Drilling Technology

Concepts of Petroleum Geology and Basic Rock Properties

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Petroleum is not found in underground lakes or rivers, but it exists within the void space of certain rocks. Unfortunately, these oil-bearing rocks are a definite minority, and the determination of their whereabouts is the basic problem confronting geologists and geophysicists.

The mechanism of the origin and accumulation of petroleum is not completely understood and is the subject of much controversy. However, a great deal has been learned about the habitat of oil and gas, i.e., the nature of the rocks in which they exist. In this chapter we will consider these problems by discussing the requirements for oil accumulations and the rock properties which are essential to these accumulations.

2.1 Requirements for Commercial Oil Accumulations

Certain requirements must be fulfilled for a commercial petroleum deposit to be present. These are

1. A source: material from which oil is formed.
2. Porous and permeable beds (reservoir rocks) in which the petroleum may migrate and accumulate after being formed.
3. A trap: subsurface condition restricting further movement of oil such that it may accumulate in commercial quantities.
4. 11 Source of Petroleum

A complete understanding of the origin of petroleum would be of great benefit to exploration operations, but unfortunately this has not yet been attained. Many theories on the origin of petroleum have been proposed and are normally classified into two general groups:

1. Inorganic theories — these are primarily of historical interest only and will not be discussed here.
2. Organic theories.

At the present time most authorities overwhelmingly favor the organic approach. Their principal reasons are the following:1

1. No inorganic theory can account for the necessary quantities of carbon and hydrogen needed to form large petroleum deposits. The abundance of plant and animal life present in sediments is a sufficient source.
2. Many crude oils contain porphyrins and nearly all contain nitrogen. The presence of these materials strongly suggests organic origin as they are present in all organic matter. Also, porphyrins of vegetable origin have been found to be more plentiful than those of animal origin.
3. Petroleum rotates the plane of polarized light. This property is restricted primarily to organic materials known as optical isomers and further suggests organic matter as the source of petroleum.

The complete process of alteration whereby organic materials are transformed into petroleum is not known. The main factor which prohibits complete laboratory verification of the theory is the inability to reproduce the million or so years during which the process occurs. The role of anerobic bacteria in promoting this alteration may be considerable, as suggested by ZoBell.2

The evidence from studies of thousands of oil fields has led most geologists to the following general conclusions:3

1. Petroleum originates from organic material, primarily vegetable, which has been altered by heat, bacterial action, pressure, and other agents over long periods of time.
2. Conditions favoring petroleum formation are found only in sedimentary rocks.

Spill point

Stage 1. Gas, oil, and water above spill point. Both oil and gas continue to be trapped while water is displaced. This stage ends when oil-water interface reaches spill point.

Water

Stage 2. Stage of selective entrapment and gas flushing. Gas continues to be trapped but oil is spilled up dip. This stage ends when oil-gas interface reaches spill point.

Stage 3. End stage. Trap filled with gas. Excess gas spills up dip as more gas enters trap. Oil bypasses trap and continues upward migration.

Fig. 2.1. Illustration of differential entrapment principle, showing various stages of hydrocarbon accumulation in an anticline. Solid and dashed arrows denote oil and gas movement respectively. After Gussow,4 courtesy AAPG.

Stage 3. End stage. Trap filled with gas. Excess gas spills up dip as more gas enters trap. Oil bypasses trap and continues upward migration.

1. 2.1. Illustration of differential entrapment principle, showing various stages of hydrocarbon accumulation in an anticline. Solid and dashed arrows denote oil and gas movement respectively. After Gussow,4 courtesy AAPG.
2. The principal sediments generally considered as probable source rocks are shales and limestones that were originally muds under saline water.
3. 12 Porous and Permeable Beds (Reservoir Rocks)

After its formation, petroleum may migrate from the source rock into porous and permeable beds where it accumulates and continues its migration until finally trapped. The forces causing this migration are

1. Compaction of sediments as depth of burial increases.
2. Diastrophism: crustal movements causing pressure differentials and consequent subsurface fluid movements.
3. Capillary forces causing oil to be expelled from fine pores by the preferential entry of water.
4. Gravity which promotes fluid segregation according to density differences.

Considerable differences of opinion exist as to the distance which petroleum may cover in its migration from source to trap. An interesting theory which logically explains some types of accumulation is that of Gussow4 which is illustrated by Figures 2.1 and 2.2.

It is certain, however, and universally agreed that if a petroleum deposit is to be of commercial significance, it must be found in a porous and permeable reservoir. The terms porous and permeable denote two distinct rock properties whose measurements and quantitative definitions have comprised much of the technical literature of the oil industry. Consequently, they must be defined and discussed in some detail.

Porosity

Porosity is a measure of the void space within a rock expressed as a fraction (or percentage) of the bulk volume of that rock.

Water

Trap 2

Water

Trap 3

Fig. 2.2. Final condition of differential entrapment in a series of interconnected traps. After Gussow,4 courtesy AAPG.

The general expression for porosity is where <f> = porosity

Vb = bulk volume of the rock

V, = net volume occupied by solids (also called grain volume)

Vv = pore volume = the difference between bulk and solid volumes

To illustrate this principle consider Figure 2.3 which shows various arrangements of packed spheres and their computed porosities.6 The bulk volume of each configuration is the figure formed by connecting the centers of eight adjacent spheres (the four shown in the front views and four behind them). Each bulk volume so formed contains one net sphere as the enclosed solid or grain volume. Note that the grain size (sphere diameter) is immaterial to the porosity value.

In actual rocks porosity is classified as

1. Absolute porosity: total porosity of a rock, regardless of whether or not the individual voids are connected, and
2. Effective porosity: only that porosity due to voids which are interconnected.

It is the effective porosity which is of interest to the oil industry, and all further discussion will pertain to this form. In most petroleum reservoir rocks the absolute and total effective porosity are, for practical purposes, the same. Actually, this restriction implies the property of permeability which will be discussed shortly.

Geologically, porosity has been classified in two types, according to the time of formation: 1. Primary porosity (intergranular): Porosity formed at the time the sediment was deposited. The voids

<W

• B) Hexagonal packing. Top row has been moved one radius to the right. 0 = 60° Vt = D2 • D sin 6
• 0.866D3 V, = ttz>76
• Z)3(0.866 - x/6) * 0.866Ds = 0.395 = 39.5%

Fig. 2.3. Three methods of packing spheres and the resultant porosities. Cubic packing (A) is the most porous and (C) rhom-bohedral packing the least porous arrangement possible.

contributing to this type are the spaces between individual grains of the sediment. 2. Secondary porosity: Voids formed after the sediment was deposited. The magnitude, shape, size, and interconnection of the voids bear no relation to the form of the original sedimentary particles.

Primary Porosity

The sedimentary rocks which typically exhibit primary porosity are the clastic (also called fragmental or detrital) rocks which are composed of erosional fragments from older beds. These are normally classified by grain size, although much looseness of terminology exists. The most widely used of these classifications is Wentworth's Scale.6 Typical clastic rocks which are common reservoir rocks are sandstones, conglomerates, and oolitic limestones.

Secondary Porosity

Porosity of this type has been subdivided into three classes based on the mechanism of formation. 1. Solution porosity: voids formed by the solution of the more soluble portions of the rock in percolating surface and subsurface waters containing carbonic and

(C) Rhombohedral packing. Top row has been moved to left and forward one radius as shown in front view 6 = 45° Vt = D2 • D sin 9 = D>/yj2 V. = W>7 6

(A) Cubic packing. Top row is directly above bottom row.

Fig. 2.4. Core samples of various producing formations. Courtesy Core Laboratories, Inc., Dallas, Texas. (A) Ellenburger dolomite, Triple "N" Field, Andrews County, Texas.

rf, = 20 2%,k = 850 md. for this sample. Excellent example of secondary porosity.

(B) Pennsylvanian reef, Dawson County, Texas. <*> = 5%, k = 186 md. Note the low porosity value despite presence of a few large voids. (C) Cardium conglomerate and sand, Pembina Field, Alberta. Conglomerate: * = 8.8% k = 3.0 md Sand. 0 -18 0% k = 9.0 md. Note that the sand is twice as porous as the conglomerate which illustrates the effect of grain size uniformity.

Fig. 2.4. Core samples of various producing formations. Courtesy Core Laboratories, Inc., Dallas, Texas. (A) Ellenburger dolomite, Triple "N" Field, Andrews County, Texas.

rf, = 20 2%,k = 850 md. for this sample. Excellent example of secondary porosity.

(B) Pennsylvanian reef, Dawson County, Texas. <*> = 5%, k = 186 md. Note the low porosity value despite presence of a few large voids. (C) Cardium conglomerate and sand, Pembina Field, Alberta. Conglomerate: * = 8.8% k = 3.0 md Sand. 0 -18 0% k = 9.0 md. Note that the sand is twice as porous as the conglomerate which illustrates the effect of grain size uniformity.

other organic acids. This is also called vugular porosity and the individual holes are called vugs. Unconformities in sedimentary rocks are excellent targets for zones of solution porosity. Voids of this origin may range from small vugs to cavernous .openings. An extreme example is Carlsbad Cavern.

1. Fractures, fissures, and joints: voids of this type are common in many sedimentary rocks and are formed by structural failure of the rock under loads caused by various forms of diastrophism such as folding and faulting. This form of porosity is extremely hard to evaluate quantitatively due to its irregularity.
2. Dolomitization: This is the process by which limestone (CaC03) is transformed into dolomite CaMg (C03)2. The chemical reaction explaining this change is:

It has long been observed that dolomite is normally more porous than limestone. This is the reverse of what might normally be expected since dolomite is less soluble than calcite. The best explanation of this seems to be that of Hohlt7 who has shown that under pressure calcite crystals tend to orient their "C" axes in the plane of bedding while dolomite crystals are always in a random packing. Conse quently, ground waters more readily percolate through dolomite, which has more and larger inter-crystalline voids, and attack more rock surface. Porosity formed by dolomitization is then due to solution effects enhanced by a previous chemical change in limestone. It should be realized that primary and secondary porosity often occur in the same reservoir rock. Figure 2.4 shows actual examples of various porosity forms.

Typical Porosity Magnitude

A typical value of porosity for a clean, consolidated, and reasonably uniform sand is 20%. The carbonate rocks (limestone and dolomite) normally exhibit lower values with a rough average near 6 to 8%. These values are approximate and certainly will not fit all situations. The principal factors which complicate intergranular porosity magnitudes are

1. Uniformity of grain size: The presence of small particles such as clay, silt, etc. which may fit in the voids between larger grains greatly reduces the porosity. Such rocks are called dirty or shaly.
2. Degree of cementation: Cementing material deposited around grain junctions reduces porosity.
3. Packing: This effect is illustrated in the systems of spheres of Figure 2.3. Geologically young rocks are often packed in an inefficient manner and are as a result highly porous. 4. Particle shape.

There are a number of references available which have compiled considerable porosity data for various formations.8'9

Quantitative Use of Porosity Data

The subject of how porosity measurements are performed will be discussed in a later chapter on core analysis. For the present, it will be assumed that such measurements have been made and that the porosity is known. As defined previously, porosity is a measure of the void space within a rock, and as such may be used to determine the quantity of fluid which may be stored within that rock.

Consider a bulk volume of rock with a surface area of one acre and a thickness of one foot. This constitutes the basic rock volume measurement used in oil field calculations, an acre-foot. It is also standard practice to express all liquid volumes in terms of barrels. The following conversion factors are useful:

5.61

7758 bbl

It is then obvious that the pore space within a rock is equal to 7758 X = Vp (bbl/acre-ft) where 4> = porosity of the rock in question. Further reasoning as shown by Figure 2.5 results in the well-known Volumetric Equation of Oil in Place:

B0 B0

where N = tank oil in place, bbl/acre-ft

So = fraction of pore space occupied by oil (the oil saturation)

Sw = the water saturation

B0 = the formation volume factor for the oil at the reservoir pressure, barrels reservoir space/barrel tank oil.

Determining the proper values of Sw in Eq. (2.2) is considerably more difficult than obtaining <f>. For the present, let it suffice to say that some water will always exist within the reservoir rock and that its volume must be subtracted from the space available for oil. This water is commonly called the connate water and is assumed incompressible in this equation. Note also that the pore space is assumed to be occupied by either oil or water, and that no free gas is present. Consequently, the equation as given must be applied to the f v.

NBo -Oil volume = 7758$%^ = 7758¿(I - S„)

• Water volume • : =7758*Sw :
• Water volume • : =7758*Sw :

Vp = 7758* barrels

Apparent relationships

• 1) So = Ii
• V
• 2)

(4) N — 7758 <t> (1 — SJ) barrels/acre-ft.

Fig. 2.5. Concepts of volumetric equation.

reservoir at or above the bubble point, and is generally used to compute the initial oil in place.

A similar expression may be derived for the amount of gas stored in a particular sand. In this case it is convenient to express the gas volume in terms of SCF or in MCF (thousands of standard cubic feet). Recall the form of the Gas Law

Ts pVr zT

where subscript, s, denotes standard conditions. zs = 1.0, and is not shown. Then:

zTps where G is the standard gas volume contained in Vp at conditions p, T, z.

But: Vp = 43,560<^(1 - S„) cu ft/acre-ft T, = 460° + 60° = 520°R p, = 14.7 psia

Substitution of these values in (2.4) gives:

0 0