Basic Log Interpretation

Introduction to Log Interpretation


© Schlumberger 1999

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Log Interpretation Interpretation is defined as the action of explaining the meaning of something. Log Interpretation is the explanation of logs ρb, GR, Resistivity, etc. in terms of well and reservoir parameters, zones, porosity, oil saturation, etc. Log interpretation can provide answers to questions on:

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Why Run Logs

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The Reservoir

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Requirements of a reservoir

To form a reservoir needs - source of organic material (terrestrial or marine) - a suitable combination of heat, pressure and time - an oxygen free environment - a suitable basin

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Reservoir Geometry

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A


Reservoir elements

The major elements of a reservoir are • permeable rock

stores the hydrocarbon

• source rock

produces hydrocarbon

• impermeable rock traps hydrocarbon • trap

captures fluids

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Reservoir Rocks

Reservoir Rocks


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Reservoir Rocks

The Earth

pl

as

tic

Crust 10 miles

plastic

liquid solid Inner Core

Core

750 miles 1400 miles ρ = 10.7 g/cc

Mantle 1800 miles ρ = 4.0 g/cc

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Reservoir Rocks

The Earth 2

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Reservoir Rocks

Plate Tectonics 1

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Reservoir Rocks

Compressional Features

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Reservoir Rocks

Tensional Features

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Reservoir Rocks

Ocean plate - Ocean Plate

Trench Mountains

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Reservoir Rocks

Ocean plate - Continental plate

Mid Ocean Ridge

Trench

Mountains

Ocean plate

Magma

Magma

Continental plate

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Reservoir Rocks

Continental - Continental

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Reservoir Rocks

Plates

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Reservoir Rocks

Rocks General There are three major classes of rock: Igneous: (e.g. Granite). Sedimentary: (e.g. Sandstone). Metamorphic: (e.g. Marble).

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Reservoir Rocks

Igneous Rocks Comprise 95% of the Earth's crust. Originated from the solidification of molten material from deep inside the Earth. There are two types: Volcanic - glassy in texture due to fast cooling. Plutonic - slow-cooling, crystalline rocks.

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Reservoir Rocks

Igneous Rocks and Reservoirs Igneous rocks can be part of reservoirs. Fractured granites form reservoirs in some parts of the world. Volcanic tuffs are mixed with sand in some reservoirs.

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Reservoir Rocks

Metamorphic Rocks 2) Metamorphic rocks formed by the action of temperature and/or pressure on sedimentary or igneous rocks. Examples are Marble -

formed from limestone

Hornfels -

from shale or tuff

Gneiss -

similar to granite but formed by metamorphosis

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Reservoir Rocks

Sedimentary Rocks The third category is Sedimentary rocks. These are the most important for the oil industry as it contains most of the source rocks and cap rocks and virtually all reservoirs. Sedimentary rocks come from the debris of older rocks and are split into two categories Clastic and Non-clastic. Clastic rocks - formed from the materials of older rocks by the actions of erosion, transportation and deposition. Non-clastic rocks from chemical or biological origin and then deposition. 15 15

Reservoir Rocks

Depositional Environments The depositional environment can be Shallow or deep water. Marine (sea) and lake or continental. This environment determines many of the reservoir characteristics

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Reservoir Rocks

Depositional Environments 2 Continental deposits are usually dunes. A shallow marines environment has a lot of turbulence hence varied grain sizes. It can also have carbonate and evaporite formation. A deep marine environment produces fine sediments.

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Reservoir Rocks

Depositional Environments 3 The depositional characteristics of the rocks lead to some of their properties and that of the reservoir itself. The reservoir rock type clastic or non-clastic. The type of porosity (especially in carbonates) is determined by the environment plus subsequent events. The structure of a reservoir can also be determined by deposition; a river, a delta, a reef and so on. This can also lead to permeability and producibility. of these properties are often changed by further events.

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Reservoir Rocks

Depositional Environment 4 The environment is not static. Folding and faulting change the structure. Dissolution and fracturing can change the permeability.

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Reservoir Rocks

Sedimentation Sediments settle to the bottom of the sedimentary basin.

As the sediments accumulate the temperature and pressure increase expelling water from the sediments.

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Reservoir Rocks

Sedimentation 2 Sedimentary muds become sedimentary rocks. Calcareous muds become limestone. Sands become sandstone. Another effect involves both the grains in the matrix and the fluids reacting to create new minerals changing the matrix and porosity. Fluids can also change creating a new set of minerals.

This whole process is called Diagenesis.

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Reservoir Rocks

Rock Cycle

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Reservoir Rocks

Clastic Rocks Clastic rocks are sands, silts and shales. The difference is in the size of the grains.

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Reservoir Rocks

Depositional Environment - Delta Sediments are transported to the basins by rivers. A common depositional environment is the delta where the river empties into the sea. A good example of this is the Mississippi.

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Reservoir Rocks

Rivers

Some types of deposition occur in rivers and sand bars. The river forms a channel where sands are deposited in layers. Rivers carry sediment down from the mountains which is then deposited in the river bed and on the flood plains at either side. Changes in the environment can cause these sands to be overlain with a shale, trapping the reservoir rock. 25 25

Reservoir Rocks

Carbonates Carbonates form a large proportion of all sedimentary rocks.

They consist of: Limestone. Dolomite.

Carbonates usually have an irregular structure.

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Reservoir Rocks

Carbonate types Chalk is a special form of limestone and is formed from the skeletons of small creatures (cocoliths). Dolomite is formed by the replacement of some of thecalcium by a lesser volume of magnesium in limestone by magnesium. Magnesium is smaller than calcium, hence the matrix becomes smaller and more porosity is created. Limestone

CaCO3

Dolomite

CaMg(CO3)2

Evaporites such as Salt (NaCl) and Anhydrite (CaSO4) can also form in these environments.

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Reservoir Rocks

Depositional Environment Carbonates

Carbonates are formed in shallow seas containing features such as: Reefs. Lagoons. Shore-bars. 28 28

Reservoir Rocks

Rock Properties Rocks are described by three properties: Porosity -

quantity of pore space

Permeability - ability of a formation to flow Matrix -

major constituent of the rock

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Reservoir Rocks

Definition of Porosity

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Reservoir Rocks

Porosity Sandstones The porosity of a sandstone depends on the packing arrangement of its grains. The system can be examined using spheres. In a Rhombohedral packing, the pore space accounts for 26% of the total volume.

With a Cubic packing arrangement, the pore space fills 47% of the total volume.

In practice, the theoretical value is rarely reached because: a) the grains are not perfectly round, and b) the grains are not of uniform size. 31 31

Reservoir Rocks

Porosity and Grain Size A rock can be made up of small grains or large grains but have the same porosity. Porosity depends on grain packing, not the grain size.

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Reservoir Rocks

Diagenesis The environment can also involve subsequent alterations of the rock such as: Chemical changes. Diagenesis is the chemical alteration of a rock after burial. An example is the replacement of some of the calcium atoms in limestone by magnesium to form dolomite.

Mechanical changes - fracturing in a tectonically-active region.

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Reservoir Rocks

Carbonate Porosity Types 1 Carbonate porosity is very heterogeneous. It is classified into a number of types: Interparticle porosity: Each grain is separated, giving a similar pore space arrangement as sandstone. Intergranular porosity: Pore space is created inside the individual grains which are interconnected. Intercrystalline porosity: Produced by spaces between carbonate crystals. Mouldic porosity: Pores created by the dissolution of shells, etc.

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Reservoir Rocks

Carbonate Porosity Types 2 Fracture porosity: Pore spacing created by the cracking of the rock fabric.

Channel porosity: Similar to fracture porosity but larger.

Vuggy porosity: Created by the dissolution of fragments, but unconnected. 35 35

Reservoir Rocks

Carbonate Porosity Intergranular porosity is called "primary porosity".

Porosity created after deposition is called "secondary porosity".

The latter is in two forms: Fractures Vugs.

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Reservoir Rocks

Fractures Fractures are caused when a rigid rock is strained beyond its elastic limit - it cracks. The forces causing it to break are in a constant direction, hence all the fractures are also aligned. Fractures are an important source of permeability in low porosity carbonate reservoirs.

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Reservoir Rocks

Vugs

Vugs are defined as non-connected pore space. They do not contribute to the producible fluid total. Vugs are caused by the dissolution of soluble material such as shell fragments after the rock has been formed. They usually have irregular shapes.

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Reservoir Rocks

Permeability Definition The rate of flow of a liquid through a formation depends on: The pressure drop. The viscosity of the fluid. The permeability. The pressure drop is a reservoir property. The viscosity is a fluid property. The permeability is a measure of the ease at which a fluid can flow through a formation. Relationships exist between permeability and porosity for given formations, although they are not universal. A rock must have porosity to have any permeability. The unit of measurement is the Darcy. Reservoir permeability is usually quoted in millidarcies, (md). 39 39

Reservoir Rocks

Darcy Experiment The flow of fluid of viscosity m through a porous medium was first investigated in 1856 by Henri Darcy. He related the flow of water through a unit volume of sand to the pressure gradient across it. In the experiment the flow rate can be changed by altering the parameters as follows:

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Reservoir Rocks

Darcy Law

K = permeability, in Darcies. L = length of the section of rock, in centimetres. Q = flow rate in centimetres / sec. P1, P2 = pressures in bars. A = surface area, in cm2. µ = viscocity in centipoise.

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Reservoir Rocks

Permeability and Rocks In formations with large grains, the permeability is high and the flow rate larger.

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Reservoir Rocks

Permeability and Rocks 2 In a rock with small grains the permeability is less and the flow lower.

Grain size has no bearing on porosity, but has a large effect on permeability.

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Reservoir Rocks

Reservoir Rocks Reservoir rocks need two properties to be successful: Pore spaces able to retain hydrocarbon. Permeability which allows the fluid to move.

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Reservoir Rocks

Clastic Reservoirs Sandstone usually has regular grains; and is referred to as a grainstone. Porosity Determined mainly by the packing and mixing of grains. Permeability Determined mainly by grain size and packing, connectivity and shale content.

Fractures may be present.

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Reservoir Rocks

Carbonate Reservoirs Carbonates normally have a very irregular structure. Porosity: Determined by the type of shells, etc. and by depositional and post-depositional events (fracturing, leaching, etc.). Permeability: Determined by deposition and postdeposition events, fractures.

Fractures can be very important in carbonate reservoirs.

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Reservoir Rocks

Cap Rock A reservoir needs a cap rock.

Impermeable cap rock keeps the fluids trapped in the reservoir. It must have zero permeability. Some examples are: Shales. Evaporites such as salt or anhyhdrite. Zero-porosity carbonates. 47 47

Reservoir Rocks

Source Rocks Hydrocarbon originates from minute organisms in seas and lakes. When they die, they sink to the bottom where they form organic-rich "muds" in fine sediments. These "muds" are in a reducing environment or "kitchen", which strips oxygen from the sediments leaving hydrogen and carbon. The sediments are compacted to form organicrich rocks with very low permeability. The hydrocarbon can migrate very slowly to nearby porous rocks, displacing the original formation water.

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Reservoir Rocks

Temperature Window

If the temperature is too low, the organic material cannot transform into hydrocarbon. If the temperature is too high, the organic material and hydrocarbons are destroyed.

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Reservoir Rocks

Hydrocarbon Migration

Hydrocarbon migration takes place in two stages: Primary migration - from the source rock to a porous rock. This is a complex process and not fully understood. It is probably limited to a few hundred metres.

Secondary migration - along the porous rock to the trap. This occurs by buoyancy, capillary pressure and hydrodynamics through a continuous water-filled pore system. It can take place over large distances.

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Reservoir Rocks

Rock Classification Clastics Rock type

Particle diameter

Conglomerate Sandstone Siltstone Shale

Pebbles Sand Silt Clay

Non-Clastics Rock type

Composition

Limestone Dolomite Salt Anhydrite Gypsum Coal

CaCO3 CaMg(CO3)2 NaCl CaSO4 CaSO4.2H2O Carbon

2 - 64mm .06 - 2mm .003 - .06mm <.003mm

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Reservoir Rocks

Reservoir Structure There are many other types of structure. The criteria for a structure is that it must have: Closure, i.e. the fluids are unable to escape. Be large enough to be economical. The exact form of the reservoir depends on the depositional environment and post depositional events such as foldings and faulting.

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Reservoir Rocks

Traps General

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Reservoir Rocks

Structural Traps The simplest form of trap is a dome. This is created by upward movement or folding of underlying sediments.

An anticline is another form of simple trap. This is formed by the folding of layers of sedimentary rock.

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Reservoir Rocks

Fault Traps Faults occur when the rock shears due to stresses. Reservoirs often form in these fault zones. A porous and permeable layer may trap fluids due to its location alongside an impermeable fault or its juxtaposition alongside an impermeable bed. Faults are found in conjunction with other structures such as anticlines, domes and salt domes.

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Reservoir Rocks

Salt Dome Trap Salt Dome traps are caused when "plastic" salt is forced upwards. The salt dome pierces through layers and compresses rocks above. This results in the formation of various traps: In domes created by formations pushed up by the salt. Along the flanks and below the overhang in porous rock abutting on the impermeable salt itself.

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Reservoir Rocks

Stratigraphic Traps

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Reservoir Rocks

Reservoir Mapping

Reservoir contours are usually measured to be below Mean Sea Level (MSL). They can represent either the reservoir formation structure or fluid layers. 58 58

Reservoir Fluids

Reservoir Fluids


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Reservoir Fluids

Definitions Fluid Contacts

Oil in Place

OIP

The volume of oil in the reservoir in barrels or cubic metres.

Gas/Oil Ratio

GOR

The gas content of the oil.

API Gravity

API

Oil gravity.

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Reservoir Fluids

Fluids in a Reservoir A reservoir normally contains either water or hydrocarbon or a mixture. The hydrocarbon may be in the form of oil or gas. The specific hydrocarbon produced depends on the reservoir pressure and temperature. The formation water may be fresh or salty. The amount and type of fluid produced depends on the initial reservoir pressure, rock properties and the drive mechanism.

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Reservoir Fluids

Hydrocarbon Composition Typical hydrocarbons have the following composition in Mol Fraction Hydrocarbon C1

C2

C3

C4

C5

C6+

Dry gas

.045

.045

.01

.01

.01

Condensate .72

.08

.04

.04

.04

.08

Volatile oil .6-.65

.08

.05

.04

.03

.15-.2

Black oil

.41

.03

.05

.05

.04

.42

Heavy oil

.11

.01

.01

.04

.8

Tar/bitumen

.88

.03

1.0

The 'C' numbers indicated the number of carbon atoms in the molecular chain. 4 4

Reservoir Fluids

Hydrocarbon Structure

The major constituent of hydrocarbons is paraffin.

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Reservoir Fluids

Hydrocarbon Classification Hydrocarbons are also defined by their weight and the Gas/Oil ratio. The table gives some typical values: GOR

API Gravity

Wet gas

100mcf/b

50-70

Condensate

5-100mcf/b

50-70

Volatile oil

3000cf/b

40-50

Black oil

100-2500cf/b

30-40

Heavy oil

0

10-30

Tar/bitumen

0

<10

The specific gravity of an oil is defined as:

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Reservoir Fluids

Hydrocarbon Gas Natural gas is mostly (60-80%) methane, CH4. Some heavier gases make up the rest. Gas can contain impurities such as Hydrogen Sulphide, H2S and Carbon Dioxide, CO2. Gases are classified by their specific gravity which is defined as: "The ratio of the density of the gas to that of air at the same temperature and pressure".

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Reservoir Fluids

Reservoir Pressure

Reservoir Pressures are normally controlled by the gradient in the aquifer. High pressures exist in some reservoirs. 8 8

Reservoir Fluids

Reservoir Pressure Calculation

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Reservoir Fluids

Reservoir Pressure Example

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Reservoir Fluids

Reservoir Temperature Gradient

The chart shows three possible temperature gradients. The temperature can be determined if the depth is known. High temperatures exist in some places. Local knowledge is important. 11 11

Reservoir Fluids

Fluid Phases A fluid phase is a physically distinct state, e.g.: gas or oil. In a reservoir oil and gas exist together at equilibrium, depending on the pressure and temperature. The behaviour of a reservoir fluid is analyzed using the properties; Pressure, Temperature and Volume (PVT). There are two simple ways of showing this: Pressure against temperature keeping the volume constant. Pressure against volume keeping the temperature constant.

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Reservoir Fluids

PVT Experiment

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Reservoir Fluids

Phase Diagram -single component The experiment is conducted at different temperatures. The final plot of Pressure against Temperature is made. The Vapour Pressure Curve represents the Bubble Point and Dew Point. (For a single component they coincide.)

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Reservoir Fluids

Phase diagram Oil The Pressure/Temperature (PT) phase diagram for an oil reservoir: Point 'A' is the initial reservoir condition of pressure and temperature. If the reservoir is produced at a constant temperature until the fluid reaches the wellbore, the line to Point 'B' is drawn. This represents the flow of fluid from the reservoir to the borehole. The fluid travelling to surface now drops in both temperature and pressure arriving at he "separator conditions" (s) with a final volume of oil and gas.

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Reservoir Fluids

Phase Diagram Condensate/Gas Point 'C' is at the initial reservoir conditions. The reservoir is produced at a constant temperature from C to D. Fluids flowing up the well now drop in temperature and pressure, crossing the Dew point line and liquid condenses out. At separator conditions (s) the result in both liquid and gas on the surface.

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Reservoir Fluids

Gas Reservoir In a gas reservoir the initial point is A. Producing the well to separator conditions B does not change the fluid produced. The point B is still in the "gas region" and hence dry gas is produced.

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Reservoir Fluids

Hydrocarbon Volumes Fluids at bottom hole conditions produce different fluids at surface: Oil becomes oil plus gas. Gas usually stays as gas unless it is a Condensate. Water stays as water with occasionally some dissolved gas.

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Reservoir Fluids

FVF Oil and Gas There is a change in volume between downhole conditions and the surface. The volume of the fluid at reference conditions is described by the Formation Volume Factor: Volume at downhole Conditions FVF =

Volume at reference Conditions

Bo = formation volume factor for oil. Bw = formation volume factor for water. Bg = formation volume factor for gas.

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Reservoir Fluids

Saturation Formation saturation is defined as the fraction of its pore volume (porosity) occupied by a given fluid. Volume of a specific fluid Saturation = pore volume Definitions Sw = water saturation. So = oil saturation. Sg = gas saturation. Sh = hydrocarbon saturation = So + Sg Saturations are expressed as percentages or fractions, e.g. Water saturation of 75% in a reservoir with porosity of 20% contains water equivalent to 15% of its volume.

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Reservoir Fluids

Saturation Definition

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Reservoir Fluids

Wettability

The wettability defines how a fluid adheres to the surface (or rock in the reservoir) when there are two fluids present, e.g. water and air. The angle measured through the water is the "contact angle". If it is less than 90° the rock is water wet; greater than 90° the rock is oil wet. Most reservoir rocks are water wet.

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Reservoir Fluids

Irreducible Water Saturation In a formation the minimum saturation induced by displacement is where the wetting phase becomes discontinuous. In normal water-wet rocks, this is the irreducible water saturation, Swirr. Large grained rocks have a low irreducible water saturation compared to small-grained formations because the capillary pressure is smaller.

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Reservoir Fluids

Capillary Forces

Pc = capillary pressure. σ = surface tension. q = contact angle. rcap = radius of capillary tube.

In a simple water and air system the wettability gives rise to a curved interface between the two fluids. This experiment has a glass tube attached to a reservoir of water. The water "wets" the glass. This causes the pressure on the concave side (water) to exceed that on the convex side (air). This excess pressure is the capillary pressure.

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Reservoir Fluids

Capillary Forces and Rocks In a reservoir the two fluids are oil and water which are immiscible hence they exhibit capillary pressure phenomena. This is seen by the rise in the water above the point where the capillary pressure is zero.

The height depends on the density difference and the radius of the capillaries. 25 25

Reservoir Fluids

Transition Zone The phenomenon of capillary pressure gives rise to the transition zone in a reservoir between the water zone and the oil zone. The rock can be thought of as a bundle of capillary tubes. The length of the zone depends on the pore size and the density difference between the two fluids.

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Reservoir Fluids

Relative Permeability Take a core 100% water-saturated. (A) Force oil into the core until irreducible water saturation is attained (Swirr). (A-> C -> D) Reverse the process: force water into the core until the residual saturation is attained. (B) During the process, measure the relative permeabilities to water and oil.

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Reservoir Fluids

Relative Permeability Experiment

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Reservoir Fluids

Drive Mechanisms A virgin reservoir has a pressure controlled by the local gradient. Hydrocarbons will flow if the reservoir pressure is sufficient to drive the fluids to the surface (otherwise they have to be pumped). As the fluid is produced reservoir pressure drops. The rate of pressure drop is controlled by the Reservoir Drive Mechanism. Drive Mechanism depends on the rate at which fluid expands to fill the space vacated by the produced fluid. Main Reservoir Drive Mechanism types are: Water drive. Gas cap drive. Gas solution drive 29 29

Reservoir Fluids

Water Invasion 1 Water invading an oil zone, moves close to the grain surface, pushing the oil out of its way in a pistonlike fashion.

The capillary pressure gradient forces water to move ahead faster in the smaller pore channels.

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Reservoir Fluids

Water Invasion 2 The remaining thread of oil becomes smaller.

It finally breaks into smaller pieces.

As a result, some drops of oil are left behind in the channel.

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Reservoir Fluids

Water Drive

Water moves up to fill the "space" vacated by the oil as it is produced.

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Reservoir Fluids

Water Drive 2

This type of drive usually keeps the reservoir pressure fairly constant. After the initial “dry” oil production, water may be produced. The amount of produced water increases as the volume of oil in the reservoir decreases. Dissolved gas in the oil is released to form produced gas. 33 33

Reservoir Fluids

Gas Invasion Gas is more mobile than oil and takes the path of least resistance along the centre of the larger channels. As a result, oil is left behind in the smaller, less permeable, channels.

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Reservoir Fluids

Gas Cap Drive

Gas from the gas cap expands to fill the space vacated by the produced oil.

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Reservoir Fluids

Gas Cap Drive 2 As oil production declines, gas production increases. Rapid pressure drop at the start of production.

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Reservoir Fluids

Solution Gas Drive

After some time the oil in the reservoir is below the bubble point. 37 37

Reservoir Fluids

Solution Gas Drive 2 An initial high oil production is followed by a rapid decline. The Gas/Oil ratio has a peak corresponding to the higher permeability to gas. The reservoir pressure exhibits a fast decline.

38 38

Reservoir Fluids

Drives General A water drive can recover up to 60% of the oil in place. A gas cap drive can recover only 40% with a greater reduction in pressure. A solution gas drive has a low recovery.

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Reservoir Fluids

Drive Problems Water Drive: Water can cone upwards and be produced through the lower perforations. Gas Cap Drive: Gas can cone downwards and be produced through the upper perforations. Pressure is rapidly lost as the gas expands. Gas Solution Drive: Gas production can occur in the reservoir, skin damage. Very short-lived.

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Reservoir Fluids

Secondary Recovery 1 Secondary recovery covers a range of techniques used to augment the natural drive of a reservoir or boost production at a later stage in the life of a reservoir. A field often needs enhanced oil recovery (EOR) techniques to maximise its production. Common recovery methods are: Water injection. Gas injection. In difficult reservoirs, such as those containing heavy oil, more advanced recovery methods are used: Steam flood. Polymer injection. . CO2 injection. In-situ combustion.

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Reservoir Fluids

Secondary Recovery 2 water injection

gas injection

42 42

Spontaneous Potential Measurement

Spontaneous Potential


1 1


SP Theory 1 SP results from electric currents flowing in the drilling mud.

There are three sources of the currents, two electrochemical and one electrokinetic.

Membrane potential - largest.

Liquid - junction potential.

Streaming potential - smallest.

2 2


SP theory 2 Membrane and Liquid Potential These two effects are the main components of the SP. They are caused because the mud flitrate and the formation waters contain NaCl in different proportions. Firstly, shales are permeable to the Sodium ions but not the Chlorine. Hence there is a movement of charged particles through the shale creating a current and thus a potential. The ions Na+ and Cl- have different mobilities at the junction of the invaded and virgin zones. The movement of the ions across this boundary creates another current and hence a potential.

Streaming Potential This is generated by flow of the mud filtrate through the mud cake. As this does not normally occur this effect is small. It will only become important if there are high differential pressures across the formations.

3 3


SP theory 3

4 4


SP scales The SP is measured in millivolts, mV. The scale on the log shows a number of mV per division for example 20mV/division. This gives a total for the track of 200mV. The scale across the track is variable and depends on the conditions in the well. The scale is set during logging to have the SP curve in the track over the zone of interest and as much of the rest of the log as possible.

5 5


log-1 The SSP is the quantity to be determined.

It is the deflection seen on the SP from the Shale Base Line (zero point) to the Sand Line (max. deflection)

6 6


example log 2 The maximum SP deflection in this example occurs at the same depths as the resistivity curves show a separation. The minimum point on the SP corresponds to where all the resistivity curves overlay, no invasion, a shale.

7 7


SP uses Differentiate potentially porous and permeable reservoir rocks from impermeable clays.

Define bed boundaries.

Give an indication of shaliness (maximum deflection is clean; minimum is shale).

Determine Rw in both salt and fresh muds.

8 8


Rw from the SP Rw is often known from client information or local knowledge. The SP can be used to check the value or compute it when it is unavailable. It is especially useful when there are variations along the borehole.

SSP = −k log

Rmfe Rwe

K is a constant - depending on the temperature.

9 9


Rw from the SP Knowing the SSP (the maximum deflection) from the log and the temperature, the ratio of resistivities is obtained from Log Interpretation Chart SP-1. Rmfe output = Rwe

10 10


Rw from SP 2

Rmf is measured, using the mud cell. Rmfe is computed from Log Interpretation Chart SP-2. Rwe is computed, from the ratio from SP1 and Rmfe. 11 Chart SP-2 output is Rw. 11

Salinities chart 10 ppm

8

Grains/gal at 75ÞF


6 5

3

300 400

2

600 500 800 700 200 0 170 0 140 0 120 0 100 0

0.8 0.6 0.5 0.4

300 0

0.3

80 70000 0 60 0 0 500 0 400 0

0.2

20, 000 1 7 , 000 14, 000 1 2 , 000 10, 000

0.1 0.08 0.06 0.05

80,0 70,0 00 00 6 0 , 0 00 50,0 0 0 40,0 00 30,0 00

0.04 0.03 0.02

,000

50 10

75 20

30

100 40

125 150 200 50 60 70 80 90 100

300

0.01

280, 250 000 200,,0000 0 170, 0 0 140, 00 120,000 000 100, 000

Resistivity of Solution (ž - m)

1

250 300 350 400 120 140 160 180 200

10 15 20 25 30 40 50

100 150 200 250 300 400 500

NaCl Concentration (ppm or grains/gal)

200

4

1000 1500 2000 2500 3000 4000 5000

10,000 15,000 20,000

Temperature (ÞF or ÞC)

This chart is used to compute salinities from resistivities of solution e.g. mud, and vice versa. It is also used to find the resistivities at a given temperature. 12 12


SP borehole Effects - 1

Baseline shifts: These can occur when there are beds of different salinities separated by a shale which does not act as a perfect membrane. 13 13


SP Borehole Effects - 2 Resistive formation: The presence of a resistive bed in a permeable interval will disrupt the SP deflection. The current is contained and hence the potential drop changes with depth. The log takes a sloped appearance.

The log in this situation can no longer define the bed boundaries correctly.

14 14


SP surface Effects The SP can be affected by a number of surface effects as it relies on the fish as its reference electrode. Power lines, electric trains, electric welding, close radio transmitters: All these create ground currents which disrupt he "fish" reference causing a poor, sometimes useless, log.

15 15

Gamma Ray Measurement



1 1


Gamma Ray Principles The Gamma Ray log is a measurement of the formation's natural radioactivity. Gamma ray emission is produced by three radioactive series found in the Earth's crust.

Potassium (K40) series. Uranium series. Thorium series.

Gamma rays passing through rocks are slowed and absorbed at a rate which depends on the formation density. Less dense formations exhibit more radioactivity than dense formations even though there may be the same quantities of radioactive material per unit volume.

2 2


Basic Gamma Ray Uses Bed definition: The tool reacts if the shale is radioactive (usually the case), hence show the sands and shales, the permeable zones and the non-permeable zones. Computation of the amount of shale: The minimum value gives the clean (100%) shale free zone, the maximum 100% shale zone. All other points can then be calibrated in the amount of shale.

3 3


GR Uses The gamma ray log is used for: Lithology/mineralogy, e.g. shaliness. Correlation: A major use of the tool is to identify marker beds and thus allow well-to-well correlation. Marker beds can be the top or bottom of the reservoir or a specific shale giving a high reading.

Subsidence logging: Radioactive bullets are placed accurately spaced in the formation. A gamma ray tool with a number of precisely spaced detectors is logged and the peaks noted. Subsequent logs will show any movement.

Tracer logging: A radioactive fluid is ejected by a tool at a chosen level. The fluid movement is monitored by the gamma ray and will show thief zones and channels in the cement behind the casing.

4 4


NGT The NGT tool measures a spectrum that is the result of the three naturally occurring radioactive series.

The Potassium has a sharper shape than the other two as it decays through a single reaction to a stable element. The other two decay through a number of daughter elements each with some contribution to the final picture. 5 5


NGT Principle

The measurement in the standard tool is made by a measurement in a number of fixed energy windows. Three of these at the highest levels are set over a characteristic peak of each of the elements. The statistical nature of the measurement is partly improved by using another two windows set at a lower energy which has a higher rate. 6 6


NGT Log

Outputs are the relative amounts of Thorium, Uranium and Potassium in the formation. With: Thorium in ppm. Uranium in ppm. Potassium in %. Additional curves are the total gamma ray (SGR) and a Uranium-corrected gamma ray (CGR). 7 7


NGT uses This tool has many applications: Lithology identification. Study of depositional environments. Investigation of shale types. Correction of the GR for clay content evaluation. Identification of organic material and source rocks. Fracture identification. Geochemical logging. Study of a rock's diagenetic history. A major application was to solve North Sea log interpretation problems in micaceous sands.

8 8


NGT uses The three radioactive elements measured by the NGT occur in different parts of the reservoir. If we know the lithology, we can obtain further information. In Carbonates: U - indicates phosphates, organic matter and stylolites. Th - indicates clay content. K - indicates clay content, radioactive evaporites.

9 9


NGT in Clastics In Sandstones: Th - indicates clay content, heavy minerals. K - indicates micas, micaceous clays and feldspars.

In Shales: U - in shale, suggest a source rock. Th - indicates the amount of detrital material or degree of shaliness. K - indicates clay type and mica. 10 10


NGT Crossplots - 1 The NGT data is interpreted using three major crossplots. In order of complexity: Thorium versus Potassium: Gives clay type

Photoelectric factor, Pe, versus Potassium: Gives clay type and micas.

Pe versus Thorium/Potassium ratio: Gives clay type and micas.

11 11


NGT Crossplots - 2

This plot can be used to determine the type of clay mineral or mica.

12 12


NGT Crossplots - 3 This plot adds in the Thorium contribution making it more precise than the previous one.

13 13


NGT/GR parameters Vertical resolution

18"

Depth of investigation

6"-8"

Readings in:

API units

Limestone Dolomite Sandstone Shale Salt Anhydrite

<20 <30 <30 80-300 <10 <10

No formation is perfectly clean, hence the GR readings will vary. Limestone is usually cleaner than the other two reservoir rocks and normally has a lower GR.

14 14


GR/NGT Limits GR - Organic materials (see the uranium as "shale"). - Micas (sees micaceous sands as shaly). NGT - Barite in the mud (reduces the count rate but can be partially corrected for). - KCI mud (Potassium in the mud masks the formation response but can be partially corrected for). - Large boreholes decrease the count rate hence increase the statistics. - Statistical errors.

15 15


GR Correction 1

GR logs require correction for the effects of the mud.

16 16


GR Correction 2

An additional correction is needed if there is mud in the borehole.

17 17

Neutron Porosity Measurement

Neutron Porosity


1 1


Lithology and Porosity The next major step in the procedure is lithology identification. Lithology data gives information on porosity and other parameters. Lithology of a formation can be:

Simple

Dirty

Complex

2 2


Lithology and Porosity Tools All tools react to lithology - usually in conjunction with the porosity. Major lithology tools are: Neutron - reacts to fluid and matrix. Density - reacts to matrix and fluid. Sonic - reacts to a mixture of matrix and fluid, complicated by seeing only primary porosity. NGT - identifies shale types and special minerals. CMR - magnetic resonance reacts to the porosity with a small element if lithology. 3 3


Neutrons

4 4


Early Neutron Tools The first neutron tools used a chemical neutron source and employed a single detector which measured the Gamma Rays of capture They were non-directional. The units of measurement were API units where 1000 API units were calibrated to read 19% in a water-filled limestone. The tool was badly affected by the borehole environment.

5 5


Neutron Tools The second generation tool was the Sidewall Neutron Porosity (SNP). This was an epithermal device mounted on a pad. The current tool is the Compensated Neutron Tool (CNT). The latest tool is the Accelerator Porosity Sonde (APS), using an electronic source for the neutrons and measuring in the epithermal region.

6 6


Hydrogen Index Hydrogen Index is the quantity of hydrogen per unit volume. Fresh water is defined as having a Hydrogen Index of 1. Hence oil has a Hydrogen Index which is slightly less than that of water. The Hydrogen Index of gas is a much smaller than that of water. In a formation, it is generally the fluids that contain hydrogen.

7 7


Thermal Neutron Theory Neutrons are slowed down from their initial "fast" state by collisions with the formation nuclei. At each collision there is some energy lost by the neutron.

The principal element involved in the slowing down is Hydrogen, because it is close in size to the neutron which loses most energy in these collisions. The CNT measures the neutron population in the thermal region. This is why the tool measures the Hydrogen Index.

8 8


Detectors Two neutron detectors are used to produce a ratio eliminating some of the borehole effects experienced by single detectors. The count rate for each detector is inversely proportional to porosity with high porosity giving low count rates.

9 9


Ratio to Porosity Transform The count rates are first corrected for the dead time of the detectors (when the detector is not available to receive counts). The count rates are calibrated with the master calibration. A ratio of these is then taken. The ratio is translated into porosity using a transform. (This is a combination of theoretical and experimental work). The current field output for the thermal neutron porosity is called TNPH.

10 10


Borehole Effects The logs have to be corrected for the borehole environment: Borehole size.

Mud cake.

Borehole salinity.

Mud weight.

Temperature.

Pressure.

Formation salinity. Stand-off. 11 11


Hole Size Correction Necessary because the tools algorithm from ratio to porosity is built to "fit" a 77/8" hole. Larger holes cause the tool to see more mud (100% porosity) around the borehole, hence the tool reads too high in larger hole sizes. The chart is entered with the porosity;

Go down to hole size. Follow trend lines to 7 7/8". Read of ∆φ. ∆φ

A correction is made automatically in open hole using caliper measurements from the combined density tool. It can be made using the bit size if a caliper is not available. The correction can be large. 12 12


Mud Cake Correction The mud cake absorbs neutrons before they can enter or leave the formation. mud cake = stand-off with porosity <100%. The larger the mud cake, the larger the correction. It is a small correction but one that is rarely ever applied because the mud cake cannot be easily measured.

13 13


Borehole Salinity Correction This arises due to Chlorine. The more Chlorine present, the more neutrons absorbed in the borehole. ==> decrease count rate. The largest effect is seen in salt-saturated muds.

Go down to the borehole salinity. Follow trend lines to zero. Read ∆φ. ∆φ

14 14


Mud Weight Correction The extra material in heavier muds means there is less hydrogen, hence more neutrons reach the formation. It also changes if the mud is full of barite. In this case the amount of material needed to achieve the same mud weight is less, hence the correction is less.

Select normal or barite mud. Enter with porosity. Go down to mud weight. Follow lines to 8 lb/gal. Read ∆φ. ∆φ

The correction is quite small. 15 15


Formation Temperature Correction The correction is large and depends on the porosity. This is a dual effect: The expansion of the water reduces the quantity of Hydrogen seen by the tool. Change in the borehole fluid capture crosssection.

Enter with porosity at the top. Go down to hole temperature. Follow trend lines to 75ÞF. Read ∆φ. ∆φ 16 16


Pressure Correction The effect is caused by the compression of the fluids downhole. In standard water-based muds the effect is small.

Select oil-based or water-based mud. Enter with porosity at the top. Go down to hole pressure. Follow trend lines to zero. Read ∆φ. ∆φ

In oil-based muds the correction is large.

17 17


Formation/Salinity Correction There are two factors affecting the neutron measurement in the formation: The chlorine in the formation water. The rock matrix capture cross-section. The simplest method is to assume that the matrix is clean and that the matrix 'Σ Σ' known. This leaves salinity (mud filtrate) as the only "variable". The complete solution is to measure the total formation 'Σ Σ' and use this to compute the correction. The correction can be large but is not applied in the field because the lithology is unknown, hence the 'Σ Σ' unknown. It is taken into account in the interpretation phase. 18 18


Stand off Correction Any space between the tool and the borehole wall is seen as 100% porosity. The value of the correction depends on the hole size: Larger holes = more correction Stand-off is rarely measured. One method is to use the SA curve recorded with a PCD. The chart is entered with the porosity at the top; Go to the nearest hole size. Go down to the stand-off value, e.g. 0.5". Follow the lines to zero. Read the ∆φ (always negative).

19 19


Standoff Correction Chart

20 20


Alpha Processing Alpha Processing is a method that enhances the resolution of the standard measurement. It utilizes the higher resolution of the near detector to increase the resolution of the more accurate far detector.

21 21


Alpha Processing The first step is to depth-match the two detectors' responses.

The next step is to match the resolution of both detectors.

22 22


Alpha Processing The difference between the two readings now gives the "high frequency" information - which highlights thin beds missed by the far detector.

23 23


Alpha processing The "high frequency" information is added to the far detector signal to give the final enhanced log.

24 24


Thermal Neutron Parameters Vertical resolution: Standard (TNPH) Enhanced

24" 12"


9"-12"

Readings in zero porosity: Limestone (0%) Sandstone (0%) Dolomite (0%) Anhydrite Salt

0 -2.00 1.00 -2.00 -3.00

Typical Readings Shale Coal

30-45 50+

25 25


Thermal Neutron Interpretation/Uses

The tool measures hydrogen index. Its prime use is to measure porosity. Combined with the bulk density, it gives the best possible answer for lithology and porosity interpretation.

26 26


Thermal Neutron in Cased Hole The CNT can be run in cased hole for the porosity. In addition to the standard corrections some others are needed to take into account the extra elements of casing and cement. The standard conditions are: 83/4" borehole diameter. Casing thickness 0.304". Cement thickness 1.62". Fresh water in the borehole / formation. No stand-off. 75ÞF. Atmospheric pressure. Tool eccentred in the hole. 27 27


Corrections in Cased Hole

28 28

Bulk Density Measurement



1 1


Gamma Ray Physics -density -1 The Density Tools use a chemical gamma ray source and two or three gamma ray detectors. The number of gamma rays returning to the detector depends on the number of electrons present, the electron density, ρe. The electron density can be related to the bulk density of the minerals by a simple equation. ρe = ρ( 2Z/A ) Where Z is the number of electrons per atom and A is the atomic weight.

2 2


Gamma Ray Physics -density 2 The assumption made in the interpretation is that: Z/A = 0.5 This is very close for most elements commonly encountered, except hydrogen which has little effect on the measurement. Therefore ρe = ρ Element H C O Na Mg Al Si S Cl K Ca

Z/A 0.9921 0.4996 0.5 0.4785 0.4934 0.4819 0.4984 0.4989 0.4794 0.4860 0.499

3 3


Calibration The tool measured density, ρb, has been experimentally related to the electron density; ρb = 1.0704 ρe - 0.1883 The tool needs to be calibrated in a known condition. This condition is fresh water and limestone, densities, 1.00 and 2.71 respectively. The bulk density versus the electron density equation fits for all the common minerals with a few exceptions: Salt true density 2.165 density tool value 2.03 Sylvite -

true density density tool value

1.984 1.862 4 4


Spine and Ribs The spine represents the line of increasing formation density on the plot of the long spacing count rate versus short spacing count rate. The presence of mud cake causes a deviation from the line in a predictable manner. Thus a correction can be made to obtain the true density.

1.9 2.0 Mud cake with barite

2.1 2.2 B

.

Long Spacing Count Rate

2.3 C 2.4 Increasing Mud cake Thickness

A

Increasing Mud cake Thickness

2.5 2.6 2.7

Mud cake without barite

2.8 2.9 Short spacing Count Rate

5 5


Spine and Ribs 1.9 2.0 Mud cake with barite

2.1 2.2 B

.

Long Spacing Count Rate

2.3 C 2.4 Increasing Mud cake Thickness

A

Increasing Mud cake Thickness

2.5 2.6 2.7

Mud cake without barite

2.8 2.9 Short spacing Count Rate

Example: The correct reading is at point A. An increasing mud cake thickness moves the point to B or C depending on whether there is heavy material (barite) in the mud or not. 6 6


Density Outputs The outputs are: RHOZ/RHOB (ρ ρb), the corrected bulk density. DRHO (∆ρ ∆ρ), ∆ρ the correction that has been applied to ρb (LDT only). RHOZ/RHOB is the main output; DRHO is a quality control curve (LDT only).

7 7


Borehole Effects The LDT is a pad tool with collimated source and detectors. It experiences little or no environmental effect. In large holes, the curvature of the pad versus that of the hole causes a minor error that needs to be corrected.

8 8


Borehole Effects

Hole rugosity may affect the measurement. The source and detectors "see" different formations/borehole. The effect is an erratic and incorrect log.

9 9


Alpha Processing

As the density tool also uses two detectors it can be Alpha processed in exactly the same way as the CNT. The resulting log shows a great improvement over the standard output.

10 10


Density Parameters Vertical resolution: Standard Enhanced

18" 6"


6"-9"

Readings in: Limestone (0pu) Sandstone (0pu) Dolomite (0pu) Anhydrite Salt Shale Coal

2.71 2.65 2.85 2.98 2.03 2.2-2.7 1.5

11 11


Interpretation/Uses The density tool is extremely useful as it has high accuracy and exhibits small borehole effects. Major uses include: Porosity. Lithology (in combination with the neutron tool). Mechanical properties (in combination with the sonic tool). Acoustic properties (in combination with the sonic tool). Gas identification (in combination with the neutron tool).

12 12


Density Porosity

ρ b = ρ f φ + ρ ma (1 − φ ) ρ ma − ρ b φ= ρ ma − ρ f

There are two inputs into the porosity equation: the matrix density and the fluid density. The fluid density is that of the mud filtrate.

13 13


Scaling/Porosity The density tool is usually run with the neutron. To aid quicklook interpretation they are run on "compatible scales". This means that the scales are set such that for a given lithology the curves overlay. The standard scale is the "limestone compatible" where the neutron porosity scale is:

To fit this the density log has to have its zero limestone point (2.7 g/cc) on the same position as the neutron porosity zero and the range of the scale has to fit the neutrons 60 porosity units hence the scale is:

Changing to a sandstone compatible scale would put the zero sandstone density, 2.65, over the neutron porosity zero to give:

14 14


Pef Physics The Photoelectric effect occurs when the incident gamma ray is completely absorbed by the electron.

It is a low energy effect hence the Photoelectric Absorption index, Pe, is measured using the lowest energy window of the tool. Pe is related directly to Z, the number of electrons per atom, hence fixed for each element. Pe = ( Z/A )3.6 Its units are barns/electron.

15 15


Pef Theory Pe can be easily computed for any lithology by summing the elemental contributions. Measurement is virtually porosity and fluid independent. Major use is Lithology identification. Another way of using it is express it in volumetric terms as: U = Peρ ρe This is called the Volumetric photoelectric absorption index. This parameter can then be used in a formula for computing the components of the reservoir. U = φUf + (1 - φ) Uma 16 16


Pef Parameters Vertical resolution: Standard

4"

Readings in: Limestone Sandstone Dolomite Shale Anhydrite Salt

5.08 1.81 3.14 1.8-6 5.05 4.65

17 17

Sonic Measurement

Sonic Measurement


1 1

Sonic Measurement

Sonic Tool The sonic tools create an acoustic signal and measure how long it takes to pass through a rock.

By simply measuring this time we get an indication of the formation properties. The amplitude of the signal will also give information about the formation.

2 2

Sonic Measurement

sonic borehole waves

3 3

Sonic Measurement

waves 2 In a fast formation both compressional and shear waves are created. The head waves in the borehole are the signals seen by the receivers. The array of receivers see the signal at different times as they are at different distances from the transmitter.

4 4

Sonic Measurement

Sonic -BHC A simple tool that uses a pair of transmitters and four receivers to compensate for caves and sonde tilt. The normal spacing between the transmitters and receivers is 3' - 5'. It produces a compressional slowness by measuring the first arrival transit times. Used for: Correlation. Porosity. Lithology. Seismic tie in / time-to-depth conversion. 5 5

Sonic Measurement

Long Spacing Sonic The BHC tool is affected by near borehole altered zones hence a longer spacing is needed with a larger depth of investigation. The tool spacings are 8' - 10', 10' - 12'. The tool cannot be built with transmitters at each end like a BHC sonde, hence there are two transmitters at the bottom. A system called DDBHC - depth derived borehole compensation, is used to compute the transmit time. The uses of this tool are the same as the BHC tool.

6 6

Sonic Measurement

Array Sonic Multi-spacing digital tool. First to use STC processing. Able to measure shear waves and Stoneley waves in hard formations. Used for: Porosity. Lithology. Seismic tie in / time-to-depth conversion. Mechanical properties (from shear and compressional). Fracture identification (from shear and Stoneley). Permeability (from Stoneley).

7 7

Sonic Measurement

DSI General In a slow formation the shear wave from a monopole source never creates a head wave. The fluid wave is the first arrival after the compressional. A dipole source is directional. It creates a flexural wave on the borehole wall and shear and compressional in the formation. The shear wave is recorded whether the formation is soft or hard.

8 8

Sonic Measurement

DSI tool Generates both monopole and dipole signals. Generates different frequencies for measuring a range of waves. Measures: Compressional and shear Two orthogonal shear - dipole signals Stoneley Application: Seismic. Mechanical properties (from shear and compressional). Fracture identification (shear and Stoneley). Permeability computation (Stoneley). Porosity / Lithology. Gas shows. 9 9

Sonic Measurement

STC Processing This type of processing is necessary to extract the shear and Stoneley information from the waveform. The processing applies a "semblance algorithm" to the recorded set of traces. This means looking for the same part of the wave (e.g. shear) on each wavetrain. Once this has been done the transit time can be computed.

10 10

Sonic Measurement

STC Map At a given depth, the slowness can be plotted against time. Regions of large coherence appear as contours.

These correspond to the compressional (fastest), shear (close to the compressional) and Stoneley (furthest away).

11 11

Sonic Measurement

STC Output

12 12

Sonic Measurement

Tools Summary Measurements:

BHC

LSS

Array Sonic x

Dipole Sonic x

Compressional

x

x

Shear/Stoneley: Hard rock Soft rock

-

-

x -

x x

Computations: Porosity Lithology Seismic tie in

x x x

x x x

x x x

x x x

Mechanical properties: Hard rock Soft rock -

-

x -

x x

Fracture detectionPermeability -

-

x -

x x

13 13

Sonic Measurement

Borehole Effects As the sonic tool is measuring the time for the signal to go from the transmitter to the receiver there are two types of erroneous responses. Cycle skipping If the signal strength is too low the detection goes to the next peak. This means that the final transmit time will be wrong. Road noise

This is noise at the receivers that is due to the borehole environment and has nothing to do with the signal being measured. 14 14

Sonic Measurement

Borehole Effects 2 There are a number of borehole phenomena which cause these effects: Borehole rugosity - causes the tool motion to be erratic, the signal may be distorted and give road noise or cycle skipping. Large holes - if the borehole diameter is very large the mud signal may arrive at a receiver before the formation signal. The proper tool setup for each condition has to be picked before the job. This means choosing whether to centralise or excentralise the tool and the equipment to be used.

15 15

Sonic Measurement

Borehole Effects 3 Gas in the well The acoustic impedance of gas is very low, hence the signal will be strongly attenuated. There may be skipping. Altered zone This is largely overcome by using a long spacing tool to read deeper into the formation. Caves Can create problems in spite of compensation as they will also reduce signal amplitude. Fractures Reduce the signal amplitude especially the shear and Stoneley waves.

16 16

Sonic Measurement

Porosity - 1 The porosity from the sonic slowness is different than that from the density or neutron tools. It reacts to primary porosity only, i.e. it does not "see" the fractures or vugs. The basic equation for sonic porosity is the Wyllie Time Average:

∆t log = φ∆t f + (1 − φ )∆t ma φ=

∆t log − ∆t ma ∆t f − ∆t ma 17 17

Sonic Measurement

porosity 2 There is another possibility for transforming slowness to porosity, called Raymer Gardner Hunt. This formula tries to take into account some irregularities seen in the field. The basic equation is:

(

)

φ 1 1−φ = + ∆t c ∆t f ∆t ma 2

A simplified version used on the Maxis is:

φ =C

∆t log − ∆t ma ∆t log

C is a constant, usually taken as 0.67. 18 18

Sonic Measurement

Porosity 3 This chart shows the relationship between the sonic compressional slowness and the porosity. Both the lithology and the equation must be known prior to using this chart.

19 19

Sonic Measurement

Crossplots The sonic measurements can be cross-plotted with the density or the neutron readings to give porosity and lithology information as with the density-neutron crossplot, however:

The neutron - sonic (TNPH-Dt) Has problems because there are two possible equations. The density - sonic (Dt-RHOB) Has problems with the transforms as there is no separation between the lithology lines.

20 20

Sonic Measurement

mechanical properties

21 21

Sonic Measurement

Mechanical Properties and Sonics A combination of compressional, shear and density measurements gives the rocks' dynamic elastic moduli. These are used to obtain the formation's mechanical properties.

22 22

Sonic Measurement

Mechanical Properties uses 1 Main uses of mechanical properties in soft formations are: Sand stability evaluation, i.e. The prediction of the formation collapse under producing conditions. Using theoretical failure criteria it is possible to predict if the perforation will produce sand. Well bore stability, i.e. The prediction of formation failure / collapse while drilling. This is especially relevant in deviated wells when drilling at high angles through soft rock can be problematic. The physical mechanism is similar to that of sand stability evaluation. 23 23

Sonic Measurement

Mechanical Properties uses 2 The major use of mechanical properties in hard rocks is to predict how they will behave under "excess" pressure: Drilling: Will the formation fracture and the drilling mud disappear? Hydraulic fracturing: How much pressure will fracture the formation and how far will the fracture extend? Experimental models are used to compute parameters such as tensile strength. Simulations are used to predict the pressures that will "crack" the rock and lengths of fractures.

24 24

Sonic Measurement

Sonic Parameters Vertical resolution: Standard (BHC, LSS, MSTC) STC 6"DT

24" 36" 6"

Depth of investigation: BHC LSS-SDT

5" 12" (12 ft spacing)

Readings in(ms/ft) Limestone (0pu) Sandstone (0pu) Dolomite (0pu) Anhydrite Salt Shale Coal Steel (casing)

47.5 51-55 43.5 50 67 >90 >120 57

25 25

Magnetic Resonance Measurement



1 1


Magnetic Resonance Sand grains Irreducible water

Free Fluid

A typical sandstone formation consists of rock grains plus fluids. The fluids are distributed as free fluids and immobile fluids The grains can be large or small or mixed. There may or may not be clay minerals associated with the formation Magnetic resonance is used to analyse the porosity distribution and estimate permeability 2 2


Dephasing and T2 Relaxation Time Z

Alignment along Bo

X

The protons are aligned in a magnetic field

Y Z

The protons are tipped out of the field by 90°

Tipping

X Y Z Dephasing

X Y

The protons precess back into line. during this time they ‘dephase’ with each other.

3 3


Precession

The spin of the proton in a magnetic is the same as a top in a gravity field. They spin around their axes and also in a direction around the applied field.

4 4


Measurement

The protons act as minute bar magnets. In a magnetic field the generate a signal at the Larmour Frequency. This is picked up by the receivers. The more protons the higher the amplitude. Hence the tool measures the number of hydrogens or the porosity 5 5


Spin Echoes

The pulse sequence consists of firstly a pulse to push the protons at 90° of the permanent field. Then after a time another pulse to ‘flip’ them through 180°. This continues for a set number of echoes. 6 6


Spin Echoes 2

The race analogy shows the runners as protons dephasing. The echo pulse reverses the field allowing the slower ‘runners’ to be in front. When they all line up again (6) a signal is generated that is picked up by the antenna. 7 7


T2 Decay

The gradual decay of the peaks reflects the formation signal to be measured, T2. The transverse relaxation time. The CPMG sequence eliminates spurious effects.

8 8


Porosities

Clay Bound Fluids

Capillary Bound Fluids

Producible Fluids

There are three ‘porosities’ in the rock system Producible or Free Fluids - fluids that can move Capillary Bound Fluids - fluids (usually water) stuck to the rock surface by surface tension forces. Clay Bound Fluids - the water associated with the clay minerals. The relaxation time for capillary bound fluids and clay bound fluids are very short.

9 9


Free Fluid vs Irreducible Fluid

The Magnetic Resonance shows a difference in the time distribution for each fluid. An empirical cut-off (for sandstone) of 33msec is used to separate the Free Fluids from the others. 10 10


Amplitude

Amplitude

Pore Size

Large Pore

Small pore

Time msec

Time msec

In a large pore the proton collides with the grain surface less often than in a small pore The relaxation time is reduced The amplitude in both cases can be the same. The porosity is the same in the large and small pores. 1/T2 (msec)

= T2

ρ(S/V) = Transverse relaxation time

S V ρ

= = =

Surface area of pore Volume of pore Surface relaxivity 11 11


Permeability

Porosity = 20% Permeability = 7.5 md

Porosity = 19.5% Permeability = 279 md

12 12


Permeability Equations Method 1: k ~ φb/(S/V)2 1/T2 = ρ2(S/V) k = a (φ φCMR)4 (T2,log)2 a ~ 4 mD/(ms)2 Method 2: Timur/Coates Equation: k = a’ 104 (φ φCMR)4 (FFI/BVI )2 a' ~ 1 mD

13 13


CMR Wellsite Presentation

The key outputs are in track 3, the CMR porosity and the CMR free fluid Index. Track 4 show the T2 distribution Track 2 shows T2 and the permeability Track 1 shows the GR.

14 14


CMR Sonde Cross Section

15 15


CMR Tool Applications • Continuous permeability • Determine Swirr • Measure free fluid volume • Identify thin pay zones (6 in.) • Lithology-independent porosity • Hydrocarbon identification • Low-resistivity pay

Tool specifications Length Weight Minimum hole Logging speed (sandstone) Measurement aperture Combinable Mud resistivity Max. temperature

14 ft 300 lb. 6.5 in. 600 ft/hr 6.0 in. Yes No limits 350°F [175°C]

16 16


CMR Example log 1

17 17


CMR Example Log-2

18 18


CMR Example log -3

19 19


Pore sizes (V/S) pore (µm) 10 -3

10 -2

10 -1

10 0

10 1

Population

Berea 100 Sandstone ρ = 5 µm/s 2

10 -4

10 -3

10 -2

10 -1

10 0

10 1

950517-01

T2 (s)

(V/S)pore = ρ2 T2 Pore Shape

V/S

Sphere diameter = dd/6 Tube diameter = d

d/4

Sheet width = d

d/2

Typical sandstone: ρ2 ~ 5 mm/s Typical carbonate: ρ2 ~ 1.7 mm/s 20 20

Electrical Resistivity Logs



1 1


Resistivity Theory

The resistivity of a substance is a measure of its ability to impede the flow of electrical current.

Resistivity is the key to hydrocarbon saturation determination. Porosity gives the volume of fluids but does not indicate which fluid is occupying that pore space.

2 2


Resistivity Theory 2 Current can only pass through the water in the formation, hence the resistivity depends on: Resistivity of the formation water. Amount of water present. Pore structure.

3 3


Resistivity Model

4 4


Mud Resistivities The first resistivities encountered are those of the mud, mud filtrate and mud cake. The surface measurements to obtain these values are often erroneous. Key points: The samples must be identical to the mud used in the logging interval. Check answers using the Chart Book formulae. Rmf < Rm < Rmc Identify the sample source (measured or charts).

5 5

Salinities chart 10 ppm

8

Grains/gal at 75ÞF


6 5

3

300 400

2

600 500 800 700 200 0 170 0 140 0 120 0 100 0

0.8 0.6 0.5 0.4

300 0

0.3

80 70000 0 60 0 0 500 0 400 0

0.2

20, 000 1 7 , 000 14, 000 1 2 , 000 10, 000

0.1 0.08 0.06 0.05

80,0 70,0 00 00 6 0 , 0 00 50,0 0 0 40,0 00 30,0 00

0.04 0.03 0.02

,000

50 10

75 20

30

100 40

125 150 200 50 60 70 80 90 100

300

0.01

280, 250 000 200,,0000 0 170, 0 0 140, 00 120,000 000 100, 000

Resistivity of Solution (ž - m)

1

250 300 350 400 120 140 160 180 200

10 15 20 25 30 40 50

100 150 200 250 300 400 500

NaCl Concentration (ppm or grains/gal)

200

4

1000 1500 2000 2500 3000 4000 5000

10,000 15,000 20,000

Temperature (ÞF or ÞC)

This chart is used to compute salinities from resistivities of solution e.g. mud, and vice versa. It is also used to find the resistivities at a given temperature. 6 6


Old Tools The voltage measured at M is proportional to the formation resistivity. This electrode configuration is the Normal tool. The distance between the A and M electrodes. The spacing determines the depth of investigation and hence the resistivity being read.

7 7


Normal and Lateral Tools The Lateral device used the same principle. The difference is in electrode configuration and spacing. Problems came from "thin beds" when the signature of the curve was used to try and find the true resistivity.

8 8


Old Tools 2

This figure shows some of the "signature curves" for the interpretation of lateral and normal devices in thin beds. A library exists plus the rules to extrapolate the measured value to the true resistivity of 9 9 the bed.


Laterolog Principle

A current-emitting electrode, Ao, has guard electrodes positioned symmetrically on either side. Guard electrodes emit current to keep the potential difference between them and the current electrode at zero. This forces the measuring current to flow into the formation of interest. 10 10


Tool Types Various configurations have been used: LL3 The first tool of its type; single guard electrodes. LL7 Four extra electrodes added, including a feedback loop to keep the bucking current at an optimal value. LL9 Two more electrodes added, plus a Shallow Laterolog measurement. Deep and Shallow measurements were taken sequentially. DLT Same as the LL9 but able to run deep and shallow simultaneously. 11 11


borehole effects Laterologs see the borehole environment as: RLL = Rm + Rmc + Rxo + Rt

Rm in

Best measurement is in salt-saturated, low resistivity mud. Worst readings obtained fresh mud. Measurements cannot be taken in oil-based mud.

Rmc

Usually neglected as very small.

Rxo

Depends on Rmf, needs to be known.

Rt

Parameter to be measured, the higher the 12 better. 12


Laterolog Corrections The log must be corrected for the effect of mud resistivity. There are two possible conditions: Centred. Eccentred. There is only a small difference between the two in most circumstances for the modern tool DLTE. The old tool, DLT-B, could only be run centred. The correction to the shallow is greater than the deep, especially in large hole sizes.

13 13


Laterolog Corrections

14 14


Correction Charts

15 15


Bed Correction The next correction accounts for the effects of adjacent beds which still occur despite focusing. If the shoulder bed is highly resistive, the log has to be reduced. (Squeeze.) If the shoulder bed is of low resistivity, the log has to be increased. (Anti-squeeze.)

LLS has a better definition because it is a shallow device.

16 16


Squeeze/Anti-Squeeze

Rs is the resistivity of the bed above and below the formation of interest. The chart is entered with the bed thickness, moving up the ratio RLLD/RS.

The correction factor is read on the y-axis.

17 17


Squeeze/Anti- Squeeze The same method is used in this chart for the Shallow Laterolog

18 18


String Effect

Laterolog tools have another problem in conductive beds due to the frequency of the measurement. In long combination tools, the LLD reads too high. The effect has been commonly seen in low resistivity formations.

19 19


Correction Example The correction depends on the hole size, Dh, and the mud resistivity, Rm. This correction has to be applied before any other borehole corrections. A new chart is needed for each tool combination.

20 20


TLC effect There are two effects occurring when a Laterolog tool is run on drill pipe. 1)In TLC operations Laterologs need a special stiff bridle usually made of three sections of tool housing giving a length of 30 feet compared to the normal 80 foot bridle.

2)The total current returns to the pipe which acts as the return electrode. The relative error is proportional to /Ra (the apparent resistivity). This can be up to 200% at low Rt/Rm contrasts and low Rm.

21 21


Example Chart The chart is used to transform the TLC reading into the reading theoretically obtained in a vertical well with a bridle.

22 22


Pseudo Geometrical Factor Once corrected, the log can be evaluated to find Rt. Neglecting the mud and mud cake resistivities (corrected log), the tool response equation is: Ra = J(di)Rxo + (1-J(di))Rt

Where J(di) is the pseudo-geometrical factor which is a function of the invasion diameter, di. For large di, J(di) is large reflecting the important contribution of the invaded zone to the measurement.

23 23


Depth of Investigation The plot shows the pseudo-geometrical factor versus di for various tools. The relative depth of investigation is defined as the invasion diameter for which the invaded zone contributes to 50% of the signal (J = 0.5). The relative depth of investigation is computed from the chart.

For example, it is 35" for the LLS. 24 24


Groningen Effect Resistive Bed

Torpedo

Laterolog Induction

bridle electrode

LLS

LLD /LLG

Groningen Response

distance to torpedo = distance below high resistivity Groningen effect seen.

LLG Induction does not react

LLD increase

DLT measure point

The high and increasing LLD reading, associated with a flat LLS, can be caused by the presence of hydrocarbon in the formation, or by the infamous Groningen effect. 25 25


Groningen Effect Physics

This is caused by the voltage reference (cabletorpedo) becoming non-zero. Caused by highly resistive beds overlying the formation that is being measured. This forces the deep current into the mud column.

26 26


Solutions The HALS/ARI tool can be corrected for Groningen effect. There is a curve measurement by the DLT called LLG, which gives an indication of the Groningen effect. LLG is: An LLD using a bridle electrode as return rather than the torpedo. An indicator of the presence of Groningen Effect because: LLG equals LLD when there is no effect. LLG is affected at a different depth than LLD. LLG is not an LLD corrected for Groningen. 27 27


Laterolog Applications Measures Rt. Standard resistivity in high resistivity environments. Usable in medium-to-high salinity muds. Good results in high contrast Rt/Rm.

Fair vertical resolution (same as porosity tools).

28 28


Laterolog Limits Cannot be used in oil-based muds. Cannot be used in air-filled holes.

Affected by the Groningen Effect in some environments. Difficult to model.

Poor when Rxo > Rt.

29 29


Modelling It is useful to model the tool response for different conditions. The approach of bed boundaries can be seen in deviated wells. Unusual log responses can be checked with different model formations. A finite element method has to be used to model Laterologs, and all resistivity tools. This type of program is heavy on computer time.

30 30


DLT Parameters Vertical resolution:

24"

Maximum reading: LLD LLS

40000ohm-m 6000ohm-m

Minimum reading: LLD LLS

0.2ohm-m 0.2ohm-m

31 31


Azimuthal Laterolog principle

The current emitting electrode is split into twelve separate electrodes. It has 12 electrodes set equally spaced around the tool giving 12 azimuthal Laterolog readings. These are focused to give a deep reading and a very shallow reading of the tool stand-off.

32 32


Azimuthal Laterolog principle 2

There are two modes: Active mode: current is emitted from each of the electrodes. 12 calibrated resistivities are output in real time. Passive mode: no current is emitted. This is used if the resistivity is above 2 ohm-m The mud resistivity is needed to compute the resistivities.

33 33


Azimuthal Laterolog corrections The borehole correction is similar to the other Laterolog measurements. It is a function of the borehole diameter and the ratio of formation to mud resistivity. This chart is used to make the correction. It can be done by the surface acquisition system.

34 34


Azimuthal Laterolog outputs The standard outputs of the Azimuthal Laterolog are: Standard LLD and LLS curves. LLhr - high resolution deep Laterolog. 12 azimuthal resistivity curves. 12 electrical stand-off measurements. An electrical image of the borehole similar to FMS.

35 35


Azimuthal Laterolog uses The simplest use of the ARI is for deep resistivity in laminated formations. Here the tools high vertical resolution reads the correct value when the LLD averages the beds.

36 36


Azimuthal Laterolog Uses 2 Another use of the ARI is fracture identification. As with any resistivity measurement it reacts to the presence of the conductive fluid (mud) in the fractures. They show up as low resistivity on each of the 12 resistivities at different depths depending on their geometry. The best indication is the image.

37 37


ARI Uses 3 There are a number of other uses for this azimuthal tool: Heterogeneous formation One or more of the resistivities will react to a heterogeneity while the others read normally. An example could be a shale lens in an oil zone. Here the resistivity will be reduced by the low resistivity shale if a standard LLD is used, however the shale will be "seen" by some of the azimuthal resistivities and the true resistivity of the oil zone can then be understood.

Horizontal well The ultimate heterogeneous formation. The azimuthal resistivities will be able to see the overlying and underlying formations, the cap rocks and the water table for example. Knowing where these are will greatly assist in completing the well as well as computing saturations.

Dip computation This is an extra due to having 12 azimuthal resistivities and the possibility of adding directional information. The output dips are not as good as a standard Dipmeter as the resolution is not as fine, however, they are sufficient for most structural interpretations. 38 38


Azimuthal Laterolog parameters Depth of investigation LLhr close to LLD Vertical resolution 8" (in a 6" hole) Azimuthal resolution 60° for a 1" stand-off Resistivity range 0.2 - 100000 ohm-m Mud resistivity < 2 ohm-m active mode < 5 ohm-m passive mode

39 39


Microresistivity Devices Shallow reading versions of resistivity tools; always pad-mounted. First was the Microlog which is still in use; Second was the Micro Laterolog (MLL), replaced by Proximity (PL) tool, replaced by MicroSpherically Focused Log (MSFL), replaced by Micro Cylindrical Focused Log(MCFL)

Objective is to read Rxo (Invaded Zone Resistivity) only. Tools are focused to pass through the mud cake.

40 40


Microlog Uses Microlog is used to identify permeable zones.

2" Micronormal. (A -> M2) 1"x1" Microinverse. (A -> M1) (Slightly different depths of investigation).

If the zone of investigation is shale (no invasion), both curves read the same. If the zone is sand (with invasion), Microinverse reads mud cake plus some of the formation and Micronormal reads some mud cake plus the formation (slightly higher). We are only interested in the separation between these curves and so scales are chosen to show this and not the rest of the readings. 41 41


MSFL Principle

This tool uses a set of 5 electrodes which focus the signal into the invaded zone just beyond the mud cake. 42 42


MSFL Borehole Corrections In spite of its focusing, the tool still needs to be corrected for the mud cake thickness and resistivity. The correction requires an input of mud cake thickness which is not measured directly.

It also needs the mud cake resistivity which is either measured or computed from charts. The tool focusing has been set assuming there is always some mud cake, hence the tool always needs some correction. 43 43


Uses and Limits Uses: Rxo measurement in water- based muds. Correction for deep resistivity tools. Sxo determination.

Limits: Rugose hole. Oil-based mud. Heavy or thick mud cake.

44 44

Induction logs

Induction Logs


1 1

Induction logs

Induction history The idea for the tool developed out of mine detector work done by Henri Doll during the Second World War. The objective was to measure resistivity in fresh or oil-based muds. The first tools had 5 coils to focus the signal. The next generation of tools employed 6 coils. Two measurement curves were eventually developed, a medium and a deep paralleling the Laterolog's shallow and deep readings.

2 2

Induction logs

Induction Principle An Induction tool uses a high frequency electromagnetic transmitter to induce a current in a ground loop of formation. This, in turn, induces an electrical field whose magnitude is proportional to the formation conductivity.

3 3

Induction logs

Geometrical Factor In a simple model, (tool centred, homogeneous formation), the response of the tool can be calculated as the sum of all the formation loops coaxial with the sonde. Each signal is proportional to the conductivity and to a Geometrical Factor, Gi which depends only on the loop position with respect to the transmitter and receiver positions.

The sum of all the geometrical factors is equal to 1.

4 4

Induction logs

Depth of Investigation This is equivalent to the plot seen for the laterolog. Once again, the depth of investigation can be obtained from this plot using the same criteria. Depth of investigation = zone contributing 50% of the signal.

5 5

Induction logs

Shoulder Bed Effect To minimise the shoulder bed effect, the tool is focused using multiple coils. In addition, the shoulder bed response is suppressed to improve the vertical resolution. Deconvolution gives greater weight to the signal measured at the sonde centre and less weight to the signals from either side. The Phasor tool uses the X-signal to make a nonlinear deconvolution correction.

6 6

Induction logs

Skin Effect Caused by ground loops creating their own fields and interfering with the signal being measured. The net result is a reduction in the measured conductivity. The correction increases with increasing conductivity. The traditional solution was to employ a booster algorithm. The current tool uses the X-signal to make the correction.

7 7

Induction logs

Borehole Effects Induction tools measure Conductivity. Induction tools measure resistivity in Parallel. Thus Induction tools see the borehole environment as:

Cm - Best readings occur in high resistivity mud, oil-based is better, fresh mud is good, saltsaturated mud is worst. Cmc - Usually neglected as very small. Cxo - Depends on Rmf - needs to be known. Ct - Parameter to be measured, the higher the better.

8 8

Induction logs

Corrections The tool has to be corrected for borehole effects. Procedure 1) Compute borehole geometrical factor. 2) Find additional signal due to the borehole. 3) Convert log resistivity into conductivity. 4) Remove borehole signal from total signal. 5) Convert result back to resistivity.

This is best done in the field using either the Surface Acquisition units It is also possible using Chart Books.

9 9

Induction logs

Corrections

10 10

Induction logs

Correction Charts

11 11

Induction logs

Correction Charts Procedure: Obtain the Borehole Geometrical factor Enter the value on the axis. Draw a line through the mud resistivity to obtain the hole signal.. Subtract the hole signal from the measured conductivity to obtain the corrected value

12 12

Induction logs

Bed Thickness

The induction needs to be corrected for the effect of resistive or conductive shoulder beds. After signal processing this effect is minor except in beds less than 6'.

13 13

Induction logs

Enhancement The standard Deep Induction tool has a vertical resolution of 6' to 8'. It is impossible to improve the tool's hardware design as the measurement is "blind" at some thickness. The Medium Induction tool can "see" all thickness. The Medium signal is used to enhance the more accurate Deep reading. Enhanced resolution of 3'. Very enhanced resolution of 1.5' to 2'. A problem - the medium may be adversely affected by borehole conditions (rugosity, caving), resulting in a poor deep reading. 14 14

Induction logs

Limits Cannot be used in salt-saturated muds unless in small hole sizes. Cannot be used in high resistivity formations. Poor in thin beds. Poor when Rxo < Rt. Dipping beds will affect the logs.

15 15

Induction logs

Uses Measures Rt.

Ideal in fresh or oil-based environments.

Ideal for low resistivity measurements and when Rxo > Rt.

16 16

Induction logs

Modelling As for the laterolog tool, it is useful to model the induction response to a given situation. The Induction is simple to model in almost any case as it is based on electromagnetic theory. Programs exist for both vertical and deviated wells. Effects such as the effect of dipping beds can be analyzed and the true resistivity of the layer obtained. Horizontal wells are also handled so that the response of an electromagnetic tool to a nearby cap rock or water table can be predicted. This is important in horizontal wells where the technique called Geosteering is used to accurately position the well trajectory. 17 17

Induction logs

Induction Parameters Vertical resolution: Standard Enhanced Very Enhanced

6' to 8' 3' 1.5' to 2'

Depth of investigation: Deep

60"

Medium

30"

18 18

Induction logs

AIT principle The tool measures 28 independent signals from 8 arrays. There is one transmitter operating at three frequencies. The in-phase (R) and the quadrature (X) signals are both measured. The conductivities are combined using radial and depth functions. These are software focused to give: 5 depths of investigation:10", 20", 30", 60" 90". 3 vertical resolutions: 1', 2' and 4'.

19 19

Induction logs

AIT depth of investigation The AIT has set radial depths of investigation which are not affected by changes in conductivity. The values are taken as the point where half the signal comes from shallower levels. In comparison to the 10", 20", 30", 60" and 90" of this tool, the medium and deep of the old tool are around 30" and 60" respectively.

20 20

Induction logs

AIT Corrections There are well defined borehole corrections to be applied to the measurement. These are made in real time by the software. The inputs required are: Borehole cross section. Mud resistivity. Stand-off. The tool can compute any of these from its measured signal as well as the formation resistivity. However, normal practice is to input at least two of them. A measurement of the mud can be made with an auxiliary sonde or surface measurement. The former is best as logs made have shown considerable heterogeneities in the mud column with depth. A caliper tool can give the hole dimensions.

21 21

Induction logs

AIT Rt-Rxo-invasion As the AIT produces five logs with differing depths of investigation, a more realistic description of the invasion can be made. The old model is:

New model:

This model has four unknowns with the addition of a ramp profiled for the invasion. 22 22

Induction logs

AIT independent model The AIT can be displayed as an image. The simplest image is of resistivity radial profile starting at the borehole and going out into the formation. This image simply extrapolates the readings of the tool assigning colour classes to the resistivity level. It is called an "independent model" because it makes no assumptions about the resistivity distribution.

23 23

Induction logs

AIT saturation To obtain a saturation image, some assumptions have to be made about the resistivity profile. The inversion model is used to produce the parameters needed for a saturation image, Rt, Rxo and an invasion distance. The r2 radius is taken as the limit of invasion for this calculation. The image will then show the saturation away from the borehole, a radial profile. This image is a more accurate picture of the invasion as long as the saturation gradient is constant with depth. The porosity is also assumed to be constant.

24 24

Induction logs

AIT volumes Variations in formation water, drilling parameters and saturation gradient obscure comparisons along a well and between wells. A filtrate invasion profile is constructed and converted to a fluid volume by multiplying it by porosity.

Hence the AIT outputs plus the Rmf are all that is needed to compute the volume of mud filtrate, Vmf. The result is integrated with depth to give the volume of filtrate per unit depth. 25 25

Induction logs

examples 2

The invaded volumes computed here show an increase with depth. The results could be used to plan sampling points or a well test. 26 26

Induction logs

examples 3

Cable tension (TENS) (LBF) 10000.0

.2

90 Inch investigation (ohmm)

2000

.2


2000

.2


2000

.2


2000

.2


2000

0.0

0.2

SFL unaveraged (SFLU) (ohmm)

0.2

Medium resistivity (ILM) (ohmm)

2000.0

0.2

Deep resistivity (ILD) (ohmm)

2000.0

2000.0

The AIT logs (2' vertical resolution) read correctly in this zone giving a hydrocarbon profile. The DIL logs are ambiguous as the SFL (electrical log) longer reading shallow because Rxo is less than Rt

27 27

Induction logs

AIT parameters Radius of investigation: 10" (A x 10) 20" (A x 20) 30" (A x 30) 60" (A x 60) 90" (A x 90) Vertical resolution (x): 1' 2' 4' Resistivity range: 0.2 - 1000ohm-m

28 28

Basic Log Interpretation

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