Fundamentals of Reservoir Properties.pdf

Fundamentals of Reservoir Properties 1-1

FUNDAMENTALS OF RESERVOIR PROPERTIES


CONTENTS

INTRODUCTION 1 RESERVOIR / STATIC BEHAVIOUR

1.1 DESCRIPTION OF PETROPHYSICAL PROPERTIES

• (PETROPHYSICAL CLASSIFICATION OF RESERVOIRS)

• DETRITAL TERRIGENOUS

1.1.1 (Siliciclastic) RESERVOIRS 1.1.2 Sands or quartzose sandstone 1.1.3 Arkose 1.1.4 Graywackes 1.1.5 Conglomerates 1.1.6 Silts and Siltstones 1.1.7 Detrital Carbonates reservoirs (Bioclastics) 1.1.8 Detrital Volcanic reservoirs (Pyroclastics) 1.1.9 Westhered plutonic reservoirs (granite or basic wash) 1.1.10 Reservoirs of chemical or biochemical origine

1.2 RESERVOIR THICKNESS

1.3 POROSITY

2 RESERVOIR / DYNAMIC BEHAVIOUR

2.1 PERMEABILITY

2.1.1 Definition of absolute permeability 2.1.2 Relationship between permeability and porosity 2.1.3 Reservoir production capacity and permeability 2.1.4 « Horizontal » and « vertical » Porosity 2.1.5 Fissures, Fractures and rock matrix importance 2.1.6 Water - Rock Contact Phenomena Capillarity Phenomena 2.1.7 Interfacial Tensions 2.1.8 Effective and relative permeabilities 2.1.9 Relationship between permeability and network 2.1.10 Influence of clay content and distribution on the permeability of

a reservoir. 3 DRAINAGE AREA AND IN PLACE RESERVE ESTIMATE 4 RESERVOIR CONTENT OF FLUID AND GAS 5 RESERVOIR GEOMETRY


5.1 GENERALITIES

5.2 GEOMETRY OF OIL AND GAS TRAPS

5.2.1 Structural traps 5.2.2 Stratigraphic traps 5.2.3 Combination traps


INTRODUCTION Virtually all of the world’s petroleum is produced from sedimentary rocks. Locating the

reservoirs that contain petroleum requires an understanding of the nature of sediments. Mud

Logging and electric logging are important methods of acquiring such information.

Global tectonic activity has altered and continues to alter the earth’s crust. Tectonic activity is

the process that distills out the lighter, low melting point materials that accumulated on the

surface and form the continents today.

Sedimentary rocks evolved from the mechanical and chemical alteration caused by exposure

to the surface environment. Since the evolution of life forms, petroleum has been generated

in sedimentary environments. When organic remains escape oxidation by early burial or

depth of burial, and a sufficient concentration of organisms are subjected to moderate levels

of geothermal heat and overburden pressure, petroleum is believed to be formed.

When these fluids migrate from source rock to porous and permeable reservoir rocks, they

are eventually trapped and the hydrocarbon accumulates to form an oil or gas reservoir. Mud logging by analyzing lithology (cuttings, core) or gas shows, monitoring and interpreting

drilling parameters.... provide the very first information related to a potential reservoir.

Consequently, the reliability and quality of Mud logging services is of outstanding importance.

Further, Electric Logs will produce complementary information and data. Well log data are

the result of measurements of the physical properties of rock matrix material and the fluids

occupying the pores. Otherwise, these data are accessible only by core analysis. Quite

naturally, mud logging, master logs and charts, electric logs and core data are often

compared and used in conjunction to define reservoir properties.

When cores are not available, log data are often used as an extension from core analysis

and log comparisons on other wells. Electric log measurements can define or at least infer

petrophysical properties such as porosity, shale volume, lithology, and water, oil, or gas

saturation. Estimates of permeability, predictions of water cut, detection of over pressured zones, and

calculations of residual oil can also be made. Log analysis is primarily used to describe

petrophysical properties in a single well. However, when a suite of logs is run in several wells

representative of a specific geographical area, it can be used as a geological tool to describe


local structure, stratigraphy, facies relationships, environments of deposition, and reservoir

geometry.

Reliable economic evaluation of a reservoir requires reasonable knowledge of certain

fundamental reservoir properties. Although the rock recovered by coring methods is the

cornerstone of formation evaluation, wireline data are more universally available for

determining the fundamental reservoir properties.

1 RESERVOIR / STATIC BEHAVIOUR

1.1 DESCRIPTION OF PETROPHYSICAL PROPERTIES

Petrophysical Classification of reservoirs

Since the quantitative interpretation model and the type of program to be used

must adapt to the complexity of the problem to be solved, and depends on the

nature of the reservoir, it is important to establish from the start the category of

reservoir to which the zone in question belongs.

From a practical point of view reservoir rocks can be classified according to their

origin, which will in part determine the type of porosity (intergranular,

intercrystalline, vuggy, effective), the geometry of the pores and their distribution

together with the mineralogical complexity of the interpretation.

Detrital Terrigenous 1.1.1 (Siliciclastic) Reservoirs

Depending on grain size, these may include conglomerates, sands or

sanstones, silts or siltstones and the porosity is of an intergranular type,

usually primary.

The mineralogical composition of the reservoir depends essentially on first,

the chemical and textural maturity of the grains and the matrix of the

sediment, and second on the nature of the cement, if any ; which binds the

grains (Fig. 1).


A chemically mature rock contains virtually nothing but quartz, the most

abundant stable mineral ; and possibly one or two other stable minerals,

either as secondary minerals or in the form of cement. These are known as

quartzitic sand or sandstone, and sometimes known as quartzite or

orthoquartzite ; the cement may be described as either calcareous, dolimitic

or saliferous.

As well as quartz, a chemically immature rock contains unstable minerals

(feldspars, micas, plagioclases) and fragments in variable proportions but

increasing in number according to its immaturity. These are referred to as

graywackes (cf. Pettijohn) and arkoses. Thus the chemical maturity of the

rock could be represented by the quartz-feldspar ratio and, as a first

approximation, by its potassium content and thus its natural radioactivity.

The textural maturity is determined by the percentage of matrix (in the

geological sense) and the degree of sorting. To a certain extent the

percentage of detrital clay is an indication of the rock textural mature

degree.

Chemical maturity and textural maturity do not necessarily appear

simultaneously ; thus a conglomerate may reveal a high textural maturity

(as is the case with numerous igneous rock pebbles). A very fine sand can

be chemically highly mature (quartz and kaolinite) and texturally immature

(poor sorting which generally decreases with grain size).

The evaluation of the two types of maturity is important from the geological

point of view as well as for production and interpretation. As for the latter

the complexity will clearly increase from quartzitic sandstones to arkoses.

In an orthoquartzite, a textural model designed to differentiate between

sands, silts, cement and possibly clays will undoubtedly be of greater use

than a mineralogical model aimed at the calculation of the percentage of

quartz, clay minerals, feldspars and micas, the last two being practically

absent or only present in insignificant amounts and then solely bound to

rock fragments which themselves are not numerous.


1.1.2 Sands or quartzose sandstones

Sand is a loose detrital sediment whose grains are for the most part

between 1/16 mm and 2 mm in diameter. A sandstones is a sand

consolidated by the presence of a cement binding the grains together and

cementation is a post-depositional process where the cement fills the pore

space.

In detrital sequences one can usually assume that the percentage of

cement cannot exceed the porosity existing at the time when the process of

cementation began.

Fig. 2 – Simplified Classification of noncalcareous sandstones


Fig.3. – Sorting of detrital terrigeneous rocks (after Petitjohn)

As shown in Fig. 2-3, quartzose sands correspond to sand containing less

than 25 % feldspars and less than 15 % matrix. They are subdivided into

protoquartzites and orthoquartzites, the latter being the purest (Table 1)


A B C D E F G H Quartz 50 60 78 65.4 32.0 71 30.9 27 Feldspar 3-5 3 3 2.2 8 10.0 2 Mica - 1 - - 0.2 tr 0.5 - Rock fragments 40 35 15 10.6 43.02 224 33.01 465 « Clay » or matrix 10 2 4 6.8 6.9 2 5.5 5 Silica cement -3 - - 11.9 trace - - - Calcite cement present - 8.5 13.0 - 19.2 20

(1) Includes 15.0 percent chert : (2) Includes 28.0 percent chert : (3) 5-10 percent,

author’s observation : (4) Includes 5.0 percent chert : (5) Includes 3.0 percent chert, 12.0 percent limestones, 27.0 percent dolomite.

A. Oswego Sandstone (Ordovician), Pennsylvania. U.S.A. (Krynine and Tuttle, 1941). B. Bradford Sand (Devpnian). Pennsylvania. U.S.A. (Krynine, 1940, C-1, table 3). C. Deese Formation (Pennsylvanian). Oklahoma, U.S.A. (Jacobsen, 1959. Table 4, Analysis

D-112). D. Salt Wash Member of Morrison Formation (Jurassic), Colorado Plateau, U.S.A. Mean of

25 thin sections (Griffiths, 1956. P. 25). E. « Calcareous graywacke » (Creataceous). Torok. Alaska. Average of 3 samples

(Krynine in Payne and others, 1952). E. « Calcareous graywacke » (Creataceous). Torok. Alaska. Average of 3 samples (Krynine

in Payne and others, 1952). F. Basal Caliborne Sand (Eocene), Texas U.S.A. (Todd and Folk, 1957). G. « Frio » Sanstone (Oligocene). Seeligson field. Jim Wells and Kleberg Counties. Texas

U.S.A. Average of 22 samples (nanz. 1954. P. 112). H. Molassesandstein (Tertiary), Germany (USM No. 186. Füchtbauer. 1964, p. 256).

Table 1 : Mineralogical composition of graywackes and proto-quartzite sands (from Petitjohn, 1963 in Petitjohn et al., 1972)

By definition, quartzose sands and sandstones are thus both chemically

and texturally mature. They are of a light color : white, grey or pink.

Allochthonous detrital minerals, such as feldspars and micas, are rare to

very rare. Accessory heavy stable minerals, such as zircon, rutile,

tourmaline, apatite, and garnet are frequent.

Autochthonous detrital minerals, e.g. glauconite, phosphates, or shell

fragments are sometimes common. The size of grain varies but the sorting

is on the whole good. The grains are round.

These parameters mean that quartzose sands are very porous and

permeable. Cement is usually secondary silica or calcite, more rarely

dolomite, anhydrite, halite, pyrite, or haematite. One assumes, due to their

maturity, that they are the consequence of several cycles of sedimentation.


Quartzose sands are frequently characteristic of either beds of winnowed

sand deposited on submarine rises, or of aeolian sands. However, they can

also be found in other environments.

1.1.3 Arkose

Arkoses are essentially rocks which have a certain textural maturity (less

than 15 % matrix) but are chemically immature (more than 25 % feldspars,

that is unstable minerals). Some arkoses can even contain up to 60 %

feldspars if the source rock is rich in feldspars and poor in quartz (Table 2).

A B C D E F G H I J Quartz 60 57 57 71 60 35 37.7 57 51 53.1 Microline 34 27 25 13 592 0.7 24 30 18.5 Plagioclase - 352 1 45.4 6 11 0.4 Micas - - - T - 4.2 3 1 6.9 Clay - - - - 5 - 12.0 9 7 17.0 Carbonate - p3 - - -- 2 p3 p3 Other 64 85 14 4 8 45 - 1 - 4.1

(1) Normative or calculated composition : (2) Modal feldspar, given by Mackie as 55 and 60. Respectively : (3) Present in amounts under 1 percent : (4) Chlorite : (5) Iron oxide (hematite) and kaolin.. A. Sparagmite (Precambrian) Norway (Barth, 1938, p. 60). B. Torridonian (Precambrian) Scotland (Mackie, 1905, p. 58). C. Jotnian (Precambrian), Satakunta, Finland (Simonen and Kuovo, 1955, Table 2. No. 5). D. Subarkose, Potsdam Sandstone (Cambrain), New York, U.S.A. (Wiesnet, 1961, p. 9). A

subarkose. E. Subarkose, Lamotte Sandstone (Cambrain), Missouri, U.S.A. (Ojakangas, 1963. P. 863).

A subarkose. F. Lower Old Red (Devonian) Scotland (Mackie, 1905, p. 58). G. Arkose (Permian), Auvergne, France (Huckenholtz. 1963. p. 917). H. Pale arkose (Triassic) Connecticut, U.S.A. (Krynine, 1950. p. 85). I. Red arkoses (Triassic) Connecticut, U.S.A. (Krynine, 1950. p. 85). J. Arkoses (Oligocene) Auvergne, France (Huckenholtz. 1963. p. 917).

Table 2 : Mineralogical composition of arkoses and subarkoses (from Petitjohn, 1963 in Petitjohn et al., 1972)

Arkoses are the product of incomplete alteration of igneous or metamorphic

rocks of the granite type such as diorite and gneiss. The typical arkose is

pink or red in color more rarely grey. Pink denotes feldspars in the matrix.

While red denotes ferric oxide. Grain size is very variable and the sorting is

often poor. The grains themselves are angular to sub-spherical.


Feldspars can be of different types but microcline and albite are the most

common. Alteration produces sericite, kaolinite, or montmorillonite. Micas

are also common along with heavy minerals while alteration of micas

produces illite, montmorillonite, or kaolinite depending on the degree of

alteration.

According to Selley the majority of arkoses are to be found in fluvial facies

(alluvial fans) and are characteristic of intracratonic basins delimited by

fault systems. However, they can also be found in other environments.

1.1.4 Graywackes Graywackes are by definition texturally immature sands because they

contain more than 15 % matrix. According to their chemical maturity, they

are subdivided into lithic graywackes, if the proportion of feldspars is below

25 %, and into feldspathic graywackes if the feldspars make up more than

25 % of the elements present (Table 3).

Graywackes are generally hard rocks, of a dark grey-green color. They are

very poorly sorted, with grain size varying from very coarse to very fine

(clay by matrix). In shape, they are angular to subangular and of low

sphericity. The quartz grains are covered by other detrital minerals, while

minerals such as hornblende and pyroxenes are often mixed in with

feldspars.

The largest grains are usually plutonic, volcanic or metamorphic rock

fragments, according to the source rock. Micas (muscovite and biotite) are

plentiful, together with chlorite and sericite which are present as

microcrystals of diagenetic origin. Finally, unstable heavy minerals are also

frequent.

All these detrital grains are embedded in an abundant matrix made up of

clay minerals (chlorite and sericite), quartz, carbonates (often in the form of

siderite), pyrite and sometimes carbonaceous organic matter. This matrix is

both syndepositional and diagenetic by alteration of unstable detrital

material.


Graywackes are generally characterised by rapid deposition in orogenic

belts associated with flysch facies. Because of their immaturity they usually

have poor reservoir characteristics, that is, average to low porosity, and low

to very low permeability.

1.1.5 Conglomerates

These are detrital sediments in which more than 25 % of the particles are

over 2 mm in diameter. Depending on the quantity of matrix the

conglomerates are classified as orthoconglomerates (grain supported) and

paraconglomerates (mud supported).

The orthoconglomerates of marine origin are without matrix at the time of

deposition, but can acquire a post-depositional matrix of fine material

carried by water flowing through the pore spaces of these permeable

formations which contain large spaces.

Fluvial orthoconglomerates, however, have a matrix deposited at the same

time as the pebbles, while paraconglomerates usually correspond to mud-

flows or to deposits of glacial origin.

Conglomerates are further subdivided according to their composition. Thus

there are monogenic conglomerates, made up of a single type of rock -

usually quartzitic sandstone - and polygenic conglomerates made up of

several types of rock.

The grain size of the conglomerates means that they are very porous and

permeable. But, because of this, fine material (matrix) can enter the pore

space and greatly reduce permeability.

1.1.6 Silts and silstones Silt is a sediment whose grains, of detrital origin, have a diameter of

between 1/16 and 1/256 mm. A siltstone is a hardened silt. The

composition of silt may vary considerably, but the most common minerals

are quartz, mica, feldspars, and the heavy minerals, with a variable

percentage of clay minerals. Grains are angular to sub-rounded. Sorting is


often average to poor, and porosity is sometimes high, but because of the

grain size, permeability is frequently poor.

1.1.7 Detrital Carbonate Reservoirs (Bioclastics)

Such reservoirs correspond to the accumulation of shell fragments or

carbonate rocks either with or without non-carbonate detrital grains

(lithoclasts), often made up of quartz. Depending on the quantity of quartz,

one finds sandy limestone, (or dolomites) or calcareous (or dolomitic)

sands.

Shell fragments may also contain detrital carbonate grains (intraclasts,

pellets, and oolites). the whole being bound by a matrix (micrite or clay) and

a cement (sparite). Depending on the relative proportion of grains to matrix.

Dunham (1962) has subdivided this type of rock into :

- mudstone, when grains make up less than 10 % of the total volume of the

rock ;

- wackestone, when the percentage of grains lies between 50 and 10 %

and the grains are thus supported by the matrix ;

- packstone, when the percentage of matrix is between 50 and 10 % and

as a result the grains are touching ;

- grainstone, when the percentage of matrix is less than 10 %.

Depending on grain size the last category can be subdivided into calc-

arenites for a given size of sand, and into calci-rudites for grain sizes above

2 mm (Grabau's classification).

Since carbonate grains are often formed on site or close by, carbonate

rocks are termed autochtonous. Furthermore, the origin of the matrix

means that they are frequently classified as rocks of chemical or

biochemical origin.

It is important to note also that these rocks are highly sensitive to

diagenetic effects which can at the same time alter their texture and even

their mineralogy (dolomitization). Vuggy secondary porosity, resulting from

dissolution is frequent (TABLES 3, 4, 5).


Aspect Sandstone Carbonate

Amount of primary porosity in sediments

Commonly 25-40 % Commonly 25-40 %

Amount of primary ultimate porosity in rocks

Commonly half or more of initial porosity : 15-30 % common

Commonly none or only small fraction of initial porosity ; 5-15 % common in reservoir facies

Types(s) of primary porosity

Almost exclusively interparticle

Interparticle commonly predominates, but intraparticle and other types are important

Types(s) of ultimate porosity

Almost exclusively primary interparticle

Widely varied because of post-depositional madifications

Sizes of pores Diameter and throat sizes closely related to sedimentary particle size and sorting

Diameter and throat sizes commonly show little relation to sedimentary particle size or sorting

Sizes of pores Strong dependence on particle shape-a « negative » of particles

Greatly varied, ranges from strongly dependent « positive » or « negative » of particles to form completely indépendant of shapes of depositional or disgenetic components

Uniformity of size, shape, and distribution

Commonly fairly uniform within homogeneous body

Variable, ranging from fairly uniform to extremely heterogeneous, even within body made up of single rock type

Influence of diagenesis

Minor ; usually minor reduction of primary porosity by compaction and cementation

Major ; can create, obliterate, or completely modify porosity ; cementation and solution important

Influence of fracturing

Generally not of major importance in reservoir properties

Of major importance in reservoir properties if present

Visual evaluation of porosity and permeability

Semiquantitative visual estimates commonly relatively easy

Variable ; semiquantitative visual estimates range from easy to virtually impossible ; instrument measurements of porosity, permeability and capillary pressure commonly needed

Adequacy of core analysis for reservoir evaluation

Core plugs of 1-in diameter commonly adequate for « matrix porosity»

Core plugs commonly inadequate ; even whole cores ( ∼ 3-in, diameter) may be inadequate for large pores

Permeability-porosity inter-relations

Relatively consistent ; commonly dependent on particle size and sorting

Greatly varied ; commonly indépendant of particle size and sorting

TABLE 4. - Comparison between porosity in sandstones and limestones (from choquette & pray)


TABLE 5. – Different types of porosity in carbonate rocks


1.1.8 Detrital volcanic reservoirs (pyroclastics)

Such reservoirs are essentially the product of volcanic rock fragments.

Depending on grain size, one can define them as :

- agglomerates, that is volcanic equivalents of conglomerates formed by

explosions and screes at the base of a volcano. Depending on the type of

volcanic origin they are made up of pebbles of lava, whose composition is

rhyolite, andesite, or basalt.

volcanic sands or tuffs or ashes, originating from volcanic explosions or an

erosion of the lava flows. They are composed of crystals, volcanic glass

and rock fragments, olivine and black mica in variable proportions

depending on the type of volcano from which they originate. They can be

deposited on the Earth’s surface or underwater.

Volcanic sands are often badly sorted due to the fact that any major

movement and winnowing would quickly remove the unstable minerals

which compose them. As a result their permeability is generally poor, and

minerals in the zeolite group are frequently present. They are the product of

deterioration of various components of the tuffs.

1.1.9 Westhered plutonic reservoirs (granite or basic wash)

Such reservoirs result from alteration of plutonic basement or intrusions.

The matrix porosity is poor (generally lower than 5 %). Fracturing is often

abundant, varying from small cracks to large open fractures. The

mineralogical composition is close to that of the parent rock (granite, diorite,

or gabbro), plus products of weathering (clay minerals, I.e. chlorite).

1.1.10 Reservoirs of chemical or biochemical origin

Such reservoirs are essentially represented by carbonates formed by

chemical deposit from a solution rich in CaCO3, by temperature variation,

by the biochemical action of algae, or by the activity of constructor

organisms. Dunham (1962) has given the name of boundstone to

carbonates resulting from this activity. They are also termed calcareous

reefs or simply reefs.


For this category of reservoir, porosity may be of different types :

intragranular, intergranular, but mainly skeletal, as shelters, casts, or even

intercrystalline (Table 3, 4 ,5). This category of reservoir is often linked with

formations resulting from an accumulation of calcareous shells (chalk,

nummulitic limestones, etc.). Such a reservoir should also include rocks

formed by accumulation of siliceous skeletons : radiolarites and diatomites.

Carbonates of chemical or biochemical origin can contain gypsum or

anhydrite. The chalk is often very porous though its permeability is poor so

that siliceous intrusions are frequently found, e.g. flint and chert.

1.2 RESERVOIR THICKNESS

The reservoir engineer requires an accurate measure of reservoir thickness,

generally, the current true vertical thickness of the reservoir rock in place.

Original orientation of reservoirs and the effects of subsequent folding, faulting,

uplifting, or downwarping also influence reservoir parameters.

The most basic information provided by wireline logging is measured well depth

and identifiable top and bottom depths of traversed geological formations. If the

borehole is nearly vertical and formations are relatively flat, the measured

thickness of different geological status is generally accurate.

However, when wells are deviated by more than about 5°, it becomes necessary

to compare measured reservoir thickness to true vertical thickness utilizing

measurements of the borehole drift angle and directions (Fig. 7 A).


Fig. 7A. – TVD priciple for a vertical well and horizontal bed

When the reservoir rock dips steeply as a result of folding or faulting, the

formation thickness must often be corrected to its true stratigraphic thickness,

and information pertaining to post-depositional structural dip is required (Fig. 7

B).


Fig. 7B. – TVD principle for a vertical well and a dipping bed

When the well is deviated and formations dip steeply, additional data are required

to correct the log measurements to true vertical thickness (Fig. 7 C).


Fig. 7C. – TVD principle for a deviated well and a dipping bed

1.3 POROSITY

The ratio of a volume of void spaces within a rock to the total bulk volume of that

rock is commonly expressed as a percentage : i.e., all the collective void space is

referred to as pore volume so that percent porosity (ø) is calculated as

Pore volume

ø = -------------------- X 100 Total volume

In practice. several descriptions of porosity exist, but the two most common are

total porosity and effective porosity (Fig. 8).

hTotal porosity represents the ratio of total pore volume within a rock to the total

bulk volume including voids as given in the previous equation.

hEffective porosity represents the ratio of the interconnected pore space to the

total bulk volume.


hOther terminology such as secondary porosity, water-filled porosity, vuggy

porosity, and fracture porosity are discussed later.

The amount of porosity is principally caused by the arrangement and shape of

the rock grains (Fig. 9), the mixing of grains of different sizes and shapes (Fig.

10), and the amount of cementing material present (Fig. 11).

Fig. 8. – Graphic Depiction of Effective,

noneffective and total pororsity Fig. 9. – Porosity relation to arrangement and

shape of rock grains

Fig. 10. – Variation size of spheres can affect

porosity type and volume Fig. 11. – Clay cement can affect porosity and

permeability

2 RESERVOIR / DYNAMIC BEHAVIOUR

2.1 PERMEABILITY

2.1.1 Definition of absolute permeability

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

the darcy.

Absolute permeability is derived from the equation governing the flow of a

fluid in a porous medium (Darcy’s law) :

1 S

Q = k ----- (P1 - P2) µ h

Already explained rock measurements of permeability are typically

expressed as millidarcies (md).

Fig. 12. – Arrangement of sand grain and pore structure affect permeability


Fig. 13. – Shape and size of grains affect permeability

The graphics (Fig. 12 and 13) demonstrate several variables that can affect

permeability horizontally and vertically.

Q = flow per unit of time (cm/s) µ = viscosity of flowing medium (cp / Pascal/s) S = cross section of rock is area in (cm2) h = the thickness of the material traversed by the fluid (cm) P1 - P2 = pressure differential (drop) k = permeability (darcy)

2.1.2 Relationship between permeability and porosity


Potentially petroleum-bearing rocks exhibit a wide range of permeabilities

(Fig. 14). Often, permeability increases with porosity : however, rocks with

very low porosity have exhibited high permeability characteristics, and

some high porosity rocks have very low matrix permeability.

Fig. 14. – Reservoir rocks demonstrate a wide range of permeability that may not follow porosity trends

Permeability values can be determined by serveral means ; e.g., well tests,

wireline formation tests, drill stem tests, transient well testing, or analysis of

different types of recovered core.

Core data are accepted as the most accurate method for determining

permeability (Fig. 15).


Fig. 15. – Permeability determination from Core

Permeability is a fundamental parameter in reservoir engineering work.

For example, a reservoir rock 10 ft thick having 1 darcy of effective

permeability will permit about 15 barrels of oil per day (BOPD) to flow into a

wellbore if the internal well pressure is 10 psi less than the reservoir

pressure. A formation 100 ft (30 m) thick that averages 2 md can be said to have 200

md-ft (60 md-m) permeability, whereas a formation 10 ft (3 m) thick that

averages 200 md can be said to have 2,000 md-ft (600 md-m) of

permeability. The thin zone obviously has better qualities of deliverability than the thick

zone.

2.1.3 Reservoir production capacity and permeability

A reservoir’s productive capacity is largely determined by its permeability. If

a 100 ft (30 m) thick reservoir is perforated with 4 shots per foot in 4.8-in.


(12.2-cm) ID casing, the well’s productivity is restricted to the capacity of

the casing, tubing, and wellhead aparatus. If a 0.7-in. (1.75-cm) choke is

placed at the surface, the well’s production capability is more severely

reduced. Within the cased well itself, productivity is restricted to the size of tubular

goods, and wellhead restrictions diminish the producing capability of the

pipe string. Each individual perforation will only produce if the well has the

capacity to accept flow into it and the ability to produce the fluids or gas at

the surface.

In this set of circumstances, a large number of perforations would not

contribute any increase to the rate of production. The perforations in the

most permeable depth intervals would contribute the vast majority of fluids

or gas, and as permeability behind individual perforations diminishes, their

ability to contribute to flow would also diminish.

2.1.4 « Horizontal » and « Vertical » Porosity

Horizontal permeability is generally accepted as the rock’s permeability in a

more-or-less horizontal direction, while vertical permeability is generally

accepted as the component perpendicular to horizontal permeability. A core

from a near-vertical borehole in steeply dipping beds may yield misleading

permeability estimates for vertical and horizontal orientation if the core

analyst is not aware of the circumstances.

Vertical permeability (kv) is usually somewhat less than horizontal

permeability because of the layering effect of sedimentation ; i.e., clay

laminae, platy minerals, etc. Horizontal permeability (kh), measured parallel

to bedding, is the major contributor of fluid flow into a typical wellbore. The

ratio of kh /kv generally ranges from 1.5 to 3.0 but might exceed 10.0 in

some reservoirs (Figs. 12 and 13).

High vertical permeability does occasionally occur, usually in clean, coarse,

unconsolidated sand or where vertical fractures, fissures, or joints are well

developed.


2.1.5 Fissures, fractures and rock matrix importance

Vertical joints and fissures often act as horizontal barriers if they are filled

with clay or other minerals. Bypassing and coning effects occur in such

reservoirs, and high vertical permeability can therefore be detrimental.

Fractures are nothing more than cracks or fissures that occur due to the

stresses and strains of rock or pore pressure realigning to stability. Most

fractures occur not as a large crack in the rock, but as several small

fissures. Orientation is usually normal, or parallel to the forces that caused

the fracture.

The type of rock matrix influences the preferred direction. Major

catastrophic events in geologic time (called revolutions, disturbances, etc.

depending on the extent) are one major cause of fracturing, while

redistributions of pore fluid or gas from an area of high pressure to an area

of low pressure are also attributed to fracturing.

2.1.6 Water-Rock Contact Phenomena - Capillary Phenomena

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

diameter, and possibly by fissures and fractures. Because of their very

small bore (a few microns) the channels act as capillary tubes and the

fluids they contain are subjected to capillary forces.

Capillary pressure is a force per unit of surface expressed by the Laplace

equation :

2 T cos θ

PC = --------------- r

where

PC is the capillary pressure in pascal ;

T is surface tension of the liquid (liquid-air separation surface) in dynes/cm

or in newtons/m in SI units ;

θ is angle of contact (in degrees) between the meniscus and the wall of the

capillary tube.


T = 73 dynes/cm at 20° C and θ = 0 if the liquid wets the solid perfectly ;

r is capillary radius in cm.

This shows that on contact with a solid surface, the liquids may be attracted

or repelled to a greater or lesser extent depending on whether or not they

wet the wall. We know that if we plunge a capillary tube into water, the

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

(Fig.16).

Fig. 16. Water rising in a table due to capillarity forces

The height, h, to which the water rises is given by Jurin’s law :

2 T cos θ

h = --------------- r o g

where h is height of the column of liquid in cm, o is the density of the fluid in

g/cm3 and g is the acceleration due to gravity.

The height is also linked to the capillary pressure, so that we have :

PC h = ---------------

o g


2.1.7 Interfacial Tensions When two fluids are present, two new concepts are introduced. The first is

the concept of a wetting liquid, generally water which fills the angular parts

of the pores and covers the solid particles with a film.

The second is the concept of interfacial tension between two non-mixing

liquids (e.g. oil and water, the oil being almost never in contact with the

rock). This tension is more or less equal to the difference between the

surface tension of each liquid relative to air :

T1-2 ≈ T1 - T2

The difference in density also comes into play and we have

2 (T1 - T2)cos θ

h = ----------------------- r (o1-o2)g

where o1 and o2 are the respective densities of the two fluids present. From this equation we may deduce that water will rise in the oil-

impregnated zone. All the more so when the difference in density between

the fluids is low and the radii of the capillaries are smaller, given that the

surface tension of the water is two or three times that of flowing oil.

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 (of

the rock matrix) will result in a longer zone than would otherwise be the

case (Fig. 17).


Fig. 17. – (A) Effect of capillary tube radius on the height of the water column, and on the capillarity pressure curves (from Arps, 1964). (B). Effect of sorting on the length of the transition zone, (a) with capillaries of equal radius representing good sorting and (b) capillaries of different radii representing poor sorting. (C)> Effect of different fluid densities, (a) the distribution of water and gas or oil in the transition zone; (b) effect of density difference on the transition zone and the capillary pressure curves (from Arps, 1964)


Perrodon (1966) describes the influence of interfacial tensions in geology

and petroleum exploration as follows :

« In migration phenomena, as in hydrocarbon exploration, the displacement

of hydrocarbons appears to depend on water-hydrocarbon contacts and

more especially, on the values of the interfacial tensions which separate the

two fluids.

The greater the interfacial tensions, the greater will be the difficulties of

moving phases which involve surface deformation and which are very

difficult.. .

« Levorsen (1956) summarises the effects of some of the factors on the

interfacial tension between, the oil and water in reservoirs :

- increased temperature reduces interfacial tension ;

- increased pressure reduces interfacial tension ;

- the more dissolved gas there is in the oil or water above the bubble point,

the lower will be the interfacial tension. The less dissolved gas there is

below the bubble point the greater will be the interfacial tension ;

- a reduction in the difference in viscosity between the oil and the water

reduces interfacial tension ;

- the presence of dispersants in the water or oil will result in a reduction of

interfacial tensions.

For water-flooding to be effective, it is important that the water displaces

the oil. The liquid which wets the rock surface occupies the space next to

the rock in the pores and the fine interstices, while the non-wetting liquid

occupies the interior of the pores.

2.1.8 Effective and Relative Permeabilities Quoting again from Perrodon (1966) : « In most sediments which are

usually wet firstly by water, oil cannot enter the pores filled with water

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

interface (Fig. 18).


Fig. 18. – Diagram strowing the progressive entry of oil in the pores of a sandstone under the

influence of increasing pressure P1<P2<P3 (from Hill at al.,)

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 rocks will be impermeable to the oil.

Thus the concept of impermeability appears to be wholly relative, that is, an

equivalent rock which is permeable to water and impermeable to oil, is

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

fluids is subjected to a pressure greater than the capillary forces ».

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

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

(water, oil, gas).We must then introduce the concepts of diphasic flow and

of relative permeability.

In fact, if the formation contains two or more fluids, their flows interfere and

when this occurs the effective permeability of each of the fluids (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

percentages of the various fluids present in the pores.


The relative permeabilities (krg, kro, krw) express the ratio of the effective

permeabilities to the absolute permeability. These permeabilities vary

between 0 and 1. They are generally expressed as percentages (%), for

example :

ko

kro = ----- k

The values of relative permeabilities vary with saturation.

The above figure shows the type of variation found in an oil-water system. It

shows that when the oil saturation increases, the relative permeability of

the oil increases while that of the water decreases.

This results in a strong inflow of oil and a weak inflow of water, which may

even cease when the minimum water saturation (Sw)min reached.

Conversely, when the water saturation increases, the relative permeability

of the oil decreases while that of the water increases and for a certain value

of this saturation there will only be an inflow of water.


2.1.9 Relationship Between Permeability and Saturation

Capillary forces result in the retention of bound water in the capillaries and

in the sharpest angles created by the piling up of grains. This interstitial

water is called irreducible water because it cannot be evacuated by the

forces acting upon the fluids which occupy the larger pores.

Thus hydrocarbon reservoirs show an irreducible water saturation (Sw)irr,

which is greater when the grain size is small and hence the permeability is

lower while the capillarity forces are stronges (Fig. 20).

Fig. 20. – Relationship between water saturation, permeability and capillary forces (from Wright and

Woody

2.1.10 Influence of Clay Content and Distribution on the Permeability of a Reservoir

Because the grain size of clay minerals is generally very small, the size of

the pores and of the channels linking them is also very small which results

in enormous capillary forces and very low permeabilities. Thus, any

presence of clay in a reservoir may have direct consequences on the


reservoir’s permeability. However, the distribution mode of the clay in the

reservoir rock must also be taken into account.

If the clay is of the structural type it will have little bearing on permeability

as long as it remains below a reasonable percentage (25 to 30 %).

If the clay is in thin layers, it will have a very important effect on the vertical

permeability but very little effect on the horizontal permeability of the

reservoir beds however narrow they are.

If the clay is dispersed through the porous space, even a small percentage

can have profound consequences on the permeability making it fall very

quickly in quite a spectacular fashion. But here again we must take into

account the type of clay mineral and its distribution in the pore space.

Large kaolinite crystals grouped in « books » (Fig. 21 a) will have much

less effect than an equivalent volume of chlorite or montmorillonite coating

the quartz grains (Fig. 21 b), and even less than an equivalent volume of

illite with crystal filaments creating bridges between the grains (Fig. 21 c).

Hence the importance of the type of distribution and the nature of the clay

in reservoir evaluation.


Fig. 21. – The three types of distribution of dispersed clay in the pores of a sandy reservoir (from

Neasham, 1977) Note: this figure is intended to illustrate the influence of the type of authigenic clay and the way in which it fills the pores on the permeability of a resevoir. 3 DRAINAGE AREA AND IN-PLACE RESERVE ESTIMATION

Data from a single well can be used to calculate reserves in place, but as previously

described, the reservoir engineer must have some idea of the area that a single well

could drain. A commonly used equation (API) for calculating barrels of oil in place is

BOIP = 7758 bbl/acre-ft x h (ft) x A (acres) ∅ x Sh

where

h = reservoir thickness (ft) A = drainage area (acres),


∅ = effective porosity (%), Sh = pore space portion filled with hydrocarbon (%)

Actual reservoir engineering work requires much more data. Permeability and reservoir

temperature and pressure are important considerations in determining productibility

behavior, accurate volumetrics, pressure maintenance procedures, etc.

The API gravity of crude oil, bubble point pressure, type of reservoir, etc. are all

important considerations. Some of this information is obtained with specialty log

measurements.

4 RESERVOIR CONTENT OF FLUIDS AND GAS Fluid (or gas) saturation is defined as the volume of fluid (or gas) divided by the volume

of pores in which the fluid (or gas) resides. Therefore total saturation is always 100 %.

So + Sg + Sw = 100 % where So = oil saturation (%) Sg = gas saturation (%) Sw = water saturation (%)

Depending on the existing conditions in any particular reservoir, the hydrocarbon

content may be in the form of oil, free gas, or both. (Air is also a gas). In reservoirs that

produce hydrocarbons, the water is generally a film coating on the rock surfaces within

pores, while the hydrocarbons occupy the center portions of the pore spaces.

A simplified sketch of the three phase in an oil and gas reservoir is illustrated in Fig. 22.


Fig. 22. – Simplified sketch of three phases in a petroleum bearing reservoir

For example, if a rock with total bulk volume of 50 cm3 was found to contain 3 cm3 of

water, 5 cm3 of oil, and 2 cm3 of free gas, then

Pore Volume = 3 + 5 + 2 = 10 cm3

therefore, ∅ = 10/50 = 20 %, Sw = 3/10 x 100 = 30 %, So = 5/10 x 100 = 50 %,

Sg = 2/10 x 100 = 20 %, 5 RESERVOIR GEOMETRY

5.1 Generalities :

The reservoir engineer must know the reservoir’s areal extent and shape in addition to

its thickness. Logs or core data from a single well cannot provide this information, but


the combined data from a number of wells allow inference of the outlying limits of the

reservoir.

Surface seismic data provide horizontal stratigraphic coverage, which is extremely

useful in determining the lateral reservoir extent and identifying lateral permeability

barriers.

Multi dimensional (2, 3 and 4 D) seismic information is even more valuable, but two or

more seismic lines in different directions can help in (2, 3 and 4 D) reservoir modelling.

When only well data are available to the engineer, the production geologist must

provide reasonably accurate cross sections, maps, and perhaps fence diagrams to

model the reservoir in 3 and 4 D (see Appendices). This requires data from a number

of wells that are not in a straight line and sufficient lateral coverage to estimate the

reservoir boundary limits and determine oil and gas traps structures.

The relationship between reservoir Geometry, sedimentology and tectonics, therefore,

is evident. This leads us to the concept of the « oil and gas trap ».

Oil and gas traps are classified following three main families :

- structural traps

- stratigraphic traps

- combination traps

OIL AND GAS TRAPS Fig. 25. – Legend and basic vocabulary

RESERVOIR ROCK

(Porous and permeable rock, usually sandstone, limestone, dolomite or fracturated rock

CAP ROCK

(Impermeable rock, usually shale, salt or micrite limestone

SALT

BASEMENT

(Igneous or methamorphic rock)

OIL

GAS

UNCONFORMITY

FAULT


5.2 Geometry of Oil and Gas Traps :

- Description and Plates -

5.2.1 Structural Traps 5.2.2 Stratigraphic Traps 5.2.3 Combination Traps


5.2.1 STRUCTURAL TRAPS

Formed by deformation of reservoir rock such as anticline or fault.

5.2.1.1 ANTICLINE

Anticlines are large, upward arches and were one of the first types of petroleum traps recognized. Anticlines are formed in areas of compression, can have multiple producing zones and can form giant fields.

5.2.1.2 NORMAL FAULT TRAP

Normal faults are caused by tensional forces. A trap is formed against the fault, where the normal fault cuts dipping rocks. The fault must be curved (as illustrated) or two faults must intersect to form sides to the trap.


5.2.1.3 BALDHEADED ANTICLINE

Baldheaded anticlines and structures produce from the flanks of the structure. The top is barren. When the anticline was originally uplifted, the potential reservoir rocks were eroded from the crest of the structure, leaving an unconformity.

5.2.1.4 RESERVE FAULT TRAP

Reserve faults are caused by compressional forces. The trap is formed by dipping rocks against the fault. The fault must be curved or two faults must intersect (as illustrated) to form sides to the trap.


5.2.1.5 FAULTED ANTICLINE

Faults, often caused by the original folding of the anticline, can sometimes form impermeable barriers and divide the structure into separate pools. Shale smeared along the fault plane can cause this.

5.2.1.6 TILTED FAULT BLOCKS

Tilted fault blocks are large blocks (often miles on a side) of sedimentary rocks that were broken and tilted by normal faulting. They are formed in areas of rifting, are now covered with sediments, and can form giant fields.


5.2.1.7 DOME

A dome is a circular or eliptical anticline. It is often formed by an underlying instrusion such as igneous rock or rising sedimentary rock (diapir) such as salt or shale.

5.2.1.8 DRAG FOLDS ON THRUST FAULT

Drag folds are formed by friction generated by movement along a fault. Thrust faults are low angle reverse faults that often occur in overthrust or disturbed belts. Drag folds form both above and below the thrust fault.


5.2.1.9 FRACTURED RESERVOIR

Fractures add porosity and greatly enhance reservoir rock permeability. Fine-grained sedimentary rocks such as shales and chalks have porosity but lack permeability, except where fractured. Fractures occur where the rock has been folded or moved along a fault.

5.2.1.10 ROLLOVER ANTICLINE ON GROWTH FAULT

Growth (Down to the Basin) faults occur in thick, unconsolidated sediments (coastal plains or deltas). Because the fault plane is curved, as the basin side of the fault moves down, a broad (rollover) anticline is formed on the basin (ocean) side.


5.2.1.11 ANTITHETIC OR SYNTHETIC FAULTS ON ROLLOVER ANTICLINE

Antithetic or synthetic faults are tensional faults that cut the rollover anticline as it forms. These faults often divide the rollover anticline into numerous, separate pools.

5.2.2 STRATIGRAPHIC TRAPS

Formed by deposition of reservoir rock such as reef or river channels or erosion of reservoir rock such as an angular unconformity

5.2.2.1 ANGULAR UNCONFORMITY

An angular unconformity is a buried erosional surface with dipping rock layers below it. The reservoir rock is located below the unconformity and the cap rock on top of it. Angular unconformity can form giant traps.


5.2.2.2 SHOESTRING SANDSTONE - CHANNEL

Shoestring sandstones are long, narrow sand bodies (channels or bars). Because they are often encased in shale, they are often filled with oil, without an oil-water contact. Channels form as abandoned river channels and distributary channels on constructive deltas.

5.2.2.3 BUTTRESS OR ONLAP SANDS

Buttress or onlap sands are beach sands that were deposited on an unconformity surface as sea level rose. Numerous buttress sands can occur along a single unconformity and each can form a pool.


5.2.2.4 SHOESTRING SANDSTONES - BAR

Bars forms as beaches, beaches on destructive deltas and offshore bars. They are usually different from channels in cross section (channel - ∪ , bar - ∩), orientation (channel at right angle, bar parallel to shoreline) and vertical sequence (channel - fining upward, barcoarsening upward).

5.2.2.5 BARRIER REEF

Barrier reefs are large reefs separated from land by a lagoon. Reef limestones in their original state of deposition good reservoir rock and lagoonal limestones are not. Porosity reversal due to later recrystallization, solution and dolomitization can reverse this condition. Barrier reefs can form giant fields.


5.2.2.6 UPDIP PINCH OUT OF SANDSTONE

An updid pinch or wedge out of a sandstone in shale forms a trap. These are common in coastal plains where updip is landward. They tend to be small traps. If uplift caused dip, the trap type is combination.

5.2.2.7 ATOLL

Atolls are large, circular or elliptical reefs with a central lagoon. In their original state of deposition the circular reef limestones are potential reservoir rock and the lagoonal micrite limestones are not. Porosity reversal can reverse this condition with time. Atolls can form giant fields.


5.2.2.8 OOLITE SHOALS

Oolites are sand-sized spheres of CaCO3 that precipitated out of shallow, tropical seas. Currents and waves wash the oolites into elongate mounds. An oolite shoal forms a small field but many shoals are often found parallel to each other.

5.2.2.9 PINNACLE OR PATCH REEFS

Pinnacle or Patch (table) reefs are small circular reefs. Pinnacle reefs are located on the basin side of a barrier reef and patch reefs in the lagoon. The reef forms a small field, but there are usually numerous reefs (and pools) in the trand.


5.2.2.10 GRANITE WASH

Granite wash is a sandstone formed by weathered granite basement rock. Granite is composed of coarse, sand-size crystals that weather to form a sandstone covering the flanks of buried granite mountains and hills. Source rocks occur deeper, along the flanks.

5.2.2.11 BIOHERM

Bioherms are mound or lens shaped deposits of biological limestone formed by organisms that grew there. This includes reefs built by framework organisms such as corals and also mounds built by nonframework organisms. They tend to form small, isolated fields.


5.2.2.12 PRIMARY OR SEDIMENTARY DOLOMITE

Primary or sedimentary dolomite is formed by alteration of limestones in the supratidal zone immediately after deposition and is often overlian by a salt layer. Fluctuating water levels can deposit numerous traps of this type along the flanks of the basin.

5.2.3 COMBINATION TRAPS

Formed by both structural and strategraphic element

5.2.3.1 SALT DOMES - OVERLYING DOMES AND FAULTS

A rising salt dome raises up the overlying sediments forming traps. As the uplifted sediments are cut by normal faults, fault traps are formed. These faults can separate the reservoir rocks into numerous pools.


5.2.3.2 SALT DOME - CAP ROCK

Salt is primarily halite that dissolves as the salt dome rises leaving insoluble minerals (anhydrite, gypsum, limestone, dolomite and sulfur) to form cap rock several hundred feet thick. Fractures and solution vugs make cap rock into reservoir rock.

5.2.3.3 SALT DOME - FLANK TRAPS

Along the flanks of salt domes, traps are formed by reservoir rocks dragged upward and pierced by the rising salt dome. Prolific traps are formed under salt overhangs. These traps tend to have thick pay zones due to high dips on reservoir rocks.


5.2.3.4 UPDIP FACIES CHANGE

The reservoir rock was deposited with a facies change, porous and permeable in one area and impermeable in another. Later uplift of the impermeable facies caused a trap along the flank of the structure. If dip was deposited, then the trap is stratagraphic.

5.2.3.5 COMPACTION ANTICLINE

Compaction anticlines form in sediments over buried hills and reefs. Sediments, because of their porosity, compact more than basement hills and limestone reefs. Sediments on the flanks of the buried structure are thicker and more compaction occurs there.


5.2.3.6 SECONDARY OR TECTONIC DOLOMITE

Secondary or Tectonic Dolomite is controlled by fractures in limestones. Waters percolating along the fractures turn the impermeable limestone into dolomite adjacent to the fractures. The field follows the orientation of the fractures.

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