OTC-24984-MS

Managing Micro-Emulsion and Scale During ASP Flooding for North Sabah Field EOR Noraliza Alwi, Noorazlenawati Borhan, Jamal Mohamad B M Ibrahim, PETRONAS Research Sdn Bhd, Subashini Paramanathan, Shell, Ron Bouwmeester, Shell

Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Asia held in Kuala Lumpur, Malaysia, 25–28 March 2014. This paper was selected for presentation by an OTC 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 Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference 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 OTC copyright.

Abstract Alkaline Surfactant Polymer (ASP) flooding has been identified as one of the best EOR methods to further recover the residual oil in Malaysian maturing fields. ASP flooding application promises a significant incremental recovery factor based on recent successful implementation on offshore fields in other parts of the world. The application of ASP flooding has been identified for a pilot in a North Sabah reservoir which is currently flooded with seawater since March 2011. Despite the promising recovery factor from the pilot laboratory and simulation study, the ASP flooding success always comes with risks and challenges. Two major challenges behind the success of ASP flooding are the formation of tight micro-emulsion with surfactant breakthrough which is very difficult to manage especially in a high water cut well and the formation of inorganic scales near wellbore and in the production system due to the high pH of the alkaline in the injection fluid. The identified pilot North Sabah reservoir which is currently being flooded with seawater is expected to further worsen the scaling effect due to the high divalent cation concentration (i.e. Ca2+ and Mg2+) in seawater. These challenges cause injectivity and formation damage which impacts flow assurance issues to the production facilities as well as impair the crude quality and saleability. This paper presents a detailed discussion on the lab test results which were designed based on the reservoir simulation output of the ASP flooding study for the North Sabah reservoir. Based on the in-situ produced water and chemical breakthrough simulated, this paper describes the extent of emulsion and scale severity at various ASP to water ratios, extensive performance tests evaluating the demulsifier and the scale inhibitor and discusses on the challenges in finding the suitable demulsifier and scale inhibitor at the simulated breakthrough condition. Background and Introduction The North Sabah field has been identified as one of the best candidates for chemical EOR injection and is planned for its first pilot test in 2016. The combination of Alkaline Surfactant Polymer (ASP) EOR scheme is chosen for the pilot aimed to give ultra-low interfacial tension (IFT) by the surfactant, good sweep efficiency by the application of polymer, and reduce surfactant adsorption to the rock formation by the alkaline. The success story of ASP injection is a well known from many reported case studies1 wordwide. Despite the success, not many reported on the challenges imposed by the application of ASP. The prominent challenges are the formation of tight micro-emulsion produces together with the ASP chemical that tightly bound the oil to water and the challenging inorganic scale effect such as CaCO3 precipitates resulted from the use of alkaline. Soda ash is used in this study as the source of alkalne. High water cut well worsen the emulsion severity and the high pH of the alkaline and the presence of divalent cation (Ca2+ and Mg2+) in the injection and formation water further aggravate the scaling problem. The presence of the stable micro-emulsion creates flow assurance problem to the downstream facilities as well as it impacts the crude oil saleability. The severe CaCO3 scale precipitates can cause formation damage at various points especially at near well bore and

2 OTC-24984-MS

in the tubing. Mechanism of Microemulsion The formation of microemulsion induced by ASP is different from conventional emulsion found naturally in crude oil. The natural emulsions are stabilized by asphaltene and resins (Hirasaki et al)2. The microemulsion induced by chemical EOR (ASP) formed and stabilized by the synergistic effects of the ASP chemicals injected. The combination of ionic, electrostatic and steric effects of these chemicals causes the formation of very stable emulsion at the oil-water interface. Microemulsion formed was thermodynamically stable and consist of surfactant-rich phase which formed at certain Winsor phase change relationship between oil, water and surfactant. Winsor (1954)3,5 classified oil/water/surfactant of the microemulsion system as type I, II and III in which the phase variable due to salinity, temperature, pressure, surfactant, co-surfactant structure and equivalent alkane carbon number (Vinay Sahni et.al)4. The ternary diagrams below represent the two- and three-phase regions formed by simple water−oil−surfactant systems at constant temperature and pressure.

Figure 1: Type I or II phase behavior (Low salinity)5

Type I: The surfactant is more soluble in water than oil i.e. the surfactant is preferentially soluble in water and oil-in-water (o/w) microemulsions form (Winsor I). In this system, the surfactant forms an oil-in-water microemulsion in the aqueous phase. This behavior is not favorable to achieve ultralow interfacial tension with surfactants.

Type II: The surfactant is mainly in the oil phase and water-in-oil (w/o) microemulsions. The surfactant-rich oil phase coexists with the surfactant-poor aqueous phase (Winsor II) i.e. surfactant is more soluble in oil than water. This behavior leads to surfactant retention in the oil phase and is unfavorable for an enhanced oil recovery (EOR) process.

Type III - As the brine salinity increases surfactant goes from being mainly in water phase through an intermediate three-phase region i.e. at optimal salinity. In this three-phase system, a surfactant-rich middle-phase coexists with both excess water and oil surfactant-poor phases. Type III also indicates the surfactant solubility in oil and water are comparable in which means the optimum salinity and optimum solubilisation ratio (volume of oil/water divided by volume of surfactant in the microemulsion) able to solubilise excess amount of oil and water which contains rich surfactant. The surfactant forms a microemulsion in a separate phase between the oil and aqueous phases, forms a bicontinuous layer containing surfactant, water and dissolved hydrocarbons. This situation is ideal to achieve ultralow interfacial tension values and is favorable for EOR

OTC-24984-MS 3

Figure 2: Type II phase behavior (High Salinity)5

Figure 3: Type III phase behavior (Optimum Salinity)5

Inorganic Scale Mechanism Generally scale is formed when two incompatible waters are mixed and as pressure depletes as the fluid is produced. The seawater with high divalent cations (Ca2+ and Mg2+) meets with the formation water which is rich in bicarbonate ions can cause the calcite scale to precipitate. In ASP injection, the application of alkaline aims to reduce the surfactant adsorption and to aid in the generation of in-situ soaps will promote a high pH environment which will worsen the scaling effect. This condition is a further challenge when the ASP chemical is injected to a field which has already been flooded by seawater before (on water injection). A careful reservoir sector model is important as the fundamental input to the scaling prediction modeling to mitigate scaling problems near injectors and producers. The model will be used to predict the probable flow pattern of fluids in reservoir and the produced fluid composition. The information on the mixing zone, the location of the scaling and its severity are vital for subsequent inorganic scale laboratory evaluation to mitigate the scaling problems.

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Experimental Work Evaluation of Microemulsion and the Demulsifier Test methods included the emulsion tendency test and demulsifier selection test using the ASP (Alkaline Surfactant Polymer) formulations planned for North Sabah EOR. The main purpose of this study is to determine whether there are any incompatibility issues between the ASP formulations applied during the EOR and the emulsions produced. If increased emulsion tendency is observed, specific demulsifiers dosage can be developed to break the emulsion specific to the condition that cause the emulsions. The chemicals were mixed with the field crude oil and the effects on emulsion tendency were studied under 80% water cut at various ASP to produced water ratios.

The demulsifier screening was then conducted at the worst case condition at an ASP to produced water ratio of 80:20 in the field crude oil. The crude oil and the produced water used for this tests contained pour point depressant (PPD). The demulsifier selection was based on the compliance to acceptance criteria as presented in Table 1.

Table 1: Demulsifier Acceptance Criteria

No Criteria Proposed Remarks

1 Time (min) 30 minutes Separator retention time. -Measurements after 5, 10, 15, 20, 30 mins

2 Temperature (oC) 30 °C Surface facilities temperature -Measurements taken at 30oC and 60oC,

3 Water Phase Clear

Criteria for water discharge -Oil in water , PETRONAS limit < 40ppm

4 Emulsion separated (%)

<25% from its initial volume

Separator emulsion breaking rate -Preferably 100% separated

5 Dosage (ppm) ≤ 50ppm Compliment to current injection facilities -Between 20ppm to 100ppm dosage

Note: BS&W not applicable for the screening purposes. Evaluation of Inorganic Scale Scale Prediction The evaluation of inorganic scale started with scaling prediction of mainly calcium carbonate (CaCO3) which involved three fluid components i.e. seawater (SW), formation water (FW) and the alkaline solution. Scaling risk was simulated throughout the injection sceme from the injection well (IW) through the producer well (PW) both at worst case bottomhole (BH) and tubing head (TH) conditions. Listed below are the conditions being studied;

100F, 2100 psia: IW, BH (lower pressure case) 100F, 2800 psia: IW, BH (higher pressure case) 105F, 60 psia: PW, TH (lower temperature, lower pressure case) 105F, 120 psia PW, TH (lower temperature, higher pressure case) 120F, 60 psia PW, TH (higher temperature, lower pressure case) 120F, 120 psia: PW, TH (higher temperature, higher pressure case) 125F, 200 psia: PW, BH 125F, 600 psia: PW, BH (minimum reservoir pressure) 125F, 1000 psia: PW, BH (maximum reservoir pressure) The brine compositions used are shown in Table 2 below.

Table 2: Brine compositions used in model predictions (mg/l)

OTC-24984-MS 5

ASP Fluid Injected FW SW 1% Na2CO3 1.5% Na2CO3 2% Na2CO3 Sodium 4585 10181.7 12206.05 14344 16544.2 Potassium 48 371.1 - - - Calcium 44 389 5 5 5 Magnesium 23 1227.3 5 5 5 Strontium 3.3 7.1 - - - Barium 1.1 - - - - Chloride 4348 18342 12156 12154 12156 Sulphate 7 2478 - - - Bicarbonate 4679 133.7 - - - Bromide 21.9 62.4 - - - Carbonate - - 5661 8493 11323

Mixtures of these brines were simulated with injected alkaline surfactant polymer (ASP) fluids of various alkali strengths, i.e. 1%, 1.5% and 2% at the injector mixing with FW, SW and mixtures of FW and SW. Scale Inhibitor Evaluation Scale Inhibitor (SI) evaluation was conducted using 4 commercial SI available in the market (Table 3). The test method included the compatibility of ASP brine to the SI, static SI inhibition test, dynamic performance test and core flooding tests.

Table 3: Tested Chemicals Chemical Type

SI A Acid Phosphonate SI B Acid Phosphonate

DETPMP Acid Phosphonate Vs-Co Sulphonated co-polymer

SI/Brine static compatibility and performance test are preliminary teststo examine the compatibility and the performance of each chemical in various mixtures of SW/FW/ASP solution. Dynamic performance test were conducted based on the required reservoir pressure and temperature under a range of ASP/FW and ASP/SW mixtures and also at different alkaline concentration in the ASP brine. The best chemical was be selected from dynamic performance test and further evaluated in the core flooding test. The core flooding test was then conducted following the sequence of injecting the pre-flush, main treatment and post flush to examine the formation damage aspects and also to determine the SI squeeze life. Results and Discussions Reservoir Sector Modeling and Simulated Water Breakthrough at Pilot Conditions The reservoir sector modeling was conducted to simulate the probale flow pattern of the injected ASP/brine system from the injector well to the producer well and the mixing with other aqueous fluids present in the reservoir as shown in Figure 4. The output of the reservoir simulation was used as input for the scale prediction modeling.

Figure 4: (Left) Movement of SW from Water Injector to Producer; (Right) Movement of ASP towards Producer

Water  Injector  SJ-­‐711C

Pilot  Injector

Pilot  Producer

Producer  SJ-­‐209L

Water  Injector  SJ-­‐711C

Pilot  Injector

Pilot  Producer

Producer  SJ-­‐209L

6 OTC-24984-MS

Figure 5 shows the dynamic model prediction of the produced chemicals during the pilot. The key input from these figures to the scaling study is the concentration of strong alkali (Na2CO3) returned at the producer. From figure 5 it shows that the return strong alkali concentrations are 3000ppm (0.3%) as the base case and 4500ppm (0.45%) as the high case.

Figure 5: Simulated Produced Chemical Concentrations at the Producer Wellhead (Pilot)

Evaluation of Microemulsion Emulsion Tendency Testing Emulsion tendency testing was conducted to select the ratio of Alkaline Surfactant Polymer (ASP) to produced water (PW) that exhibited the tightest emulsion for its respective water cut. Bottle tests were done for the cases shown in Table 4 and 5. Results showed minimal emulsion effects with the emulsion level varying from 1% to 6% at 80% water cut (Figure 6).

Table 4: Scenario for ASP B formulation, crude oil and produced water at 80% water cut Crude Oil Water Cut

(ASP: Produce Water) Testing Condition Composition

% Testing ASP B

concentration, ppm 20% 80%

( 20:80 )

Crude Oil 20% - ASP 16% A = 4,000

S = 1,200 P = 260

Total Salinity = 17,732ppm

Synthetic Produced Water (PW)

64%

20% 80% ( 40:60 )

Crude Oil 20% - ASP 32% A = 8,000

S = 2,400 P = 520

Total Salinity= 22,674ppm

Synthetic Produced Water (PW)

48%

20% 80% ( 50:50 )

Crude Oil 20% - ASP

40% A = 10,000

S = 3,000 P = 650

Total Salinity = 25,145ppm Synthetic Produced

Water (PW) 40%

0

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2500

3000

3500

4000

4500

5000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Conc  in  PPM

Months  after  Start  of  ASP  Injection

Alkali Surfactant Polymer

0

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3000

3500

4000

4500

5000

0 1 2 3 4 5 6 7 8

Conc  in  PPM

Months  after  Start  of  ASP  Injection

Alkali Surfactant Polymer

Base Case High Case

OTC-24984-MS 7

Figure 6: Separation profiles of ASP formulation B for North Sabah crude and produced water at 80% water cut at 30oC for 15

minutes and 30 minutes The emulsion however was ranging up to 2% to 22% for 60% water cut (Figure 7). For the ASP formulation B at worst case scenario (Table 5) it was observed that the system appeared to be at over optimum salinity i.e. 32,558ppm with type II phase behavior conditions in which a significant fraction of the surfactants partitioned into the oil phase. Although stable microemulsion middle phases were not observed in the testing, the oil phase clearly showed a significant amount of water in oil emulsions is present.

Table 5: Worst Case Scenario for ASP B formulation, crude oil and produced water at 40% water cut (current water cut)

Crude Oil Water Cut (ASP: Produced

Water)

Testing Condition Composition %

Testing ASP B concentration, ppm

60% 40% ( 80:20 )

Crude Oil 60% - ASP 32% A = 16,000

S = 4,800 P = 1,040

Total Salinity = 32,558ppm

Synthetic Produced Water (PW)

8%

Comparing worse case (Table 5) to (Table 4), it was observed that ASP formulation B was at under optimum salinity from 17,732 ppm to 25,145ppm which results in type I phase behavior conditions with a significant fraction of the surfactants partitined into the water phase in which the water phase contains some solubilised oil. Therefore stable microemulsion middle phases do not form in this condition (Figure 7).

Ideally, the interfacial tension (IFT) at optimum salinity conditions i.e. type III phase behavior will be very low and exhibits a micro emulsion layer as a middle phasemaking separation difficult, especially under dynamic conditions. It is recommended to determine the optimum salinity of the surfactants for the next phase of the demulsifier screening, preferably on-site using freshly sampled crudefor the demulsifier study and adjust the ASP salinity accordingly.

Figure 7: Separation profiles of ASP formulation A for North Sabah crude and produced water at 60% water cut at 30oC for 10 minutes and 30 minutes

8 OTC-24984-MS

Figure 8 shows the percentage of fluid observed at 80%water cut which indicates slight increases of 2% emulsion over time for mixing scenario ASP:PW of 20:80, 40:60, 50:50 from 15 minutes to 30 minutes. This indicates a longer time needed for emulsion partioning resulted from water-in-oil emulsions known as “reverse” emulsion which consists of water droplets in continuous oil phase and oil-in-water emulsion consist of oil droplets in water continuous phase (Sunil.Kokal et al.,2005)6 A significant reduction in emulsion level was observed by adding co-solvent in ASP formulation cocktail from formulation B (Figure 6)into formulation A (Figure 7). The addition of short chain-alcohol co-solvent such as secondary butyl alcohol( SBA) or Isobutyl alcohol (IBA) in ASP formulations is intended to solubilise the surfactant into the injection phase as well as to reduce the viscosity of the microemulsion formed in the reservoir (Kirk Raney et al.,2010)7 Increasing the total salinity (NaCl and Na2CO3) of the ASP formulation from 35,000ppm in ASP formulation A to 37,500ppm in ASP formulation B (Table 5) and increasing the viscosity by polymer,( hydrolysed polyacrylamides) from 1000ppm in ASP formulation A (Table 6) to 1300ppm in ASP formulation B also affects the emulsion separation behaviour (Sahni et al.,2010)4

Table 6: ASP formulation A, crude oil and produced water at 60% water cut

Crude Oil Water Cut (ASP: Produced Water)

Testing Condition Composition %

Testing ASP A Concentration, ppm

40% 60% ( 40:60 )

Crude Oil 40% - ASP 24% A = 4,000

S = 1,500 P = 400

Total Salinity= 22,297ppm

Produced Water (PW) 36%

Figure 8: Picture Emulsion tendencies ASP formulation B at 80% water cut at various ASP: PW ratio; Temperature: 300C for 15

minutes and 30 minutes.

0:100 20:80 40:60 50:50 60:40 80:20

15minutes; Temp: 300C

30 minutes; Temp: 300C

0:100 20:80 40:60 50:50 60:40 80:20

OTC-24984-MS 9

Demulsifier Performance Testing Demulsifier performance testing was done at a water cut of 80% for ASP formulationB, ASP: PW ratio 20:80, 40:60 and 50:50 with demulsifier B dosage of 50ppm. Increasing the temperature from 30°C to 60°C between 15 to 30 minutes shows increased oil in water content. Increasing the dosage to 100ppm at temperatures of 30°C to 60°C shows minimal reduction in the oil in water content for separation times of 15 to 30 minutes. All oil in water content results exceeded the PETRONAS limit i.e. <40ppm. A longer separation time (16hrs) at the crude oil processing terminal and dilution prior to discharge will minimise the oil in water content.

Table 7: Result on % Emulsion Breaking and % Oil Recovered for ASP formulation B at 80% water cut; Temperature: 300C and 60oC for Demulsifier B

ASP B:PW (80% WC)

Emulsion Tendencies %

T=30oC

Crude Oil % Before T=30oC

Dosage ppm

B

Emulsion %, T=30oC

Crude Oil %, T=30oC

Emulsion %, T= 60oC

Crude Oil %, T=60oC

Time, min 15 30 15 30 15 30 15 30 15 30 15 30 20:80

Total Salinity = 17,692ppm

1.5 4 18.5 16 50 4 4 18 18 0 0 16 18* 100 2 2 16 16 0 1 18 17

40:60 Total Salinity = 22,644ppm

4 4 16 16 50 4 4 18 18 2 0 16 18* 100 4 4 10 10 0 2 16 16

50:50 Total Salinity = 25,120ppm

4 6 16 16 50 6 6 16 16 8 6 10 12 100 2 2 10 10 0 2 16 16

Note: *No changes in % oil recovered by increasing temperature from 30oC to 60oC.

Demulsifier B at dosage 50ppm performance shows for ASP B:PW for 20:80, 40:60 and 50:50 the oil phase level relatively improved by 2% respectively at the operation temperature i.e 30oC. Whenincreasing the temperature to 600C at 50ppm dosage (Table 7) it shows the demulsifier B performance has relatively reduces the emulsion level by 2% to 4% respectively, howeverat some extend the % oil phase level has insinigficant by the effect of higher temperature.. When increasing dosage from 50ppm to 100ppm at operation temperature of30oC using demulsifier B shows emulsion level relatively reduces by 2% to 6% respectively, however the % oil phase level were surprisingly reduced and this was supported by significant increases the oil in water content results in water phase ( Table 8). This can be concluded that by increasing temperature system at 600C with higher dosage of demulsifier at 100ppm shows emulsion level relatively reduces by 2% to 4% respectively and some extend of S:PW ratio the % oil phase level can be consideredimproved by minimal reduction the oil in water content results in water phase

Table 8: Result Oil in water content at 80% water cut; Temperature: 300C and 60oC for Demulsifier B

ASP B:PW (80% WC)

Demulsifier B Dosage

Oil in water content at 30oC, ppm Oil in water content at 60oC, ppm

20:80 Total Salinity = 17,692ppm

50 ppm 311 481 100 ppm 1974 1097

40:60 Total Salinity = 22,644ppm

50 ppm Over limit detection by instrument 892 100 ppm 3373 1716

50:50 Total Salinity = 25,120ppm

50 ppm 1360 1603 100 ppm 2161 3071

Inorganic Scale Evaluation Scaling Prediction The results of scaling tendency and scaling mass at worst case (reservoir condition) are presented in Figure 9 and 10 with the summary of the scaling tendencies is summarise in Table 9. These results were compared to the probable flow pattern of the

10 OTC-24984-MS

ASP fluid and reservoir brine as simulated in the reservoir sector modeling. Based on existing model, it appears that it is possible that the SW and ASP do not pre-mix much in the reservoir before reaching the wellbore of the pilot producer. As shown in Figure 4, due to the location of the existing water injector relative to the pilot area, the pilot producer could be drawing in SW from a different direction compared to the ASP direction. This would mean that scaling is likely to occur at the wellbore. Scaling prediction calculations in relation to the reservoir sector modeling predicted moderate scaling tendencies for mixtures of FW and ASP at reservoir and production conditions, with significantly higher scaling tendencies for mixtures of ASP and SW. In this case, mitigation for scaling should be planned for the worst case scenario to protect production wells against the co-production of ASP fluids with formation water and possible commingling with sea water. Effective scale inhibitors need to be identified or the limitations on produced water composition for inhibitors to be effective needs to be identified. This will likely be a significant challenge in ASP fluid mixes with SW containing produced waters in the near-well region of the reservoir or within the production wellbore.

Figure 9: Calcium carbonate scaling tendency for FW, SW (reservoir saturated) and ASP (1.5% Na2CO3) at 125F, 600psi

Figure 10: Calcium carbonate predicted mass for FW, SW and ASP (1.5% Na2CO3) at 125F, 600psi.

Calcium carbonate ST

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0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Brine ratio in mix

Scal

ing

Tend

ency

100:0 FW:SW80:20 FW:SW60:40 FW:SW50:50 FW:SW40:60 FW:SW20:80 FW:SW0:100 FW:SW

Calcium carbonate mass

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imum

mas

s mg/

l 100:0 FW:SW80:20 FW:SW60:40 FW:SW50:50 FW:SW40:60 FW:SW20:80 FW:SW0:100 FW:SW

OTC-24984-MS 11

Table 9: Summary of Scaling Tendency and Scaling Mass (mg/l) Scenarios Scaling Tendency Scale Mass (mg/l)

Peak SW case

SW 45%; Na2CO3 0.15% 20 250

Peak Alkali Base case

SW 30%; Na2CO3 0.3% 25 370

Peak Alkali High case

SW 30%; Na2CO3 0.45% 70 300

As a general rule of thumb, the scaling risk can be defined as shown in Table 10 below;

Table 10: Scaling Severity Table (Reference: SPE 87430)8

Scale Inhibitor Evaluation From the four chemicals tested, DETPMP, Vs-Co and SI A display good compatibility i.e. no scaling or precipitation for mixtures of ASP / FW when using both 1% and 1.5% Na2CO3. Severe incompatibilities were however observed in mixtures of ASP /SW due to the higher divalent cation concentration (viz: Ca in FW – 44mg/l, Ca in SW = 389mg/l, and Ca in 50:50 FW: SW = 216.5mg/l). This however related to the high solution pH’s (> pH 10 (lab)). When the pH of the mixture was adjusted to be ~ pH 9, the chemicals compatibility improved considerably with only minor incompatibility observed. SI B displayed more major incompatibility / scaling than the other three chemicals even in ASP/FW mixtures, and thus deselected from the remaining performance test. Dynamic tube blocking inhibitor performance tests then was conducted under a range of different ASP/FW and ASP/SW brine mixtures and also at different levels of Na2CO3 present in the ASP injection water. Tests have been conducted at the highest expected field temperature of 52°C and at adjusted pH simulating downhole in situ pH values.

FW/ ASP Summary: The lab testing results have shown that the associated calcium carbonate scale formation in the FW only flooded wells can be controlled by a SI squeeze. The chemicals MIC’s are recorded as summarised in table 11, for the mixture of 50:50 FW: 1% Na2CO3.This represents a case where SW does not enter the wellbore of pilot producer.

12 OTC-24984-MS

Table 11: 50:50 FW: ASP (1.0% Na2CO3), MIC’s over 1 and 2 hour pass times

Chemical MIC (1 hour pass)

(ppm)

MIC (2 hour pass)

(ppm)

SI A 25-50 30-40

DETPMP 0-15 10-15

VS-Co 10-15 30- 40

SW/ ASP Summary: Initial testing in SW/ASP mixtures resulted in very poor performance at between 30 and 60% SW in mixtures with ASP of strength 1% Na2CO3, with Minimum Inhibitor Concentration (MIC’s) in the region of 500mg/l or greater (Table 12). Supportive full field modelling indicated that the maximum concentration of alkali present in the produced waters would be in the region of 0.45% during which SW content is ~ 30%. This compares with tests using 40:60 SW:0.75% Na2CO3. The results from selected conditions are shown in Table 12.

Table 12: Various SW: ASPIW MIC’s

Ratio SW: 0.75% Na2CO3 % CO2

sparging of SW MIC of Scale Inhibitor

80:20 SW: 0.75% Na2CO3 50% 0 – 5 ppm (2h passes) 40:60 SW: 0.75% Na2CO3 100% >500ppm

60:40 SW: 1% Na2CO3 100% 300 – 500ppm 30:70 SW: 1% Na2CO3 100% > 500ppm

20:80 SW: 0.75% Na2CO3 100% > 500ppm 10:90 SW: 0.75% Na2CO3 100% 10 – 15 ppm (2h passes)

Green = acceptable performance Red = Poor performance

In summary, scale control can be achieved with DETPMP for cases where SW content is ≤ 10% or resulting Na2CO3 content is ≤ 0.15%.

Core Flood – SI Performance and Formation Damage Test

Testing was performed with a SI A, partially neutralised to pH 3.55 prior to injection to minimise the risk of formation damage. No significant formation concerns were indicated by the core flood test. While retention of scale inhibitor was satisfactory, the high pH produced brine strips off the inhibitor and leads to reduced number of pore volumes to maintain the minimum effective concentration of scale inhibitor.

OTC-24984-MS 13

Figure 11: Core Flood Result

Inhibitor Retention and Release

Evidence of significant chemical retention was recorded throughout the chemical treatment applications and during the subsequent 16 hours shut-in period. However, during initial post-flush, the high pH / low salinity post-flush ASP brine mixture did not just displace the bulk shut-in fluid but also stripped retained chemical from the core. Figure 11 shows that the SI A chemical concentration dropped gradually to ~2.2 ppm after ~310PVs (~12 days) of post-flush throughput. Testing for Formation Damage:

• Injectivity: A progressive increase in differential pressure was recorded during the chemical application stage. Whereas the increasing trend is expected to predominantly correspond to residual fluid levels stabilising in the reversed flow direction, the increasing trend could also (partially) correspond to some formation damage.

• Permeability Recovery: The differential pressure in the formation to wellbore (F>W) flow direction was similar pre and post chemical application. In addition, the post-treatment multi-rate effective brine permeability measurement that is most comparable to the measurement directly prior to chemical application, showed permeability recovery values of ~ 93% -109%. This indicates that no permanent formation damage was caused through chemical application.

• Cation Analysis: Cation effluent concentrations show evidence of dissolution of Ca, Mg and Fe-bearing minerals

during chemical application. It is expected that the chemical retained during this stage by forming a complex with the released cations.

• SEM Analysis showed no significant disparity between selected pre and post-treatment samples. Pre-treatment

analysis did identify a significant proportion of matrix fines that would be sensitive to fines mobilisation. In addition, Ca, Mg and Fe-rich minerals were recorded. As a result, the maximum flow rate was kept at a maximum of 12ml/h and the chemical was applied part pH neutralised to limit formation damage. Subsequently, the post-treatment samples showed no evidence of significant dissolution, precipitation, fines generation or fines mobilisation.

In summary, application of the part neutralised (pH 3.5) to SI A did not result in permanent formation damage. Evidence of significant chemical retention was recorded, but also of subsequent chemical stripping by the high pH / low salinity post-flush brine mix. Summary and Conclusions

This paper summarizes the assessment of the risk and impact to the field under ASP EOR scheme on the flow assurance and

SI concentration vs post-flush injected PV recorded during post-flush for core flood 0932/01 Conditions: 5Wt.% ST8040 in 3% KCl, T = 52ºC. Study 0932, Shell Malaysia / Petronas CF.

0

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0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340Post Flush Injected Pore Volume

Scal

e In

hibi

tor

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ratio

n (p

pm)

Chemical Concentration (by ICP)

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14 OTC-24984-MS

formation damage i.e. the inorganic scaling and microemulsion. Formation of tight microemulsion contain a mixture of ASP which involved a complicated formation mechanism is of serious concern and need to be managed carefully by evaluating a suitable emulsion breaker or demulsifier. A more challenging inorganic scale inhibition induced by high pH environment as a result from alkaline application needed to be given more attention. Scale inhibitor application is expected to be feasible for regions of the field containing formation water with low levels of sea water contamination. For those regions which have previously been flooded with sea water, scale inhibition at the production wells may only be feasible over limited ranges of ASP and SW mixing ratios. However, if extensive mixing of ASP and SW occurs within the reservoir, rather than at the production wells then scaling in the reservoir would reduce the scaling potential at the producers. Also, dilution by FW and/or depletion of alkali within the ASP slug would lower pH and hence the scaling potential.

Acknowledgement

The authors would like to thank the PETRONAS EPTD, PETRONAS Research Sdn Bhd and Shell personnel who directly or indirectly involved in this North Sabah ASP EOR Pilot Optimization project. Appreciation is also extended to M Razib Raub, Pauziyah A Hamid and Scale team from Scaled Solution Limited (SSL) for their technical assistance to the project. Lastly the authors also wish to thank PETRONAS and Shell Management for their permission to publish this paper

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