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.
This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in a proposal submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to a proposal of not more than 300words; illustrations may not be copied. The proposal must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.
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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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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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(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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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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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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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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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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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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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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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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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