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Petrophysics Practice and Pitfalls Tutor: Graham Webber Edinburgh November 2010

What you should expect to be able to do by the end of the course? Understand what logs (wire-line and LWD) are available and what they contribute to formation evaluation. Plan well data acquisition programmes. Value of Information Data Types Available

Quality check log data. Make a quick-look interpretation of logs.

Make a simple deterministic interpretation of logs to include: Lithology – Clay Volume Porosity Permeability Sw Know when to use shaly sand analysis and when not.

Net & Pay 2

What you should expect to be able to do by the end of the course?

Understand the necessity and means of using core measurements to calibrate petrophysical models. Porosity Calibration Permeability Predictors Use of Capillary Pressure Data

Understand the main differences between clastic and carbonate petrophysics. Appreciate the importance of the petrophysicist communicating with the whole subsurface team to ensure: Other specialists insights are considered when selecting appropriate parameters and methods.

Other specialists requirements of the petrophysical model are understood before the model is developed. 3

Course Outline and Timetable Day 1 Module 1: Petrophysics Definition and Contribution

Section 1.1: Introduction Section 1.2: Petrophysical Properties Section 1.3: Capillarity and Fluid Distribution Section 1.4: Net and Pay

Module 2: Well Environment and Data Available Section 2.1: …..The Borehole Environment Section 2.2:……Petrophysical Data Types 1: Wire-line Log Data

Module 3: Looking at Logs Section 3.1: …..Log Quality Assurance Section 3.2:……Quick-look Analysis of Logs Exercise 1 4

Petrophysics Practice and Pitfalls Practice Performance; actual doing, proceeding; habitual action (Chambers Twentieth Century Dictionary).

Pitfall A concealed hole in the ground that serves as a trap.

An unpleasant source of trouble or danger; a hidden hazard. 5

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Module 1

Petrophysics Definition and Contribution

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Section 1.1 Introduction

Introduction: Petrophysics Definitions Petrophysics is the study of rock properties and their interactions with fluids. Description of oil and/or gas distributions and the production flow capacity of reservoirs, from interpretations of pore systems and fluid interactions using all available data.

8

Introduction: What do we want to learn from Well logs?

Depth Permeable formations Porosity Thickness of reservoirs Net Sand / Net Pay Subsurface Pressures Fluid phase, gas, oil, water Fluid saturations Sw, So, Sg Moveable Hydrocarbons Depth of formations Environment of Deposition Lithology Temperature Velocity/Time Seismic responses Correlation with other wells

9

Where petrophysicists sit in the sub-surface world? Geophysicist

Geologist

• Rock Physics

• Porosity

• Gassmann Substitution

• Permeability • Saturation Height

Reservoir Engineer

• Net Vclay

• Petrel

• Fluid contacts

• Relative Permeability • Saturation Height

Petrophysics

Geomechanics

• Core

Commercial

Production Technologists

• Sonic / Density

• Porosity

• Formation Strength

• Permeability

• Sanding Tendency

• Fluid Analysis • Perforation Depths

Drilling • Pore Pressure • Bit Selection

10

The Petrophysicists Contribution to Calculating STOIIP More of the parameters used in the calculation of STOIIP are provided by Petrophysics than any other discipline!

Petrophysicist

Geophysicist

STOIIP Where,

STOIIP GRV Net Gross Ø Sw B0

= = = = = = =

GRV

N G

1 (1 S w ) B0

Stock tank oil initially in place. Gross rock volume. Net Reservoir Gross Reservoir Porosity Water Saturation Formation Volume Factor

Reservoir Engineer Geologist 11

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Section 1.2 Petrophysical Properties

Porosity Defined as the ratio of Void space to Bulk Volume of the rock: Porosity is a measure of the space available for storage of fluids:

Vp Vt Where,

Ø = Porosity Vp = Pore Volume Vt = Total Volume

Expressed as Percentage (%) or Decimal (v/v) 13

Porosity Types by mode of formation Types of porosity Primary – originating as the sands were laid down Inter-granular or inter-particle Intra-granular Inter-crystalline Bedding planes Secondary – formed by various processes after sands were formed Solution porosity or Dissolution Dolomitisation Fractures Vugs Shale Porosity Secondary porosity is generally far more important in carbonates than sandstones

Fracture

Inter-granular or intercrystalline pores

Micropores

Vugs

For clean sandstones and carbonates, Porosity can readily be derived from logs For complex formations porosity data from core is required to calibrate the log response 14

Porosity Types: Total versus Effective

Total Porosity Øt Ratio of all pore space (and clay structural water seen by some tools) to bulk volume. Includes all pores regardless of the degree of connectivity or pore size. Includes water in clay structure.

Effective Porosity Øe Ratio of interconnected pore volume to the bulk volume.

15

Volumes and Porosity

Porosity Definitions

Absolute or Total Porosity Øt Matrix

Effective Porosity Øe

VSHALE Quartz

Clay Layers

Clay surfaces & Interlayers

Small Pores

Large Pores

Hydration or Bound Water

Capillary Water

Hydrocarbon Pore Volume

Isolated Pores

Structural Water

Irreducible or Immobile Water

16

Controls on Porosity Carbonates

Sabkha Facies Rocks – Carbonate Dominated

Dolostone

Inter-granular Intra-granular Mouldic Reefal Dolomitisation

Sandstones Grain size Grain shape Sorting Packing Cementation Clay volume and type Compaction/depth of burial

5 cm

5 cm

Core Photo

17

Porosity Ranges

Type

Porosity Range (%)

Recent Sands – Unconsolidated

35-45

Sandstones

15-35

Tight Sandstones

5-15

Limestones

2-20

Dolomites

2-30

Chalks

5-40

Note: Theoretical maximum inter-granular porosity for cubic-packed spherical grains is 47.6% 18

Porosity Measurements Core porosity Measure two of: pore volume, grain volume and bulk volume of core plug and ratio them. Direct measurement but: Measure Øt or Øe (or something in between) depending on pore types present, clay content and method of cleaning and drying. Measured under laboratory conditions rather than reservoir stress. Require correction to reservoir conditions for comparison with or calibration of log porosity.

Log Porosity Sonic, Density, Density/Neutron, NMR. Porosities measured differ. No log measures porosity directly. Calibrate to core when possible. 19

Porosity and measuring techniques Log and core Porosity Measurements Total Porosity, Sonic Log Total Porosity, Neutron Log Total Porosity, Density Log Absolute or Total Porosity

VSHALE Quartz

**

Oven-dried Core Porosity

Matrix

Clay Layers

**

Humidity-dried Core Porosity

Clay surfaces & Interlayers

Small Pores

Large Pores

Hydration or Bound Water

Capillary Water

Hydrocarbon Pore Volume

Isolated Pores

Structural Water

Irreducible or Immobile Water

** If sample is completely disaggregated (after Eslinger and Pevear, 1988)

20

Permeability Permeability is a measure of the ability of a porous medium to allow fluids to flow through interconnected pores. Fundamental to the success of oil and gas production.

Controls on permeability: Effective porosity. Hence: Grain size, grain shape, grain size distribution (sorting), grain packing, degree of consolidation, cementation.

Types of clay present: Swelling (when in contact with fresh water) clays, smectite and montmorillonite. Pore filling clays, illite. Fibrous Pore Filling Illite in Sandstone*

21 * Reference D. R. Pevear Proc. Natl. Acad. Sci. Vol 96. March 1999.

Darcy Equation for fluid flow

Flowrate  Q

k . A. P µ.L

Where, Q = Flow Rate in cm3/sec (m3/sec) k = permeability in Darcy (m2) A = cross sectional area of sample in cm2 (m2) ∆P = Pressure differential across the sample in atm (Pa) µ = viscosity of flowing fluid in centipoise (Pa.sec) L = Length of sample in cm (m) (The conversion of CGS to SI units is 1 Darcy = 0.9869 x 1012 m2)

Poor

< 2mD

Fair

2-10m

Good

50-100mD

Excellent

500mD 22

Permeability Measurement and Estimation Carman-Kozeny Correlation Kozeny modelled permeability in a set of capillary tubes. He related permeability to porosity and specific surface area:

k

Where,

k = SVGR = Ø =

1 2 SVGR

3

1

2

Permeability Specific surface area (total area exposed in pore space/grain volume) Porosity

Permeability is measured on core. In most (all) cases it is difficult to estimate permeability from logs without core calibration. No log measures permeability directly.

23 Image Reference http://faber.ms.northwestern.edu/shanti.html

Fluid Saturation Water saturation Sw is the fraction of the porosity filled with water. Expressed in % or v/v. The objective in formation evaluation is derivation of Hydrocarbon Saturation (Shc).

It is normally easier to derive Water Sw and calculate Shc:

S hc (1 S w ) 24

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Section 1.3 Capillarity and Fluid Distribution

Capillarity and distribution of fluids in the reservoir 3. At increasing height above the FWL progressively smaller pores are filled and oil saturation increases.

Depth Capillary Pressure Pc

Oil Gradient Water Gradient Free Water Level

Pressure 1. The reservoir is initially water saturated. Migration of oil into the reservoir causes drainage of water.

2. Close to the FWL only large pores are invaded by oil. Low oil saturation.

26

Capillarity, the drainage process

Oil replaces water Water

Oil

Po

Pw

So

Drainage Oil enters largest pores: Pentry

Po-Pw 350

Matrix The higher the pressure within the oil Po the higher the curvature of oil/water interface and the smaller are the pores penetrated by oil.

Swirr

30

250

25

200

20

150

15

100

10

50

Capillary Pressure psi

Pw

Height above FWL ft

Oil

Po

300

35

5

Pentry

0

0 0

0.2

0.4

0.6 SW

0.8

1

27

Hydrocarbon / Transition and Water Zones

Mixed Hydrocarbon and Water Production

Hydrocarbons

Transition Zone OIL / WATER CONTACT FREE WATER LEVEL

Water

Water Production

0

Water Saturation

Decreasing Sw to Swirr / Increasing Hydrocarbon Saturation

Water-free Hydrocarbon Production

Increasing Height above the Free Water Level

Sw Irreducible (Swirr)

1.0

28

Saturation Height: Relation to Rock Quality

Poor quality rock:

Swirr

Asymptote

Swirr

Low Ø, Low K small pores Transition Zone

Depth

Poor Rock Oil/Water Contact

Poor Rock Entry Height

Plateau

Good Rock

Good quality rock:

High Ø , High K larger pores

Free Water Level

0

Oil/Water Contact

1 Water Saturation

29

Fluid Distribution with Varying Rock Type and/or Quality

Rock Type

B

A

C

B

B A B C B C

Capillary pressure or Height

Sedimentary Sequence

C

OWC

OWC

A OWC

-

Water Saturation

+

-

Sw Log +

30

Dependence of Permeability on Saturation: Relative Permeability Previously described permeability to a single fluid.

1

In the presence of a second fluid permeability to the first is reduced. Relative Permeability

0.8

Relative permeability:

0.6 Kro Krw

0.4

0.2

Permeability to one fluid in the presence of a saturation of a second fluid.

0 0

0.2

It is fraction relative to the permeability for a single fluid and is reduced as the saturation of the second fluid increases. Sw Critical

0.4

0.6

0.8

1

Water Saturation

So Irreducible 350

Sw Irreducible

At SCritical dry oil is produced. In the transition zone produce oil with a water-cut.

300

Height above FWL ft

Kro (or Krg) and Krw

35 30

Dry Oil Zone

250

25

200

20

150

15

Transition Zone

100

10

50

At oil saturations below Sor produce only water.

Capillary Pressure psi

This effect is quantified by relative permeability.

5

Water Zone

0 0

0.2

0.4

0.6

0 0.8

1

SW

31

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Section 1.4 Net and Pay

Net and Pay Gross Rock: Comprises all rock in the evaluation interval.

Net Sand: Comprises those rocks which may have useful reservoir properties. Sand is a generic oilfield term for lithologically clean sedimentary rock. Determined using a Vclay cut-off. Vcl cut off

Net Reservoir Comprises those rocks which do have useful reservoir properties. Determined using a porosity cut-off on Net sand. cut off

Net Pay: Comprises the net sands that contain hydrocarbon. Determined using a water saturation cut-off on Net Reservoir Sw

cut

off

33

Determining Net cut-offs

Determine using cut-offs equivalent to appropriate permeability: Oil field k=1mD Gas field k=0.1mD

Check sensitivity to cut-offs Compare with core data if possible Compare with production profile from PLT 34

Determination of Net Pay

„Net Pay‟ is derived from Net

Sw cut off of 50% -60% commonly used – arbitrary.

120 Relative Permeability (%)

Reservoir with the additional cutoff of water saturation to take into account the relative permeabilites of hydrocarbons and water.

Example: Relative Permeability v. Water Saturation

Kro

100

KrW

80 60 40 20 0 0

20

40

60

80

100

Water Saturation (%)

May be justified by examination of relative permeability data. 35

Course Outline and Timetable Day 1 Module 1: Petrophysics Definition and Contribution Section 1.1: Introduction Section 1.2: Petrophysics Properties Section 1.3: Capillarity and Fluid Contacts Section 1.4: Net and Pay

Module 2: Well Environment and Data Available Section 2.1: …..The Borehole Environment Section 2.2:……Petrophysical Data Types 1: Wire-line Log Data

Module 3: Looking at Logs Section 3.1: …..Log Quality Assurance Section 3.2:……Quick-look Analysis of Logs Exercise 1

36

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Module 2: Well Environment and Data Available to the Petrophysicist

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Section 2.1 The Borehole Environment

The Borehole Environment

Introduction The borehole is a very „extreme‟ environment, subject to changes in: temperature pressure chemistry

as drilling progresses. Mud circulation stops and starts, drilling rates vary; mud/rock interactions can cause formations at the borehole wall to swell, fracture or disintegrate, leading to tight hole or enlargement.

All borehole measurements are therefore affected to some degree by drilling mechanics and drilling fluid characteristics. 39

The Borehole Environment

Muds There are many types of drilling mud systems: Water, Oil, Synthetic Oil, Foam or Air based. (The most commonly used are Water- or Oil-based systems). Water-based muds are conductive. Oil-based muds are resistive.

All fluid muds perform a number of functions: 1. 2. 3. 4. 5.

Cooling the drill bit as it cuts through rock formations Clearing the rock „cuttings‟ from the bit and circulating them out of the hole Lubrication of the drilling bottom hole assembly (BHA) decreasing drag Preventing formation fluids, especially hydrocarbons, from escaping to surface Preventing rock cuttings from settling out from the mud column while drill pipe connections are made

6.

Sealing the borehole wall to reduce fluid loss to porous / permeable formations 40

The Borehole Environment

Effect of Muds on Log Data Water-based mud (WBM) often cause chemical reactions with clay minerals in the formations (mudstones / shales), which lead to clay swelling or clay movement within the pore spaces of the rock. Potassium Chloride (KCl) is sometimes used in the water based muds to help to reduce this reaction. However, the Potassium, being radioactive, has an effect on wire-line log quality (Gamma Ray). Barite is often used as a weighting agent in drilling mud. When present it masks the formation PEF log curve but may provide a fracture indicator. Oil-based mud (OBM) avoids, to a greater degree, the chemical interaction of water-based mud with reactive clays. From a formation evaluation standpoint oil-based muds are non-conductive and water based muds are conductive. This influences the type of logging tool used to measure formation resistivity (and the SP cannot be logged in OBM). 41

The Borehole Environment

Washouts Hole enlargement mechanical / chemical. Weakly cemented sands or chemically-reactive shales / mudstones can be eroded by the force of the mud circulation in the well bore. This can enhance the cutting effect at the bit and enlarge the hole diameter. The longer the hole is left uncased, the more chance of increased hole enlargement.

Over gauge

42

The Borehole Environment

Tight Hole Conditions Hole diameter may be reduced in a number of situations: 1. When swelling shales „squeeze‟ into the borehole 2. When a mud cake is developed across a porous and permeable formation 3. When halite (Rock Salt) „flows‟ as pressure of overburden is released by drilling to the well bore under gauge in gauge

Over gauge

43

The Borehole Bit Diameter

under gauge

overgauge gauge

In gauge

Under-gauge Hole - due to development of drilling mud cake against porous and permeable beds but may also indicate chemical instability e.g. swelling clays which are reacting to mud chemistry.

Over-gauge Hole - due to weak formation mechanical or chemical properties - exploited by drilling mud pressure and drill and BHA action.

In-Gauge Hole - due to mechanically and chemically stable rock properties and good mud chemistry and overbalance.

44

The Borehole Environment

Invasion Formation fluids are kept in place by maintaining an „overbalance‟ pressure of the mud in the borehole. The pressure exerted by the weight of the mud column is greater than the pressure of fluids trapped in the formation. In porous and permeable formations this overbalance pressure will force a net inflow of a portion of the drilling mud - the mud filtrate - into the pore spaces of porous and permeable formations. This phenomenon is called „Invasion‟. The larger mud solids collect at the borehole wall and develop a „mud cake‟, which has a very low permeability and thus tends to seal off the formation to further filtrate invasion. Build up of Mud Cake (under gauge)

45

The Borehole Environment

SECTION VIEW PLAN VIEW

Rmc Ro

Hmc

Rxo

Rm

Sxo

Sw

Rt Ri Invaded Zone

Non-invaded

Si

R = Resistivity S = saturation m = mud mc = mudcake xo = flushed zone i = invaded zone t = uninvaded zone w = formation water o = 100% water saturated, uninvaded zone

Transition Zone Flushed Zone Mudcake

Borehole

46

The Borehole Environment

Invasion The depth of invasion is controlled by the formation porosity and permeability and the mud characteristics (pressure differential between mud column and formation, viscosity and fluid loss).

Rmc Ro Rt

Rxo

Rm

Sxo

Ri

Sw Si

Invaded Zone

High permeability beds generally tend to show less invasion, due to fast mudcake build-up, while lower permeability beds tend to have more invasion.

Non-invaded Transition Zone Flushed Zone Mudcake Borehole

As mud invasion is a volume system, the depth of invasion in high porosity beds is shallow and correspondingly the depth of invasion in low porosity beds is deep.

The effect of invasion will decrease away from the wellbore so that there is a „transition zone‟ developed, from mud filtrate at the well, through a zone of mixed filtrate and formation fluid, to the „non-invaded zone‟ where original formation fluids are found.

47

Mud Filtrate Invasion

Well Bore

Mud Cake

FORMATION FORMATION WATER WATER

MUD MUD FILTRATE FILTRATE

Resistivity

Mud Cake

Well Bore

MUD FILTRATE

OIL

FORMATION WATER Flushed Zone

Flushed Zone Transition Zone

Non-Invaded Zone

Transition Zone

Non-Invaded Zone

Well Bore

OIL FILTRATE

FORMATION WATER

Well Bore

Mud Cake

Oil-Based Mud System (c) Water-bearing formation (d) Oil-bearing formation

Mud Cake

Resistivity

Water-Based Mud System (Rmf >> Rw) (a) Water-bearing formation (b) Oil-bearing formation

OIL FILTRATE

OIL

FORMATION WATER Flushed Zone

Flushed Zone Transition Zone

Non-Invaded Zone

Transition Zone

Non-Invaded Zone

48

The Borehole Environment

Log Corrections Poor hole conditions (or large hole diameters) will affect logging devices that are calibrated to measure in a specific borehole diameter. Log measurements may have to be corrected for a number of borehole effects such as: • • • •

Borehole diameter Presence of mud-cake Depth of mud filtrate invasion The proximity of the tools to boundaries of beds with differing lithology, and hence, log characteristics

49

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Section 2.2 Petrophysical Data Types 1 Wire-Line Log Data

Data Types Wire-line Logs Down-hole Pressure Measurements LWD (FEWD) Logs Core Data Sidewall Core Plugs Percussion Mechanical

Drilling Data All drilling data is captured on mud logs, these comprise: Cuttings Description and Percentage Inferred Geological column Hydrocarbon Shows (Gas and Fluorescence) ROP and other Drilling Parameters 51

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Wire-line Log Data

Wire-line Logging Tool Development

Wire-line 1927 First well log Pechelbronn field - Electric Log Hand plotting of log data 1931 SP (spontaneous potential)

1931 Continuous pen recorder 1936 Photographic film recording Typical logging combo 1936- late ‟50s SP short normal long normal lateral log resistivity

Recorded separately until 1946 1941 GR and Neutron tools 1946 Sonic log 1949 Induction Resistivity 1951 Laterolog (focussed deep resistivity) 1953 MLL 1953 MSFL 1962 SNP (Sidewall neutron porosity) 1963 DIL (dual induction log) 1964 FDC (compensated formation density) 1970 CNL (compensated neutron log) 1981 LDT (litho-density log) 53

Logging Development: Evolution of Logging and data implications 1950s/60s

Platform Express (PEX)

GR/Neutron, Electric Log, Lateralog, Microlog 3 separate runs, film recording, prints/film only, logs needed digitising if computer interpretation required

1970s/80s GR/Bore hole compensated sonic /Dual Laterologs/Microlaterologs or Induction logs GR/Neutron-density GR/WFT Fluid sampling

2 separate runs to acquire basic logs Computerised data recording and depth shifting Digital data recording to tape Data transmission started at the end of period (used rarely)

1990-Date LWD as part or whole substitute for wire-line GR/Density-Neutron/resistivity) single run GR/Modular formation testers Down-hole fluid typing Additional logs NMR, Array sonic etc Data transmission commonplace

54

Data Types

Wire-line Logs Wire-line logging tools are lowered from the logging unit (Self-contained unit offshore / truck-mounted unit onshore) on an electrical cable into the borehole. The wire-line cable provides two-way communication between the logging unit and the logging tool. Instructions can be sent to the tools / logging measurements are transmitted to the logging unit. Depth measured by length of cable spooled out. Logging is normally carried out when the tools are pulled out of the hole. Allowance for cable stretch and slippage are made by reference to magnetic marks registered at regular intervals on the cable.

Additional measurements made while logging include cable tension, mud resistivity and borehole temperature. The common logging tools are described in the following sections.

55 Schlumberger

Log Names – a few common examples

Description

Mnemonic

Alias

Caliper

CAL

CALI

Gamma Ray

GR

SGR

Spontaneous Potential

SP

Deep Resistivity

LLD

RD, RDEEP

Deep Induction

ILD

RILD

Sonic Compressional

DT

AC, DTCO, DT24

Sonic Shear

DTS

DTSM

Density

RHOB

ZDEN

Neutron

NPHI

CNC

Photoelectric Factor

PE

PEF

Full list of curve mnemonics, listed by company, in SPLWA website: http://www.spwla.org/

56

Caliper Log –

Units Inches or mm, Typical Log scale (6 – 16”)

The calliper log measures borehole diameter by means of either: 1. Mechanical arms attached to the tool which extend to contact the borehole wall as the tool is pulled up through the wellbore. 2. An acoustic signal measurement. – LWD tools.

Uses For calculation of borehole volume in casing cement jobs. Identification of hole enlargement (washouts) or swelling clays. Identification of mud cake development across porous / permeable formations. Breakout analysis for down-hole stress calculations. Input to environmental corrections.

Important Considerations There are different types of callipers: Mechanical 1, 2, 4 Arms / Acoustic Borehole size may exceed the arm length of the calliper tool in very badly washed out holes 57

Gamma Ray Log -

Units GAPI, Typical Log Scale (0 – 150)

Some chemical elements in naturally occurring minerals emit radiation in the form of gamma rays.

The commonest radioactive elements in the earths crust are Potassium (K40), Thorium (Th232) and Uranium (U238). Claystones / Shales, have a large amount of Potassium and Thorium and correspondingly exhibit high total gamma ray readings. Most clean reservoir rocks (sandstones, limestones and dolomite) have very low concentrations of radioactive minerals and therefore are characterized by low Gamma Ray log response. The difference in gamma ray reading is therefore used as a way to discriminate reservoir from non-reservoir rock. 58

Natural Gamma Ray Tool The Gamma Ray tool consists of a sensitive Gamma Ray detector that measures the natural gamma ray emissions of the rock column as the tool is passed in and out of the well. The total gamma ray value is recorded against depth. Uses Lithology determination Correlation between wells Clay volume (“shaliness”) calculation Depth matching or tie-in of multiple logging runs in a well

Important Considerations The tool can be run with most other logging tools The Gamma Ray log is a statistical tool. Therefore exact reproduction of the log curve may not be attained from one logging run to the next. Potassium-bearing muds (KCl) will increase the gamma ray readings Some reservoirs contain radioactive minerals which will mask the contrast between the reservoir and adjacent shale beds. Nuclear Source Tools (Density & Neutron) „activate‟ the formation, hence a higher gamma ray response may be apparent when run in combination with these tools. Some non-reservoir rocks such as coals, salt, anhydrite, gypsum and occasionally shales contain little or no radioactive minerals The log is affected by: formation density, borehole size (large washouts cause a decrease in log value), mud density (the heavier the mud, the more material between the detector and the borehole wall) and the presence of casing (tool response is attenuated by the presence of the steel and cement). 59

Spectral Gamma Ray Log

The Spectral Gamma Ray log is used to analyse the contributions of the main radioactive elements (K, Th and U) to the gamma ray signal. The main occurrences of the three radioactive minerals are: Potassium (%): micaceous clays, feldspars, micas, radioactive evaporites Thorium (ppm) : shales, heavy minerals Uranium (ppm) : phosphates, organic matter

60

Spectral Gamma Ray Tool

The Spectral Gamma Ray tool consists of a sensitive Gamma Ray detector that measures the natural gamma ray emissions of the rock. The gamma ray spectrum is measured while the conventional GR log measures the total count rate. The gamma ray counts are „binned‟ around the energy peaks for K, Th and U and the readings converted to individual log readings for these elements. SGR total GR . CGR GR with U component subtracted.

Th/K Th/U U/K

Uses Shale volume calculation – in sands without appreciable clay volumes, the Spectral Gamma Ray may permit better calculation of shale volume (CGR). Heavy mineral sand identification. Log correlation. Lithology determination – K vs Pe (photo-electric factor), Th / K ratio vs Pe Clay type – ratios e.g. Th / K are used to distinguish particular clay minerals Source rock potential – relationship between U / K ratio and organic carbon in shales.

Important Considerations Environmental corrections for hole size and mud weight are required. Statistical tool requires slow logging speed. 61

Spontaneous Potential Log –

Units (mV)

Uses Detection of permeable and non-permeable beds Shaliness indicator Formation water resistivity (Rw) calculation

Important Considerations The shale base line is frequently not a fixed value from surface to TD but tends to „drift‟ with increasing depth in the well. Poor resolution in thinly bedded formations. Cannot be run in wells with non-conductive muds. If salinities of mud and formation waters are similar there will be very little deflection of the SP curve. SP curve requires environmental corrections for bed thickness, hole size, invasion and resistivity contrasts. The calculation of Rw requires a clean, non-shaly bed response on the SP. SP response is dampened by the presence of hydrocarbons. 62

Spontaneous Potential Log

SP measures the difference between the electrical potential of a fixed electrode (Ground) at the surface and a moving electrode on the logging tool.

Shale

The logging response is generally constant in shale. This is called the “Shale Base line”. Permeable

Deflection of the log response occurs at permeable beds. SHALE

The direction of the response depends upon the mud filtrate salinity and the formation fluid salinity: „Negative‟ deflection to the left = formation water more saline than mud filtrate. „Positive‟ deflection to right = formation water is less saline than the mud filtrate. The magnitude of the SP deflection from base line depends on many factors.

Bore Hole

Permeable

63

Spontaneous Potential Log

xxx

Scale : 1 : 400

DEPTH (8390.FT - 8520.FT) DEPTH FT

GR (GAPI) 0.

SP (MV) 150. 0.

29/05/2004 19:54 LLD (OHMM)

100. 0.2

2000. MSFL (OHMM)

0.2

2000.

8400

8500

64

Sonic Log -

Units µsec/ft, Typical Log Scale (140 – 40 µsec/ft)

The Sonic tool essentially comprises a transmitter that emits a sound pulse and 2 or more receivers that record the returning signal. The first arrival at the receivers is the compressional (p) wave, which travels by the fastest path through the formation. The difference in arrival time of the compressional wave at the two receivers is called the interval transit time (Δt). Other sound waves, like the shear waves, travel through the mud and formation more slowly and arrive later at the receivers.

Modern Sonic tools commonly use multiple transmitters and receivers to correct or „compensate‟ for borehole enlargement or irregularity and tool tilt. 65

Sonic Log Tool

Uses Velocity derivation. Time to depth correlation. Acoustic Impedance calculation. Porosity calculation particularly when Neutron / Density logs are affected by large hole size. Evaluation of secondary porosity in combination with Neutron and / or Density logs – secondary porosity (vugs and fractures) is generally not seen by the Sonic log. Fracture identification – as above for secondary porosity. Overpressure evaluation – change in shale Δt with increasing depth. Lithology identification – some rock types, in their pure state, have diagnostic sonic Δt‟s (halite, anhydrite, gypsum) . Shear velocity from Array sonic data. 66

Sonic Tool and Principles

T1

Mud Dt Sensors

Transmitter compression

R1 R2

R3

8 Receiver Array

Compressional (P) Wave

Upper Receivers

Lower Receivers

Shear (S) Wave

R4

Lower Receivers

T2

Transmitter

Transmitters P Arrival

S Arrival

Stoneley Arrival

1

2 3

Borehole Compensated Sonic (BHC)

Array Sonic 4 5 6 7 8

t

T2 R1

T2 R2

T1 R4

T1 R3

2

67

Sonic Log Tool Important Considerations Cycle skipping – where the first arrival (p wave) is too weak to trigger the far receiver. Instead the tool records a later arrival, leading to a large travel time measurement. The Sonic log shows a large, abrupt „spike‟ to a higher transit time value. This may occur where there is washed out hole or where an inappropriate threshold setting has been applied during acquisition.

Δt is 57 μsec/ft in casing and provides a simple check that the tool is functioning properly. Stoneley Shear Compressional

First motion

68

Shear Sonic Log QC (Monopole & Dipole)

A quality check of the Monopole and Dipole measured shear log should be carried out in order to determine if the shear data is fit for purpose.

GreenbergCastagna lines

Areas where the log is affected by mud arrivals, processing artefacts and poor data are identified from Vp/Vs cross-plots by comparison with GreenbergCastagna empirical lines. Note: Dipole data can also be affected by mud arrivals.

Scale : 1 : 500

Test Well 1 DEPTH (8500.FT - 8600.FT)

DEPTH FT

09/02/2004 15:15

DTS_Mon (uSec/f t) 240.

PHIE (Dec) 40. 0.5

0.

DTLN (US/F) 240.

40.

Mud Arrival 69

Density Tool Tool Skid-mounted tool with radioactive source, shielded receivers and a calliper arm to record hole rugosity.

Uses Density determination. Caliper Arm Porosity determination. γ Fracture identification. Gamma Far γ Detectors Near γ Identification of minerals in evaporite deposits. γ γ Detection of gas. Gamma Source Determination of hydrocarbon density. Evaluation of shaly sands. Calculation of overburden pressures. Acoustic impedance calculation. Photoelectric 'absorption' Index (Pe) [second generation tools onward] lithology sensitive measurement largely unaffected by porosity and fluids. Fluids have low atomic numbers and very little influence on Pe.

γ

γ γ

70

Density Log -

Units gm/cc, Typical Log Scale (1.95 – 2.95 gm/cc)

A radioactive source (Caesium137 / Cobalt60) bombards the formation with focused medium-energy gamma rays (661 keV energy). The gamma rays collide with electrons of the formation in three different types of interaction. These interactions occur at different energy levels.

Pair Production – (>2M MeV high energy interaction) Not important in Density log energy window. Compton Scattering (0.5 – 2 MeV medium energy interaction) Important for the measurement of formation density. Photo-electric Absorption ( 10k eV, Source – 4.5MeV) Intermediate Neutrons (100 – 10k eV) Epithermal Neutrons (0.1-100 eV) Thermal Neutrons (< 0.1 eV)

Increasing Time

78

Neutron Log In a Compensated Neutron Log (CNL) the source and 2 (near and far) detectors are mounted on a tool that is pressed against the borehole wall to minimize the borehole and mud-cake effect. Different neutron detectors tools measure neutron activity at either „thermal‟ or „epithermal‟ energy levels. The ratio of the count rates at the 2 detectors is processed by the computer to produce a linearly-scaled recording of neutron porosity index. Uses Porosity determination. Lithology interpretation. Identification of gas bearing intervals.

79

Neutron Log Important Considerations Shales / micas – shales and some other minerals e.g. gypsum, contain hydrogen in the crystal lattice, as bound water. Since the Neutron responds to all hydrogen, it results in large neutron porosity readings when logging through shale sections. Neutron absorbers – count rates at the thermal neutron detectors are affected by the presence of chemicals such as Chlorine and Boron in the formation water and rock matrix. Gas effect – Gas bearing formations have a reduced hydrogen density and hence an apparently low neutron porosity. Neutron log can be recorded through casing Porosity determination - in gas bearing or shaly formations can be made using the neutron and density logs combined. Neutron porosities are calibrated for clean, water-bearing limestone. Porosity measurements for other lithologies must be corrected for lithology. Borehole effects – Neutron logs can be affected by hole size, temperature, salinity standoff and pressure and are usually corrected for borehole salinity and hole size when processed at the well-site. 80

Summary Log Plot

81

Laterolog Resistivity - Units ohm.m, Typical Log Scale (0.2–2000 ohm.m)

Laterolog devices are „focused‟ electrode tools designed to minimise the effects of drilling mud and adjacent beds. Laterologs provide better vertical resolution than induction logs. The measuring current is forced to flow radially as a thin sheet of current into the formation being logged, thus minimizing the influence of the borehole and of the surrounding formations. Laterolog tools use focusing, or „Bucking‟ currents to force the current into the disc shape. The potential drop varies as the measure current and the formation resistivity change. The Dual Laterolog tool provides 2 depths of investigation for deep and shallow resisitivity (LLD / LLS) 82

Dual Laterolog Tool and Principles

Mud cake

Deep Laterolog (LLd)

Shallow Laterolog (LLs)

Focusing Electrodes Focusing Electrodes

Transmitting Electrode

Focusing current is returned to nearby electrodes causing the measure current to diverge more quickly as it enters the Formation leading to shallow depth of investigation. Both Shallow and Deep Laterolog measurements use the same electrodes and have the same current beam thickness. The different focusing current characteristics produce the different depths of investigation.

Focusing Transmitter Electrodes

MLL Pad

Saturation in the invaded zone as well as the diameter of the Invaded zone must be known to be able to correct apparent resistivity Ra to Rt. 83

Laterolog Resistivity Tool

Uses Can be used only in WBM. Lithology determination and correlation Recognition of resistive fluids (usually hydrocarbons) in the formation. Water Saturation estimation. Important Considerations Invasion and mud type can severely affect laterolog measurements. Fresh water muds cause log readings to be overly influenced by the resistivity of the invaded zone. Laterologs are generally recommended for use in saline muds, lower porosity and high resistivity formations Groningen Effect – A shift in deep resistivity measurement arises when high-resistivity formations (anhydrite, salt) force currents returning to the surface electrode into the borehole. An artificially high formation resistivity results and can lead to incorrect saturation calculations. The shallow resistivity (LLS) is not affected. 84

Induction Resistivity – Units ohm.m, Typical Log Scale (0.2–2000 ohm.m)

Purpose :Measurement of Formation Resistivity. High frequency alternating current of strength is sent through a transmitter coil.

constant

The electromagnetic field thus created induces secondary currents in the formation. These currents flow in circular ground loops and create, in turn, a magnetic field that induces a voltage in the receiver coil. The receiver signals are essentially proportional to the conductivity of the formations. 85

Induction Resistivity Tool and Principles

Mud cake

Receiver Coil Receiver Amplifier

Transmitter Amplifier

Foucault Current Ground Loop

The Foucault Current provides current focussing that ensures the transmitted current travels deep through the formation before reaching the receiver. „Bucking‟ currents eliminate the direct coupling of the transmitter and receiver coils

Transmitter Coil

Originally developed to measure formation resistivity in boreholes containing oil-based muds or air. 86

Induction Tool Uses Can be used in WBM or OBM. Recognition of resistive fluids (usually hydrocarbons) in the formation. Water Saturation estimation. Lithology determination and correlation.

Important Considerations The Induction log works best where the borehole fluid is of low conductivity. (This is the only tool for measurement of Rt in oil-based mud.) The tool also works in water-based mud wells as long as the mud is not too saline, the formations too resistive or the borehole diameter too large. Data should be environmentally corrected for borehole size, adjacent bed effects and invasion (in that order of priority). Limitations on the use of Induction logs are dictated by bed thickness, the depth of invasion, and the ratio between formation and mud resistivity. Induction devices do not read accurately at values > 200 Ohmm. 87

Micro Resistivity Log (MSFL or MLL)

Purpose: Measurement of formation resistivity close to the borehole. Pad mounted tool, focused electrode device, pressed against the borehole wall. The measuring current is forced to flow radially as a thin sheet of current into the formation, thus minimizing the influence of the borehole and surrounding formations. Uses Determination of Rxo, flushed zone resistivity. Lithology determination and correlation. Recognition of resistive fluids (usually hydrocarbons). Detection of mud-cake, hence permeable beds. Detection of thin beds.

Important Considerations Check hole rugosity and mud-cake on caliper log. Computed Sxo should always be greater than Sw in hydrocarbon-bearing zone. Zones of interest should be re-logged if pad contact is poor. 88

Nuclear Magnetic Resonance (NMR) Log

The Halliburton MRIL tool operates in a centralised mode, the Schlumberger CMR tool in a sidewall mode. NMR logs can provide information on Porosity (Total and Effective) and Hydrocarbon types. Largely unaffected by the rock matrix material. and requires little calibration to formation lithology.

In practice, NMR responses have been found to be complex and are frequently calibrated with respect to core measurements.

89

Nuclear Magnetic Resonance Log

Before NMR logging, the protons in the formation fluids are randomly oriented. As the NMR logging tool passes through the formation the magnetic fields generated by the tool „activate‟ the protons.

A permanent magnet firstly aligns (polarizes) the „spin axes‟ of the protons in a particular orientation. (This polarization increases exponentially with a time constant T1). An oscillating magnetic field is then applied, via the antennae on the tool, in order to „tip‟ these protons away from their new orientation. As the oscillating field is switched off, the protons try to re-align, or „relax‟, to their previously imposed orientation. Specific pulse sequences are used to generate a series of so-called „spin-echoes‟ which are measured by the NMR tool.

90

Nuclear Magnetic Resonance (NMR)

mm scale of measurement

1.Randomly oriented Hydrogen Protons in formation fluids

ffff

Spin-echo Amplitude (calibrated to Ø)

Magnet

ØTotal ØNMR

2. Hydrogen Protons aligned to imposed static magnetic field

3. Hydrogen Protons „tipped‟ by oscillating radiofrequency pulses

4. Hydrogen Protons „relaxing‟ to orientation of static magnetic field

T2 Cut-off for Clay-bound water < 3 msec T2 Cut-off Capillary-bound water >3 – 3?msec

T2 Cut-off for moveable fluids Moveable Fluids

FFI

Inter-echo Spacing (TE)

0

10

20

30

40

50

Time (milliseconds)

Bulk Volume Irreducible (BVI) & Clay Bound Water (MCBW)

60

70

80

T2 Spinecho Decay Curve

Free Fluids Index (MFFI)

T2 cut-off relates to pore radius or cap. pressure

Area under the curve equals Porosity (with proper calibration)

T2 Relaxation Time (milliseconds) Log Scale

91

fff

Nuclear Magnetic Resonance Log

The amplitude of a spin echo train is proportional to the number of hydrogen nuclei associated with the pore filling fluid. Thus amplitude can be calibrated to calculate porosity.

Properties of the fluids that affect the echo trains are: Hydrogen Index (HI) - the measure of the density of Hydrogen atoms in the fluid. Longitudinal Relaxation Time Constant (T1 - milliseconds) – a measure of how fast the randomly orientated protons align parallel to the imposition of a static magnetic field by the tools permanent magnet. Transverse Relaxation Time Constant (T2 - milliseconds) - a measure of how fast the „tipped‟ protons in the fluids relax perpendicular to the static magnetic field, after being disturbed by the radio-frequency, oscillating, pulse. T2 Cut-off (milliseconds) a value of T2 empirically related to a rock or fluid property such as pore size (inter-crystalline versus vuggy pore) or oil versus water saturation. Diffusivity (D) – is a measure of the extent to which molecules move at random in the fluid.

92

Nuclear Magnetic Resonance (NMR):

Mnemonics and

Porosity/Fluids breakdown

Conductive Fluids

Matrix

Dry Clay

Clay Bound

Capillary

Water

Bound

Mobile water

Hydrocarbon

Water

(MCBW)

(MBVI)

(MBVW)

Free Fluid (MFFI) Effective Porosity (MPHI) Total Porosity (MSIG)

Porosity Log Response Resistivity Log Response

(After cross-plot Corrections)

(After Clay Corrections)

MRIL Response 93

NMR Processed Example

Cumulative Amplitudes of Binned T2 distribution Permeability derived using Porosity, and Movable volumes (Coates Eqn)

Differential Spectrum used to remove water signal and identify hydrocarbons Hydrocarbons

Movable Water (mud filtrate)

Bound Water Waveforms of T2 distribution 94

Nuclear Magnetic Resonance Log The tool provides: A continuous measurement of fluids, including: effective porosity, capillary bound water, free fluid, clay-bound water and hydrocarbon types. Indications of pore size distribution, formation permeability, fluid characterisation.

Important Considerations: Limitations in carbonates – unable to see large vugs. Limitations in gas reservoirs – small signal. Stationary measurements and the stacking of signals greatly improves signal to noise ratio. Operates in the flushed zone. 95

Geochemical Logging - Principals

Schlumberger ECS (Elemental Capture Spectroscopy Sonde). The geochemical sonde measures relative elemental yields based on neutron-induced capture gamma ray spectroscopy.

The primary elements measured in both open and cased holes are for the formation elements: Silicon (Si) Iron (Fe) Calcium (Ca) Sulphur (S) Titanium (Ti) Gadolinium (Gd) Chlorine (Cl) Barium (Ba) Hydrogen (H)

Matrix properties and quantitative dryweight lithologies are calculated from the dry-weight elemental fractions using the empirical relationships derived from an extensive core chemistry and mineralogy database. Dry-weight lithology fractions (from elements) total clay total carbonate anhydrite + gypsum from S and Ca QFM (quartz + feldspar + mica) pyrite siderite coal salt

Matrix properties (from elements) matrix grain density matrix thermal and epithermal neutron matrix sigma.

96

Geochemical Logging - Applications

Independent determination of Clay fraction. Complex reservoir analysis defining: Carbonate Gypsum or anhydrite Pyrite Siderite

A matrix density for more accurate porosity calculation. Sigma matrix for sigma saturation analysis. Mineralogy-based permeability estimates. Geochemical stratigraphy (chemo-stratigraphy) for well-to-well correlation. Enhanced completion and drilling fluid recommendations based on clay versus carbonate cementation. Coal bed methane bed delineation, producibility, and in situ reserves estimation. 97

Wire-line Image Tools

Four or six arm tools. Resistivity or sonic wire-line devices. Complement coring and formation tester programmes. The resulting high-resolution borehole images can be used to identify geological and borehole features. These include: Planar features such as bedding, fractures, faults. Thin beds and new pay definition. Rock texture, grain size profile. Anisotropy. Permeability barriers. Paleocurrent directions. Stratigraphic features such as crossbedding and ichnofabrics. Borehole wall features such as breakout and drilling-induced fracturing. 98

Wire-line Formation Tester - Units Psia or Bar

The purpose of the tool is to obtain formation pressures and to sample formation fluids.

Probe Packer Piston

A retractable probe is sealed, using a rubber packer, against the borehole wall. A pressure draw-down is then applied at the probe by retracting the small cylinders in Pre-test chambers 1 and 2. The formation fluid will start to flow through the probe into the tool. The pressure measured by the tool will equilibrate to formation pressure if the formation is sufficiently permeable and the wait time long enough.

Pressure Gauge

x

Equalising Valve

Tool Probe Pre-test Chambers (10cc each)

Fluid Sample Chambers (5-20 litres)

Mud cake

Borehole

99

Formation Pressure Devices

Formation Pressure Wire-line data types:

MDT

FIT – through casing explosive setting- few points (psig)* RFT/MDT first generation strain gauges used (psig)* Note psia = psig+14.7 psi

Later RFT/MDT quartz gaugeshigher resolution (psia) MDT quartz gauges (psia) & alternative arrangements (dual probe, dual packer, through casing) XPT slimmed down express MDT Dual Packer Arrangements

LWD Tools since early 2000‟s Schlumberger Stethoscope Baker Hughes TesTrak Halliburton GeoTap 100

WFT Tool and Principles

The time taken for formation pressure to equilibrate gives a measure of the permeability (Fast equilibration - good permeability). Mobility is determined based on the drawdown achieved in the pretests.

To recover larger quantities of formation fluid the pressure draw-down can continue with fluid flow diverted to large containers within the body of the tool. Water samples and oil /gas samples can be segregated and sealed in pressurised or non-pressurised containers before recovering the tool at surface. Fluids can be typed down-hole using optical spectrometry and fluorescence sensors (Schlumberger LFA and CFA) which characterise fluid flowed through the tool. Pressure (psi)

Idealised Pressure Draw-down Recording

Mud Hydrostatic Pressure

Pre-Test Pre-Test 1 2

Mud Hydrostatic Pressure Formation Pressure

Time

101

WFT Fluid Densities & Contacts and FWL Pressure Versus Depth Plot

GOC defined by intersection of gas and oil gradients.

depth (tvdss)

Multiple tests

pressure vs. depth

FWL defined by intersection of oil and water gradients. OWC is above the FWL if the formation is water wet. – OWC close to FWL if the entry height is small as is often the case in sandstones.

Fluid gradients give formation fluid densities

Gas/Oil Contact

FWL

formation pressure 102

Wire-line Formation Tester Tool Uses Formation pressure measurements are important to help establish fluid density (oil, gas, water). To determine reservoir pressure. Permeability can also be estimated from pressure stabilisation data. Formation fluid samples can be collected to determine water salinity / resistivity, oil and gas properties. Fluid contact depths (FWL, OWC, GWC, GOC) can be evaluated given good quality pressure data. Inference of reservoir continuity or lack of it in field under production.

Important Considerations If the pressure returns to the higher „mud‟ pressure it is likely the packer is not sealing against the formation. In tight formation (low permeability) the pressure of the mud filtrate may not be dissipated within the formation, leading to pressure readings intermediate between mud and formation pressures. This effect is called „supercharging‟. Operating conditions, such as tight formation, usually limit the use of the Formation Test tool. Pressure / sampling points should be selected from in-gauge hole, avoiding washouts. Measurements from the tool are from very small reservoir volumes. Measurements should be taken going from shallow to deep to avoid gauge hysteresis.

103

Induction log

80 cm

Laterolog

80 cm

Neutron

40 cm

Gamma-ray

30 cm

Density

20 cm

Sonic

60 cm

Micro resistivity Micro log Dipmeter FMI

Resolution

Logging Tool Depths of Investigation and Vertical Resolution

5 cm 2 cm

250 cm

200 cm

150 cm

100 cm

Depth of Investigation

50 cm

0 cm

104

Course Outline and Timetable Day 1 Module 1: Petrophysics Definition and Contribution

Section 1.1: Introduction Section 1.2: Petrophysics Properties Section 1.3: Capillarity and Fluid Contacts Section 1.4: Net and Pay

Module 2: Well Environment and Data Available Section 2.1: …..The Borehole Environment Section 2.2:……Petrophysical Data Types 1: Wire-line Log Data

Module 3: Looking at Logs Section 3.1: …..Log Quality Assurance Section 3.2:……Quick-look Analysis of Logs Exercise 1

105

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Module 3: Looking at Logs

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Section 3.1: Log Quality Assurance

Log Quality Control and Quality Assurance: Use of Prints ├ The paper (or image file) log header presentation contains important acquisition details

and data. ├ Header Data can be obtained from other sources - from composite logs, routine drilling and geological reports if necessary. ├ A comprehensive log header should document the logs run, the mud type and properties in the well, bottom hole temperatures, casing shoe depths, the environmental corrections applied. ├ Digital databases are frequently presented without adequate log acquisition information and potential interpretation errors may result.

├ In the case of old log data, depending on it‟s origin, it may be necessary to confirm that it data matches the original field prints to be sure whether environmental corrections or depth shifts have been applied. ├ In the case of new data a repeat section is usually logged, the repeat section should be compared with the main log to confirm log repeatability. 108

Log Quality Control: Log Header Information

Log Header Information

Purpose

Tool Types

Environmental Corrections.

Casing points

Identify potential gaps, poor data.

Drill and Log TD

Identify depth discrepancies.

Bottom Hole Temperature (BHT)

Environmental Corrections & estimation of formation temperature.

Mud Type

Environmental Corrections & expected log types, Potassium in mud.

Mud Weight

Environmental Corrections.

Mud resistivities

Environmental corrections, Rw from SP.

List of Logs acquired

Identification of available curves.

Engineers remarks

Warning of problems acquiring logs.

109

Wire-line Depth Measurement and Control Depth Measurement, Wireline

Wire-line depth is measured by measuring the length of cable reeled out.

Tension device

Magnetic mark detector

Depth wheels

Uses Measuring wheels on the logging unit.

Tool zero

Derrick floor

Datum level

Copyright 2001 SIEP B.V.

Magnetic markers on cable. Shell Learning

Stretch corrections are applied to the cable. Depth zero established by lowering the tool until the zero measure point is level with the KB or rotary table.

Logging Wheels

110 May 23rd 2000: Petrophysics for Non-Petrophysicists: Operational Petrophysics

Wire-line Depth Measurement and Control

First Run in hole Tool zero. Calculate stretch correction near TD. Log up.

Subsequent runs in hole Tool zero. Run repeat section. Start main log after repeat section has been put on depth with first run log. Usually use GR for tie-in. Continue checking tie-in during logging.

GR in previous hole section

+/- 50m overlap

Subsequent hole sections Tool zero. Run repeat section. Start main log only after the repeat section has been put on depth with the previous hole sections first run log. Usually use the GR with ~50m of overlap – May need more overlap if there are no clear features near the previous hole section TD,

GR

TD

111

LWD Depth Measurement and Control LWD data stored on a time basis. Drillers Depth attributed to the LWD data on the basis of time and pipe in hole. Drillers Depth: Cumulative tally of all drill-pipe, stabilisers, drill collars etc. in the hole. Usually measured vertically in the derrick or pipe rack. Rarely measured under tension. 112

Log Quality Control and Quality Assurance

Depth Logs can be off-depth for several reasons: ├ Incorrect log offset adjustments can be applied by logging engineer. ├ Successive runs in a well may not be correctly depth matched. ├ Tool sticking can cause apparent tool movement due to cable stretch – see tension logs. ├ Problems are often restricted to pad tools, for example Density and Neutron logs. Hence GR for first run non-pad tool usually used as reference log.

113

Log Quality Control and Quality Assurance: Example Depth error Depth is the most important measurement made in logging! Check Drill depth and Loggers depth are not in conflict.

IC-1

Scale : 1 : 200

DEPTH (9149.98FT - 9300.24FT)

DB : IPDB (1)

DEPTH BS (in) 6. 20. 0. FT CALI (in) 6. 20. 0.

GR (API)

07/03/2006 18:01

ILD (ohm.m) 150. 0.2

GR (API)

DT (US/F) 200. 180.

40.

ILD (ohm.m) 150. 0.2

200.

If they are investigate why. Hole fill? Wrong pipe tally?

Drillers depth should always be greater than loggers by the amount of pipe stretch.

Ensure logs from each hole section tie in to those from previous section. 9200

Usually use GR from first run tool string in each hole section. Engineer may tie-in to casing-shoe if GR is featureless.

Top Upp Isongo Lwr Sd

Ensure logs in the same hole section are all on depth with each other. If mixing LWD and wire-line data need to check that the two are on depth.

DST 5 GAS 202mcum/d 9250

Usually shift LWD to wire-line depth. Exceptions for example if shallow sections are logged with LWD.

DST4 Water +TR GAS?

114

Log Quality Control and Quality Assurance

Calliper ├ Is it valid? Check its value inside casing. Gamma Ray ├ In a sand / shale sequence the GR log normally responds to lithology change unless there is low GR shale or high GR sand. ├ Note GR readings decrease in large diameter hole or if run through casing.

Spontaneous Potential ├ In a sand / shale sequence the SP log normally responds to lithology change, given that salinities of mud filtrate and formation water are different.

115

Log Quality Control and Quality Assurance

Resistivity logs should track porosity logs except in the presence of hydrocarbons. Induction Resistivity ├ There are induction limitations when run in saline muds and resistive formations. ├

Works best in low resistivity formations.

Laterolog Resistivity ├ Problems with the Deep Laterolog can occur below thick resistive beds (Groningen effect - A special tool configuration can be utilised to overcome this problem). ├ Works best in resistive formations. ├

A Porosity v. Rmf/Rw plot is a useful guide for selecting whether a Laterolog or an Induction log is most suitable. 116

Log Quality Control and Quality Assurance Microlaterolog Resistivity ├ Microlaterolog Resistivity logs should track deeper reading Resistivity logs, except where mud filtrate invasion occurs. ├

If poor pad contact occurs then the tool will respond to the mud resistivity rather than formation resistivity.

├

The (compressional) Sonic log should track the other porosity logs in a given lithology.

├

Cycle skipping is the most common problem, produces larger values of ∆T (slower velocity) and can occur in washed out hole.

├

Noise can also be picked up and manifests as smaller values of ∆T.

├

Check value in casing (steel transit time 57 us/ft).

Sonic

117

Log Quality Control and Quality Assurance Shear Sonic ├ Shear logs have a slower velocity than the compressional sonic but the two logs normally track each other for a given lithology apart from in shale. ├ Shear log processing often generates multiple versions of shear curves and identifying the correct one is not always straight forward. ├ A quality control check can be made by using a Vs v. Vp plot with reference to a GreenbergCastagna sand and mud line overlay.

Density ├ The Density Log should track the Sonic or Neutron log in sands / limestones. ├ May be affected in washed out or rugose holes due to lack of pad contact. ├ Always check the Calliper and Drho ( ρb) curves. ρb should be less than 0.05 gm/cc; if larger the density log is likely to be unusable.

Neutron ├ The Neutron log should track the Sonic log or Density log in sands /limestones.

118

Environmental Corrections All logging companies publish chart-books of log environmental corrections. Logging tools are calibrated to work in a particular environment. The further you get away from this environment the greater the need to apply an environmental correction to the resultant log curves. Sometimes environmental corrections are applied at the wellsite, computer centre post processed before delivery to the client or done by the client/consultant sometime later. Understanding what has or has not been corrected for can often be a challenge, especially on older data where all curve history has been lost.

In such circumstances its better not to correct than over correct. Unless a correction is obviously required. 119

Environmental Corrections Common corrections: GR casing and borehole correction (correction should increases GR)

Density borehole mud correction (correction usually very small in 9 inch or less hole)

Laterolog Borehole Correction small in 8.5” and smaller hole Adjacent Bed Correction Invasion corrections Conductive WBM suppresses resistivity response

Neutron Correction Hole size correction usually done in the field, need to remove before applying other corrections. Often when all corrections applied you get back to near starting point. Better to correct by choice of parameters in individual wells. 120

Environmental Corrections A main motive for environmental correcting data is to try and standardise curves and then perhaps your interpretation parameters. However many of the parameters required to allow correction are ill-defined and may vary with depth. They therefore need to be guesstimated or adjusted to provide a result which matches something that is well known. For example Neutron Standoff adjusted to provide N/D porosity which matches core porosity.

An alternative to applying environment corrections is to compensate within your interpretation by zoning and parameter selection. 121

Deep lateralog Borehole correction Differ if tool is centred or or eccentred. Use appropriate chart.

Dependant on: RLLD/Rm. Hole size Small correction for: Small hole RLLD Large

122

Dual lateralog LLD Tornado plot Enter with Rlld/Rlls & Rlld/Rxo Determine Depth of invasion Rt

123

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Section 3.2 Quick-look Analysis of Logs

Quick-look Interpretation: Part of the log QC process Scale : 1 : 100

SYNTHETIC NEW

DB : IPDB (7)

DEPTH (5010.FT - 5098.5FT)

1 DEPTH (FT)

3

5

GR (GAPI) 0.

RDEP (OHMM) 150. 0.2

Caliper (inches) 0.

7

RHOB (GM/CC) 2.95 140. NPHI (%)

RMIC (OHMM) 12. 0.2

40. PFMN_Depleted (psia)

200. 0.45

-0.15 2100. DRHO (gm/cc)

3

200. -1.05 PFMN (psia) 2150.

1

DT (US/FT)

200. 1.95 RMED (OHMM)

12. 0.2 BS (inch)

0.

05/01/2009 15:13

6

2200.

0.1 2200.

Define Gas and Oil Legs from D/N

5020

Evaluate Lithology and Net from GR and D/N 5040

6 5060

Calculate Sw 2 4

Identify

5080

Water Leg from Resistivity

5 Calculate Rw

Calculate Ø from D/N and Sonic

125

Quicklook Interpretation Resistivity/Porosity “Mae West” Effect Curves Responding in opposite directions

Porosity (%)

Resistivity (Ohm.m)

Wet or Tight

OWC TRAMLINE

Curves Tram-lining

MAE WEST

Hydrocarbon

126

• Exercise 1 Group Quicklook Analysis

Course Outline and Timetable Day 2 Module 4: Petrophysics Data Types 2 Section 4.1: Logging While Drilling Section 4.2: Conventional and Sidewall Core Data Section 4.3: Mud Logging Data

Module 5: Basic Deterministic Interpretation Section 5.1: ….. Preparation for Interpretation Section 5.2:…… Clay Volume and Lithology Section 5.3:……Porosity Section 5.4:……Water Saturation Section 5.5:……Permeability Section 5.5:……Net and Pay Exercises 2-6

Module 6: Reporting and Pitfalls Section 6.1: …..Petrophysical Report Writing Section 6.2:……Hints, Tips and Pitfalls

Module 7: Water Saturation in Shaly Sands

127

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Module 4 Petrophysical Data Types 2

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Section 4.1 Logging While Drilling

Logging While Drilling (LWD) or FEWD

Measurement While Drilling (mid 80s on)

MWD

Logging While Drilling (Late 80s, Early 90s on)

LWD

Formation Evaluation While Drilling

FEWD

Insurance Logging Thin Bed Resolution Correlation

Replacing Wire-line logs Geosteering/pore pressure indication Geomechanics during drilling

130

Logging While Drilling (LWD) Conventional wire-line logs are recorded at convenient points in the drilling program LWD is acquired in real time while drilling. Most of the principal logs can be acquired using LWD tools during drilling, providing data for timely, effective formation evaluation. Gamma Ray Resistivity Density Neutron Sonic NMR Formation pressures (during pauses in drilling)

LWD tools overcome the problems of logging in high angle / horizontal wells where tool access on wire-line can be difficult, expensive, time consuming or impossible. Furthermore, the logging is made while the bore-hole is in (usually) reasonable condition and where there has been minimal mud invasion. The logging environment is, however, more „extreme‟ than for conventional wire-line logging (vibration & noise). 131

LWD Logging Tools The tools are integral to the bottom-hole assembly (BHA). Power is supplied to the tools by batteries or by turbines powered by the mud circulation. A subset (selection of curves at larger depth increment than memory data) of the log data is transmitted to the surface using a mud-pulse telemetry system through the mud column in the well. Transmitted or Real-time data. Data are also stored in down-hole memory for later recovery at surface. Memory data.

Telemetry Systems Two modes of data transfer from tool to surface: Positive pulse – The tool extends an hydraulically driven „poppet‟ into the orifice aperture in order to cause a momentary flow restriction. This causes a positive pressure wave. Negative Pulse – The tool creates a pulsed pressure decrease in the mud column by opening and closing an electrically driven sleeve valve across the orifice aperture in the collar wall.

Issues Memory Size - Ensure large enough for length of bit run. Battery Life - Ensure long enough for length of bit run. Rotating and sliding modes. 132

LWD Logging Telemetry

Telemetry Receiver

Pressure Transducer

Computer

MUD PUMP

Drill String Positive Pulse Telemetry

Pressure Pulse Signal Orifice Aperture Mud Pulsor Sensors Mud Motor Bit

Hydraulic „Poppet‟ Mud Flow

133

Data Acquisition: While Drilling - Geosteering

MWD inclination

Bit inclination

Courtesy of Schlumberger

Drill to the Geology encountered rather than to a planned trajectory

134

LWD GR/D/N/Resistivity Azimuthal Density and Azimuthal GR Images –Example U L D R U U L D R U

Azimuthal Density

Azimuthal Gamma Ray

Density/Neutron

Resistivity

Gamma Ray © 2003 Baker Hughes Incorporated All rights reserved.

135

Integrated LWD tool strings

Second Generation LWD/FEWD

Most Service Companies have now launched integrated LWD strings which can offer services comparable to wire-line equivalents GR/Resistivity/D/N/Sonic/Formation Pressure/NMR Baker Hughes: Star series StarTrak, LithoTrak, SoundTrak,TesTrak, MagTrak Schlumberger: Scope series: Stethoscope, Telescope, Ecoscope, Periscope; etc Vision series: ArcVision, AdnVision, SonicVision etc LWD StarTrak Resistivity Tool 137

LWD Sonic

138

LWD Formation Pressure Measurements

Halliburton GeoTap (probe)

Ha llib ur ton - GeoTa p Schlumberger Stethoscope (probe) Baker Hughes TesTrak (probe) Pathfinder DFT (dual-packer)

Formation Pressure Measurements made during pauses in drilling.

Pathfinder DFT

141

LWD Logging Tool considerations

Density tool variations ADN is built into a stabiliser blade and records 4 densities ROBB, ROBL, ROBR, ROBU; hence have to make a choice which is appropriate. Other LWD densities centralised sensors and single measurement.

Neutron/density source arrangements ADN sources wire-line recoverable from surface. EcoScope – no chemical source for Neutron and Density - reduced consequences if tool lost in hole.

LWD/FEWD tools and services are rapidly developing; check out service company web-sites for current capabilities: http://www.slb.com/ http://www.halliburton.com/ http://www.bakerhughesdirect.com/cgibin/bhi/myHomePage/myHomePage.jsp 143

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Section 4.2 Conventional and Sidewall Core Data

Core Types

Conventional Coring core barrel sleeved core rubber, fibreglass, aluminium

sponge core pressure barrel gel coring

Sidewall Cores percussion rotary sidewall 145

Core Analysis – Why Is it done?

RHIIP

CAh (1 S wi ) RF Boi

Dynamic model

Static model Description

Data Source

RHIIP

Recoverable HIIP

C

Constant

Depends on oil or gas

A

Area

Maps, Seismic, Logs

h

Net Pay

Welltest, Logs, Core (perm)

Porosity

Logs, Core (log calibration)

Swi Initial Water Saturation

Logs, Core (m & n, Dean-Stark, Pc)

Boi Fluid Expansion Factor

PVT

RF Recovery factor

Technical, Economic (Core K, Rel K)

146

Core Coring provides essential calibration data for the integration of log analysis with actual reservoir rock samples. This calibration data includes: Routine Core Analysis: Grain Density. Porosity. Permeability. Water & Oil Saturation. Use of (1)Low Invasion Core Bits (2) Sample Preservation Techniques and (3) Mud Tracers can provide reliable saturation data.

Special Core Analysis: Core Compaction (Porosity and Permeability stress corrections). Archie Parameters (a, m and n). Capillary Pressure. Cation Exchange Capacity (CEC). XRD (Mineralogy).

147

Sidewall Cores

Usually limited in diameter/length. Small volume – greater inaccuracy.

Samples taken directly at sand face.

Percussion

In invaded zone. In potentially weakened zone as a result of possible wellbore failure due to too low (or sometimes too high) mud weights. Strength tests often invalid.

Rotary sidewall cores are superior.

Rotary

Often only grain density, lithology, etc from percussion. Not a substitute for conventional core. Small samples. From zone weakened by drilling. Flushed by mud filtrate. May contain mud solids. 148

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Section 4.3 Mud Logging Data

Mud Logs

The Mud Log records the rate of penetration (ROP), weight on bit (WOB), rotary torque, revolutions per minute (RPM) and pump pressure (SPP) measured by sensors connected to the drilling machinery on the rig. Drilling mud also carries rock cuttings and released formation fluids to the surface where they can be detected and recorded at regular intervals. Analysis of this information can give the Petrophysicist key information for the formation evaluation exercise. Relative increases and decreases in gas concentrations can indicate the penetration of hydrocarbon-bearing reservoirs and source rocks. Gas ratio analysis can be used to characterize the hydrocarbon type. 150

Example Mud Log

Example Mud Log

151

Course Outline and Timetable Day 2 Module 4: Petrophysics Data Types 2 Section 4.1: Logging While Drilling Section 4.2: Conventional and Sidewall Core Data Section 4.3: Mud Logging Data

Module 5: Basic Deterministic Interpretation Section 5.1: ….. Preparation for Interpretation Section 5.2:…… Clay Volume and Lithology Section 5.3:……Porosity Section 5.4:……Water Saturation Section 5.5:……Permeability Section 5.5:……Net and Pay Exercises 2-6

Module 6: Reporting and Pitfalls Section 6.1: …..Petrophysical Report Writing Section 6.2:……Hints, Tips and Pitfalls

Module 7: Water Saturation in Shaly Sands

152

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Module 5: Basic Deterministic Interpretation

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Section 5.1 Preparation for Interpretation

Evaluation Sequence

Gas Hydrocarbons  Reservoir  Rock 

Oil Water

Non-reservoir Lithologies: Sand Limestone Chalk Dolomite Clays Coals Calcite Anhydrite Halite

Porosity Permeability Reservoir quality Net sands

Water saturation

Hydrocarbon Type Fluid Contacts

GR SP D/N SGR

Sonic Density Neutron NMR WFT draw-downs

Porosity & DIL DLL

D/N WFT

Cuttings description CSTs Core Description Thin Sections

Core porosity Core permeability Core photographs

Formation water samples: WFT samples Produced water samples

PVT samples: WFT samples Down-hole samples

155

Preparation for Interpretation Talk to the rest of the team Stratigraphy - Tops- Geologist / Geophysicist. Mineralogy & Petrology - Geologist. Heterogeneity – Geologist. Modelling strategy – what do you need to deliver – Geologist and Reservoir Engineer. Production history – expected pressures, reservoir fluids – Reservoir Engineer. Drilling events (losses, kicks etc) Drilling engineer or end of well reports.

Assemble Well Header Data Contractor and Dates logged. Logs run and intervals logged. TD Logger and Driller. Logging problems noted (variable tension, cycle skipping etc). Bottom Hole Temperature (BHT). Mud Type (OB, WB, KCL) and Weight. Mud resistivity's.

Examine all data: Shows. Lithology log/cuttings description. core data and photographs. test and fluid sample data. Offset logs etc.

Make environmental corrections GR. Density – borehole correction in large holes. Neutron – care needed depending on corrections applied at well-site. Resistivity – depending on tool type and mud properties.

Pre-calculate Formation Temperature log. Determine Lithology flags (coals, calcite stringers, anhydrite, salt). Washouts flags.

QC logs 156

Important Conversations With the Geologist

The Reservoir Engineer

Make sure they understand the importance of tops to your interpretation!

Ensure that you deliver a saturationheight function that fits the Reservoir simulation requirements.

That changes to tops may change your interpretation!

What type of permeability input do they need in the model?

Make sure you understand the nature of the reservoir.

With the 3-D Modeller Make sure that the parameters required by your saturation height function will be available in the model.

Make sure you both know and agree how the model is to be built: Map Øe or Øt ? Map Net ? Map k or use K/Ø relationship

157

Log Evaluation Workflow Lithology Clay Volume Estimation Porosity Computation

Water Saturation Calculation

Fluid Zones Permeability Determination Net Pay / Net Reservoir Quantification

Reality check 158

Log Evaluation Workflow Lithology Clay Volume Estimation Porosity Computation

Reasons for iteration New Well data

Core calibration

Water Saturation Calculation Core derived parameters Comparisons with core Saturation-height

Fluid Zones

New Production data

New core data

Part or Total iterations

Fluids present Fluid contacts FWL

Permeability Determination

Inconsistencies seen in sense checks

Fluid samples Problems in 3-D modelling

Core derived predictors

Net Pay / Net Reservoir Quantification Reality checks Uncertainty Analysis

Problems in simulation

159

Log Evaluation Workflow: Reality Checks 1 Look for consistency: Between parameters from different data types. Different data types may not all tell the same story but any conflicts should be explained. Conclusion 1 shows and core data should be identified prior to Lithology, hydrocarbon log evaluation.

Lithology and Clay volume: Compare with clays and other minerals seen in core. Use core grain density as guide to main matrix material. Compare with core mineralogy (XRD, thin section).

Porosity Porosity: Differences or similarity of different log porosities. Log to core comparison or calibration. Sense check magnitude of porosity. 160

Log Evaluation Workflow: Reality Checks 2 Log derived water saturation should be compared with: Capillary pressure curves. Core fluid saturation measurements (Dean Stark). DST and WFT samples. Discrepancies may point to the need for modified interpretation.

Log derived permeability should be calibrated to core data. Compare cumulative log permeability with production log inflow profiles. Compare permeability-height (KH) from log permeability with KH from well tests.

Net Pay and Net Reservoir should be compared to permeability indicators and core if available. Effective formation evaluation is a process of integration of different data types in order to provide a robust interpretation.

161

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Section 5.2 Clay Volume and Lithology

Basic Interpretation Workflow Lithology Interpretation ├ The Gamma Ray log responds to natural radioactivity in rocks. Contrast between sand and shale.

├ Exceptions: Feldspathic (potassium feldspars), micaceous, or glauconitic sands will show an atypical, high gamma ray response. Source rock shales can have very high GR values – often a characteristic of the Kimmeridge Clay Formation in the North Sea. ├ Neutron and Density logs when run together are, by convention, displayed with the curves superimposed in the same log track, on standard scales such that curves overlay in water-bearing limestones. The curves shift according to lithology and porosity. ├ Some minerals have characteristic D/N responses and cross-plots can be used to determine these. ├ Calcite, Coal, Salt, Anhydrite, Gypsum etc ├ The photo-electric curve (PE or PEF) can also be used.

163

Typical Log Responses to Lithology and Gas

Density

Reservoir Rock

Neutron

Log response Decreases with Increasing Porosity Low High

Limestone (Reference)

2.71 g/cc

Sandstone

2.65 g/cc

Log response Increases with Increasing Porosity High Low ≈ 0%

Log response Decreases with Increasing Porosity High Low 47.5 us/ft ≈ 52.5 – 55.5 us/ft Variable with Compaction

≈ - 4%

2.83 to 2.87 g/cc

Dolomite

Sonic

≈ 42.5 us/ft

≈ 6 to 8 %

Non Reservoir Rock 2.98 g/cc

Anhydrite 2.33 g/cc

Gypsum

Salt

Shale

2.08 g/cc

≈ - (1 to 2) %

52 us/ft

48 %

67 us/ft

0%

Wide Range 2.3 – 2.7 g/cc Variable with Clay Density

≈ 50 us/ft

Reads High Increases with Clay Bound Water

≈ 130 – 175 us/ft Variable with Compaction

Hydrocarbon Gas Effect

Reads Low

Reads Low

Reads High

164

Lithology Example 1 Minerals Determined from D/N Cross-plot: 41/8-2

Scale : 1 : 1000

DEPTH (2300.FT - 3000.FT)

DB : IPDB (4)

Salt

ip:VWCL (Dec) 0.

Dolomite

1. ip:VSILT (Dec)

0.

1. ip:PHIE (Dec)

1.

Anhydrite

0. ip:VSALT (Dec)

0.

1. coalflag ()

Roter Saltzon

DEPTH raw :RD (OHMM) CAL ZDENds (G/CC) 0. 150. FT 0.2 2000. 6.16. 1.95 2.95 raw :SP (MV) raw :RMLL (OHMM) CNCds (dec) -200. 200. 0.2 2000. 0.45 -0.15 BIT (FT) ZCORds (G/CC) 5. 20. -1. 0.25 raw :CAL (INCH) ACds2 (US/F) 5. 20. 140. 40. rftp (psia) PEds (BARN) 1700. 2000. 0. 20.

07/03/2006 15:47

raw :GR (API)

0.

2.

3.

40 40 40

Leine Halite

Plattendolomit

10

20 10

SS 0

Halite StrassfurtDeckanhydrit

Basalanhydrit Hauptdolomit Werraanhydrit

2900

20

2.4

10

LS 0 2.8 DOL 0 (WA) Neutron Density Overlay, Rhofluid = 1.0 (Ch.6-42 1985) 3. -0.05 0.05 0.15 0.25 0.35 Neutron

2800

Hauptdolomit

30

20

2.6

2600

2700

30

Den sity

Plattendolomit

2500

2.2

Hauptanhydrit

2400

30

1319 points plotted out of 1334 Zone Depths (7) Leine Halite 2319.F - 2474.F (9) Plattendolomit 2485.F - 2611.F (10) Deckanhydrit 2611.F - 2654.F (11) Strassfurt Halite 2654.F - 2657.F (12) Basalanhydrit 2657.F - 2775.F (13) Hauptdolomit 2775.F - 2994.F

0.45

165

FMT Gradient = 0.474 psia/ft . Sample results similar to mud filtrate.

Lithology Example 2

41/8-2

Scale : 1 : 1000

DEPTH (4300.FT - 5050.FT)

DB : IPDB (4)

Minerals Determined from D/N Cross-plot:

07/03/2006 16:02

raw :GR (API)

DEPTH raw :RD (OHMM) CAL ZDENds (G/CC) 2000. 6.16. 1.95 2.95 FT 0.2 raw :SP (MV) raw :RMLL (OHMM) CNCds (dec) -200. 200. 0.2 2000. 0.45 -0.15 BIT (FT) ZCORds (G/CC) 5. 20. -1. 0.25 raw :CAL (INCH) ACds2 (US/F) 5. 20. 140. 40. rftp (psia) PEds (BARN) 1700. 2000. 0. 20. 0.

ip:VWCL (Dec)

150.

0.

1. ip:VSILT (Dec)

0.

1. ip:PHIE (Dec)

1.

0. ip:VSALT (Dec)

0.

Limestone

1. coalflag ()

0.

3.

Claystone-sandstone 4400

Interval : 4200. : 5100.

2.

raw :GR 150.

40 40

4500

135. 40 30 2.2

120.

30

4700

105.

30

20 20

2.4 Den sity

Undifferentiated Carboniferous

Undifferentiated Carboniferous

4600

10

90. 20

75.

10 2.6

60. SS 0

10

45.

LS 0

4800

2.8

30. DOL 0

4900

5000

(WA) Neutron Density Overlay, Rhofluid = 1.0 (Ch.6-42 1985) 3. -0.05 0.05 0.15 0.25 Neutron 1791 points plotted out of 1801 Well Depths 41/8-2 4200.F - 5100.F

15.

0.35

0.45

0.

166

Clay Volume Determination from Wire-line Logs

Clay Volume (Vclay) The clay content reflects the amount of clay minerals present in a rock. The term „SHALE‟ normally denotes assemblages of „clay grade‟ particle sizes which include clay minerals as well as other minerals such as quartz, mica etc. The proportion of clay in „shale‟ can range from 50 to 100%.

Clay volume is estimated to determine: Shale / Sand ratios. Shale corrections in porosity determination. Shale corrections to Sw . Log facies. Reservoir Delineation. 167

Clay Volume Determination from Wire-line Logs Commonly used Clay Indicators are: GR. SP. Resistivity (in hydrocarbon-bearing reservoir). Neutron-Density log Cross Plot.

Typically determine Vclay using several alternative methods and use either the minimum or average value of them Care required: If radioactive minerals (other than clays) occur in sands VclayGR is an overestimate. If hydrocarbon type is gas VclayDN is an underestimate.

The Vclay from logs should be calibrated or compared with core data where possible: Shale count observed in core. Thin section point count data. XRD data. 168

Clay Volume from Gamma Ray VclayGR

Normally shales contain radioactive minerals and sands do not. Sands may contain radioactive minerals e.g. Biotite, Potassium feldspars or Glauconite. Need corroboration with other clay indicators.

Select „clay‟ and „clean sand‟ lines. A linear relationship is normally assumed (non-linear versions Larinov or Clavier used in FSU for older rocks).

Vclay is obtained from the following equation:

Where,

VclayGR GRlog GRsand GRclay

VclayGR

= Clay volume from GR (v/v) = Log GR (GAPI) = GR in clean sand (GAPI) = GR in clay/shale (GAPI)

(GRlog GRsand ) (GRclay GRsand )

169

Clay Volume from Gamma Ray: Thin Beds

Heterogeneity – Thin Bed Problem In rock beds less than 2 feet thick, log resolution starts to have an impact by being strongly influenced by adjacent beds. Thinly laminated sand-shale sequences can have clean sands, which are not resolved and are interpreted as „shaley‟ sands or shales. Note: This problem is not limited to shale volume detection and the GR log. Similar effects with respect to nonresolution of thin beds also occur with porosity and resistivity tools. 170

Clay Volume from Gamma Ray – Plot illustrating picking sand and clay GR It is often difficult to decide which shales are characteristic of the clays dispersed in the sands: This will depend on the mode of deposition of sands and shales. Talk to the project geologist to get his insights!

Test Well

Scale : 1 : 750

DEPTH (8100.FT - 8400.FT)

GR Sand Line

Other considerations It is likely that different parameters will be required in different intervals in the well. Take care to note changes of hole diameter or presence of casing. Both will change the attenuation of the GR.

Parameters are chosen by one of several methods:

DEPTH 0. FT

GR (GAPI)

22/05/2004 15:02 VCLGR (DEC)

150. 0.

1.

GR Clay Line 8200

8300

By “eyeballing” sand and clay GR. Using sand and clay lines in a depth plot. Note: GRsand