CORE Fluid saturations
Saturation of a particular fluid is the proportion of that fluid compared to the porosity:
       1: Swtr  = Vwtr / PHIcore
       2: Soil   = Voil / PHIcore
       3: Sgas = Vgas / PHIcore
       4: Swtr + Soil + Sgas = 1.00

In the laboratory, it is easier to measure weight (mass) than volume, although both are often recorded.
       5: Fluid weight = Weight water + Weight oil + Weight gas
 OR 6: Fluid weight = DENSwtr * Vwtr + DENSoil * Voil + DENSgas * Vgas
 OR 7: Fluid weight = PHI * (DENSwtr * Swtr + DENSoil * Soil + DENSgas * Sgas) 

During coring, moveable hydrocarbons are flushed from the core and replaced by mud filtrate, leaving residual oil and irreducible water. Some of the irreducible water may be replaced by mud filtrate as well. During recovery and transport of the core, the majority of the water will drain out, leaving residual oil and irreducible water. The sum of residual oil saturation plus irreducible water saturation is usually less than 1.0, the balance being the moveable oil saturation. In older reservoirs with many years of production, there may also be some moveable water. This will also be flushed by the mud filtrate. To appreciate the meaning of the core saturations,  it is important to know the history of a reservoir relative to the when the core was cut.

In petrophysical analysis, we utilize the core water saturation as a guide to the irreducible water saturation in a reservoir above the transition zone. In a core, the difference between residual oil and water saturation is usually assumed to be the moveable oil fraction of the reservoir fluids, when the reservoir is at initial conditions. The core water saturation is usully assumed to be close to the irreducible water saturation.

In older reservoirs, no longer at initial conditions,, there may be some moveable water as well as the moveable oil. This can often be seen on the log analysis results depth plots where log analysis saturation is higher than core water saturation. The excess water saturaton is a measure of potential water production.

If corroboration of water saturation is required, air-brine capillary pressures should be taken, along with electrical properties, from at least a dozen core plugs with some variations in porosity or pore geometry. This will resolve the initial irreducible water saturation question. A reservoir simulation history match would be needed to resolve the question of moveable water saturation.

Cores taken in oil based mud give a better view of irreducible water, as these muds do not displace the water.

The main use for core analysis oil saturation in conventional reservoirs is to estimate minimum possible residual oil saturation, and to assist in locating gas-oil and oil-water contacts. Gas and water zones have low residual oil, unless they were once oil zones (recently or in earlier geologic time). Oil saturation from core analysis is quite useful in tar sand and sometimes in heavy oil evaluations, where flushing is minimal.

In oil sands (tar sands), the oil mass is the primary measurement used to evaluate reservoir quality and oil in place calculations. Since there is no drilling fluid invasion in a tar sand core (unless free gas is also present in the pore space) the sum of Soil + Swtr = 1.0.
 

CORE saturation measurements
A common method for direct measurement of saturation in a core sample is the distillation retort method. Core samples are heated, fluids are vaporized and condensed into a graduated glass receptacle. This is a rapid method to determine oil and water volumes. Unfortunately, high temperature (1100 F) may destroy the sample and drives off clay bound water (CBW). Clay bound water may be estimated by observation of water volume versus time - pore water is recovered first and clay bound water later, as the temperature increases..


 

In a core drilled with water base mud, the oil volume is divided by the porosity to obtain a residual oil saturation. Similarly, a water saturation is determined, but the sum of Soil + Swtr will not equal 1.00 due to evaporation of water prior to the measurement. In an oil based core, the sum of fluid volumes gives total porosity (PHIt).

In both cases, coking and cracking of the oil reduces oil volume, resulting in low estimated oil saturation. Core lab companies scale the recovered oil by a factor to account for this. The scale factor (KSF) varies from about 1.08 for light oil to 1.28 for heavy oil. Final results are calculated from:
       8: Swtr = (Vwtr - CBW) / PHIe
       9: Soil = (Voil * KSF) / PHIe

PHIe is usually determined by an independent lab method from a very nearby core sample.

The solvent extraction method is somewhat similar. The core sample is held in a thimble above a source of solvent, which is heated. The solvent vapour mobilizes the water, dissolves the oil, and all are condensed, recovered, and measured.

The method gives an accurate water saturation, can be done as part of the core cleaning process, and is non-destructive. The method is slow and can take several days. Oil saturation is determined by an indirect method, as follows:
       10: Swtr = Vwtr / PHIe
       11: Voil = ((WTinit - WTdry) - Vwtr * DENSwtr)
                     / DENSoil   
       12: Soil = Voil / PHIe

Only in rare cases will Soil + Swtr = 1.00 - the balance is Sgas, usually air that entered the core during transport and storage.
 

SAMPLE CORE ANALYSIS REPORT

02181815W4R

#27771

780118

 

Revised Analysis - Soil and Swtr from Original Analysis

S#

Top

Base

Len

Kmax

K90

Kvert

Poros

GrDen

BkDen

Soil

Swtr

Lithology

 

feet

feet

feet

mD

mD

mD

frac

Kg/m3

Kg/m3

frac

frac

 

1

3499.19

3500.17

0.98

370.0

316.0

264.0

0.255

2850

2378

0.129

0.448

SS VF

2

3500.17

3501.16

0.98

445.0

425.0

326.0

0.248

2680

2263

0.123

0.450

SS VF

3

3501.16

3502.17

1.02

764.0

751.0

231.0

0.248

2670

2256

0.111

0.520

SS VF

4

3502.17

3503.16

0.98

445.0

417.0

127.0

0.234

2670

2279

0.129

0.479

SS VF

5

3503.16

3503.88

0.72

479.0

411.0

84.0

0.241

2700

2290

0.110

0.504

SS VF PRY

6

3503.88

3504.57

0.69

860.0

790.0

172.0

0.242

2680

2273

0.118

0.466

SS VF

7

3504.57

3504.67

0.10

 

0.1

0.1

 

 

 

 

 

SHALE

8

3504.67

3505.26

0.59

 

0.1

0.1

 

 

 

0.151

0.398

RUBBLE

9

3505.26

3505.49

0.23

486.0

402.0

261.0

0.246

2670

2259

0.134

0.358

SS VF SH INC

10

3505.49

3505.98

0.49

355.0

326.0

8.3

0.207

2640

2301

0.143

0.268

SS VF SHBKS

11

3505.98

3506.96

0.98

376.0

192.0

32.2

0.240

2650

2254

0.131

0.471

SS VF

12

3506.96

3507.88

0.92

250.0

245.0

17.6

0.218

2640

2282

0.156

0.399

SS VF CARB INC

13

3507.88

3508.47

0.59

491.0

0.1

0.1

0.237

 

 

0.119

0.389

SS VF

14

3508.47

3508.87

0.39

304.0

0.1

0.1

0.219

 

 

0.136

0.422

SS VF CARB BK

15

3508.87

3509.88

1.02

309.0

288.0

127.0

0.230

2850

2425

0.132

0.440

SS VF

16

3509.88

3510.87

0.98

845.0

340.0

135.0

0.237

2660

2267

0.131

0.323

SS VF SH INC

17

3510.87

3511.88

1.02

298.0

287.0

75.3

0.218

2650

2290

0.146

0.422

SS VF SH INC

18

3511.88

3512.87

0.98

139.0

0.1

0.1

0.208

2650

2307

0.103

0.354

SS VF

19

3512.87

3513.79

0.92

139.0

0.1

0.1

0.174

 

 

0.073

0.418

SS VF

20

3513.79

3514.38

0.59

 

0.1

0.1

 

 

 

0.096

0.441

RUBBLE

21

3514.38

3515.07

0.69

65.1

0.1

0.1

0.257

 

 

0.119

0.387

SS VF

22

3515.07

3515.16

0.10

 

0.1

0.1

 

 

 

 

 

SHALE

23

3515.16

3516.18

1.02

1050.0

385.0

385.0

0.254

2670

2246

0.044

0.492

SS VF

24

3516.18

3516.77

0.59

385.0

471.0

471.0

0.220

2660

2295

0.042

0.501

SS VF

25

3516.77

3517.46

0.69

835.0

183.0

183.0

0.237

2670

2274

0.050

0.531

SS VF CARB INC

26

3517.46

3518.28

0.82

901.0

644.0

644.0

0.238

2650

2257

0.046

0.487

SS VF

27

3518.28

3519.07

0.79

438.0

103.0

103.0

0.240

2690

2284

0.079

0.494

SS VF CARB INC

28

3519.07

3519.99

0.92

1430.0

278.0

278.0

0.251

2660

2243

0.063

0.501

SS VF

29

3519.99

3520.58

0.59

 

0.1

0.1

 

 

 

0.052

0.563

RUBBLE

30

3520.58

3521.46

0.89

1050.0

951.0

951.0

0.258

2570

2165

0.055

0.516

SS VF

31

3521.46

3522.48

1.02

382.0

61.5

61.5

0.210

2690

2335

0.064

0.450

SS M P/SCARB INC

32

3522.48

3523.47

0.98

570.0

48.9

48.9

0.186

2680

2368

0.058

0.408

SS M P/SCARB INC

33

3523.47

3524.48

1.02

 

0.1

0.1

 

 

 

0.082

0.411

RUBBLE

34

3524.48

3525.47

0.98

3149.0

321.0

321.0

0.209

2590

2258

0.051

0.391

SS VF

35

3525.47

3526.48

1.02

 

0.1

0.1

 

 

 

0.073

0.360

RUBBLE

36

3526.48

3527.47

0.98

285.0

48.8

18.8

0.170

2690

2403

0.046

0.481

SS M P/S

37

3527.47

3528.16

0.69

193.0

0.1

0.1

0.169

2770

2471

0.042

0.548

SS M P/S CARB

38

3528.16

3528.88

0.72

 

0.1

0.1

 

 

 

0.066

0.462

RUBBLE

 

 

 

 

 

 

 

 

 

 

 

 

 

Arithmetic Averages

0.78

602.9

228.6

140.2

0.227

2679

2297

0.095

0.443

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Use the oil saturation (Soil) data in this core analysis example to find the oil - water contact.
 

CALIBRATING LOG ANALYSIS TO CORE SATURATION EXAMPLES
These examples demonstrate the close match between log analysis water saturation and core analysis water saturation. It works most of the time, especially with cores cut after the mid 1980's, provided they have been handled according to best practices. If it doesn't work, or doesn't seem to make sense, forget it and move on.


Bakken “Tight Oil” example showing core porosity (black dots), core oil saturation (red dots). core water saturation (blue dots), and permeability (red dots). Note excellent agreement between log analysis and core data. Separation between red dots and blue water saturation curve indicates significant moveable oil, even though water saturation is relatively high. Log analysis porosity is from the complex lithology model and lithology is from a 3-mineral PE-D-N model using quartz, dolomite and pyrite.


Sandstone example (left) and carbonate example (right) showing close match of log analysis and core analysis water saturation. Black dots are core porosity and permeability. Light blue dots are core analysis water saturation, which fall close to log analysis saturation curve (blue). Red dots on sandstone example are residual oil saturation, showing lots of moveable oil between the water curve, even though the water saturations are quite high (due to poor pore geometry).



Oil sand analysis with top water, bottom water, top gas, and mid zone gas. Core and log data match - but oil mass is the critical measure of success. Core porosity matches total porosity from logs, due to the nature of the summation of fluids method used in these unconsolidated sands. Minor coal streaks occur in this particular area.
 

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