I. Introduction

Reservoirs are the porous and permeable rocks that contain commercial deposits of hydrocarbons.

Porosity and permeability are the most important physical properties of these reservoirs, so we'll quickly discuss ways of describing these attributes, and how they may be modified by diagenetic changes.


Next we'll talk about their size and lateral and vertical continuity, which will be important for calculations of oil and gas reserves

II. Porosity

A. Definition

Porosity is the opening in a rock. Strictly speaking it is a ratio:

• Often multiplied by 100 to be expressed as a percentage.
  
• symbol is the greek letter phi f
  
  

B. Morphological classification

There are three types of morphologies to the pore spaces:

(1) Caternary- where the pore opens to more than one throat passage


(2) Cul-de-sac- where the pore opens to only one throat passage


(3) Closed pore- where there is no connection with other pores

Morphological types (1) and (2) are called effective porosity because they allow hydrocarbons to move into and out of them. Morphological type (3) is ineffective porosity becaues no HC can move in or out.

Caternary pore are the best type for a HC reservoir because the HC in the reservoir can be flushed from rocks (e.g. secondary and tertiary recovery through water/gas flooding).


Cul-de sac pores cannot be flushed, but they can produce HC by release of pressure, e.g. gas expansion.


Closed pores cannot produce any type of HC. Thus it is very important (and also very difficult) to determine the ratio of effective to total porosity. Total porosity is fairly easy to measure, but may not tell much about the amount of HC that can be produced.

C. Porosity measurements

Can be measured using three techniques:

(1) Well logs- one of the primary uses of well logs. Often map out subsurface trends of porous lithologies as a play strategy. Different types of logs can be used for porosity measurements depending on lithology (Sonic, Neutron, and Density)


(2) Seismics- through change in acoustic impedence (v*r). density decreases with increasing porosity


(3) Direct measurments of cores- Generally involves filling pore space with gas, measuring the volume of the gas, and independently measuring the volume of the rock and porosity.

D. Genetic classification of porosity

Standard sedimentologic description of porosity:

Primary- formed when sediment deposited. Two types:

(1) interparticle. Lost quickly in muds and carbonate sands through compaction and cementation respectively. Retained and common in siliciclastic sands.


(2) intra particle. Interiors of carbonate skeletal grains.

Secondary- formed after deposition.

(1) dissolution- typical of carbonate reservoirs


(2) fracture porosity- typically not voluminous, but are very important becuase they can enhance permeability (e.g. open closed pores).


• Fractures can be identified on well logs, seismics, and production statistics, although all identifications are open to interpretation.
  
• Fractures are often tectonic related: (1) folds, (2) faults. Also may occur through hydrofracturing where pore fluid pressures are greater than lithostatic.
  
• Fractures can create reservoirs out of otherwise impermeable rocks such as basement rocks, or extremely tight sedimentary formations (e.g. Bredehoeft article, also the Monterey Fm).
  
  

III. Permeability

A. Hydraulic conductivity:

Permeability is a measure of the ability of fluids to pass through a porous medium. This is a more difficult variable to measure in reservoir rocks, but in many ways may be more important than porosity.

Definition, From Darcy's experiment.

Darcy flowed water through sand filled tube and found that the flow rate. Fig. 4.12 Fetter

Darcy showed that discharge, Q, is proportional to the difference in the height of water, H, and inversely proportional to the length of the tube, L:

Discharge is also proportional to the cross sectional area of the pipe, A. In order to make the proportionalities equal, there has to be a proportionality constant, called Kc:

or for infintesimally small segments of the pipe (e.g. calculus):

The deriviative, dh/dl, is called the hydraulic gradient, and the negative sign indicates that the direction of flow is in the direction of decreasing hydraulic gradient.

The proportionality constant, Kc, is called the hydraulic conductivity or coefficient of permeability. It has units of velocity, or L/T.

B. Intrinsic Permeability

(1) Fluid variables: The hydraulic conductivity is contolled only by the reservoir parameters, but there clearly are controls by the properties of the fluids, specifically its viscosity, µ and its specific weight, g

Viscosity is a measure of the resistance of a fluid to flow- i.e. how much shear force is required to cause the fluid to start to move and continue moving. There is an inverse relationship between viscosity and discharge:

Specific weight is the force of gravity on a unit volume of fluid- i.e. the force that drives fluids. Discharge is directly proportional to specific weight:

(2) Other reservoir variables: Empirical evidence shows that discharge is also proportional to the square of the diameter of the grains that make up the reservoir:

All of these proportionalities allows a different version of Darcy's law to be written, with a new proportionality constant, C:

Now can introduce a new variable, called intrinsic permeability, K, which represents a propoerty of the porous reservoir only, specifically the size of the pore openings. The relationship between the intrinsic permeability and the hydraulic conductivity is:

Intrinsic permeability has units of length squared (L2) or area. It is essentially a measure of the surface area of the grains in a porous medium. The correct (ie SI) units are meter squared (m2). It common unit in petroleum engineering is the darcy which is defined as:

Most petroleum reservoirs have permeabilities less than 1 Darcy, so they are reported as millidarcy (md).

C. Measuring permeability

Although permeability is one of themore important aspects of a reservoir, it is difficult to measure. Can be measured in drill holes with Drill Stem Tests (DST) or estimated with log response. Also can be measured directly on core samples with Permeameters.

(1) Drill stem tests

• The section of a drill hole is sealed off from the surface using inflatable rubber rings called Packers. The section can be in open hole or in perforated cased holes. The section can be at the bottom of the hole, requiring only one packer, or it can be in the upper hole, requiring two packers (this way is more likely to fail).
  
• Once the section of the hole is sealed, it is opened to atmospheric pressure, and fluid is allowed to flow into the pipe. The pressure and rate of flow are measured at the beginning and end of the tests, and samples of the fluid are recovered. All variables for permeability calculations are known.
  
• Important also to identify if oil, water, or gas is present in the formation (also remember mud logging).
  
  

(2) Wire line logs- More details later, but in general, the technique relies on changes in log response as a result of infiltration of the drilling fluid. These are not quantitative measurements of permeability.

(3) Permeameters- direct measurements of permeability

• Devices that hold samples of material to be measured. They can be rocks, or unconsolidated sediment.
  
• They all have the same mode of operation- they force fluid through the sample and the discharge is measured, form which permeability is calculated.
  
  

D. Interpretation of permeability

Darcy's law is commonly used to describe flow in the subsurface. But there are many qualifications to its use. It is formulated for very specific cases. Also direct measurements of permeability can be difficult:

(1) There can be no chemical reactions between rocks and fluids (e.g. no hydrocarbon generation, cementation, dissolution)


(2) Darcy's law only applies to porous flow, with uniform porosity. Dual porosity systems, such as vugs, fractures etc are not modelled by darcy's law.


(3) Direct measurement of permeability can be difficult because of contamination of cores from the drilling mud.


(4) Permeability is rarely uniform within a reservoir, and often is different in vertical and horizontal directions. Often is controlled by bedding.


(5) Only one phase fluid can fill the reservoir to use Darcy's law. For hydrocarbon provinces, this is almost never the case- there is commonly water, gas, and liquid HC.

This last problem relates to the distinctly non-linear behavior between different fluids in the reservoir and leads to ideas of relative permeability, wettability, and capillary pressure. These concepts are very important because they ultimately control the amount of HC that can be produced from the reservoir.

(1) Relative permeability

The ratio of the effective permeability to the total permeability of the rock. The effective permeability is the permeability of one of the phases at some saturations.

e.g. see Fig. 6.13.

(2) Wettability

Look at Fig. 6.14

Wettability is describes the relative adhesion of two fluids to a solid surface. It is a measure of the tendency of one of the fluids to spread over the surface of the solid phase in preference to the other fluid.

Wettability is controlled by the particularly minerals exposed to the fluids, chemical constituents in the fluids and the saturation history of the samples.

There are different degrees of wettability:

a) Water wet reservoir: Water will fill the small pores and spread over the surface of the grains. When additional water is added to the system, the reservoir will take up the water, displacing HC.


b) Oil wet reservoir: Oil fills the smaller pores and coats the grains. Thus the reservoir will take up oil, but not additional water.


c) Other wettability terms:


• Neutral wetatability- when a reservoir has equal amounts of water and oil coating the surface of the grains
  
• fractional wettability- whendifferent portions of the reservoir water and oil wet to different extents.
  
• mixed wettability- smaller pores are occupied by water, and the larger pores are occupied by oil.
  
  
  

Wettability is very important for all types of fluid-solid interactions: capillary pressure, relative permeability, electrical properties, irreducible water saturation, residual oil and water saturation. Wettability can be difficult to analyze in cores because its characteristics can change during drilling and core-handling.

(3) Capillary pressure- Capillary pressure results from molecular attraction of liquids and solid surfaces. The phenomenon results in movement of liquids up capillary tubes. It also controls the convexity of two fluids.

(1) Oil wet systems, the oil surface is concave relative to the water, i.e. the oil is attracted to the solid surfaces


(2) water wet systems, the water surface is concave relative to the oil.

See fig. 6.17

Capillary pressure can be measured on reservoir rocks. This is an important parameter of these rocks for two reasons: (1) the reservoir was originally saturated with water, and the oil had to get into the pores somehow, and (2) the oil has to be gotten out, and its capillarity controls the pressure required to get it out and ultimately, how much can be removed.

Test involves taking a plug of the sample and injecting it with some fluid (water, mercury, oil). The presure at which the fluid invades the reservoir is called the displacement pressure. The saturation at which no more water can be put into the reservoir is called the irreducible water saturation.

There can be different qualities of reservoirs, depending on the pressures required to move the fluids.

See Fig. 6.18

IV. Relationship between porosity, permeability, and texture

Texture is a description of the shape, size, sorting and fabric of sedimentary rocks. All of these variable influence porosity and permeability, although there are no clear correlations between the variables.

There is little theory, and empirical evidence in equivocal.

(1) Grain shape- porosity ( and possibly permeability) may decrease with sphericity and rounded grains.

(2) Grain size-

Porosity is theoretically independent of grain size, but there is a general empirical correlation between porosity and permeability. May be caused by increased cementation or because of poorer sorting.

Permeability decreases with decreasing grain size because pore throats are smaller and the capillary pressure goes up.

(3) Packing- Porosity (and permeability) will decrease with tighter packing. Most reservoirs are buried and altered, so packing is generally not an issue- the rocks are already packed.

(4) Deposition process- no clear relationship, too many other variables

(5) Grain orientation- controlled primarily by layering in the beds.

V. Diagenesis

The changes to reservoirs that occur following deposition are probably more important than any primary depositional texture, except perhaps sorting. Clearly diagenesis in sandstones differs from diagenesis is carbonates.

A. Sandstones

(1) Porosity in sandstones decreases with depth, like all other sediments. The rate at which it decreases depends on the type of sandstone

(a) mature sands retaining porosity longer than immature sands.


(b) poorly sorted sands (with clay minerals) will compact faster than well sorted sands.

(2) Other factors effecting porosity gradients are the in situ P and T:

(a) higher geothermal gradient cause faster diagenetic reactions, thus faster cementation


(b) abnormal pressure gradients may preserve porosity by reducing compaction.

(3) Hydrocarbons can preserve porosity- they prevent circulation of water, thereby stopping cementation.

Causes of changes in porosity include cementation and dissolution:

(1) cemention- Primary cements include quartz, calcite, and clays.

(a) Quartz and calcite have different geochemistry. Qtz solubility increases with increasing pH, calcite solubility increases with decreasing pH.

(b) Clay cements:

Clays are very important to revervoir quality. Complex mineralogy, but 3 basic types: Kaolin, illite, montmorillonite (smectite). They each alter reservoir quality depending on their habit.

(1) Kaolin generally has a blocky habit, so it can reduce porosity of reservoir, but not greatly the permeability.


(2) Illite- fibrous habit, and so can greatly reduce permeability


(3) Smectite clays- these are clays with interlayer water- swell clays. They can increase in size with coming into contact with water (such as drilling mud). When they swell, the greatly reduce permeability. Must know reservoir characteristics for production- e.g. wouldn't want to water flood a reservoir that contains smectite clays.

(2) Dissolution

Dissolution of mineral grains or cements can enhance porosity.

(3) Diagenesis in relation to migration

Because HC prevent alteration of reservoir rocks, it is important to know the timing of migration relative to cementation. There can be cementation of reservoir rocks after migration of hydrocarbons into traps that seals them off. Several problems/effects:

(1) prevent further migration of HC.

(2) reduce water drive of reservoirs.

(3) It can change the shape of reservoirs if they are tectonically tilted.

B. Carbonates

Much of the generalities of sandstone reservoirs can also be applied to carbonate reservoirs. For carbonate reservoirs, their depositional environment can play a very big role in their quality

(1) Reefs

Reefs typically have very high porosities after deposition because they are generally cemented in place.

Reefs are also subject to shallow burial diagenesis because they commonly are near sealevel, and the movement up and down of sealevel can cause cementation.

Deeper burial of cementation also will occlude porosity.

It is important for preservation of reefs that HC migrate into the pore spaces early in order to preserve the porosity.

(2) Carbonate sands

Carbonate sands have high initial porosity, but the lose the porosity quickly by compaction and cementation with burial.

The earlier the cementation, the better the reservoir, because the sands don't lose porosity by compaction.

(3) Carbonate muds

These deposits are commonly aragonite, which is metastable at earth surface T and P. Its recrystallization to calcite commonly destroys porosity.

Some deposits of carboante muds are calcite- these are called chalk, and are typically composed of the tests of coccolithifers. They can have very high porosities that are preserved with depth of burial. They also tend to have very low permeabilities because of their small size. When they are fractured, they can make good reservoirs. e.g. the Austin Chalk of Texas. Very low production rates, but very long lived wells.

(4) Dolomite

Dolomites often form good reservoirs. The common dogma is that it is because Mg is 13% smaller than Ca, so that during dolomitization, there is a total decrease in volume of the material by 13%, thereby generating 13% porosity.

A similar argument is made for the conversion of aragonite to calcite, ony now it is the opposite direction and there is not an exchange of elements, only of structure.

Enhancement or destruction of porosity during conversion from one mineral to another is unlikely to relate to the mineralogical differences between the minerals. It is more likely to be dissolution or precipitation phenomenon.

C. Other types of reservoirs.

These type of reservoirs account for around 10% of the world's production. The remaining 90% is in sandstones and carbonates. Two major processes can create porosity and permeability of other types of rocks:

(1) dissolution

This is a fairly typical way to generate reservoirs. Largely from dissoltuion of feldspars in granites- called granite wash. This is what the Hugoton field produces from.

(2) Fracturing

Can generate porosity and permeability in otherwise tight rocks. Fractures commonly vertical, so deveated wells can be useful for drilling these types of reservoirs.

VI. Reservoir Continuity

The most important aspect of a reservoir is its dimensions, vertical and horizontal. Much of development geologists jobs involve mapping in the subsurface the dimensions of reservoirs (Contour isopach maps).

Horizontal dimensions are controlled by the depositional environment of the reservoir: e.g. barrier island, point bars, reef, sand dunes, diagnesis

Vertical dimensions are divided into gross pay and net pay.

Gross pay: The total thickness from the top of the reservoir to the oil/water interface.


Net pay: The total thickness from which the HC can be produced.

The difference between the two is controlled by the porosity distribution within the reservoir. In other words, reservoirs are not continuous- there continuity can be disrupted by barriers to porosity/permeability caused by variations in depositions, subsequent diagenesis or by structures

A. Depositional barriers (sandstones)

Depositional barriers are a result of the shape that reservoir bodies are deposited. These are usually discussed in terms of sandstones, and the sandstones generally have horizontal distributions that are the same as when they were deposited.

There are psuedo-statistical descriptions of the sands:


(1) Horizontal dimensions: Based on their length to width ratios. Given names based on the value of the ratios: Sheet, Pod, Ribbon etc, See fig. 6.39 for the diagrams


(2) Lateral dimesions: often describe on the basis of the thickness and continuity of sandstones. Also can be described on the basis of the continuity of the shales. This is very important for determining the best way to produce the field- i.e. exactly where to drill production and flood wells. see Fig. 6.40, 6.41, 6.42

B. Diagenetic Barriers (carbonates)

• These are largely cemented regions within carbonate reservoirs. They may be zones of mixed waters that allow carbonate precipitation, or oil water contacts.
  
  

C. Structural barriers (faults)

• Faults can be open and permeable for fluids- in this case they may connect reservoir and source beds.
  
• Faults can also be impermeable and thus act as a seal and/or trap for a reservoir.
  
• Wether the fault is permeable or impermeable depends on may factors: physical properties of rocks, fluid pressure, juxtaposition of sands and shales.
  
  

D. Reservoir characterization:

• Once the barriers have been defined, the next tack is to construct maps of the reservoir that show as much detail as possible.
  
• Details include, porosity distribution (barriers) and permeability distributions. Information for this comes from a variety of sources: well logs, cores, seismics, production tests, DST's, outcrop information etc.
  
• It is all of this information that goes into the reserve calculations:
  
  

VII. Reserve calculations

These calculations are usually done by a reservoir engineer (if there is one in the company you work for). Small companies may not have engineers, and it is up to the geologist to make these calculations. They are simple and fun.

A. Preliminary volumetric reserve calculations:

• These are the kind of calculations you would go through if you wished to "join" in the drilling or a well, or if you were planning to bid on acreage. Essentially a way to evaluate the value of particular area:
  
• The technique is to map out the area of the reservoir, contour its thickness and sum up the thicknesses. Then two fudge factors have to be applied:
  
• Estimated porosity of the reservoir
  
• Recovery factor- depends on drive mechanism, viscosity of oil, permeability, well spacing. Recovery factors can range up to 30% or more for sandstones, most carbonate reservoirs, it will be in the 10 to 20% range.
  
  

B. Postdiscovery reserve calculations

Once accurate resevoir data are know, it is possible to make better calculations. This is often done during "unitization" of a field, a process where all owners pool their interest and divide up the recoverable oil. The recoverable oil is calculated according to a formula:

• the value 7758 converts from acre-feet to bbls
  
• V = volume of reservoir in acre-feet
• f = porosity
• Sw = water saturation
• R = recovery factor- this can only be estimated, but may be accurate if enough history of surrounding wells is known
• FVF = formation volume factor
  
  

The FVF is a scaling factor that converts the volume of oil at T and P or the reservoir to the T and P of the surface, as well as extracts the volume taken up by reservoir gas. it is genreally a number between 1.1 and 2, but since it is in the denominator it reduces the ultimate recovery.

(1) it can be calculated on the basis of the Gas-Oil ratio


(2) it can be determined in the laboratory

Note that as the field is produced, the composition of the fluids can change considerably. The primary changes are that the oil/water contact will move up, and a gas cap may form on the top of the oil layer. See Fig. 6.50

VIII. Production Methods

The type of driving mechanism that allows HC to flow to the surface is usually the concern of the petroleum engineer. But it is important for a petroleum geologist to be aware of the different kinds of driving mechanism. Three main types: water drive, gas drive, and dissolved gas drive:

A. Water drive

In this case, the pressure in the reservoir is hydrostatic. The pressure depends on the recharge at the earth's surface.

In this case, oil water contact may rise as the reservoir is produced. The oil water contact in most cases will not rise evenly- controlled by permeability- this will cause fingering of water into the more permeable layers. Also, the water may cone up into the wellbore if the well is produced too fast

Production history: As these reservoirs are produced, reservoir pressure drops inversely with the recharge of the aquifer. There is little change in gas/oil ratio (GOR). The amount of fluid produced generally remains constant, but the water/oil ratio increases. See fig. 6.54

B. Gas Cap Drive

In this case, the reservoir contains a gas cap- freee gas sitting on top of oil. During production, the pressure in the reservoir decreases, and causes the gas to come out of solution of the oil. Thus, free gas fills the voids that are left by the produced oil.

Production history: Pressure and oil production decrease steadily during production, but the GOR increases. See Fig. 6.56

C. Dissolved Gas Drive

In this case, there is sufficient gas in solution to keep pressure of the reservoir high. The expantion of as it comes out of solution keeps the pressure high. If the pressure drops low enough, free gas cap will form. This is called the critical gas saturation. At this point, pressure decreases quite a lot, and production drops off. See fig. 6.58

D. Artificial Lift and Enhanced Recovery

(1) If original pressure is sufficient, hydrocarbons will flow to the surface on their pressure alone. In all cases, after a certain amount of production, the pressure decreases enough that punps have to be installed.

(2) Eventually, the pressure is reduced so that pumps cannot lift the Hydrocarbons. In this case, secondary and tertiary production techniques are started

All of these procedures are designed to keep reservoir pressure high. They generally involve injection various types of fluids into the reservoir. Some of the types of fluids include:

gases- e.g. hydrocarbon gases from the field or nearby fields, or inert other gases such as nitrogen or carbon dioxide

water- this is probably the most common type of secondary recovery, so these type of operations are often called water floods. The water that is injected has to have a very specific chemistry because water that is different from the formation fluids may adverse effects on the formation- e.g. precipiate salts or cause clays to swell.

detergents (foams) can be injected that emulsify heavy oils, or can make the water more dense so that it will move more hydrocarbons.