pressure-i.e., the total interconnected pore volume.

Pd is the extrapolated mercury displacement pressure required to enter the largest pore throat.

G is the pore geometrical factor, reflecting the distribution of pore throats and their associated pore volumes.

It has been observed

that these parametersFig-17:Characterization of

are related through a capillary pressure

hyperbolic relationship

that can be expressed

as

(Vb) pc / (Vb) p∞ =

-G / log (Pc / Pd)e

Where (Vb) pc is the

fractional bulk volume

occupied by mercury

at some capillary

pressure Pc. Large

value of Pd suggest

that the largest pores

or pore throats are

small. Large value of G suggests that pore throat are tortuous and/or pore sizes are

poorly sorted.

(Fig-18) is capillary curves of different facies within a geologic formation. It illustrates

the variation of Thomeer parameters and hence provides information regarding

pore-size distribution. It also shows how permeability is controlled by pore size

distribution. One can also think about 1) the pore-space properties of sediments as

deposited and 2) the effects of diagenetic processes on pore space. Original pore-

size distribution in clastic rocks depends mainly on the textural properties of the

26

solids. Once a clastic sediment is

deposited, diagenesis begins to

modify the pore system through

compaction, cementation,

solution, clay-filling etc. The

result is usually a pore geometry

with poorer

petrophysical/reservoir

characteristics than the original.

(Fig-19,20,22) illustrate scanning

electron microscope

photomicrographs of pore

systems of clastic rocks having

the following characteristics.

Grain size and sorting

vary from lower fine

grained, very well sorted

to lower very fine grained, moderately to poorly sorted.

Little or no cement is present.

Little or no clay is present.

Also shown are porosity, permeability, and capillary pressure curve data

representing variations in petrophysical /reservoir characteristics.

(Fig-21) illustrates scanning electron microscope photomicrographs of pore systems

of clastic rocks having the following characteristics.

Grain size and sorting are the same as rock of Fig-19

Significant amount of cement and clay are present.

(Fig-23) illustrates scanning electron microscope photomicrographs of pore systems

of clastic rocks having the following characteristics.

Grain size and sorting are similar as rock of Fig-19.

Significant amount of dispersed clay are present in the pores.

Different types of dispersed clays are present.

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Fig-18: Family of capillary-pressure curves in sandstone formation

Fig-19,20: Pore-space properties & petrophysical characteristics sandstone

Fig-21,22: Pore-space properties & petrophysical characteristics sandstone

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4.2 Porosity Definition: Porosity is the fraction (or percentage) of rock bulk volume occupied by pore

space. At the time of

deposition it will be high, in the range

of 0.35-0.40 for a well sorted to about

0.25 for a poorly sorted sand. Besides

the above simple definition of porosity,

a family of porosity definitions has

evolved to meet various petroleum

engineering & well logging conditions.

Table 2-10 & Fig-24 summarize the

definitions of porosity.

4.3 Permeability Definition : The

permeability of a medium is its

capacity to permit the flow of a fluid

(gas, oil or water). If the fluid is

homogeneous and has no major

chemical influence on the surrounding

media, then the permeability is said to be absolute. It is represented by the symbol

„k‟, and the unit of measurement is Darcy.

Absolute permeability is derived from

the equation governing the flow of a

fluid in a porous medium (Darcy‟s

law).

Q=k S (p1-p2)/h

Q- Flow rate m3/S

- Viscosity in Pascal/S

S- Area in m2 through which

flow occurs.

h- Thickness of the material in

m traversed by the fluid.

P1 & P2 are the pressure, in

Pascal, upstream &

downstream of the flow

respectively.Fig-24: porosity definition

Fig-23: pore-space properties having dispersed clay

k- Absolute permeability in m2. (1 Darcy=10-12 m2)

Newly deposited clastic sediments are extremely permeable. Artificially packed

sands have permeability ranging from less than 2.4 to 475 darcies and the following

relationship between permeability and textural properties.

Permeability decreases as grain size decreases.

Permeability decreases as sorting becomes poorer.

Permeability increases as grain sphericity decreases and as grain angularity increases.

Diagenesis usually decreases the permeabilities of clastics, and the effect (positive

or negative) is often greater than on the porosity.

Table: 2.10: Definition of porosity

4.4 Fluid Distribution (Static Condition): In the static condition of a reservoir the

viscous forces have no effect and gravity & capillary forces are in balance. This

30

static system 1) generally defines the original fluid distribution in the reservoir, 2) is

the one encountered upon discovery of a petroleum reservoir,3) is the one that must

be interpreted through the use of well logging data.

Three factors control a reservoir‟s static fluid distribution:

The geometric configuration of the interstitial spaces-i.e., pore-space system – of the rocks.

The physical and chemical natures of the interstitial surfaces-i.e., pore walls- of the rocks.

The physical and chemical properties of the fluid phases in contact with the interstitial surfaces and each other.

Fig-25 illustrates static fluid distribution in a petroleum reservoir, by means of a

schematic vertical sandstone column in which three regions of saturation are

present:

Fig-25: Fluid distribution in a homogeneous reservoir.

Saturation region: In this region the rock is 100% saturated with the wetting phase

(water, in this case) up to a Level A, the 100% water level. The 100% water level is

characterized by displacement pressure (threshold pressure or entry pressure) of the

capillary-pressure curve. Displacement pressure is that capillary pressure at the

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top of the saturation zone; the minimum pressure required for the no wetting phase

to displace wetting phase and enter the pore system.

1) Funicular region (transition zone) : In this zone, large changes in saturation

occur over relatively small changes in reservoir height, and are represented by the

Plateau of the capillary-pressure curve of Fig-25. This region, between level A &B

reflects the most abundant and accessible pore-throat sizes. The steeper the

capillary pressure curve in this region, the less uniform the pore throats.

2) Pendular region : In this region the wetting phase is found mostly in pendular

ring around grain-to-grain contacts, in very small pores or coating the grain surfaces

with a very thin film. In this region only small changes in saturations occur over large

changes in reservoir height , and are represented by the steep slope of the capillary-

pressure curve, The wetting phase saturation in this region is often called the

„irreducible wetting-phase saturation‟. The saturation/height relationship occurs

because under static condition equilibrium exists between gravity and capillary

forces in a reservoir-rock/fluid system.

4.5 Capillary Pressure

The pores of a rock are usually linked by fine channels of very small diameter (a few

microns). The channels act as

capillary tubes and the fluid

they contain are subjected to

capillary forces. Capillary

pressure is a force per unit of

surface expressed by the

equation:

Pc=2T cos Θ / r

Pc – Capillary pressure in

Pascal

T- Surface tension of the

liquid (liquid-air separation

Fig-26:Water rising in tube due to capillary forces surface) in dynes/cm.

Θ- Angle of contact (in

degrees) between the meniscus and the wall of the capillary tube.

r- Radius of capillary tube.

32

A liquid, on contact with a solid, may be attracted or repelled to a greater or lesser

extent depending on whether or not they wet the wall. If a capillary tube is plunged

into the water, the water will rise in the capillary as a result of the forces of surface

tension( Fig-26). The height „h‟ to which the water rises is given by:

h=2T cos θ / rρg

h- Height of the liquid column in

cm. ρ- Density of liquid ingm/cm3.

g- Acceleration due to gravity.

4.6 Interfacial Tensions:

When two fluids are present in a formation- water along with hydrocarbons, then

water is the wetting liquid. There is also a interfacial tension between two non-mixing

liquids (e.g., oil & water). This tension is almost equal to the difference between the

surface tension of each liquid relative to air:

T 1-2 ≈ T1- T2

The difference of density also comes into play. So we have

h=2 (T1- T2) cos θ / r (ρ1- ρ2) g

Where ρ1 & ρ2 are the respective densities of the two fluids present.

From the equation it may be deduced that water will rise in the oil impregnated zone.

The height of the water will be more, when smaller is the difference of density

between the two liquids & smaller are the radii of the capillaries. This explains why

the water-oil transition zones are longer than those of water-gas or oil-gas, which are

usually very short. Similarly, poor sorting will result in a longer transition zone.

Another view:

The most popular theory of the genesis of oil says that the porous rocks which make

up an oil reservoir were filled with water at the time of deposition and that the oil

later migrated into them from the source rock. Since this migrating oil is lighter than

33

water it moved into the highest structural position in the trap. The accumulated oil

gradually displaced the water downward. This displacement continued until the water

saturations were reduced to the point where the water became discontinuous and

would no longer flow. This irreducible saturation is always found in oil reservoirs at

those places that are a sufficient distance above the water table. Between this

irreducible saturations condition & the fully water saturated water table, there exists a

transition zone where the saturation gradually changes from one condition to other.

This transition zone is the result of capillary action.

Fig-27 shows an example of static fluid distribution through a cross section of five

wells in a oil reservoir of inhomogeneous sandstone. The capillary curves used to

characterize the rock are the same as shown in Fig-18.

The free-water level is by definition a horizontal plane where h = 0. However, the

100% water level is not a horizontal plane, but its elevation above the free water

Fig-27: Schematic example of static fluid distribution

level varies with pore geometry, and is quantified by the displacement pressures of

the several capillary pressure curves. Note that a 100% water level is seen in wells 1

and 3 at widely varying elevations. The difference is caused by different pore

34

geometries. Likewise, the elevation of any other saturation level (for example, the

50% water level) varies with pore geometry as shown. Note that well no 3 penetrates

the bottom portion of a very long transition zone. Note also that both well no. 2 and

well no. 4 penetrate reservoir rock at irreducible water saturation; however, the water

saturation in well 4 (structurally higher well) containing type D rock is three times

greater than the water saturations found in well no2 containing type A rock. Note that

had well 2 encountered type D rock, it probably would have been a non-commercial

well.

4.7 Effective & Relative Permeability:

In most sediment which is usually wet firstly by water, oil cannot enter the pores filled

with water unless it has a force greater than the capillary pressures of the water-oil

interface (Fig-28). In other words, in the case of rocks showing high capillary forces,

that is, rocks with very fine channels, there will have to be a strong pressure on the

oil for it to displace the water. Under normal circumstances these

Fig-28: Diagram showing the progressive entry of oil in the pores of a

sandstone under the influence of increasing pressure, P1< P2 < P3.

rocks will be impermeable to the oil. Thus the concept of impermeability appears to

be wholly relative, that is, a rock which is permeable to water & impermeable to oil, is

impermeable to a given pressure but becomes permeable if one of the fluid is

subjected to a pressure greater than the capillary pressures.

The Darcy‟s law assumes that only one fluid flows through the porous medium.

However, it often happens that a reservoir contains two or even three fluids (water,

35

oil, gas). We must then introduce the concepts of diaphasic flow and of relative

permeability. In fact, if the formation contains two or more fluids, their flow interferes

and when this occurs, the effective permeability of each of the fluid (Kg, Ko, Kw) is

less than the absolute permeability.

The effective permeability of a fluid is

a measure of the ease with which this

fluid may pass through a reservoir in

the presence of other fluids. Effective

permeabilities depend not only on the

rock itself but also on the respective

percentage of the various fluids

present in the pores. The relative

permeability (Krg, Kro, Krw) express

the ratio of the effective permeabilities

to the absolute permeabilities. These

permeabilities vary between 0 & 1.

The values of relative permeabilities

vary with saturations. Fig-29 shows the relative permeability of water & oil in a typical

rock as a function of water saturations. The left side of this plot represents the

situation existing in the undisturbed zone of an oil bearing reservoir well above the

water table. Water saturation is at its irreducible value, Swi. No water will flow, so the

relative permeability to water, Krw, is zero. Oil will flow virtually unhindered because

the water exists only on the grain surfaces, at grain contacts, and in very fine pores,

leaving major passageways open for oil flow. Thus, the relative permeability of oil,

Kro, is close to unity.

At the other extreme, the right hand side of the plot applies to the invaded portion of

an oil bearing zone where residual oil occupies 10-40% of the pore space and water

occupies the remainder. The residual oil is immobile so that Kro is zero. However,

water will not flow unhindered because the residual oil is left as isolated globules

occupying a number of the medium-to- large pore spaces. These substantially

reduce the no. of branching passageways available to water flow and thereby

reduce Krw value from unity to a value in the range of 0.3-0.6.

36

in an oil bearing formation.

Fig-29: Relative permeability to oil & water

Between the two extreme is the situation that exists when oil & water flow

simultaneously. Both Krw & Kro are substantially less than one, and in fact their sum

is also significantly less than unity.

In order to predict the rate at which water & oil will be produced from a reservoir rock,

we need to know the relative permeabilities at the existing water saturations as well

as the absolute permeability.

4.8 Relationship between porosity & permeability:

In detrital rocks there is often found a good correlation between porosity and

permeability Fig-30,31 show the relationship between porosity & permeability and

with respect to grain size. These relationships show that for the development of a

empirical relationship between porosity & permeability, it is better to base it on facies

or environment. Fig-32 shows the relationship between permeability & grain size. It

shows that in theory permeability can be determined from the irreducible water

saturation which in turn depends on grain size. Hence, several equations were

developed to predict permeability from porosity irreducible water saturation (Swi):

4.9 Relationship between porosity & water saturations:

Fig-33,34 show literature examples of porosity/water saturations relationships.

Buckles shows that, for a given rock type, an hyperbola equation of the form

ØSw = C

Where

Ø = porosity

Sw = water saturation, and

C = Correlation factor,

Often fits porosity/irreducible-water-saturation data reasonably well.(Fig-33). The

transition zones (with water saturation greater than irreducible) fail to form coherent

hyperbolic patterns in a porosity/saturation crossplot. Such lack of coherence also

can be caused by variations in rock type.

In Fig-34, the data appear to be incoherent and typical of a transition zone until

distinguished by rock type; then a typical hyperbolic relationship for each rock is

apparent. Buckles also showed that a particular formation in a particular field has a

definite value of C. Fig-37,38 show porosity-saturation relationship of few wells of a

field of Eastern Region.

4.10 Relationship between permeability & water saturations:

Fig-36 show examples of permeability/water saturations relationship.

37

Fig-30: Examples of relationship between porosity & permeability. a)from

Fuchtbauer 1967 ; b)from Dupuy 1963; c)from Timur 1968.

Fig-31: Relationship between porosity & permeability for various grain

sizes. ( from Chilingar)

38

Fig-33:porosity-water Fig-32: permeability- saturation relationship grain size relationship

Fig-34:porosity-water saturation relationship

39

Fig-36: permeability-water-saturation relationship

Fig-37: Porosity-water saturation relationship

40

Fig-38: Porosity-water saturation relationship

41