a break through fluid technology in acidizing sandstone

8/9/2019 A Break Through Fluid Technology in Acidizing Sandstone

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Copyright 2006, Society of Petroleum Engineers

This paper was prepared for presentation at the 2006 SPE International Symposium andExhibition on Formation Damage Control held in Lafayette, LA, 15–17 February 2006.

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AbstractChallenges in sandstone acidizing still exist, although great

improvements have been made in the last decade. Factors that

contribute to these challenges include: multiple types of co-existing formation damage; uncertain rock mineralogy;

multiple fluids and pumping stages; complex chemical

reactions between fluids and formation minerals; and fast

reaction kinetics at elevated temperatures. Others are:

inadequate zonal coverage; limited live acid penetration; rockdeconsolidation due to acid-rock interactions; acid emulsion

and sludge tendencies; corrosion; and health, safety, and

environmental (HSE) concerns. These factors contribute to thelow success rate of sandstone acidizing treatments especially

in acid-sensitive, and clay- and carbonate-rich sandstone

formations at high temperatures.

In this paper, we review some current practices used to

address these challenges in the industry and present a newmulti-pronged approach that would improve the success rate

of sandstone acidizing treatments. The system requires the use

of a geochemical simulator to “design for success” byselecting the safest fluid for the formation and for optimizing

the fluid volumes and injection rates, and a breakthrough fluid

that uses novel chemistry to simplify treatments and minimize

the risk of acid-induced formation damage.

Batch reaction studies indicate that the new fluid reacts

more slowly with aluminosilicates than conventional mineralacids, thus preventing secondary and tertiary precipitates. Core

flow tests demonstrate that the new fluid prevents the near-

wellbore deconsolidation problems generally experienced withHF-based systems in high-temperature sandstone acidizing

treatments. These laboratory results were corroborated with

field core samples and geochemical simulations, especially

with high-clay and high-carbonate sandstone formations.

Extensive laboratory tests also demonstrate that the fluidresults in less emulsion and sludge tendencies; lower corrosion

rate to tubulars and equipment; better HSE footprint due to its

almost neutral pH; and better tolerance to damage andformation uncertainties.

IntroductionTraditionally, hydrofluoric (HF) acid-based systems have beenfound to be effective in dissolving aluminosilicates in

sandstone formations. Depending on the rock mineralogy and

treatment temperatures, various formulations have been used

in the industry with mixed results; sometimes leading to rapiddecline in post-treatment production. These formulations are

usually composed of hydrochloric acid (HCl) and HF at

various concentrations, ranging from low strength to high

strength to retarded. Examples of these HCl:HF formulationsinclude: 6:1.5, 9:1, and 12:3 systems. In retarded systems, HC

is replaced with an organic acid like acetic acid.

The relatively poor results of conventional systems may be

attributed to several reasons. First, there is a high risk of

secondary and tertiary precipitation in the zones that are notadequately covered by the preflush due to inadequate fluid

volumes due to poor job designs, and inefficient placement in

the zones of interest. Second, the main treatment fluid mayend up in the most permeable zones, leaving the less

permeable zones either under-stimulated or unstimulated

Third, the treatment fluids could deconsolidate acid-sensitive

rock in the near-wellbore area and subsequently lead to the

production of formation fines. Additionally, these treatmentare operationally very complex and time-consuming due to

multiple fluids and stages. These issues are exacerbated a

higher bottomhole temperatures due to the accelerated reactionkinetics and corrosion inhibition difficulties at elevated

temperatures.

A number of existing high-temperature sandstone

acidizing systems were reviewed and a new system developed

to improve the success rate of these treatments. Extensive

laboratory tests were performed, and results reported in this paper, to validate the effectiveness of the system.

Conventional Sandstone Acidizing Systems

A typical sandstone acidizing job that is required to treat a100-ft production interval would require pumping up to four

different fluids in five treatment stages and twenty-five or

more different pumping steps, depending on the type of

diversion technique used; a recipe for operational problemsand high risk of failure.

In conventional treatments, acid-compatible brine (e.g.

NH4Cl) is pumped as a preparatory flush (Brine Preflush) to

help remove and dilute acid incompatible species (e.g., K + orCa2+). The function of the HCl Preflush is to remove as much

of the calcites as possible, prior to injection of the HF-based

acid. The function of the main treatment fluid, which is

usually HF-based, is to dissolve the clays and fines that may

SPE 98314

A Breakthrough Fluid Technology in Stimulation of Sandstone ReservoirsF.E. Tuedor, SPE, Z. Xiao, SPE, M.J. Fuller, SPE, D. Fu, SPE, G. Salamat, SPE, S.N. Davies, SPE, and B. Lecerf, SPE,Schlumberger


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2 SPE 98314

be plugging the pore spaces and impairing production. The

overflush or postflush displaces the spent acid and reaction

products away from the critical matrix and maintains a low pHin order to minimize prevent secondary precipitation.

Generally, due to uncertainties in the mineralogy of the

rock and damage, and unpredictable fluid placement, the

correct volume of the HCl Preflush may not be available to

dissolve the calcites in the matrix. This could lead to theformation of an insoluble calcium fluoride (CaF2) precipitate

as shown in Equation (1) and thus secondary damage to theformation. Other damaging products of the reaction between

the HF-based fluids and the minerals, 1 include hydrated silica

from the secondary reaction of HF in Equation (2) and

aluminum leaching in Equation (3), and ferric chloride inEquation (4).

2HF + CaCO3 CaF 2 + CO2 + H 2O…………………………(1)

2SiF 6 -2 + 16H 2O + Al 4Si4O10(OH)8

6HF + 3AlF 2 +

+10OH -1

+ Al +3

+ 6 SiO2.2H 2O..…….…………(2)

12H + + Al 4Si4O10(OH)8

4Al +3 + 2 H 2O + 4 SiO2.2H 2O………………..………………(3)

6H +

+ Fe2O3 2FeCl 3 + 3H 2O……………………………(4)

In addition to the potentially damaging precipitates fromthe reaction products, it is generally understood that it can be

extremely difficult, expensive, and sometimes impossible, to

achieve the desired corrosion protection time withconventional systems at bottomhole temperatures above

310oF. In some cases, very high corrosion inhibitor loadings

may be required to protect well tubulars made out of high

chrome steel. Lastly, high strength HF-based systems couldsometimes deconsolidate or deform high clay content rocks.

High Temperature SystemsSeveral approaches have been used to address hightemperature sandstone acidizing challenges in the past2. These

involve the use of both HF and non-HF systems. The HF-

based systems include retarded acids like organic acid:HF, andaluminum chloride (AlCl3):HF systems3 to slow down the

reaction kinetics. The non-HF systems include the use of a

phosphonic acid-based system to reduce the risk of insoluble precipitates from HF-based reactions and reduce the HSE

hazards of these treatments.4,5

Whilst these methods address the issue of secondary andtertiary precipitation, there is no single system that addresses

all the above-listed factors that contribute to the poor success

rate of high-temperature sandstone acidizing treatments. The

risk of inadequate volumes of preflush leading to CaF2

precipitation still exists in some cases, while problems ofshallow acid penetration due to the aggressive nature of the

HF-based systems, and inadequate damage removal and hence

low skin reduction, still persists. Additionally, highconcentrations of corrosion inhibitors are usually required to

protect well tubulars at very high temperatures at a high cost,

with a potentially negative effect on the performance of other

acidizing additives and the formation. Furthermore, emulsion

and sludge problems still result from the incompatibilities

between certain formation fluids and the conventional acid

systems.An alternative approach uses chelating agents as the main

treatment fluid. Frenier 6 and Ali7 have both demonstrated tha

formulations based on the hydroxyethlaminocarboxylic acid

(HACA) family of chelants could be used to effectively

stimulate both carbonates and sandstone formations at hightemperatures. These systems, however, require multiple stages

and are more effective in high-carbonate and low-clay contenformations.

The New Sandstone Acidizing SystemThe new sandstone acidizing system is based on a newlydeveloped chelating agent that is very tolerant of high content

of both carbonates and aluminosilicates, and iron- and zeolite

bearing minerals. It is designed to effectively treat hightemperature sandstone formations. It is particularly useful in

treating multi-layered production intervals that may have

uncertain rock and damage mineralogies between the layers.

The new system is pumped as a single fluid compared tocurrent systems that require several stages of preflush, main

fluid, and overflush. Other high-temperature sandstone

acidizing challenges addressed by the new system arecorrosion of the tubulars due to exposure to acidic fluids due

to its mild pH; and emulsion and sludge formation. This

system addresses the fluid-related shortcomings, and reducesthe risk, of conventional multi-stage systems.

The new system, which has been very effective in

stimulating Berea sandstone and field cores at high

temperatures up to 375oF, shows reaction kinetics that are

retarded compared to inorganic acid:HF systems. This breakthrough technology has the benefits of:

• Increased production and success rate of sandstoneacidizing treatments

• Reduced risk of secondary and tertiary precipitation

• Reduced well and surface equipment repair costs due tocorrosion damage

• Operational simplicity

• Better HSE footprint on location

• Improved image of the industry

In addition to minimizing the treatment risk and simplifying

the solution using a novel chemistry, it is essential to properlydivert the fluids using effective placement techniques. The

new system is compatible with commonly used mechanica

and chemical diversion techniques including foam and

viscoelastic surfactants. The treatments may be bullheaded or pumped through coiled tubing.

Job Design and Fluid Volume Optimization. This done with

the aid of a powerful geochemical simulator that determinesthe optimum formulation of the fluid based on its ability to

remove identified formation damage, reduce skin, and

minimize the risk of secondary precipitation. The simulatoralso optimizes treatment volumes and pumprates to ensure

sufficient volumes of fluid are pumped to achieve the desired

skin reduction results. Additionally, the simulator enables the

user to compare various fluid systems and pumping schedules


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SPE 98314 3

(for example, volumes, rates of injection, shut-in times), and

to run sensitivity analysis various job design parameters until

an optimal design is achieved.The rock mineralogy that is used to calibrate the simulator

is obtained from X-Ray powder Diffraction (XRD) analysis of

field core samples or from Elemental Capture Spectroscopy

logs. The computed minerals and mineral groups from these

measurements include total clay, total quartz-feldspar-mica,total carbonate, total salt, total pyrite, total siderite, total coal,

and total anhydrite.8 Details of the geochemical simulator have been previously

published and presented.1, 9

ExperimentalBatch Reaction Tests. These tests were performed using

several minerals with properties shown on Table 1. The

minerals were crushed in a plastic bag, and then ground to a

fine powder using a mortar and pestle. Selected samples were

subjected to XRD analysis. The fluid/mineral ratio was 9/1 byweight. Slurry reactor tests consisted of 70 g of powered test

material and 600 g of solvent. The effluents were filteredthrough a 0.2-filter before dilution with DI water and analysis

using inductively coupled plasma spectrometer (ICP) for the

ions in solution.

Coreflood Tests. These tests were conducted using the newsystem on both Berea sandstone and field core samples. Table2 shows the Berea core mineralogical composition that was

obtained from the XRD analysis. Berea Core. In order to compare the new system and other

acids in homogeneous stimulation of formation, 2” sectional

pressure differential data were monitored along the 6” longcore plugs. The permeability figures corresponding to these

sections are defined as k 1, k 2, and k 3 and the total permeability

is k t. The test conditions and procedures for this test aresummarized on Table 3.

Damaged Field Cores. Field core A was damaged by finesas described in Table 4, using a procedure that was previously

presented.10 The damaged core was then treated by flowing 15

pore volumes of the new system at 210oF.

Field Core B that had original permeability 21mD, was

artificially damaged by a drilling fluid containing 20ppb drill

solids (ground core) at 250oF and 100psi overbalance. The

filter cake on the damaged core was then scratched off and acore flow test conducted.

Field Core C was treated with three different fluids

respectively, i.e., HF system 1, HF system 2, and the new

system. High Temperature Case. The above-stated procedures

were also applied to a core sample from a field with a

bottomhole temperature of 300oF.

Geochemical Simulation. Batch reaction data was

accumulated in the geochemical simulator and, based on the

core flow tests, the specific surface area of various mineralswas calibrated to perform further geochemical simulation of

the fluid under various formation conditions. A sensitivityanalysis was then performed using various rock and treatment

parameters, which included fluid formulation, mineralogy,

temperature, pump rate, and fluid volume.

Corrosion Tests. Comparative corrosion tests were run

between conventional sandstone acidizing systems and the

new system using standard fluid compatibility and emulsiontesting procedures.

Emulsion Test. A heavy crude oil sample from the field was

tested with both HF system 1 and the new system to see their

emulsion tendencies at 185o

F.

Results and Discussion Batch Reaction Tests. Three acid systems reaction results

with kaolinite/calcite (65g/5g) mixture at 212oF are shown inFigures 1 and 2. As the acids spent, both HF-based systems

precipitated CaF2 while the new system showed increasingCa2+ concentration because of its slower dissolution rate andgreater Ca2+ chelation capacity. At 212

oF, the reaction rate of

the new system with kaolinite in the mineral mixture is about

25% that of HF system 1. Additionally, the new systemshowed much less silica precipitation tendency than HF

System 1.

Coreflood Tests with Berea Core. In order to compare the

new system and other acids in homogeneous stimulation of

formation, 2” sectional pressure differential data were

monitored along the 6” long core plugs. The permeabilitiescorresponding to these sections are defined as k 1, k 2, and k

and the total permeability is k t.As shown in Figure 3, for the same total stimulation ratio

of k t/k 0 = 1.5, HF systems 1 and 2 had the most stimulation

effect on the first 2” section; resulting in lower stimulation

ratio in section 2 and additional damage in section 3. The newsystem on the other hand, showed a more homogeneous

stimulation of all three sections. Figure 4 shows that HFsystem 1 disintegrated the rock, while the rock sample that

was treated with the new system maintained its integrity.

Coreflood Tests with Damaged Field Core.

Field Core A. The final permeability was higher than

original permeability without fines migration damage, as

shown in Figure 5.Field Core B. The results are shown in Figure 6. The mud

damage was completely removed after treating with the new

system and the final permeability was even higher than theoriginal undamaged permeability.

Field Core C. Figure 7 summarizes the test results. The

cores treated by HF systems 1 and 2 were further damaged

instead of being stimulated (only 30% and 80% of the origina permeability regained respectively). The new system, on the

other hand, resulted in 110% regained permeability. High Temperature Case. Figure 8 shows that at a high

temperature of 300oF, the new system was effective a

removing damage in rocks that had carbonate content of 30%

and 12%.

Geochemical Simulation. The geochemical simulator

software was used to estimate the skin reduction of the fluidon this formation over a range of temperatures.

Case 1: A plot of the skin reduction (as a percentage of the

initial skin value) against temperature is shown on Figure 9


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4 SPE 98314

Subsequent experiments were also conducted using the HF

system 1, and two other systems used in the industry. The

results show that the new system consistently outperformsother commercial acidizing systems at temperatures above

200ºF.Case 2: The impact of fluid placement on the treatment

results was also simulated. Figure 10 shows that a properly

executed HF system 2 treatment on this formation would need100 gal/ft of acid preflush. Assuming only 30 gal/ft of the

preflush was effectively placed, the simulator demonstratesthat the skin would increase, instead of decrease, due to the

generation of CaF2 from the reaction between HF and the

undissolved CaCO3. On the contrary, the new system, which is

very tolerant of high amounts of carbonates, showedimpressive skin reduction regardless of the preflush volume.

Corrosion Test. The new system showed extremely low

corrosion rates on a variety of metal samples through the

temperature range of interest (200-375ºF), as shown on Figure11. The low corrosion rates, which were visibly below the

acceptable corrosion rate of 0.05 lb/ft2, were achieved with alow loading (1% w/w) of A272 corrosion inhibitor. The

system was also able to protect a 25CRW125 steel against

corrosion at test conditions of up to 375ºF, as shown onFigure 12. This was achieved without the aid of a corrosion

inhibitor in the system. This is not feasible with mostcommercial acid systems.

Emulsion Test. The results of the emulsion tests using the

new system and a field crude sample are summarized onTable 5. The results show that whereas it took about 120

minutes for the new system to completely separate from theoil/acid mixture, only 75% separation was achieved with the

HF system 1after 240 minutes.

Scanning Electron Microscopy (SEM). SEM images that

clearly show the ability of the new system to remove claydamage have previously been presented.7

Conclusions(1) Laboratory tests have shown that the new system is an

effective chelant-based formulation for matrix stimulation

of challenging sandstone reservoirs with BHST between200-300ºF

(2) Field core tests have demonstrated that the system can be

effective in treating formations that have medium to highclay and/or calcite content.

(3) Geochemical simulations show that the new system isable to decrease skin in all the simulated cases. Its ability

to react with both carbonates and clays results in a largeskin reduction, though it dissolves less clay than most

high-strength HF-based systems.

(4) The new system requires little or no corrosion inhibition

due to the near-neutral pH of the fluid. This also makes it

safer to handle, resulting in a lesser HSE footprint onlocation.

(5) The new sandstone acidizing system is compatible with

many formation fluids, resulting in less emulsion andsludge problems.

(6) The new sandstone acidizing system, when combined

with the geochemical simulator, addresses three success

factors for sandstone acidizing treatments; “design for

success”, simplify the solution, and reduce the treatmentrisk.

AcknowledgementThe authors acknowledge the support and permission of

Schlumberger management for the writing and publication othis paper. Special thanks to Dawn Alamia and theSchlumberger North America client support laboratory for the

testing and the analytical data produced for this project.

Nomenclature HF system 1 = 9:1 HCl: HF system

HF system 2 = Organic acid: HF system

HF system 3 = Boric acid-based system

References1. Hartmann, R.I. et al .: “Acid Sensitive Aluminosilicates

Dissolution Kinetics and Fluid Selection for Matrix StimulationTreatments,” paper SPE 82267 presented at the 2003 SPE

European Formation Damage Conference. The Hague, The Netherlands.

2. Rae, P. and Di Lullo, G.: “Matrix Acid Stimulation: A Review o

the State-Of-The-Art”, paper SPE 82260, presented at the 2003SPE European Formation Damage Conference. The Hague, The

Netherlands.3. Gdanski, R.D.: “AlCl3 Retards HF Acid for More Effective

Stimulation,” OGJ (1985) 110-1154. Martin, A.N.: “Stimulating Sandstone Formations with non-HF

Treatment Systems,” paper SPE 90774 prepared for presentationat the 2004 SPE Annual Technical Conference and Exhibition

Houston, September 26 - 29

5. O’Driscoll, K., et al.: “A Review of Matrix Acidizing Sandstonesin Western Siberia, Russia,” paper SPE 94790 at the 2005 SPE

European Formation Damage Conference. The Hague, The Netherlands.

6. Frenier,W., et al.: “Hot Oil and Gas wells Can Be StimulatedWithout Acids,” paper SPE 86522 presented at the 2004 SPEInternational Symposium and Exhibition. Lafayette, Feb. 18 –20.

7. Ali, S.A., et al .: “Stimulation of High-Temperature SandstoneFormations from West Africa with Chelating Agent-Based

Fluids”, paper SPE 93805, presented at the 2005 SPE

European Formation Damage Conference. The Hague, The

Netherlands.

8. Grau, J. A., et al .: “A geological model for gamma-rayspectroscopy logging measurements,” Nuclear Geophysics

(1989) Vol. 3, No. 4, p. 351–359.9. Ziauddin, M., et al .: “The Use of a Virtual Chemistry Laboratory

for the Design of Matrix Stimulation Treatments in the HeldrunField,” paper SPE 78314 presented at the 2002 SPE EuropeanPetroleum Conference. Aberdeen, Scotland

10. Devine, C.S., Ali, S.A., and Kalfayan, L.J.: “Method for PropeHF Treatment Selection, ” Journal of Canadian PetroleumTechnology (July 2003)54-61.

Metric Conversion Factors°F (°F . 32)/1.8 = °C

in. 2.54* E + 00 = cm

lbm 4.535 924 E . 01 = kg psi 6.894 757 E + 00 = kPa

*Conversion factor is exact.


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SPE 98314 5

TABLE 1 – MINERAL PROPERTIES FOR BATCH REACTION TESTS

TABLE 2 – MINERALOGY OF BEREA CORE SAMPLE

Mineral Composition (wt%)

Illite 2

Kaolinite 2

Ankerite 0

K-Feldspar 21

Albite 4

Quartz 70

TABLE 3 – TEST CONDITIONS AND PROCEDURES FOR BEREA CORE SAMPLE

Mineral Formula MW Structure Si/Al Ratio

Analcime Na2O.Al2O3.4SiO2.2H2O 343 Molecular sieve 2

Kaolinite Al2Si2O5(OH)4 258 Layered 1

Chlorite (Mg(Fe))5 Al2Si3O10(OH)8 556 Layered 2

Illite (K,H)Al2(Si,Al)4O10(OH)2 Varies Layered 1-2

Albite NaAlSi3O8 278 Chains of 4 member rings 3

Montmorillonite Ca0.17 Al2.3Si3.7O10(OH)2 257 Layered 2

Muscovite KAl3Si3O10(OH)2 398 Layered 1

Test Parameters HF System 1 HF System 2 New System

Core Size (inch) 1” diameter 6” long 1” diameter 6” long 1” diameter 6” long

Flow Rate (cc/min) 5.0 5.0 5.0

Confining/Back Pressure (psi) 2500/1000 2500/1000 2500/1000

Temperature (oF) 210 250 210 and 250

Flow Sequence

Initial Permeability

Preflush

Main Treatment

Postflush

Final Permeability

5%NH4Cl

15%HCl (15PV)

HF System 1 to k/k0=1.5

5%NH4Cl (15PV)

5%NH4Cl

5%NH4Cl

15%HAc (15PV)

HF System 2 to k/k0=1.5

5%NH4Cl (15PV)

5%NH4Cl

5%NH4Cl

New System to k/k0=1.5

5%NH4Cl


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TABLE 4 – TEST CONDITIONS AND PROCEDURES FOR FIELD CORE SAMPLES

TABLE 5 – EMULSION TEST RESULTS

Test A B C

Core Size (D/L, inch) 1”/6” 1”/3” 1”/4.5”

Flow Rate (cc/min) 1.5 1.0 2.0

Confining/Back Pressure (psi) 2500/1000 2500/1000 2500/1000

Temperature (oF) 210 250 260

Mineralogy

Quartz

Feldspar

Carbonate

Clays

62

8

11

19

83

1

1

15

60

10

10

20

Flow Sequence

Damage

Initial Permeability

Treatment

Final Permeability

-10cc/min to fines damage

-5%NH4Cl

-New System (15PV)

-5%NH4Cl

-16hrs mud damage

-5%NH4Cl

-New System (30PV)

-5%NH4Cl

-As received

-5%NH4Cl

-New System (30PV)

-5%NH4Cl

Percentage of Separation (%)

Time (min) HF System 1 New System

0 64 79

30 65 80

60 67 82

90 69 85

120 71 88

150 72 91

180 74 94

240 77 100


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SPE 98314 7

0

2000

4000

6000

8000

10000

12000

14000

16000

15 30 60 120 240Time (min)

A l C o n c e n t r a t i o n ( p p m )

0

100

200

300

400

500

600

700

800

900

S i C o n c e n t r a t i o n ( p p m )

A l - O l d C h e l a n t ( p p m )

Al-HF System 1 Al-New System Si-HF System 1

Si-New System Al-Old Chelant Si-Old Chelant

Figure 1 - ICP analysis of solution during slurry reaction of the new system showing kaolinite dissolution at212

oF

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

15 30 60 120 240Time (min)

A l a n d C a

C o n c e n t r a t i o n ( p p m )

0

200

400

600

800

1000

1200

1400

S i C o n c e n t r a t i o n ( p p m )

Al-HF System 1 Ca-HF System 1 Al-New System

Ca-New System Si-HF System 1 Si-New System

Figure 2 - ICP analysis of solution during slurry reaction of the new system showing clay/calcite dissolution


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8 SPE 98314

Figure 3 – Comparison of the stimulation ratios of 2 different systems shows homogeneous dissolution by thenew system

Figure 4 – Photo showing rock deconsolidation with HF system 1 on the left compared to the sample on the rightthat maintained its integrity with the new system.

0

1

2

3

4

5

6

7

8

New System HF System 1 New System HF System 1

210 degF 250 degF

S t i m u l a t i o n r a t i o

Total k1/k0 k2/k0 k3/k0


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SPE 98314 9

0

10

20

30

40

50

60

Untreated Core Fines MigrationDamage

Treated with NewSystem

P e r m e a b i l i t y ( m D )

Figure 5 – Field core (A) showing damage removal by the new system

0

5

10

15

20

25

Untreated Core Damaged Core Treated with New

System

P e r m e a b i l i t y ( m D )

Figure 6 – Field core (B) showing drilling mud damage removal by the new system


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10 SPE 98314

Figure 7 – Comparison of damage removal by three systems on three core samples showing the effectiveness ofthe new system

Figure 8 - Summary of linear coreflood test results of high and medium carbonate-content rock samples at 300oF

showing effectiveness of the new system at high temperatures.

0

20

40

60

80

100

120

10PV Acetic Acid +20PV HF System 2 +20 PV NH4Cl

Core Sample A Core Sample B Core Sample C

30 PV New S ystem

R e g a i n e d P e r m e a b

i l i t y

10PV Acetic Acid +20PV HF System 3 +20 PV NH4Cl

0.01

1.1

4

0.67

0

1

2

3

4

5

P e r m e a b i l i t y ( m d )

k(initial)

k(final)

New System New System

30%

acid-soluble

12%

acid-soluble


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SPE 98314 11

Figure 9 – Geochemical simulator output showing the ability of the new system to achieve a high reduction inskin even at temperatures of up to 350

oF whereas other systems’ performance tend to decline at temperatures

above 200oF.

Figure 10 – Geochemical simulator output showing the negative impact of pumping inadequate volumes ofpreflush with HF System 2. The new system does not need any acid preflush.

-25

0

25

50

200 250 300 350Temperature (°F)

S k i n R e d u c t i o n ( % )

HF System 3

HF System 2

HF System 1

New System

- 30

- 20

- 10

0

10

20

30

0 50 100 150

Volume (gal/ft)

S k i n R e d u c t i o n ( % )

HF System 2

New System


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12 SPE 98314

Figure 11 – Corrosion tests results showing the effectiveness of the new system at temperatures up to 375oF

0

0.01

0.02

0.03

0.04

0.05

0%

Corrosion

Inhibitor

C o r r o s i o

n R a t e ( l b / f t 2 )

Acceptable Corrosion Rate = 0 05cceptable Corrosion Rate = 0 05

0.5%

Corrosion

Inhibitor

1%

Corrosion

Inhibitor

Figure 12 – Corrosion tests results showing the new system is able to protect 25CRW125 steel for up to 12 hoursat a temperature of 375

oF without the aid of a corrosion inhibitor. A low concentration of inhibitor is required to

achieve a longer protection time.

0

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0.04

225 275 325 375

Temperature (degF)

C o r r o s r i o n R a t e ( l b / f

t 2 )

13 Cr N80 HS80

a break through fluid technology in acidizing sandstone

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