Reservoir Formation Damage Episode 3 Part 5 pdf

Hypothetical zones not to scale around an Energy Field well in which reactions were simulated after Demir, 1995; reprinted by permission of the Illinois State Geological Survey... After

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0 15 30km Figure 17-14 Areal distribution of Aux Vases formation waters resistivities

(after Demir, 1995; reprinted by permission of the Illinois State GeologicalSurvey)

Acid Treatment of Wells

Demir (1995) simulated the treatment of the Morgan Coal no 3 well

in Energy Field, Williamson County, Illinois using mud-cleaning acids(MCA) Table 17-5 presents the reservoir mineralogy data from a nearbywell, the Morgan Coal no 2 well, used by Demir (1995) for the MorganCoal no 3 well Figure 17-16 by Demir (1995) describes the hypotheticalzones around the well considered for simulation of the MCA treatment

of the near wellbore formation Considered for simulation were 7.5 and15% HCL-MCA solutions containing 0.1 molal KCL (clay stabilizer) and

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r2 = 0.992-O.B-] \"

Figure 17-15 Relationship between Aux Vases and Cypress formation water

resistivities and IDS The r2 is the square of the correlation coefficient (afterDemir, 1995; reprinted by permission of the Illinois State Geological Survey)

Table 17-4 Saturation Indexes (SI) a of Minerals that have the Potential for Formation Damage in Five Aux Vases and Five Cypress Formation Water Samples*

Aux Vases King

Mattoon Carmi North Clay City Eldorado

0.4 0.3 0.8 -0.7 -0.5

0.3 0.5 -1.0 0.1 0.1

-3.3 -0.5 -0.3 -1.8 -0.3

-0.4 -2.0 -0.7 -0.2 -0.7

-2.8 -0.5 -0.4 -1.5 -0.3

-0.3 -1.6 -0.5 -0.3 -0.3

0.8 0.2 0.0 1.3 0.0 0.3 0.4 0.3 0.5 0.1

2.1, 2.1, 2.5, 2.0, 2.5,

1.5, 2.2, 2.0, 2.1, 2.5,

2.2, 2.2, 2.6, 2.1, 2.7,

1.6, 2.3, 2.1, 2.2, 2.6,

11.0 11.5 11.1 11.4 12.1

10.6 10.7 11.5 11.3 11.7

a Sl>0, supersaturated; Sl=0, equilibrium; Sl<0, undersaturated.

b The first, second, and third numbers belong to pyrothite, troilite, and pyrite, respectively.

* See Table 17-1 for detailed information on the samples and text for computation of reservoir temperatureand pressure

After Demir, 1995; reprinted by permission of the Illinois State Geological Survey

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Table 17-5Mineralogical Composition and Porosity of the Producing Sandstone

Interval in the Morgan Coal No 2 Well, Energy Field

Minerals (wt %, except the last row) Porosity

Depth (ft) Illite Illite/smectite Chlorite Quartz K-feldspar Plagioclase Calcite Other (%)

2.4 1.9 2.5 1.7 3.0 4.1 2.6 2.3

81 57 85 73 76 63 73 71

0.0 0.2 0.6 0.2 0.4 0.0 0.2 0.3

8.2 8.2 2.6 7.8 6.3 2.5 5.9 6.0

6.0 31.0 6.7 17.0 13.0 27.0 16.8 16.1

4.7 5.7 0.6 0.4 0.0 tr 1.9 1.8

21.3 21.7 23.6 23.3 20.6 13.6 - 22.0 a

a 22.1 was rounded to 22 in geochemical modeling computations.

' / ' "

• ' * r 9

' '•'.".•••

.' zone 2 • ' flush ' pore ' volume

Figure 17-16 Hypothetical zones (not to scale) around an Energy Field well

in which reactions were simulated (after Demir, 1995; reprinted by permission

of the Illinois State Geological Survey)

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the formation brine with the analysis given for sample EOR-B6 in Table17-1 The reservoir temperature was taken as 36°C.

The simulated changes of the mineral contents in various zones after

2 days of exposure to the treatment fluids are presented in Tables 17-6and 17-7 by Demir (1995), respectively, for 15 and 7.5% HCL-MCAtreatments Table 17-8 by Demir (1995) shows the predicted pH, and the

CO 2 gas and dissolved iron species produced by 7.5 and 15% HCL-MCAtreatments Figures 17-17 and 17-18 by Demir (1995) show the predicted

changes in mineral compositions and the fugacity of the produced CO2

gas, which dissolves in aqueous phase readily at elevated reservoir fluidpressure conditions, for 15% HCL-MCA treatment

The results of the simulations by Demir (1995) indicate an increase

in porosity with either 15% or 7.5% HCL-MCA treatment Demir (1995)concludes, however, that the probability of asphaltene precipitation

is higher with 15% HCL-MCA treatment because of the higher acidityand dissolved iron concentrations in this case compared to 7.5% HCL-MCA treatment

Water/loading

Demir (1995) simulated the consequences of waterflooding operations

in the Dale consolidated field Demir (1995) considered the injection andthe Aux Vases formation brines with the analyses of samples EOR-B101and EOR-B107, respectively, given in Table 17-1 The Aux Vases reservoirformation mineralogical composition and porosity were approximated bydata obtained from a McCreery no 1 well core, given in Table 17-9 byDemir (1995) The Aux Vases formation brine pH had to be adjusted to5.85 to achieve convergence in the simulation, although the actual fieldmeasured value was 5.34 The reservoir temperature taken was 37°C.Demir (1995) simulated two different scenarios: (1) replacement of porewater by flushing, and (2) mixing of pore and injection waters

In the first case, a ten pore volume of injection water was injected tocompletely flush out the pore water and react with the formation mineralsuntil thermodynamic equilibrium As can be seen by the simulated resultsgiven in Table 17-10 by Demir (1995), the porosity is unaffected andremains constant at 20%, for all practical purposes, when compared withthe values given in Table 17-9 by Demir (1995), in spite of the variation

of the individual mineral constitutients of the formation, as shown inFigure 17-19 by Demir (1995)

In the second case, Demir (1995) simulates the consequences of mixingthe injection and pore waters at a ratio of 1:1 and the resultant reactions

(text continued on page 590

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Table 17-6 Mineral Volume Corresponding to Each kg (917 cm 3 ) of Pore Water (at a 50% water saturation), or 1834 cm 3 Total Pore Volume Before and After Treatment of a Production Well in Energy Field with 15% HCI-MCA

Net change in total mineral volume

% Change in total pore volume"

Final porosity (%)°

Final volume (cm 3 )

Predicted Net change*

4703 393 147 0 0 0 0 161 115 0.1 83

4703 393 239 0 0 0 0 161 115 0.2 84

4703 393 1053 102

92 (muscovite)"

90 0 39 0.2 2 0.3

0 0 -913 -154 -112 -26 -17 +161 +115 +0.1 +83 -863 +47.1 32.4

0 0 -821 -154 -112 -26 -17 +161 +115 +0.2

^tM -770 +42 31.2

0 0 -7 -52 -20 +64 -17 +39 +0.2 +2 +0.3 +9.5 -0.5 21.9

3 Difference between original measured values and values after reaction path ended.

b (net change in total mineral volume/original total pore volume) x 100.

0 (1 + (% change in total pore volume/100)) x (original porosity).

d Model assumes muscovite is a proxy for illite.

tr = trace.

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Table 17-7Mineral Volume Corresponding to Each kg (917 cm3) of

Pore Water (at a 50% water saturation), or 1834 cm3 TotalPore Volume Before and After Treatment of a Production

Well in Energy Field with 7.5% HCI-MCA

Mineral Measured Predicted

% Change in total pore volume 6

Final porosity (%) c

Predicted Net change 8

4703

393 699

0 0 29 0 165 86 80

4703 393 735 0 0 29 0 161 115 0.2 90

4703 393 1056 109

90 (muscovite)

87 0 0.2 37 0.3

0 0 -361 -154 -112 +3 -17 +165 +86 +80 -310 +16.9 25.7

0 0 -325 -154 -112 +3 -17 +161 +115 +0.2 +90 -239 +13 24.9

0 0 -4 -45

d -22 +61 -17 +0.2 +37 +0.3 +10.5 -0.6 21.9

a Difference between original measured values and values after reaction path ended.

6 (net change in total mineral volume/original total pore volume) x 100.

c (1 + (% change in total pore volume/100)) x (original porosity).

d Model assumes muscovite is a proxy for illite.

tr = trace.

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Fe ++ (molal) FeCI 2 (molal) FeCI + (molal) Total Fe (molal) 7.5% HCI-MCA

CO 2 gas fugacity pH

Fe+ + (molal) FeCI 2 (molal) Fecr (molal) Total Fe (molal)

1Q 1.5

4.50 0.0047 0.0015 0.0049 0.0110

Concentration Zone 3

1Q 1.8

4.29 0.0066 0.0100 0.0144 0.0310

10 13

4.65 0.0041 0.0015 0.0046 0.0100

Zone 4

6.51 0.0012 0.0010 0.0020 0.0042

6.59 0.0008 0.0006 0.0012 0.0026

r eprinted by permission of the Illinois State Geological Survey.

Figure 17-17 Predicted changes in mineralogical compositions along the

reaction path when 1 part of pore water is flushed with 10 parts of 15% MCA in an Energy Field well (after Demir, 1995; reprinted by permission ofthe Illinois State Geological Survey)

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HCI-20 25 30 H* reacted (moles)

Figure 17-18 Predicted change in CO2 fugacity along the reaction path when

1 part of pore water is flushed with 10 parts of 15% HCI-MCA in an EnergyField well (after Demir, 1995; reprinted by permission of the Illinois StateGeological Survey)

Table 17-9 Mineralogical Composition and Porosity of the Producing Sandstone Interval in McCreery No 1 Well, Dale Consolidated Field

Minerals (wt %, except the last row) Porosity Depth (ft) Illite Illite/smectite Chlorite Quartz K-feldspar Plagioclase Calcite (%)

0.7 0.7 0.6 0.9 0.7 0.8 0.6 0.9 0.4 0.5 0.7 0.5 1.9 0.8 0.8

84.5 81.6 84.9 79.5 88 80.7 82.5 82.3 77.8 83.7 67.8 82.9 68.4 80.4 80.8

1.3 1.7 1.5 1.2 1.9 2.6 2.7 2.6 1.5 1.2 0.8 1.7 1.2 1.5 1.6

2.5 3.2 3.7 4.3 3.2 2.6 3.7 3.3 1.9 2.4 1.5 2.8 1.8 2.7 2.7

6.4 8.6 5.6 8.1 2.0 8.5 6.8 5.5 14.2 7.6 21.8 8.4 16.8 9.3 9.1

20.4 23.4 25.6 23.6 19.8 24.8 24.3 21.4 18.6 21.4 14.5 13.1 11.5

20.0 a

a 20.2 was rounded to 20 in geochemical modeling computations.

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Table 17-10 Mineral Volume Corresponding to Each kg (917 cm 3 ) of Pore Water (at a 50% water saturation), or 1834 cm 3 Total Pore Volume, Before and After Flushing the Pore Volume Ten Times with Injection

Water in Dale Consolidated Field

Original mineral volume (cm 3 )

P, Predicted vc Minerals Measured by model re

% Change in total pore volume0

Final porosity (%) d

5894 193 657

22 (daphnite)

176 (muscovite) b

71 (nontronite + saponite) 116

131 tr 0.1 tr

redicted mineral Hume (cm 3 ) after action path Net change 8

5937 167 656 0

331 (muscovite) b

111 (nontronite + saponite) 0

38 1 1 tr

+84 -26 -1 -58 +41 +34 -116 + 38 +1 +1 nd -2 +0.1 20.0

tr = trace, nd = not detectable.

(text continued from page 585)

until thermodynamic equilibrium The results presented by Demir (1995)

in Table 17-11 indicate a negligible change of porosity from 20 to 20.2%

In both the 10 times pore volume flush and 1:1 mixture cases, the pHwas predicted to remain approximately neutral (Figure 17-20 by Demir,1995) Therefore, Demir (1995) concludes that asphaltene precipitation,which occurs in acidic media, is not likely during waterflooding, and clayswelling should not occur because the TDS and chemical compositions

of the injection and formation brines are similar

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H 2 O reacted (kg)

Figure 17-19 Predicted changes in mineral concentrations along the reaction

path when 1 part pore water is flushed with 10 parts injection water in theAux Vases reservoir, Dale Consolidated Field (after Demir, 1995; reprinted

by permission of the Illinois State Geological Survey)

Carbon Dioxide Flooding

Demir (1995) simulated the consequences of carbon dioxide flooding

in Tamaroa field Demir (1995) compared the results of two scenarios:(1) reaction of 1 mole of carbon dioxide, and (2) reaction of 5 mole ofcarbon dioxide with the formation minerals and/or brine until thermo-dynamic equilibrium The formation brine was assumed the same assample EOR-B22 given in Table 17-1 and the average formation mineralcomposition and porosity were assumed as those given in Table 17-12

by Demir (1995) The reservoir temperature was taken as 32°C

In the first case, the reaction of 1 mole of carbon dioxide within aformation containing 1 kg of brine was simulated As can be seen fromthe results presented in Table 17-13 and Figure 17-21 by Demir (1995), theporosity remain approximately constant, in spite of the changes of theindividual mineral constitutes Demir (1995) concludes that pH is above theoriginal pH value of 6.5 (Figure 17-22) making the asphaltene precipitationunlikely and the relatively high TDS should prevent clay swelling

In the second case, Demir (1995) simulates the reaction of 5 mole ofcarbon dioxide The results presented in Table 17-14 and Figure 17-23

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Table 17-11 Mineral Volume Corresponding to Each kg (917 cm 3 ) of Pore Water (at a 50% water saturation), or 1834 cm 3 Total Pore Volume, Before and After Mixing Injection and Formation Waters at a 1:1

Ratio in Dale Consolidated Field

PI Predicted vc Minerals Measured by model re

Final porosity (%) d

5894 193 657

22 (daphnite) 176(muscovite) b

71 (nontronrte + saponite) 116

131 tr 0.1 tr

redicted mineral

>lume (cm 3 ) after laction path Net change 9

5948 184 657 26

327 (muscovite) b

65 (saponite) 0

28 0.4 0.2 tr

+95 -9 0 -32 +37 -12 -12 -116 +28 +0.4 +0.2 nd -20.4 +1.1 20.2

tr = trace, nd = not detectable.

by Demir (1995) indicate a reduction of porosity from 19 to 18.4% Based

on the simulated pH variation given in Figure 17-22, Demir (1995)concludes that decreased pH values may initiate asphaltene precipitation,but the peptizing effects of resins (about 10-18% present in the oil)minimizes the possibility of asphaltene precipitation

Alkali Flooding

Demir (1995) simulated the consequences of alkali flooding in Tamaroafield Demir (1995) considered the same formation minerals and brineinformation used in the carbon dioxide flooding Three alkali solutions

were considered: (1) 0.5 mole of NaOH, (2) 0.25 mole of Na2 CO 3 , and

(3) 0.25 mole of Na 2 SiO 3 Simulations were carried out for 30 days

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10x flush

H 2 O reacted (kg)

Figure 17-20 Predicted change in pH along the reaction path when 1 part

of pore water is flushed with 10 parts of injection fluid and when pore andinjection waters are mixed at a 1:1 ratio in the Aux Vases reservoir, DaleConsolidated Field (after Demir, 1995; reprinted by permission of the IllinoisState Geological Survey)

Table 17-12 Mineralogical Composition and Porosity of Producing Sandstone

Interval in Stockton No 1 Well, Tamaroa Field

Depth (ft)

Minerals (wt %, except the last row)

0.6 3.5 3.7 0.5 2.9 2.9

0.2 1.6 3.1 0.3 1.3 1.1

98 90 77 97 90.5 90

0.5 4.1 9.8 1.8 4.1 4.2

0.4 0.1 4.6 0.2 1.3 1.3

21.5 20.7 15.8 19.3

19.0 a

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Table 17-13 Mineral Volume Corresponding to Each kg (943 cm 3 ) of Pore Water (at a 40% water saturation), or a Total Pore Volume of 2358 cm 3 , Before and After the Reaction of 1 mol CO 2 Gas with the Cypress

Reservoir in Tamaroa Field

P,

Predicted vc Minerals Measured by model re

% Change in total pore volume d

Final porosity (%) e

9045

423 132

redicted mineral

>lume (cm 3 ) after (action path Net change 3

9045

423 133

4 (daphnite)

303

13(muscovite) c

64 (saponite) + saponite)

23 5 26

0.2 0.1 tr

0 0 +1 -99 +12 -9 +55 +23 +5 +26 +0.2 +0.1 nd +14.3 -0.6 18.9

a Difference between original measured values and values after reaction path ended.

b The original measured volumes of these minerals were adjusted somewhat to make the simulation runs converge (compare the first and second columns of this table to those of table 11).

0 Model assumes muscovite is a proxy for illite.

d (net change in total mineral volume/original total pore volume) x 100.

6 (1 + (% change in total pore volume/100)) x (original porosity),

tr = trace, nd = not detectable.

following an injection of ten pore volumes of alkali solutions to flushout the pore water The results are presented in Tables 17-15 through 17-

17, and Figures 17-24 through 17-26 for the NaOH, Na2 SiO 3 and Na2 CO 3

alkaline floods, respectively The average porosity decreased from 19%

to 18.6, 17.7 and 17.7% for the NaOH, Na 2 SiO 3 and Na 2 CO 3 alkalinefloods, respectively

As shown in Figure 17-27 by Demir (1995), the aqueous phase Na+

activity available for improved oil recovery was reduced significantly

(text continued on page 603)

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