03 Porosity Measurement

Schlumberger

Contents C1.0 POROSITY POROSITY MEASURE MEASUREMENT MENTS S ............................................ ................................................................... .............................................. .................................1 ..........1 C2.0 POROSITY POROSITY MEASURE MEASUREMENTS MENTS FROM THE BHC SONIC TOOL............. ........ ....... ....... ........ ....... . 3 C2.1 C2. 1 INTROD INTRODUCTI UCTION ON .............................................. ..................................................................... .............................................. .............................................. .........................3 ..3 C2.2 POROSITY POROSITY DETERMINA DETERMINATION............................. TION.................................................... .............................................. ............................................4 .....................4 C2.3 FACTORS AFFECTING SONIC INTERPRETATION:................................................................7 C3.0 POROSITY MEASUREMENTS FROM THE LITHO-DENSITY TOOL...........................................11 C3.1 C3. 1 INTROD INTRODUCTI UCTION ON .............................................. ..................................................................... .............................................. ..............................................11 .......................11 C3.2 PRIN PRINCIPLE CIPLE....................... .............................................. .............................................. .............................................. .............................................. ...............................1 ........1 1 C3.3 POROSITY POROSITY FROM A DENSITY DENSITY LOG........................... LOG.................................................. .............................................. ...................................1 ............1 3 C3.4 LITHOLOGY FROM THE PE MEASUREME MEASUREMENT........................................ NT............................................................... ..............................1 .......1 7 C3.5 FACTORS AFFECTING DENSITY LOG:................................................................................20 C4.0 POROSITY MEASUREMENTS FROM THE COMPENSATED NEUTRON TOOL.........................21 C4.1 INTROD INTRODUCT UCTION........................... ION................................................... ............................................... .............................................. ..........................................21 ...................21 C4.2 PRIN PRINCIPLE CIPLE .............................................. ..................................................................... .............................................. .............................................. ...............................2 ........2 1 C4.3 FACTORS FACTORS AFFECTIN AFFECTING G CNL LOGS............................................. LOGS.................................................................... ..........................................23 ...................23 C5.0 TOTAL TOTAL POROSIT POROSITY Y DETERM DETERMINA INATION TION ............................................. .................................................................... ..........................................29 ...................29 C6.0 GR LOG..................... LOG............................................ ............................................... ............................................... .............................................. ..........................................31 ...................31 C6.1 C6. 1 INTROD INTRODUCT UCTION ION .............................................. ..................................................................... .............................................. ..............................................31 .......................31 C6.2 PROPERTIES PROPERTIES OF GAMMA GAMMA RAYS .............................................. ..................................................................... ..........................................31 ...................31 C6.3 NATURAL GAMMA RAY SPECTROMETRY TOOL...............................................................34 C7.0 BOREHOLE BOREHOLE GEOMETRY GEOMETRY BY CALIPER CALIPER MEASUREMENT MEASUREMENT ....... ....... ........ ....... ....... ........ ....... ...... 37 C7.1 PHYSICAL PHYSICAL PROPERTIE PROPERTIES............. S.................................... .............................................. .............................................. ..........................................37 ...................37 Single-Arm Single-Arm Caliper Caliper Configurati Configuration........ on............................... .............................................. .............................................. ..........................................40 ...................40 Two-Arm Two-Arm Caliper Caliper Conf Configura iguration tions s ........................................... .................................................................. .............................................. ...............................4 ........4 0 Three-Arm Three-Arm Caliper Caliper Configurat Configurations ions...................... ............................................. .............................................. .............................................. ...........................4 ....4 1 Four-Arm Four-Arm Caliper Caliper Configurat Configuration ion ............................................ ................................................................... .............................................. ...............................4 ........4 1 C8.0 WORK SESS SESSION............................... ION...................................................... .............................................. .............................................. ..........................................43 ...................43

(05/96)

Introduction to Openhole Logging

(05/96)


(05/96)

Schlumberger

C1.0

Porosity Me Measurements

C1.1 INT INTRODUC ODUCTI TIO ON Total porosity may consist of primary and secondary porosity. Effective porosity is the total porosity after the shale correction is applied. Rock porosity can be obtained from the sonic log, density log or neutron log. For all these devices, the tool response is affected by the formation porosity, fluid and matrix. If the fluid and matrix effects are known or can be determined, the tool response can be determined and related to porosity. Therefore, these devices devices are usually referred referred to as porosity logs.

All three logging techniques respond to the characteristics of the rock immediately adjacent to the borehole. Their depth of investigation is shallow—only a few centimeters or less—and therefore generally within the flushed zone.

For example, the formula for a density log measurement including all these variables can be written as

ρ b = φe × S w × ρ f + φ e (1 – S w) ρhy + V sh ρsh + (1 – φe – Vsh ) ρma . Solving for porosity in this case would not be easy because there are several unknowns and only one measurement. However, when we compare other porosity and log measurements, we can solve for these unknowns.

As well as porosity, the logs are affected by - volume volume and and nature nature (lith (litholog ology) y) of mamatrix material - amount amount and and nature nature of of pore spac spacee concontents (pore geometry, water, hydrocarbons) - volume volume and nature nature of of shales shales..

(05/96) C-1


(05/96) C-2

Schlumberger

C2.0

Porosity Measurements from the BHC Sonic Tool

C2.1 INTRODUCTION In its simplest form, a sonic tool consists of a transmitter that emits a sound pulse and a receiver that picks up and records the pulse as it passes the receiver.

The computer also integrates the transit time readings to obtain total traveltimes (see Figures C1 and C2).

The sound emanated from the transmitter impinges on the borehole wall. This establishes compressional and shear waves within the formation, surface waves along the borehole wall and guided waves within the fluid column. The sonic log is simply a recording versus depth of the time, t comp, required for a compressional sound wave to traverse 1 m of formation. Known as the interval transit time, transit time, ∆t or or slowness, t comp is the reciprocal of the velocity of the sound wave. (For the remainder of this document, t comp is known as ∆t .) .) The interval transit time for a given formation depends upon its lithology and porosity. This dependence upon porosity, when the lithology is known, makes the sonic log useful as a porosity log. Integrated sonic transit times are also helpful in interpreting seismic records. The sonic log can be run simultaneously with many other services. The borehole-compensated (BHC) tool transmitters are pulsed alternately, and ∆t values are read on alternate pairs of receivers. The ∆t val values from the two sets of receivers are averaged automatically by a computer at the surface for borehole borehole compens compensation. ation. Figure C1: Schematic of BHC sonde, showing ray paths for the two transmitter-receiver sets. Averaging the th e two ∆t measurements cancels errors from the sonde tilt and hole-size charges.

(05/96) C-3


Sometimes the first arrival, although strong enough to trigger the receiver nearer the transmitter, may be too weak by the time it reaches the far receiver to trigger it. Instead, the far receiver may be triggered by a different, later arrival in the sonic wave train, and the travel time measured on this pulse cycle will then be too large. When this occurs, the sonic curve shows an abrupt, large excursion towards a higher ∆t value; this is known as cycle skipping. Such skipping is more likely to occur when the signal is strongly attenuated by unconsolidated formations, formation fractures, gas saturation, aerated muds or rugose or enlarged borehole sections.

The sonic log is run with ∆t presented on a linear scale in tracks 2 and 3 with a choice of two scales: 500–100 and 300–100 µsec/m. A three-arm caliper curve representing the average borehole diameter and a gamma ray (GR) curve are recorded simultaneously in track 1 (See Figure C3). The gamma ray curve measures the natural radioactivity of potassium, uranium and thorium in the formation and is usually representative of the amount of shale present. This is because radioactive elements tend to concentrate in clays and shales. Later, we will use the GR to compute volume of shale ( V sh ). C2.2 POROSITY DETERMINATION a) Wyllie Time-Average Equation After numerous laboratory determinations, M.R.J. Wyllie proposed, for clean and consolidated formations with uniformly distributed small pores, a linear time-average or weighted-average relationship between porosity and transit time (see Figure C4):

9.8 m

tLOG = φt f + (1 – φ)t ma

(C1)

t LOG – t ma

or φ =

(C2) t f – t ma

2.25 m

Figure C2: BHC Sonic—GR tool distances

(05/96) C-4

where t LOG is the reading on the sonic log in µsec/m t ma is the transit time of the matrix material

Schlumberger

BOREHOLE COMPENSATED SONIC FILE 2

BS 125.0000

(MM)

125.0000

(MM)

375.0000

CALI 375.0000

GR 0.0000

(GAPI)

DT 150.0000

500.0000

(US/M)

100.0000

600

Figure C3 : Borehole-Compensated Sonic Log

(05/96) C-5


t f is the transit time of the saturating fluid (about 620 µsec/m for freshwater mud systems) φ is the porosity or volume occupied by pores 1 − φ is the volume of the matrix.

Typical Values:

Sand Lime Dolomite Anydrite

∆t matrix ∆t matrix ∆t matrix ∆t matrix

= 182 µsec/m = 156 µsec/m = 143 µsec/m = 164 µsec/m

When the formations are not sufficiently compacted, the observed ∆t values are greater than those that correspond to the porosity according to the time-average formula, but the φ versus t relationship is still approximately linear. In these cases, an empirical correction factor, C p, is applied to Equation 2 to give a corrected porosity, φSVcor (Equation 3):

t - t ma

φ SVcor =

1

× t f - t ma

(C3) C P

The value of C p is given approximately by dividing the sonic velocity in nearby shale beds by 328. However, the compaction correction factor is best determined by comparing φ SV , as obtained from Equations 1 and 2, with the true porosity obtained from another source. b) Raymer-Hunt Over the 25 years since acoustic velocity well logging was introduced, deficiencies have been noted in the transform of transit time ∆t to porosity φ.

Based on extensive field observations of transit times versus porosity, the new empirical Raymer-Hunt transform was derived. The new transform equation is too complicated to be presented in this course. An approximation of the transform is given in Equation C4 and the exact transform is presented in the chart books as the red lines on all sonic charts. t LOG - t ma

φ sv = C

(C4) t LOG

Figure C4: Components of the Wyllie Time-Average Equation

(05/96) C-6

The value of the constant C has a range of 0.625 to 0.7 depending upon the investigator. Chart Por-3m (Figure C6) uses 0.7 for C : this was the value originally proposed. However, more recent transit time-to-porosity comparisons indicate that a value of 0.67 is more appropriate.

Schlumberger

For the case of a gas-saturated reservoir rock, C becomes 0.6. It should be used when the rock investigated by the sonic tool contains an appreciable amount of hydrocarbon in the gassy (vapor) phase. Because of the shallow depth of investigation, this condition normally exists only in higher porosity sandstones (greater than 30%). From the example sonic log (Figure C3) at 593 m we read 352 µsec/m. Given ∆t ma =182 µsec/m we can solve for φ: Wyllie:

Raymer-Hunt (approximation):

5(352 - 182)

φ =

≅ 30% 8(352)

Chart Por-3m (Figure C6) solves this equation graphically. Enter t log of 352 µsec/m on abscissa and project upward until the appropriate ∆t ma line is reached (V ma = 5500 m/sec). If different values of V ma are used, we get different values of φ. With a ∆t log = 250µsec/m we would get

352 - 182

φ=

≅ 39% 620 - 182 V ma V ma

∆ t ma

V ma

(m/sec)

(µ sec/m)

Sandstone

5486

182

(m/sec) Range of Values 5486–5944

Limestone

6400

156

6400–7010

Dolomites

7010

143

7010–7925

Anhydrite

6096

164

6100

Salt

4572

219

4566

Casing (iron)

5334

187

5348

Fluid Transit Time: V1 = 1615 m/sec

∆ tf = 620 microsec/m for fresh muds = microsec/m for salt muds

Figure C5: Chart showing values used for common reservoir rocks

Sandstone (5500 m/sec) Lime stone (6400 m/sec) Dolomite (7010 m/sec)

Wyllie F

RaymerHunt F

16% 21% 26%

18.5% 24% 28.5%

C 2.3 FACTORS AFFECTING SONIC INTERPRETATION Lithology Lithology must be known to obtain the correct V ma . An incorrect choice of V ma will produce erroneous calculations. Shale Shale content generally causes ∆t to read too high for a porosity calculation because of the bound water in the shale. The sonic reads primary porosity, which may be affected by shale.

(05/96) C-7


Porosity Evaluation from Sonic Svf = 1615 m/s vf = 1615 m/sec 50

50 Time average Field observation

1.1

40

40

1.2 1.3 t e i

o m

l o D

30

t e i

l c a

C

) . u . p (

t z r u a

1.4

n e t o s n d s a

Bcp

n e t o s n d s a

φ

20 vma (ft/sec)

10

y t i s o r o p , φ

20

t e i z t m r o a l e u n e o t D l i c d q t o a 0 t e d s 0 C n n 0 e a 8 s m 0 z e t 0 r 0 C a 7 0 u 0 6 4 0 Q 5 9 5 0 0 5 5

10

0

0 100

150

200

250

300

350

400

t, interval transit time ( µsec/m)

EXAMPLE:

76 µ s/ft (249 µ s/m) SVma = 19,500 ft/s (5950 m/s) - Sandstone Thus, φ = 18% (by either weighted average or empirical transform)

t =

Sandstones Limestones Dolomites

SVma (ft/S) 18,000 - 19,500 21,000 - 23,000 23,000 - 26,000

tma (µs/ft)

55.5 - 51.3 47.6 - 43.5 43.5 - 38.5

Por-3m Figure C6

(05/96) C-8

) . u . p (

1.6

Q

y t i s o r o p ,

30

1.5

SVma (m/s) 5486 - 5944 6400 - 7010 7010 - 7925

tma (µs/m)

182 - 168 156 - 143 143 - 126

Schlumberger

Fluid Type The depth of investigation of the sonic is shallow; therefore, most of the fluid seen by the sonic will be mud filtrate. Oil Oil usually has no effect. Water There is usually no effect from water except where the drilling fluid is salt saturated, and then a different V f should be used, usually 607 µsec/m. Gas Residual gas causes ∆tlog to read too high when the formation is uncompacted. The gas between the sand grains slows down the compressional wave resulting in a long ∆t. In compacted sands, the wave will travel from one sand grain to another and the gas effect will be reduced. Compaction The value of ∆t log will read too high in uncompacted sand formations. Compaction corrections can be made if the compaction factor ( Bcp ) is known.

An approximate Bcp is obtained from the surrounding shales ( Bcp = ∆tsh /328). Bcp can also be obtained by comparing the porosity obtained from another source (core, density log, neutron log, computed log porosity) to that obtained from the sonic log in a clean water zone. (For example, if the neutron log in a clean water zone reads 20% and the sonic log reads 25%, then Bcp = 25%/20% = 1.25.) Secondary Porosity The sonic generally ignores secondary porosity. For example, in vugular porosity, the traveltime through the formation matrix is faster than the time through fluid in the vugs, because ∆t f is about 3 to 4 times the value of ∆t ma . Borehole Effect The compensated sonic is unaffected by changing hole size except in the case of extremely rough, large holes where the formation signal is severely affected by the noise of the mud signal and formation damage. Mudcake Mudcake has no effect on the BHC sonic because the traveltime through the mudcake is compensated.

(05/96) C-9


(05/96) C-10

Schlumberger

C3.0

Porosity Measurements from the Litho-Density Tool

C3.1 INTRODUCTION Litho-Density logs are primarily used for porosity and lithology measurements. Other uses include the identification of minerals in evaporite deposits, detection of gas, determination of hydrocarbon density, evaluation of shaly sands and complex lithologies, determination of oil-shale yield and calculation of overburden pressure and rock mechanical properties. C3.2 PRINCIPLE A radioactive source, applied to the borehole wall in a shielded sidewall skid (Figure C7), emits medium-energy gamma rays (662 keV) into the formation.

These gamma rays may be thought of as highvelocity particles that collide with the electrons in the formation. At each collision, a gamma ray loses some, but not all, of its energy to the electron and then continues with diminished energy. This type of interaction is known as Compton scattering. The scattered gamma rays reaching the detector, at a fixed distance from the source, are counted as an indication of formation density. The number of Compton-scattering collisions is related directly to the number of electrons in the formation. Consequently, the response of the density tool is determined essentially by the electron density (number of electrons per cubic centimeter) of the formation. Electron density is related to the true bulk density ρ b, which, in turn, depends on the density of the rock matrix material, formation porosity and density of the fluids filling the pores.

(GR energy > 1.02 MeV) (over entire GR energy range) ( ρ e ) (low-energy GR) (Z )

Figure C7: Schematic Drawing of the Dual Spacing Litho-Density Logging Device

Classical GR interactions by energy level are shown in Figure C8. Because of the mediumenergy GR emission, only points 2 and 3 occur with respect to Litho-Density operation.

Figure C8: Classical GR— Matter Interactions by Energy Level

(05/96) C-11


In addition to the bulk density measurement, the tool also measures the photoelectric absorption index of the formation, Pe . Photelectric absorption can be related to lithology; whereas the ρ b measurement responds primarily to porosity and secondarily to rock matrix and pore fluid, the Pe measurement responds primarily to rock matrix (lithology) and secondarily to porosity and pore fluid. At a finite distance from the source, such as the far detector, the energy spectrum may look as illustrated in Figure C9. The number of gamma rays in the higher energy region (region of Compton scattering) is inversely related only to the electron density of the formation (i.e., an increase in the formation density decreases the number of gamma rays). The number of gamma rays in the lower energy region (region of photoelectric effect) is inversely related to both the electron density and the photoelectric absorption. By comparing the counts in these two regions, the photoelectric absorption index can be determined.

The gamma ray spectrum at the near detector is used only to correct the density measurement from the far detector for the effects of mudcake and borehole rugosity.

7m

4.5 m

E (keV)

Figure C9: Variations in Spectrum forFormation with Constant Density but Different Z

(05/96) C-12

Figure C10: Basic SGT- CNT- LDT Tool Configuration

Schlumberger

This can be written as

ρ

ρma – ρb

ρ

ma

f

(1 – φ)

φ ρ

b

Figure C11: Components of Density Porosity Calculation

C 3.3 POROSITY FROM A DENSITY LO G For a clean formation of known matrix density ρ ma , with a porosity φ that contains a fluid of average density ρ f ,, the formation bulk density ρb, will be (Figure C11):

ρ b = φρ f + (1 – φ) ρma (clean wet zone) where: ρb is the measured bulk density (from Litho-Density tool) ρma is the density of the matrix ρ f is the density of the fluid φ is the percent volume of pore space (1 – φ) is the percent volume of matrix.

φ D = ρma – ρ fl where: ρma depends on lithology ρb is measured by the density log ρ fl depends on fluid type in pore volumes. The equation for ρb can be proven mathematically, unlike the sonic equation, which is an empirical relationship. Values of ρb are used for common reservoir rocks (zero porosity) (Figure C12). From the example Litho-Density log (Figure C13) at 593 m we read ρb = 2180 kg/m3. Given ρ f = 1000 kg/m3, ρma = 2650 kg/m 3, we can solve for φ D :

2650 − 2180 φ D =

= 28.5%

2650 − 1000 Chart Por-5 (Figure C14) solves this equation graphically. For ρb = 2180 kg/m 3 solving for porosity using other matrix values gives:

ρma = 2710 kg/m 3

φ D = 31%

ρma = 2870 kg/m 3

φ D = 36.9%

(05/96) C-13


ρ b Values for Common Reservoir Rocks and Fluids Compound

Formula

Quartz Calcite Dolomite Anhydrite Sylvite Halite

SiO2 CaCO3 CaCO3MgCO3 CaSO4 KCI NaCI

2654 2710 2870 2960 1984 2165

2648 2710 2876 2977 1863 2032

Compound

Formula

Actual Density ρ

ρa (as seen by tool)

Fresh Water Salt Water Oil Gas

H2O 200,00ppm n(CH2) C1.1 H4.2

1000 1146 850 ρg

1000 1135 850 1.325 ρg-0188

Figure C12

(05/96) C-14

ρa (as seen by tool)

Actual Density ρ

Schlumberger

LITHOLOGY DENSITY FILE 2

BS 125.0000

(MM)

375.0000

CALI 125.0000

(MM)

DRHO 375.0000

-250.0000

GR 0.0000

(GAPI)

(K/M3)

250.0000

RHOB 150.0000

2000.0000

(K/M3)

3000.0000

600

Figure C13

(05/96) C-15


Formation Density Log Determination of Porosity

1.0 0.9 0.8

ρf

1.1 1.2 40

) t e i m l o ) o d ( n e o ) 7 t 8 t e i d s 2 . 3 c l n = a 8 c s a ( a 2 . z 1 t ρ m = r 7 a 2 . 6 8 q u a ρ m = 2 . ( a 5 = 6 ρ m a . 2 ρ m =

30

a ρ m

) . u . p ( , y t i s o r o p ,

20

φ =

ρma – ρb ρma – ρf

φ

10

0 2.8

2.6

2.4

2.31

2.2

2.0

ρb, bulk density (g/cm 3)

Bulk density, ρ b, as recorded with the FDC* or LDT density logs, is converted to porosity with this chart. To use, bulk density, corrected for borehole size, is entered in abscissa; go to the appropriate reservoir rock type and read porosity on the appropriate fluid density, ρf . scale in ordinate. (ρ f is the density of the fluid saturating the rock immediately surrounding the borehole - usually mud filtrate.) EXAMPLE: ρb = 2.31 Mg/m3 in limestone lithology ρma = 2.71 (limestone) ρf = 1.1 (salt mud) Therefore

φD = 25 pu Por-5 Figure C14

(05/96) C-16

Schlumberger

C3.4 LITHOLOGY FROM P e MEASUREMENT The Pe curve is a good matrix indicator. It is slightly influenced by formation porosity and the presence of gas, but responds mainly to lithology (Figure C15). Hence, a safe interpretation of matrix lithology can be made for simple lithologies (one-mineral matrix). In conjunction with other log data, more complex mineral combinations can be analyzed.

P e

Typical Litho-Density responses for common minerals are presented in Figure C16. The Pe measurement is used 1. alone as a matrix indicator (the lithology curve) 2. in combination with density ρ b to analyze two-mineral matrices and determine porosity

φt 0.5 0.4 0.3 0.2 0.1 0

Figure C15: Photoelectric Absorption Index as a Function of Porosity and Fluid Content

(05/96) C-17


3. In combination with the density and neutron to analyse more complex lithologies (solutions to three-mineral matrices and porosity). A direct benefit from the more accurate description of the matrix is a more reliable distinction between gas and oil. In this section of the course, we use the Pe curve as a matrix indicator in simple lithologies. Using Pe for more advanced applications

P e

(complex lithology identification and heavy mineral-detection) is covered in Section H, Porosity in Complex Lithologies. Examples of the direct use of the Pe curve for lithology identification are shown in Figure C17. In the case of an anhydrite, Pe is equal to that of limestone. Anhydrite is positively identified by the bulk density or density porosity values.

ρ b

ρ

e

0

0 0 0 0

Figure C16: Typical Litho-Density Responses for Common Sedimentary Rocks

(05/96) C-18

Schlumberger

Figure C17: Lithology Identification with the CNT, Litho-Density and Pe

(05/96) C-19


C3.5

FACTORS AFFECTING THE DENSITY LOG

Lithology The correct ρma must be known to get correct porosity. Shale The density of shale in sands can range from 2200 to 2650 but is usually close to 2650, the same as sandstone. In shaly sands, the density usually gives a good value of effective porosity regardless of the shale content. The shale appears as matrix to the density tool.

ρb = ρ f φ e + ρma (1 – φ e – Vsh ) + ρsh Vsh collecting terms:

ρb = ρ f (φ e ) + ρma (1 – φe ) + Vsh (ρsh – ρma ) if ρsh = ρma , the last term is zero. Fluid Type The depth of investigation is quite shallow: usually most of the formation fluid is flushed away from the wellbore and the density tool sees drilling fluid or filtrate in the pore space. Hence, the values of ρ f to use is that of the drilling mud filtrate rather than the formation water density. Oil Residual oil will make density porosities slightly high, because oil is lighter than drilling mud filtrate. Water Water density is proportional to the amount of salt content. The value of ρ f is selected in the computer for porosity determination.

(05/96) C-20

Gas The ρf of gas is 100–300 kg/m3. Porosity determination in gas zones may be high if there is residual gas near the borehole. Usually most of the gas is flushed and little effect is seen on the density log. Compaction The density tool is unaffected by lack of compaction. Secondary Porosity The density reads intercrystalline, vugular and fractured porosity. The porosity measured is therefore total porosity. Borehole Effect Density gives good values for smooth holes up to 381 mm in diameter. The tool compensates for minor borehole rugosity, but a rough hole causes the density to read too low densities (high porosities) because the skid-to-formation contact is poor. Mudcake For normal mudcake thickness, there will be no effect because the tool automatically compensates for mudcake.

However for a ∆ρ correction of 100 kg/m 3 and greater (i.e., ∆ρ > 100 kg/m3), the tool compensation may be insufficient and the ρb no longer representative of the formation density. In this case, the density should obviously not be used for porosity calculations.

Schlumberger

C4.0

Porosity Measurements from the Compensated Neutron Tool

C4.1 INTRODUCTION Neutron logs are used principally for the delineation of porous formations and determination of their porosity. They respond primarily to the amount of hydrogen in the formation. Thus, in clean formations that have pores filled with water or oil, the neutron log reflects the amount of liquid-filled porosity.

Gas zones can often be identified by comparing the neutron log with another porosity log or a core analysis. A combination of the neutron log with one or more other porosity logs yields even more accurate porosity values and lithology identification—even an evaluation of shale content.

3 3 /8-in. DIAMETER

C4.2 PRINCIPLE Neutrons are electrically neutral particles, each with a mass almost identical to the mass of a hydrogen atom. High-energy (fast) neutrons are continuously emitted from a radioactive source in the sonde. These neutrons collide with the nuclei of the formation materials in what may be thought of as elastic billiard-ball collisions. With each collision, the neutron loses some of its energy.

The amount of energy lost per collision depends on the relative mass of the nucleus with which the neutron collides. A greater energy loss occurs when the neutron strikes a nucleus of practically equal mass (i.e., a hydrogen nucleus). Collisions with heavy nuclei do not slow the neutron much. Thus, the slowing of neutrons depends largely on the amount of hydrogen in the formation. Within a few microseconds, the neutrons have been slowed by successive collisions to thermal velocities, corresponding to energies of about 0.025 eV. They then diffuse randomly, without losing more energy, until they are captured by the nuclei of atoms such as chlorine, hydrogen or silicon. The capturing nucleus becomes intensely excited and emits a high-energy gamma ray of capture.

Figure C18: Schematic Drawing of the Dual Spacing Compensated Neutron Tool

(05/96) C-21


When the hydrogen concentration of the material surrounding the neutron source is large, most of the neutrons are slowed and captured within a short distance of the source. On the contrary, if the hydrogen concentration is small, the neutrons travel farther from the source before being captured. Accordingly, the counting rate at the detector increases for decreased hydrogen concentrations and vice versa. Thus, the neutron tool responds to the hydrogen index of the formation. The hydrogen index is a measurement of the amount of hydrogen per unit volume of formation (HI of water = 1).

sidewall neutron porosity (SNP) tools (in limited use) and the CNL tool series, which includes the compensated neutron and DNL* Dual-Energy Neutron Log. The current tools use americium-beryllium (AmBe) sources to provide neutrons with initial energies of several million electron volts. 1) SNP - detects epithermal neutrons - utilizes a skid mounted single detector - can be run in open hole only, either liquid-filled or empty - most corrections are automatically applied during logging - limited availability.

Neutron logging tools include the GNT (Figure C19) tools series (no longer in use),

0

Figure C19: Neutron Energy Travel History

(05/96) C-22

Schlumberger

2) CNL tool detects thermal neutrons - The CNL tool uses a two-detector system that depth and resolution matches each count rate before the ratio is computed. The ratio value is then converted to porosity on a linear scale (Figure C20), based on the matrix selected for the computation (limestone, sandstone or dolomite). - Conversion from one porosity assumption to another can be done using Chart Por-13b (Figure C22). Por-13b converts curves labelled "NPHI" that are not environmentally corrected and also converts for curves labelled "TNPH" and "NPOR," which are environmentally corrected. - The CNL tool is especially designed for use in combination with other devices. - The CNL tool can be run in liquid-filled holes, either open or cased, but not empty holes (i.e., air- or gas-filled holes.) 3) DNL tool detects thermal and epithermal neutrons - The DNL tool incorporates two epithermal neutron detectors in addition to the two thermal neutron detectors. Two separate porosity measurements are obtained, one from each pair of detectors. - Improves the response to gas and enhances interpretation in the presence of thermal neutron absorbers. - In shaly formations containing a large number of thermal neutron absorbers, the porosity measured by the epithermal

detectors reads lower and agrees more closely with density-derived porosity. - As with the CNL tool, the DNL tool is especially designed for use in combination with other devices. In addition, the DNL tool can be run in liquid-filled holes, air/gas-filled holes (epithermal porosity only) and open or cased holes.

C4.3

FACTORS AFFECTING CNL LOGS

Lithology A single known matrix must be present to accurately determine porosities. Large errors can occur if the matrix selection is incorrect. Shale The presence of hydrogen in chemically bound water causes the CNL/DNL tool to read high porosities in shales or shaly formations. Fluid Type Water: Fresh water has no effects. Saline water has a reduced hydrogen content and the CNL/DNL tool will read low porosity; the correction is in the chart book. Liquid Hydrocarbons: If the hydrogen content is close to that of water, there is little or no effect. Gas: If the hydrogen concentration is low, the CNL/DNL tool reads low porosity. Compaction All neutron logs are unaffected by compaction.

(05/96) C-23


COMPENSATED NEUTRON LITHODENSITY (NO PEF CURVE) FILE 2

BS 125.0000

(MM)

125.0000

(MM)

375.0000

CALI

DPHI 375.0000

0.6000

GR 0.0000

(GAPI)

0.0000

NPHI 150.0000

0.6000

600

Figure: C20

(05/96) C-24

(K/M3)

(V/V)

0.0000

Schlumberger

Secondary Porosity All neutron equipment measures total porosity (including primary and secondary). Borehole Effect The effects of rough hole are minimized by a large depth of investigation obtained by the use of a high-yield source and the two-detector system.

When run in combination with the density tool, an automatic caliper correction system is accurate to [356 mm]. Normally there is zero standoff correction.

Mudcake Corrections for mudcake, fluid (mud and formation) salinity, mud weight, pressure and temperature are in Charts Por-14(a) and 14(b), in the Log Interpretation Chart Book , but are not discussed in this course.

The average net correction is usually between one and three porosity units. Hence, for calculations by hand, the correction is usually not done.

(05/96) C-25


Neutron Porosity Equivalence Curves Sidewall Neutron Porosity (SNP), Compensated Neutron Log (CNL*) 40

l a i r e t a M x i r t a M d e t a c i d n I r o f y t i s o r o P e u r T ,

30

n e t o s n d a n e S t o s e m i L

20

t e i m l o o D

10

φ

SNP CNL

©Schlumberger

0 0

10

20

30

40

φSNPcor, Apparent Limestone Neutron Porosity (p.u.) φCNLcor, Apparent Limestone Neutron Porosity (p.u.)

When the SNP or CNL log is recorded in limestone porosity units, this chart is used to find porosity in sandstones or dolomites. For the SNP log, first correct for mudcake thickness. (Chart Por-15 is used for SNP mudcake corrections.) For the CNL log, simply enter the chart in abscissa with the apparent limestone neutron porosity; go to the appropriate matrix line, and read true porosity on the ordinate. (Chart Por-14 is used for CNL environmental corrections.) EXAMPLE: Sandstone bed Giving, hmc = 1 / 4 in. øSNP = 13 pu (apparent limestone porosity) øSNP = 11 pu (corrected for mudcake) Bit Size = 77 / 8 in. And, øSNP (sandstone) = 14 pu 5 SNP caliper = 7 / 8 in. This chart can also be used to find apparent limestone porosity (needed for entering the various CP-crossplot charts) if the SNP or CNL recording is in sandstone or dolomite porosity units. This chart should be used for CNL values labeled NPHI—it should not be used for CNL values labeled TNPH or NPOR.

Por-13a Figure C21 (05/96) C-26

Schlumberger

Neutron Porosity Equivalence Curves Compensated Neutron Log (CNL*)

40 Formation salinity 0 kppm

TNPH

250 kppm

NPHI l a i r e t a m x i r t a m d e t a c i d n i r o f y t i s o r o p e u r t ,

30

e n t o

) e d s n n o t s a e s z m t i r l i t e ( m u a e o t l i Q l c D o a

20

C

10

φ

0 0

10

20

30

40

φCNLcor, apparent limestone neutron porosity (p.u.)

*Mark of Schlumberger

Por-13b

Figure C22

(05/96) C-27


(05/96) C-28

Schlumberger

C5.0 Total Porosity Determination We have seen that porosity measurements are inferred from measurements of bulk density, hydrogen index and acoustic traveltimes. We have also seen that each measurement provides the necessary input to calculate porosity under the following conditions: – Porosity type is intergranular, not fractured or secondary (vuggy, moldic, etc.). – Matrix type is known and constant. – Rock is clean, (i.e., no shale present). – Porosity is filled with fluid. Violations of any of these conditions will cause the different porosity measurements to disagree in one fashion or another. This can be used to determine lithology, primary and secondary porosity and gas vs. liquid content. The question to be answered here is: Which porosity measurement should be used? In a sand-shale sequence, for initial computations,

a) if φ D is available, use φTOTAL = φ D b) if φ N and ∆t are available, use φTOTAL = φS with compaction corrections applied. In a carbonate, for initial computations (limestone matrix), a) if φ N and φ D are available in sandstone and limestone units, then use φTOTAL :

φ N + φ D φ T = 2 b) if only ∆t is available, use φTOTAL : φ T = φS + estimate φVUGS . If gas is present in the reservoir, additional corrections to φ N and φ D must be applied, as discussed in Section F. Porosity calculations in complex lithologies shall are discussed in Section H.

(05/96) C-29


Figure C23: Porosity Comparison between the LDT, CNT and SLT

(05/96) C-30

Schlumberger

C6.0

GR Log

6.1 INTRODUCTION The GR log is a measurement of the natural radioactivity of the formations. In sedimentary formations the log normally reflects the shale content of the formations. This is because the radioactive elements tend to concentrate in clays and shales. Clean formations usually have a very low level of radioactivity, unless radioactive contaminant such as volcanic ash or granite wash is present or the formation waters contain dissolved radioactive salts.

"Clean" Formation Sands Limestones Dolomites

Each of these elements emits gamma rays, the number and energies of which are distinctive for each element. Figure C24 shows the energies of the emitted gamma rays: potassium (K40) emits gamma rays of a single energy at 1.46 MeV, whereas the uranium and thorium series emit gamma rays of various energies.

GR Reading 15 to 30 API 10 to 20 API 8 to 15 API

The GR log can be recorded in cased wells, which makes it very useful as a correlation curve in completion and workover operations. It is frequently used to complement the SP log and as a substitute for the SP curve in wells drilled with salt mud, air or oil-base muds. In each case, it is useful for the location of shales and nonshaly beds and, most importantly, for general correlation. 6.2 PROPERTIES OF GAMMA RAYS Gamma rays are bursts of high-energy electromagnetic waves that are emitted spontaneously by some radioactive elements. Nearly all the gamma radiation that occurs in the earth is emitted by the radioactive potassium isotope of atomic weight 40 (K40) and by the radioactive elements of the uranium and thorium series.

Figure C24: Gamma Ray Emission Spectra of Radioactive Minerals

(05/96) C-31


In passing through matter, gamma rays experience successive Compton-scattering collisions with atoms of the formation material, losing energy with each collision. After the gamma ray has lost enough energy, it is absorbed, by means of the photoelectric effect, by an atom of the formation. Thus, natural gamma rays are gradually absorbed and their energies degraded (reduced) as they pass through the formation. The rate of absorption varies with formation density. Two formations with the same amount of radioactive material

(05/96) C-32

per unit volume, but with different densities, will show different radioactivity levels; the less dense formations will appear slightly more radioactive. (Figure C25). GR uses: 1. definition of shale beds 2. indicator of shale content 3. detection of radioactive and radioactive minerals 4. identification of formation tops.

non-

Schlumberger

Figure C25: Relative GR Response for Various Rocks/Formations

(05/96) C-33


6.3

NGS NATURAL GAMMA RAY SPECTROMETRY TOOL Like the GR log, the NGS Natural Gamma Ray Spectrometry tool measures the natural radioactivity of the formations. Unlike the GR log, which measures only the total radioactivity, this log measures both the number of gamma rays and the energy level of each and permits the determination of the concentrations of radioactive potassium, thorium and uranium in the formation rocks (Figure C27). Physical Principle Most of the gamma ray radiation in the earth originates from the decay of three radioactive isotopes: potassium (K40), uranium 238 (U238) and thorium 232 (Th232).

Potassium-40 decays directly to the stable argon-40 with the emission of a 1.46-MeV gamma ray. However, uranium-238 and tho-

rium-232 decay sequentially through a long sequence of various daughter isotopes before arriving at stable lead isotopes. As a result, gamma rays of many different energies are emitted and fairly complex energy spectra are obtained, as Figure C26 shows. The characteristic peaks in the thorium series at 2.62 MeV are caused by the decay of thallium-208 and bismuth-214 respectively. It is generally assumed that formations are in secular equilibrium; that is, the daughter isotopes decay at the same rate as they are produced from the parent isotope. This means that the relative proportions of parent and daughter elements in a particular series remain fairly constant; so, by looking at the gamma ray population in a particular part of the spectrum it is possible to infer the population at any other point. In this way, the amount of parent isotope present can be determined.

Figure C26: Potassium, Thorium and Uranium Response Curves (NAl Crystal Detector)

(05/96) C-34

Schlumberger NATURAL GAMMA SPECTROMETRY

ACCUMULATED INTEGRATION VALUES SUMMARY: Integrated Hole Volume: 2.07418 M3

FROM 209.87 M

TO 1995.07 M

TENS(N ) 50000.

0.0 SGR(GAPI)

0.0

150.00 POTA

THOR(PPM )

0.0

.09370

0.0

POTA 40.000

CGR(GAPI)

0.0

.10000

URAN(PPM )

0.0

150.00

-10.00

30.000

THORIUM

POTASSIUM

CP 32.6

FILE

3

00- -1941 00:39

INPUT FILE(S) CREATION DATE 61 02-JUN-1992 15:15

1/240

2000

2025

TENS-- ---SGR ---URAN ---THOR ---POTA ---P OTA ---CGR

Figure C27

(05/96) C-35


Once the parent isotope population is known, the amount of nonradioactive isotope can also be found. The ratio of potassium-40 to total potassium is stable and constant on the earth, whereas, apart from thorium-232, the thorium isotopes are rare and so can be neglected. The relative proportions of the uranium isotopes depend somewhat on their environment, and there is also a gradual change because of their different half-lives; at present, the ratio of uranium-238 to uranium-235 is about 137.

Applications: - identification of radioactive sands that may be misinterpreted as shales - identification of different types of shales/clays (see Figure C28) - depth correlation (same as GR) - complex lithology analysis.

Figure C28: Classification of Radioactive Minerals as a Function of the Th and K Values

(05/96) C-36

Schlumberger

C7.0

Borehole Geometry by Caliper Measure

C7.1 PHYSICAL PROPERTIES The hole diameter is usually recorded in conjunction with the following surveys: - Sonic logs (BHC versions, ASI Array Seismic Imager, DSI Dipole Shear Sonic Imager) - Microresistivity logs (microlog, MicroSFL, EPT Electromagnetic Propagation logs) - Litho-Density logs - Dipmeter logs (Dual Dipmeter Formation MicroScanner, FMI Formation MicroImager tools) - Borehole geometry log

The readings given by different calipers in the same hole may be different depending on the caliper design and the hole cross section. Figure C29 shows the characteristics of the different calipers:

No. of Arms

Phasing of the Arms (Degrees)

Sonic tool

3

120

16 in. [406 mm]

Microlog tool

1

0

20 in. [508 mm]

Micro-SFL tool (option A)

1

0

16 in. [406 mm]

Micro-SFL tool (option B)

4

90

22 in. [558 mm]

Density tool

1

0

Short Arm 16 in. [406 mm] Long Arm 21 in. [533 mm]

Dipmeters

4

90

FMS/FMI 22 in. [558 mm]

Borehole Geometry tool

4

90

Standard 30 in. [762 mm] Special 40 in. [1016 mm]

Dual Axis

2

180

Caliper tool

Maximum Diameter

16 in. [406 mm]

Remarks 3 1 1 1 1 1

arms coupled reading arm reading arm reading

4 arms coupled 2 × 2 2 paired readings 1 1 4 2 4 2

arm reading arms coupled 2 × 2 independent readings arms coupled 2 × 2 independent readings

2 arms coupled 1 reading

Figure C29: Caliper Specifications for Different Devices Statedon the Logs

(05/96) C-37


1) Mudcake is a good reason to have different calipers reading different values: - If the arm of the caliper is the blade type, it will cut into the cake and this arm will ignore the thickness of the mudcake. - If the arm is of the pad type, it will skid over the cake and the mudcake thickness will be taken into account. 2. Assuming no mudcake, the readings of different calipers in a perfectly round hole will be identical. But holes are not always round. In clearly ovalized holes, two- three- and four-arm calipers will read different hole diameter values, mostly because of the way these arms are coupled together. If the logging tool is fairly free to rotate inside the hole: - Two-arm calipers will ride using the larger diameter of the hole. - Four-arm calipers will ride with one pair of coupled arms using the larger diameter of the hole. 3) In deviated wells, calipers may partially collapse under their own weight and give readings that are too low. The following example (Figure C30) shows different calipers in an ovalized hole:

(05/96) C-38

- The sonic caliper (three arms linked together) shows an average hole diameter. - The density caliper (one arm) is applied on the wall with strength. Its back-up arm will cut into the mudcake. If no small-axis hardware is used, it will orient itself to read the largest diameter. If small-axis hardware is used, the Litho-Density tool tracks the smoother, short axis of the hole (if ovality exists). - The microlog caliper (one arm) will probably orient itself to read the larger diameter. Its pad will skid on any mudcake. This is the case in the upper part and lower part of this section. - Most calipers are designed to record accurate hole diameters in cylindrical boreholes. When boreholes are noncylindrical and depending on caliper configurations, a tool string will orient itself in some preferential direction. This can effect both caliper readings and log responses. Using Figure C31, consider the caliper responses in a 200- × 400-mm oval borehole for the various caliper types, configurations and preferred tool orientations. 100 m of 200- × 400-mm hole has a volume of 6.28m 3.

Schlumberger

Figure C30: Comparison of Various Caliper Responses

(05/96) C-39


Single-Arm Caliper Configuration: • records one borehole diameter = 400 mm • calculated 100 m hole volume = 12.57 m3 (+100% error) • tool examples: - Litho-Density log (No short-axis hardware) - MicroSFL tool (option A) - EPT Electromagnetic Propagation tool.

Two-Arm Caliper Configurations: a. Unidirectional • records one borehole diameter = 400 mm • calculated 100 m hole volume = 12.57 m3 (+100% error) • tool example: - MicroSFL tool (option B).

b. Bidirectional Long Axis • records one borehole diameter = 195 mm • records a second diameter = 195 mm • calculated 100 m hole volume = 2.9 m 3 ( −53%).

c. Bi-directional Short Axis • Records one borehole diameter = 273 mm • Records a second diameter = 273 mm • Calculated 100m hole volume = 5.85m3 (−7%).

Figure C31: Caliper Responses Under Various Hole Conditions

(05/96) C-40

Schlumberger

Three-Arm Caliper Configurations: a. Centered • records one borehole diameter = 260 mm • calculated 100 m hole volume = 5.31m3 (−15%) • tool example: - sonic log.

b. 90- Degree Offset • records one axis diameter = 200 mm • records a second diameter = 382 mm • calculated 100m hole volume = 6.00 m3 (−4%) • tool examples: - CNL Compensated Neutron log - Litho-Density log (short-axis hardware applied). Four-Arm Caliper Configuration: • records one-axis diameter = 200 mm • records a second diameter = 400 mm • calculated 100-m hole volume = 6.28 m3 (0%) • tool examples: - borehole geometry log - Dual-Dipmeter tool - Formation MicroScanner - FMI Formation MicroImager.

Figure C31 (Continued)

(05/96) C-41


(05/96) C-42

Schlumberger

C8.0 Work Session 1a. For the example logs of Figures C32 – C34, calculate the following: (Formation = Sandstone) 581 m

600 m

a. R ILD b. Rt c. ∆t d. φ S e. φ D f. φ N

2. Using the sonic log of Figure C34, calculate the sonic porosity at 586 m.

∆t f = 620 µsec/m ∆t ma = 182 µsec/m

∆t - ∆t ma φ s =

=

∆t f - ∆t ma 5(∆t - ∆t ma ) φ s =

=

8∆t

b. Using Chart Por-3m (Figure C6)

φs Wyllie Time-Average = φs Field Observation =

(05/96) C-43


3a. On the CNT–Litho-Density log of Figure C35, what effect is seen at 1941 to 1946 m?

b. Using the Pe , what is the lithology in this zone?

c. Convert the log readings (φ N and φ D ) to equivalent sandstone values.

d. Explain the effect identified in question 3a.

(05/96) C-44

Schlumberger DUAL INDUCTION - SP/SFL FILE 2

ILM 0.2000

(OHMM)

0.2000

(OHMM)

2000.0000

ILD

SP -150.0000

(MV)

2000.0000

SFLU 0.0000

0.2000

(OHMM)

2000.0000

600

Figure C32

(05/96) C-45


COMPENSATED NEUTRON LITHODENSITY (NO PEF CURVE) FILE 2

SANDSTONE

BS 125.0000

(MM)

375.0000

CALI 125.0000

(MM)

375.0000

0.6000

GR 0.0000

(GAPI)

0.0000

NPHI 150.0000

0.6000

600

Figure C33

(05/96) C-46

DPHI (V/V)

(V/V)

0.0000

Schlumberger

BOREHOLE COMPENSATED SONIC FILE 2

BS 125.0000

(MM)

375.0000

CALI 125.0000

(MM)

375.0000

GR 0.0000

(GAPI)

DT 150.0000

500.0000

(US/M)

100.0000

600

Figure C34

(05/96) C-47

03 Porosity Measurement

Recommend Documents