SPE 155112

Modelling of Enhanced Scale Control via Inhibition of Stimulation Fluids for Deepwater Developments Oleg Ishkov, Eric Mackay (Heriot-Watt University), Myles Jordan (Nalco)

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Conference and Exhibition on Oilfield Scale held in Aberdeen, UK, 30–31 May 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

The injection of seawater into oil bearing reservoirs to maintain reservoir pressure and improve secondary recovery is a well-

established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulphate) to the

injection and production wells during such operations has been much studied. The current deepwater subsea developments

offshore West Africa, Gulf of Mexico and Brazil have brought into sharp focus the need to manage scale in an effective way.

In recent years there has been some consideration given to deployment of scale inhibitor within the fluids associated with the

completion of production wells, prior to the start up of production. Until now, effective scale control in frac packed wells at

low water cuts has been achieved with phosphonate-based inhibitors applied as part of the acid perforation wash and

overflush stages, prior to the actual frac packing operation itself. The deployment of these inhibitors has proved effective in

controlling barium sulphate scale formation during initial seawater production, and eliminating the need to scale squeeze the

wells at low water cuts (<10% BS&W). Recent developments allowing inclusion of scale inhibitor in the linear and cross

linked gel stages has highlighted the need to be able to model this process effectively, thereby enabling optimal use of the

chemical and improved squeeze designs.

This paper outlines simulation work carried out using the Petroleum Experts REVEAL software to assess introduction of

scale inhibitor into frac pack operations, and identify the most suitable stage of the well completion process during which to

apply the inhibitor, to maximise treatment life. Simulation results and field data from these treatments are compared to

demonstrate the opportunity this technique presents, and to highlight the importance of chemical placement and the post

stimulation flow regime to squeeze life.

Introduction

This paper outlines the simulation work conducted in the Reveal reservoir simulator code from Petroleum Experts to assess

introduction of inhibitor into frac pack operation and assess the most suitable stage of the well completion to apply the

inhibitor to maximise treatment life. The simulator has been developed over the past decade and a half by integrating

additional physics and chemistry within a reservoir simulation engine. The objective is to investigate and interpret complex

non-linear interactions and develop optimisation strategies incorporating the relevant physics and chemistry in the context of

a field simulation model. It is a fully thermal code, and includes aqueous phase thermodynamic equilibrium chemistry for

scale and pH dependent processes; it also has integrated rock mechanics for sand predictions, thermal fracturing and stress

dependent permeability changes, as well as the potential to model various oilfield chemical processes. In the context of this

work, it has been used to model the inclusion of scale inhibitors during the injection of stimulation fluids to fracture a well.

A typical well squeeze treatment deployed during the production phase consists of four stages: preflush (clean-up), main

treatment with Scale Inhibitor (SI) injection, postflush stage to push the SI deeper in the rock, and shut in or soak period. This

treatment may require over 24 hours of workover time and well shut in, which may lead to significant deferred oil costs in

addition to the treatment costs themselves. Combining frac pack operations with a squeeze treatment creates clear advantages

2 SPE 155112

in terms of taking advantage of economic and time efficiency of injecting scale inhibitor chemicals at the same time as the

stimulation fluids, ensuring protection from day one of production, and reduction of disruption to subsequent production.

In this study we investigated different scenarios for the addition of SI to the different stages of a frac-pack operation.

Modelling was performed of the addition of 5 wt.% SI to the clean up acid, to the overflush stages, and to the linear and

crosslinked gel during the fracturing process, and SI adsorption, desorption and flow back to the well were included in the

calculations. Modelling the fracturing of a well entails simulation of three stages: clean-up, fracturing, and back-production,

which creates three different possible scenarios for addition of SI: in acid clean-up stage only, during the fracturing stage

only, and in both acid clean-up AND the fracturing stages.

Another parameter that has to be considered in order to assess the well flow regime is the extent to which the fracturing

process has been successful (Robertson et al., 2001, Seright et al., 1998, Svendsen et al., 1991). Three more scenarios thus

had to be modelled: the fracture was unsuccessful which implies a radial flowback pattern, the fracture was successful (high

fracture conductivity), leading to linear flowback, and finally fracturing occurred, but the fracture closes during back-

production.

Nine injection scenarios in total were modelled (schematically illustrated in Figure 1). These are described below.

Three A* cases (no fracture created):

1A - Radial injection, Scale Inhibitor in Acid clean-up stage only. Radial flowback.

2A - Radial injection, Scale Inhibitor in fracturing stage only. Radial flowback (Fracturing un-successful).

3A - Radial injection, Scale Inhibitor in both acid clean-up and fracturing stage. Radial flowback (Fracturing un-successful).

Three B* cases (fracture created and remains open during flowback).

1B - Radial injection at clean up stage, linear flow during fracturing, Scale Inhibitor in acid clean-up stage only. Linear

flowback during production.

2B - Radial injection at clean up stage, linear flow during fracturing, Scale Inhibitor in fracturing stage only. Linear flowback

during production.

3B - Radial injection at clean up stage, linear flow during fracturing, Scale Inhibitor in both acid clean-up and fracturing

stage. Linear flowback during production.

Three C* cases (fracture created but closes during flowback).

1C - Radial injection at clean up stage, linear flow during fracturing, Scale Inhibitor in acid clean-up stage only. Radial

flowback during production.

2C - Radial injection at clean up stage, linear flow during fracturing, Scale Inhibitor in fracturing stage only. Radial flowback

during production.

3C - Radial injection at clean up stage, linear flow during fracturing, Scale Inhibitor in both acid clean-up and fracturing

stage. Radial flowback during production.

SPE 155112 3

FR

FR

FR

FR

CL FR P CL CL P

CL FR P CL CL P

CL FR P CL CL P

- Radial flow

- SI added

- Linear flow

1A

2A

3A

1B

2B

3B

1C

2C

3C

No fracture Fractured Closed fracture

CL – cleanup stage FR – fracturing stageP – production

FR P

P

P

FR

Figure 1 Schematic illustrating flow scenarios.

Initial setup

Initial parameters used in the simulations are presented in Table 1. Displacement volumes are illustrated in Figure 2 and

modelling was performed with the assumption that all fluid stages successfully enter the rock. The main volume of

displacement fluid (86%) is injected during the fracturing stage.

Table 1 Initial parameters.

Fracture height 84 ft (also assumed also to be thickness of net pay)

Fracture length 88 ft (each wing)

Matrix permeability 500 mD

Matrix porosity 25%

SI concentration 5 wt. %

Pre-fracturing (radial) displacement

Perforation acid cleanup 108 bbl

Overflush brine 195 bbl

Displacement during fracturing

Linear gel 1095 bbl

Cross-linked gel 805 bbl

Water production 1,500 bpwd for 24 months

4 SPE 155112

108

195

Linear gel, 1095

Cross-linked gel, 805

1900

Perforation acid cleanup Overflush brine Linear gel Cross-linked gel

Figure 2 Treatment volumes. Displacement during fracturing takes 86% of total volume.

The frac-pack and full fracture were modelled by setting different matrix rock to fracture permeability contrasts. In the base

case a frac-pack permeability contrast of 1 to 10, resulting in a fracture permeability of 5000 mD, while a 1:1000 ratio was

used for the full fracture.

Simulation

The reservoir model grid consisted of 79 x 42 x 21 cells. Cell dimensions in the vicinity of the wellbore were set to 4 ft x 4 ft

x 4 ft. The cell size was chosen to provide a balance between numerical accuracy and speed of calculations. A top view of the

model is presented in Figure 3. The basic model properties are shown in Table 1. A single phase model (water only) was used

for this particular comparative study. A fixed size fracture was modelled, with the fracture dimensions as given in Table 1.

Figure 3 Reservoir model grid showing fracture location. Top view.

A phosphonate scale inhibitor adsorption isotherm was supplied. The version of Reveal used required that parameters for a

Langmuir adsorption isotherm be entered. A best fit of the coreflood derived adsorption isotherm was sought using Langmuir

parameters for inclusion in the model (Figure 4). (It is anticipated that future versions of the simulator will allow input of

isotherms in table form.)

SPE 155112 5

0

10

20

30

40

50

60

0 5000 10000 15000 20000 25000 30000 35000 40000

Ad

sop

rtio

n, k

g/m

3

Concentration, ppm

Adsorption

Reveal Langmuir

Figure 4 Langmuir isotherm fit to coreflood derived isotherm for inclusion in the model.

Results

Results grouped by flow regimes

The first series of Scenario A cases, where radial injection and radial flowback were modelled, indicates that case 3A – where

scale inhibitor is included in both stages, provides a longer squeeze treatment life (Figure 5). Simply, under radial flow

conditions a longer squeeze life is achieved when a larger volume of scale inhibitor is injected (line 3A in Figure 5), and

when the scale inhibitor is injected in the earlier stages of the treatment.

0.1

1

10

100

1000

10000

0 500000 1000000 1500000 2000000

Scal

e I

nh

ibit

or

con

cen

trat

ion

, p

pm

Water Produced, STB

1A

2A

3A

Figure 5 Scale Inhibitor return profiles for Scenario A cases with radial injection and flow back.

MIC

10 ppm

MIC

2.5 ppm

6 SPE 155112

Table 2 Barrels of water produced before reaching MIC levels of 10 ppm and 2.5 ppm, including % increase in

squeeze lifetime when changing from 10 ppm MIC to 2.5 ppm MIC.

Water produced, bbl

MIC 10 ppm 2.5 ppm Change, %

1A 249900 431400 73%

2A 587400 885900 51%

3A 657900 975900 48%

1A 2A 3A

Adsorbed SI, kg/m3 before Production

SI in water, ppm before Production

CL

FR

PCL

FR

PCL

FR

P

Figure 6 Scale Inhibitor distribution in the reservoir for Scenario A cases.

Results of modelling cases when a fracture is created and remains open during flowback indicate that adding Scale Inhibitor

during the fracturing stage is more beneficial when compared to adding it to the acid clean-up stage only (Figure 7).

However, SI addition in both stages does not provide a particular advantage compared to addition of SI to the fracturing stage

only (Figure 7, lines 2B and 3B). An extended run was performed to test the sensitivity to matrix/fracture permeability

contrast, and to extend the production stage until scale inhibitor return levels reached an MIC of 2.5 ppm.

The results of the calculations indicate that for this particular modelled well, the squeeze lifetime can be doubled compared to

a purely radial displacement in the case where the same volume of scale inhibitor is added to the fracturing stage (in Figure 5

line 3A crosses 2.5ppm at roughly 976,000 bbl of water produced for the unfractured case, while line 3B in Figure 9 crosses

2.5ppm after about 2,560,000 bbl of water is produced in the fractured well case).

SPE 155112 7

0.1

1

10

100

1000

10000

0 500000 1000000 1500000 2000000 2500000 3000000

Scal

e I

nh

ibit

or

con

cen

trat

ion

, p

pm

Water Produced, STB

1B

2B

3B

MIC 2.5

Figure 7 Scale Inhibitor return profiles for Scenario B cases where there is linear flow during injection and linear

flowback, and where the cases are run till SI return reaches an MIC of 2.5 ppm.

Table 3 Barrels of water produced before reaching MIC levels of 10ppm and 2.5 ppm for the frac-pack case.

Water produced, bbl

MIC 10 ppm 2.5 ppm Change, %

1B 331435 803185 142%

2B 1218680 2560430 110%

3B 1304180 2589680 99%

1B 2B 3B

SI in water, ppm before Production

Adsorbed SI, kg/m3 before Production

FR

CL

PFR

CL

P FR

CL

P

Figure 8 Scale Inhibitor distribution in the reservoir for Scenario B cases.

The fracture permeability contrast (matrix/fracture) were also taken into account, but even a permeability contrast between

matrix and fracture permeabilities of only a factor of 1:10 (simulating the frac-pack as shown in Figure 8) adds significant

benefit compared to a radial injection. The full fracture case (1B_inf, 2B_inf and 3B_inf in Figure 8) creates an even greater

advantage in terms of squeeze lifetime.

8 SPE 155112

0.1

1

10

100

1000

10000

0 500000 1000000 1500000 2000000

Scal

e I

nh

ibit

or

con

cen

trat

ion

, p

pm

Water Produced, STB

1B

2B

3B

1B_inf

2B_inf

3B_inf

Figure 9 Impact of matrix/fracture permeability contrast.

Table 4 Barrels of water produced before reaching MIC levels of 10 ppm and 2.5 ppm for the full fracture cases.

Water produced, bbl

MIC 10 ppm 2.5 ppm Change, %

1B_inf 217556 977727 349%

2B_inf 1900740 > 2 million -

3B_inf 1997550 > 2 million -

Scenarios where the fracture or frac-pack does not remain open after the fracturing stage were also considered (Figure 10).

Addition of SI in the fracturing stage extended squeeze lifetime (lines 2C and 3C), however, from this plot it is unclear

whether this is solely the effect of a bigger treatment volume or of the actual flow regime. In order to investigate this, the

following subsection presents comparison plots grouped by which stage SI is added into.

Frac pack

Fracture

SPE 155112 9

0.1

1

10

100

1000

10000

0 500000 1000000 1500000 2000000

Scal

e I

nh

ibit

or

con

cen

trat

ion

, p

pm

Water Produced, STB

1C

2C

3C

Figure 10 Scale Inhibitor return profiles for Scenario C cases where linear injection and radial flow-back occurs (if

the fracture or frac-pack fails to stay open).

Table 5 Barrels of water produced before reaching MIC levels of 10 ppm and 2.5 ppm for cases where the fracture

closes after the treatment.

Water produced, bbl

MIC 10 ppm 2.5 ppm Change, %

1C 249150 432900 74%

2C > 2 million > 2 million -

3C > 2 million > 2 million -

Results grouped by SI injected stages

This subsection investigates the effect of flow regimes on the squeeze treatment lifetime. In all scenarios (Figure 11, Figure

12, Figure 13 and Figure 14) in the fractured cases longer squeeze treatment lifetimes are observed compared to the radial

flow cases, even if the fracture closes during the flow-back period (2C vs 2B_inf/2B in Figure 12, and 3C vs 3B_inf/3B in

Figure 13).

0.1

1

10

100

1000

10000

0 500000 1000000 1500000 2000000

Scal

e I

nh

ibit

or

con

cen

trat

ion

, p

pm

Water Produced, STB

1A 1B 1C 1B_inf

Figure 11 Scale Inhibitor return profiles. SI is

added in the acid clean-up stage.

0.1

1

10

100

1000

10000

0 500000 1000000 1500000 2000000

Scal

e I

nh

ibit

or

con

cen

trat

ion

, p

pm

Water Produced, STB

2A 2B 2C 2B_inf

Figure 12 Scale Inhibitor return profiles. SI is

added in the fracturing stage only.

10 SPE 155112

0.1

1

10

100

1000

10000

0 500000 1000000 1500000 2000000

Scal

e I

nh

ibit

or

con

cen

trat

ion

, p

pm

Water Produced, STB

3A 3B 3C 3B_inf

Figure 13 Scale Inhibitor return profiles. SI is

added in both the acid clean-up and the

fracturing stages.

In terms of addition SI in both the acid clean-up and the fracturing stages versus addition to the fracturing stage only, there is

not much of a difference (Figure 14. Lines 2B vs 3B, and lines 3C vs 2C). Overall, the comparison presented in Figure 14

supports the concept that addition of SI into a fracturing stage itself allows scale inhibitor to be placed deeper into the

formation (Scenario A cases vs Scenario B cases). It is not critical in terms of squeeze lifetime to have the fracture open

during the flow back period (Scenario B cases vs Scenario C cases), although, obviously it will be critical from a well

productivity point of view. (This does, however, confirm that temporarily fracturing a production well during a squeeze

treatment could be of considerable benefit in terms of squeeze lifetime (Al-Rabaani and Mackay, 2011)).

The permeability contrast between the matrix rock and the fracture does have to be considered (Scenario B-inf cases vs

Scenario B cases).

0.1

1

10

100

1000

10000

0 500000 1000000 1500000 2000000

Scal

e I

nh

ibit

or

con

cen

trat

ion

, p

pm

Water Produced, STB

1A 2A 3A 1B

2B 3B 1C 2C

3C 1B_inf 2B_inf 3B_inf

Figure 14 Scale Inhibitor return profiles for all cases.

Conclusions

Results of the modelling presented here suggest that the Petroleum Experts Reveal simulator is capable of modelling scale

inhibitor adsorption under radial and linear flow regimes. This makes it a suitable tool to use for modelling squeeze

treatments under fractured conditions.

SPE 155112 11

If fracturing is performed for stimulation purposes it is suggested that scale inhibitor be included in the fracturing fluid, while

no significant additional benefit is observed in the modelling when scale inhibitor is added to both the acid-cleanup and

fracturing stages.

The results of the modelling suggest that the flow regime plays a major role in determining the squeeze lifetime. Injection of

scale inhibitor in a linear flow regime provides a longer squeeze lifetime than when it is injected under radial flow, while

inhibited stimulated fracture treatments lead to longer squeeze lifetimes than when the same volume of scale inhibitor is

injected under radial flow conditions.

Addition of scale inhibitor to the stimulation fluid reduces the need to perform treatments during the production phase of a

well life cycle, which can bring significant cost savings in deepwater scenarios, and reduce risk of scaling from the onset of

water production.

Acknowledgements

The authors thank Nalco for support for this work and for supplying data.

References

Al-Rabaani, A. and Mackay, E.J.: “What Would Be the Impact of Temporarily Fracturing Production Wells During Squeeze

Treatments?” paper SPE 98774 SPE Production & Operations (August 2011) 26 (3) 262-269. DOI: 10.2118/98774-PA

Robertson, E., Mackay, E.J., Jordan, M.M. and Graff, C.J.: “Design of Scale Inhibitor Squeeze Treatments in Fractured

Wells: Analysis and Field Application”, paper SPE 65371 presented at SPE International Symposium on Oilfield Chemistry

held in Houston, Texas, 13–16 February 2001.

Seright, R.S., Liang, J., and Seldal, M.: “Sizing Gelant Treatments in Hydraulically Fractured Production Wells”, paper SPE

52398, SPE Production and Facilities (November 1998), pp223-229.

Svendsen, A.P., Wright, M.S., Clifford, P.J., and Berry, P.J.: “Thermally Induced Fracturing of Ula Water Injectors”, paper

SPE 20898, SPE Production Engineering (November 1991) 384-393.

Ishkov, O., Mackay E., Sorbie K.: “Scale Inhibitor Squeeze Treatment Efficiency in Unfractured and Fractured Wells” paper

SPE 131273 presented at the International Conference on Oilfield Scale, Aberdeen, United Kingdom, 26–27 May 2010.