Options for High-Temperature

Well Stimulation
As wells become deeper and hotter, there is a growing need for high-temperature
matrix acidizing techniques. Newly developed procedures allow acidizing of both
carbonates and sandstones at elevated temperatures. These advances vary from new
chemical agents to simplified fluid-placement techniques.

Salah Al-Harthy
Houston, Texas, USA
Oscar A. Bustos
Mathew Samuel
John Still
Sugar Land, Texas
Michael J. Fuller
Kuala Lumpur, Malaysia
Nurul Ezalina Hamzah
Petronas Carigali
Kerteh, Terengganu, Malaysia
Mohd Isal Pudin bin Ismail
Petronas Carigali
Kuala Lumpur, Malaysia
Arthur Parapat
Kemaman, Terengganu, Malaysia
Oilfield Review Winter 2008/2009: 20, no. 4.
Copyright 2009 Schlumberger.
OneSTEP, StimCADE, SXE and Virtual Lab are marks of
Schlumberger.

52

Oilfield Review

Using acids to improve well performance by

removing or bypassing damage has been a
common practice for a long timenearly as long
as the existence of the oil industry itself. In 1895,
the Ohio Oil Company used hydrochloric acid
[HCl] to treat wells in a limestone formation.
Production from these wells increased by several
foldand unfortunately so did casing corrosion.
As a result, acidizing to stimulate production
disappeared for about 30 years.
Acidizing in limestone reservoirs experienced
a rebirth in 1931 with the discovery that arsenic
inhibited the corrosive action of HCl on wellbore
tubulars.1 But acid treatments for sandstones
required a different approach. HCl does not react
easily with minerals that reduce sandstone
permeability, but hydrofluoric acid [HF] does.
Early attempts using HF in sandstones failed
because of plugging from secondary reactions.
This problem was overcome in 1940 with a
combined HF-HCl treatment. The HF in the acid
combination dissolves mineral deposits in
sandstones that hinder production, while the HCl
controls precipitates. These acidizing techniques
have evolved over subsequent years, but the goal
has not changedcreate or restore production
pathways close to the wellbore in a new or
existing well.
Well acidizing, more commonly referred to as
matrix acidizing, is one of two intervention
methods used to restore flow in an oil or gas
formation. The other routehydraulic or acid
fracturingcreates fractures to allow relatively
distant accumulations of oil and gas to flow to the
wellbore. Acidizing works on the formation near
the wellbore to bypass damage or to dissolve it.
The choice of fracturing or acidizing to stimulate
production depends on a multiplicity of factors
that include formation geology, production
history and intervention goals.
Well-intervention techniques such as matrix
acidizing play an important role in helping
operators produce all they can from their fields.
Pressure on acidizing experts to develop new
treating formulations and techniques is coming
from several directions. One important need is
extension of acidizing to high-temperature
environments. Use of conventional mineral acids
such as HCl and HF at higher temperatures
above 93C [200F]leads to reaction rates that
are too rapid. These fast rates cause the acid to
be consumed too early, reducing its effectiveness, and may cause other problems.

Winter 2008/2009

Acidizing in Limestone: 2HCl + CaCO3

CaCl2 + CO2 + H2O

Carbonate core
Acidizing in Dolomite: 4HCl + CaMg(CO3)2

MgCl2 + CaCl2 + 2CO2 + 2H2O

> Carbonate acidizing. Limestone and dolomite cores treated with HCl
develop macroscopic channels called wormholes (red). These channels
are the result of the reaction of HCl with the calcium and magnesium
carbonates in the cores to form water-soluble chloride salts.

Furthermore, as regulations tighten, there is a

greater need within the industry for fluids with
reduced environmental and safety risks.2
Conventional mineral acids such as HCl and HF
are difficult to handle safely, corrosive to wellbore
tubulars and completion equipment, and must be
neutralized when returned to the surface.
Additionally, as the bottomhole temperature
increases, corrosion-inhibitor costs rise rapidly
because of the high concentrations required
particularly with some exotic tubulars currently
used in well completions. Finally, conventional
sandstone acidizing techniques typically involve
many fluid treatment steps, increasing the
potential for error.
This article will focus on matrix acidizing and
discuss how this technology has been extended
to higher-temperature environments through
development of new fluids and techniques. Case
studies from Africa, the USA, the Middle East and
Asia demonstrate how these techniques are
being successfully employed around the world.
Different Formations
Different Acidizing Chemistry
The first consideration in matrix acidizing any
particular wellhigh-temperature or notis
formation lithology. Carbonate reservoirs are
mostly acid soluble, and acid treatment creates
highly branched conductive pathways called
wormholes that can bypass damage. Conversely,
in sandstone reservoirs, only a small fraction of
the rock is acid soluble. The goal of acid
treatment in sandstones is to dissolve various
minerals in the pores to restore or enhance

permeability. The chemistry and physics for

treating both types of reservoir have been
extensively studied and are well-understood.
Carbonate reservoirsprincipally limestone
and dolomitereact easily with HCl in
moderate-temperature environments to form
wormholes (above). The reaction rate is limited
primarily by the diffusion of HCl to the formation
surface. Wormholes in carbonate reservoirs
increase production not by removing damage,
but by dissolving the rock and creating paths
through it.
The formation of wormholes in carbonates is
explained by the manner in which acidizing
affects the rock. Larger pores receive more acid,
which increases both their length and volume.
Eventually, this extends into a macroscopic
channel, or wormhole, that tends to receive more
acid than the surrounding pores while it
propagates through the rock. The shape and
development of wormholes depend on acid type
as well as its strength, pump rate and temperatureplus the lithology of the carbonate.
Under the right conditions, wormholes can grow
1. Crowe C, Masmonteil J, Touboul E and Thomas R:
Trends in Matrix Acidizing, Oilfield Review 4, no. 4
(October 1992): 2440.
2. Hill DG, Dismuke K, Shepherd W, Witt I, Romijn H,
Frenier W and Parris M: Development Practices and
Achievements for Reducing the Risk of Oilfield
Chemicals, paper SPE 80593, presented at the
SPE/EPA/DOE Exploration and Production Environmental
Conference, San Antonio, Texas, March 1012, 2003.

53

Face Dissolution

Conical Channels
Ramified Wormholes

Wormholes
1.0

Porosity

Pore volumes to core breakthrough

Face Dissolution

0.2

Flow rate

> Carbonate dissolution patterns. Wormhole structure is related to the efficiency of the acidizing
operation and can be viewed by plotting the number of pore volumes to core breakthrough (PVBT)
versus the flow rate. Porosity patterns obtained from a software model calibrated with experimental
data illustrate how dissolution proceeds with increasing flow rate. The least efficient acidizing
operation is face dissolutionthe entire matrix must dissolve in order to advance the reaction front.
Slightly more efficient at higher flow rates is the creation of large, conical channels. The most
efficient operation occurs at the curve minimum, with creation of highly dispersed wormhole
channels. At even higher flow rates, the curve turns upward and large channels, called ramified
wormholes, form. Increasing to higher flow rates leads again to uniform face dissolution.

to substantial lengths, resulting in efficient use

of acid to bypass damage. In conditions that are
less favorable, the acid creates short channels
that do little to increase production. For any
formation being treated, there is an optimal set
of treatment parameters that creates wormholes
with the most efficient use of acid (above).3

In contrast to carbonate formations, the

quartz and other minerals that make up most
sandstone reservoirs are largely acid insoluble.
Acid treatment for sandstoneHF usually
combined with HClseeks to dissolve the
damaging particulates that block the pores and
reduce permeability (below).4 Acidizing in

B
C

D
E

> Sandstone matrix. The framework of sandstone reservoirs is typically made up of grains of quartz
cemented by overgrowth of carbonates (A), quartz (B) and feldspar (C). Porosity reduction occurs
from pore-filling clays such as kaolinite (D) and pore-lining clays such as illite (E).

54

sandstone targets damage in the first 0.9 to 1.5 m

[3 to 5 ft] radially from the wellborethe area
that experiences the largest pressure drop during
production and is critical for flow. This area is
typically damaged from migrating fines, swelling
clays and scale deposition. Sandstone acidizing
reactions occur in areas where acid meets
minerals that can be dissolved. The primary
dissolution reactions of the clays and feldspar
with a typical HF-HCl mix form aluminosilicate
products. Sandstone acidizing chemistry is
complex, and the initial reaction products can
react further and possibly cause precipitation.
These secondary reactions are slow compared
with the primary dissolution reactions and rarely
present problems with mineral acids except at
higher temperatures (next page, top).
Extension of matrix acidizing to temperatures above 93C presents the operator with both
possibilities and concerns. The possibilities are
obviousacidizing at higher temperatures
allows stimulation of hot wells using familiar
field procedures. However, at higher temperatures, use of HCl causes a host of problems. In
carbonates, the rapid HCl reaction rate at
elevated temperature may lead to face attack
instead of wormhole creation and may create
acid-induced sludge with high-viscosity crudes.
High-temperature problems in sandstones are
different. Clay dissolution may be too rapid,
decreasing penetration by the acid, and
secondary reactions may cause precipitation.
Finally, rapid reaction rates can deconsolidate
the sandstone matrix, creating mobile sand.
Of particular concern in high-temperature
sandstone and carbonate reservoirs is accelerated
corrosion of tubulars and other wellbore equipment. Although increased injection of inhibitors
may adequately control corrosion rates, the
greater inhibitor loading at higher temperatures
may itself cause formation damage.5
The challenges of extending matrix acidizing
to higher temperatures have led to development
of new treating fluids and techniques. Treating
fluids include acid-internal emulsions to retard
reaction rates in carbonate reservoirs and mild,
slightly acidic chemical agents for treating both
carbonates and sandstones. New techniques
include a simplified sandstone-treating system
that uses laboratory data and predictive
softwarein combination with new chemical
treating agentsto arrive at a simplified
procedure. These new treatments and techniques can be easily understood by examining
some of the laboratory data that were
instrumental in their development.

Oilfield Review

Winter 2008/2009

AIFx + H2SiF6

H2SiF6 + mineral + HCl

silica gel + AIFx

AIFy + silica gel ; x > y

Tertiary

Secondary

AIFx + mineral

Distance from wellbore

> Sandstone acidizing reactions. When sandstone formations are treated with
HF and HCl, three sets of reactions occur. Close to the wellbore, the primary
reaction of the acids with the minerals forms aluminum and silica fluorides.
These reactions rapidly dissolve the minerals and do not yield precipitates.
Farther from the wellbore, these primary products undergo slower secondary
reactions to form silica gel, which can precipitate. Finally, at a somewhat
greater distance from the injection zone, a tertiary set of reactions can occur,
forming additional silica gel precipitate. The kinetics of the secondary and
tertiary precipitation reactions become exponentially more rapid at higher
temperatures and may cause sandstone acidizing treatments to fail.

Diesel
Emulsifier,
corrosion inhibitor,
H2S scavenger

HCl

20

Reservoir face

HCl,%
15
28

19

Retardation factor, FR

3. Fredd CN and Fogler HS: Optimum Conditions for

Wormhole Formation in Carbonate Porous Media:
Influence of Transport and Reaction, SPE Journal 4,
no. 3 (September 1999): 196205.
Panga MKR, Ziauddin M and Balakotaiah V: Two-Scale
Continuum Model for Simulation of Wormholes in
Carbonate Acidization, AIChE Journal 51, no. 12
(December 2005): 32313248.
4. Damaging particulates may include native clays and
carbonates or material from drilling and workovers.
Damage may also occur from other mechanisms
including clay swelling, scale, organic deposits,
wettability changes and bacterial growth.
5. Van Domelen MS and Jennings AR Jr: Alternate Acid
Blends for HPHT Applications, paper SPE 30419,
presented at the SPE Offshore Europe Conference,
Aberdeen, September 58, 1995.
6. Zaeff G, Sievert C, Bustos O, Galt A, Stief D, Temple L and
Rodriguez V: Recent Acid-Fracturing Practices on
Strawn Formation in Terrell County, Texas, paper SPE
107978, presented at the SPE Annual Technical
Conference and Exhibition, Anaheim, California, USA,
November 1114, 2007.
7. Brownian diffusion or motion is the random movement of
particles suspended in a liquid or gas.
8. Navarette RC, Holmes BA, McConnell SB and Linton DE:
Laboratory, Theoretical and Field Studies of Emulsified
Acid Treatments in High-Temperature Carbonate
Formations, SPE Production & Facilities 15, no. 2
(May 2000): 96106.

HF + mineral + HCl

Primary

Laboratory Testing
Testing new treatments and techniques in the
laboratory offers many advantages including
simplicity, cost and avoidance of possible
problems in the field. Good laboratory data will
confirm treatment models and indicate the right
path for successful field operations. Proper
laboratory testing for acidizing techniques can
optimize treatment volumes and pinpoint
potential problem areas as well as confirm
theoretical underpinnings. A strong case in point
is the use of emulsified acids in matrix acidizing
of carbonate formations at higher temperatures.
One way to address the problem of fast
reaction rates at high temperatures is to use
acid-oil emulsions to retard the reaction rate.
These emulsions have been applied in both acid
fracturing and matrix acidizing of carbonates. In
acid fracturing, the emulsions help enhance and
enlarge conductive pathways far from the
borehole. Acid fracturing typically employs
chemical and mechanical diversion techniques
to ensure that the treatment flows to its intended
location.6 By contrast, acid-oil emulsions for
matrix acidizing are designed to work close to
the borehole and have lower treatment volumes
than those for acid fracturing techniques.
Acid-oil emulsions for matrix acidizing of
carbonate formations consist of an internal HCl
phase and an external oil phase. Hydrogen ion
transport from the acid droplets to the rock
surface takes place by Brownian diffusion
which dramatically slows the acid reaction rate.7
Laboratory data show that when HCl droplets are
suspended in diesel oil, the reaction rate can be
retarded by more than an order of magnitude
(right).8 In addition to the slow reaction rate

18

17

16

15
250

300

350

> Emulsions. Acid-oil emulsions decrease reaction rates by limiting access

of the HCl droplets to the reservoir face. Each droplet contains HCl plus
other components such as emulsifiers, corrosion inhibitors and hydrogen
sulfide [H2S] scavengers (top). The extent to which the emulsion retards the
reaction rate can be expressed as the retardation factor, FR. This factor is a
function of the ratio of the reaction rate with HCl to the reaction rate of the
emulsion. Laboratory core data on carbonates using 15% and 28% HCl in
stabilized emulsions show that reaction rates can be retarded by factors of
15 to 19 times in the temperature range 250 to 350F [121 to 177C] (bottom).
(Retardation data adapted from Navarette et al, reference 8.)

55

CO2H
HO2C

Polyaminocarboxylic
acids

CO2H

HO2C

HO2C

HO2C
Ethylenediaminetetraacetic acid
(EDTA)

HO

CO2H
CO2H
CO2H

Diethylenetraminepentaacetic acid
(DTPA)

CO2H
CO2H

Hydroxyaminopolycarboxylic
acids (HACAs)

CO2H
Hydroxyethyliminodiacetic acid
(HEIDA)

HO

CO2H

HO2C
Hydroxyethylethylenediaminetriacetic acid
(HEDTA)

> Chelants. Typical chelants used in the oil field include both polyaminocarboxylic acids and
hydroxyaminopolycarboxylic acids (HACAs). These compounds consist of one to three nitrogen atoms
surrounded by either carboxylic [CO2H] groups (EDTA and DTPA) or carboxylic and hydroxyl [HO]
groups (HEIDA and HEDTA). Molecular weights range from 177 for HEDTA to 393 for DTPA.

with the carbonate rock, acid-in-oil emulsions

have other advantages. Their relatively high
viscosity improves distribution in heterogeneous
reservoirs, and since the acid does not have
direct contact with well tubulars, corrosion is
reduced. Although emulsified acid systems have
been commonly used for matrix acidizing of
carbonates below 93C, laboratory data indicate

0.18

13 Chrome steel
80 Nickel steel

0.16

Corrosion rate, lbm/ft2

0.14
0.12
0.10
0.08
0.06
0.04
0.02
0

HEDTA

HCl

Mud acid

> Corrosion testing. Four-hour corrosion tests at

350F were performed on two metallurgies with
three acid-stimulation componentsa 20% by
volume sodium HEDTA chelant, a 15% by volume
HCl and a 9-to-1 mud acid (9% by weight HCl to
1% by weight HF). Corrosion rates for the chelant
are very low at 0.01 lbm/ft2 [0.049 kg/m2] for both
chrome and nickel steels. In contrast, corrosion
rates using conventional HCl and HF treatments
are 5 to 10 times higher for these metals.

56

that they can be extended to higher temperatures if properly formulated.

The Schlumberger acid-oil emulsion
formulationcalled the SXE-HT systemwas
developed for high-temperature acidizing in
carbonate reservoirs. It consists of an acid phase,
containing a corrosion inhibitor, and a diesel-oil
phase with an emulsifier. These two mixtures are
combined at high shear rates to form an oilexternal acid emulsion. Laboratory data on the
physical properties of this formulation show low
corrosion and pitting for a variety of metals, high
viscosity retention even up to 177C [350F] and
good emulsion stability. For example, a typical
SXE-HT emulsion is stable for at least two hours
at 149C [300F], and this stability time can be
prolonged by increasing the emulsifier concentration. Tests on limestone cores with the
SXE-HT fluid at 135C [275F] confirm its ability
to create wormholes at typical injection rates.
Use of a properly formulated acid-oil emulsion
is one solution for well stimulation at high
temperature. Another approach is to consider a
completely different type of reservoir acidizing
fluid. Data confirm that a different class of
chemicalschelantsallow well stimulation at
conditions that preclude the use of mineral acids.
The term chelation is derived from the Greek
word meaning claw, and chelants are often used
to bind, sequester or capture other molecules
typically metals. Although these agents have been
used frequently in the past to control metals or in
some cases to dissolve scale, their new focus is
well stimulation at elevated temperatures.

The chelants typically used in oilfield services

are complex organic acids (left).9 These
compounds not only bind metals, but also are
active dissolution agents in acidizing reactions.
Well stimulation with chelants yields several
advantages, including retarded reaction rates,
low corrosion rates and improved health, safety
and environmental benefits. While chelants
such as ethylenediaminetetraacetic acid (EDTA)
have been widely used for control of iron precipitation, hydroxyaminopolycarboxylic acid (HACA)
chelants have the additional advantage of
high acid solubility, and their primary role is
matrix acidizing.
The slower reaction rates exhibited by the
HACA chelants at high temperatures have
important implications. In carbonates, slower
rates allow efficient wormhole creation, while in
sandstones there is less possibility of damage to
sensitive formations. Low corrosion is another
important characteristic of HACA chelants. For
example, at high temperature, hydroxyethylethylenediaminetriacetic acid (HEDTA) exhibits
corrosion rates up to an order of magnitude lower
than those of conventional mineral acids (below
left).10 Significant health and environmental
benefits include lower toxicity, reduced need for
return fluid neutralization and lower
concentrations of corrosion products in these
fluids. Of all these advantages of HACA chelants,
however, the most important may be slower
reaction rates at elevated temperatures.
Coreflood testing in carbonates at elevated
temperatures demonstrates the advantage of
using a chelant rather than HCl to create an
efficient wormhole network (next page).11
Another gauge of chelant effectiveness in
carbonates versus that of HCl is the amount of
acid required to penetrate a formationas
measured by pore volumes to core breakthrough
(PVBT). In one simulation that was scaled up
from laboratory data, PVBT values for HCl and
HEDTA were predicted for acidizing a carbonate
formation at a depth of 2,185 m [7,170 ft], a
bottomhole temperature of 177C, and with
damage that extended 0.3 m [1 ft] from the
wellbore.12 At a pump rate of 0.95 m3/min
[6 bbl/min], the simulation predicted that the
PVBT for HCl was nearly 100 times that for
HEDTAindicating low acidizing efficiency for
HCl at high temperature.
As in carbonates, use of HACA chelants in
sandstones offers a way to avoid the rapid
reaction rates that lead to precipitation.
Laboratory tests on West African sandstone with
an HACA chelant confirm that proposition.

Oilfield Review

HCl

CO2H
HO

CO2H

HO2C

> Carbonate core tests. A coreflood test was performed on Indiana limestone with 15% HCl at 150F
[65C]. A photograph of the core face shows dissolution ending in a single dominant wormhole (top
left ). A longitudinal CT scan of this core indicates that this single wormhole extended the entire
length of the sample (top right ). Similar testing was carried out on a limestone sample with HEDTA at
350F and the same flow rate (bottom left ). Use of a chelant resulted in a complex network of
wormholes at the higher temperature level (bottom right ).

The Nemba reservoir is one of a group of

production zones lying offshore Cabinda,
Angola.13 This layered reservoir consists of varying
thicknesses of sandstone, limestone and shales.
Although some high-permeability streaks exist
due to fissures and fractures, permeability
elsewhere is low and temperature is high
149C. The Nemba formation contains high levels
of native calcium carbonate, making the
formation particularly difficult to acidize at
elevated temperatures without causing deconsolidation. Prior treatment and workovers in the
Nemba formation had caused significant damage
related to carbonate scale. Nemba sandstone
samples represent good candidates for evaluating
the use of chelants in high-temperature acidizing.
Ten core samples were taken from the Nemba
field over a narrow depth interval at about

3,534 m [11,595 ft] and subjected to a variety of

experiments with an HEDTA chelant. These
experiments measured composition, examined
metals evolution during reaction and determined
permeability. The composition of the Nemba core
samples ranged from 5% to 44% calcium
carbonate with significant amounts of feldspar
and chlorites. Two different procedures were
performed in the laboratory to determine the
results of HEDTA treatmentslurry reactor
tests and coreflood permeability tests.
The slurry reactor tests on the Nemba
sandstone samples used an isothermal, stirred
reactor to measure product composition as a
function of time. Powdered sandstone samples
containing 24% and 44% carbonate levels were
treated in the reactor with HEDTA at 149C.
Samples of the reaction mix were withdrawn over

time and analyzed by inductively coupled plasma

emission spectrometry. For both carbonate levels,
the concentrations of calcium, silicon, aluminum
and magnesium rose smoothly over time with no
decreases that would indicate precipitation.
The same slurry reactor test was repeated for
a 30% carbonate-containing sample using a
conventional 9:1 mud acid.14 In this experiment,
concentrations of calcium and other components
showed an initial rise followed by a decrease
indicating precipitationa common cause of
sandstone treatment failure. The slurry reactor
data on HEDTA suggest that this chelant
dissolves the pore-filling and blocking minerals
at high temperature without causing precipitation. These positive results for HEDTA were
followed by coreflood tests at two carbonate
levels. Results from these tests show that the

9. Frenier WW, Wilson D, Crump D and Jones L: Use of

Highly Acid-Soluble Agents in Well Stimulation
Services, paper SPE 63242, presented at the SPE
Annual Technical Conference and Exhibition, Dallas,
October 14, 2000.
10. Frenier W, Brady M, Al-Harthy S, Aranagath R, Chan KS,
Flamant N and Samuel M: Hot Oil and Gas Wells Can
Be Stimulated Without Acids, paper SPE 86522,

presented at the SPE International Symposium and

Exhibition on Formation Damage Control, Lafayette,
Louisiana, February 1820, 2004.
11. Frenier et al, reference 9.
12. Frenier et al, reference 10.
13. Ali S, Ermel E, Clarke J, Fuller MJ, Xiao Z and Malone B:
Stimulation of High-Temperature Sandstone Formations
from West Africa with Chelant Agent-Based Fluids,

paper SPE 93805, presented at the SPE European

Formation Damage Conference, Scheveningen,
The Netherlands, May 2527, 2005.
14. A conventional 9:1 mud acid is 9% by weight HCl
combined with 1% by weight HF.

Winter 2008/2009

57

CO2H
HO

CO2H

HO2C

Pretreatment

Posttreatment

Permeability, mD

5
4

k (initial)
k (final)

3
2
1
0

24% carbonate
sample

12% carbonate
sample

> Sandstone and chelants. Laboratory permeability tests were carried out
on Nemba sandstone cores with varying carbonate levels before and after
coreflood treatment with sodium HEDTA at 149C (bottom ). In the 24%
carbonate sample, the chelant increased permeability (k) by a factor of 25.
In the 12% carbonate sample, permeability increased by 35%. Samples of
the cores were photographed using a scanning electron microscope before
and after treatment with an HEDTA chelant. Before treatment, the sandstone
shows pore blocking as a result of dolomite and chlorite particles in addition
to quartz overgrowth. After treatment, the sample shows significant removal
of the pore-blocking minerals.

15. Ali S, Frenier WW, Lecerf B, Ziauddin M, Kotlar HK,

Nasr-El-Din HA and Vikane O: Virtual Testing: The Key
to a Stimulating Process, Oilfield Review 16, no. 1
(Spring 2004): 5868.
16. The Smackover Formation, http://www.visionexploration.
com/smackover.htm (accessed October 20, 2008).
17. Navarette et al, reference 8.
18. The composition of the emulsion as % by volume was
30% of an HCl solution (20% by weight HCl in water)
mixed with 70% diesel oil.
19. Nasr-El-Din HA, Solares JR, Al-Mutairi SH and
Mahoney MD: Field Application of Emulsified AcidBased System to Stimulate Deep, Sour Gas Reservoirs
in Saudi Arabia, paper SPE 71693, presented at the

58

SPE Annual Technical Conference and Exhibition,

New Orleans, September 30October 3, 2001.
20. Cocoalkylamine is a cationic surfactant that includes
high concentrations of several long-chain acids that
include lauric, myristic, palmitic and caprylic varieties.
21. Nasr-El-Din HA, Al-Dirweesh S and Samuel M:
Development and Field Application of a New, Highly
Stable Emulsified Acid, paper SPE 115926, presented
at the SPE Annual Technical Conference and Exhibition,
Denver, September 2124, 2008.
22. Like the cocoalkylamine, tallow amine acetate is a
cationic mixture of acids. However, this emulsifier has
longer carbon chains and contains some double bonds.
23. Frenier et al, reference 10.

chelant significantly increases permeability in

the damaged cores (left).
In aggregate, the laboratory results on
carbonate and sandstone samples provide an
advance in overcoming problems associated with
acidizing in high-temperature environments. In
contemplating the scale-up of laboratory data to
actual field operation, treating carbonates represents a more direct extension of the technology
since secondary precipitation reactions are not
present. Complex, multilayer sandstone formations present a more difficult problem since both
complicated mineralogy and precipitation
reactions must be considered. Job success in
sandstones can be improved by using a geochemical simulator package called Virtual Lab
software that optimizes stimulation parameters for
a variety of fluids and bottomhole conditions (next
page, left).15
Field results from the application of these
advances in high-temperature acidizing confirm
their potential.
Acidizing High-Temperature Carbonate Wells
The carbonate reservoirs of the Smackover
formation, located in the southeastern USA, have
been prolific producers of oil and gas since their
initial discoveries in 1937.16 Although interest in
this formation continues, many of the wells
drilled years ago now require stimulation to
boost declining production. High-temperature
gas wells drilled in Alabama Smackover dolomite
20 years ago have been acidized with good results
using oil-HCl emulsions.17 These retrograde
condensate wells reach a depth of 18,500 ft
[5,640 m] and can attain bottomhole temperatures of 320F [160C] and static bottomhole
pressures of 2,500 to 4,000 psi [17.2 to 27.6 MPa].
The treatment and production history of one of
these wells illustrates application of retarded
emulsions at high temperature in carbonates.
The gas well treated in the Alabama
Smackover field with a retarded oil-HCl emulsion
was drilled and completed in 1986. By 1998, gas
and condensate production from the well had
declined significantly. Prior to treating the well
with the emulsion, two workover operations were
performed. First, withdrawal of a chemical
injection string allowed additional perforations.
Next, tubular scale was removed using 15% HCl.
This well was then treated with nearly 214 bbl
[34 m3] of an HCl-diesel emulsion at a rate of
9 bbl/min [1.43 m3/min].18 Immediately after
treatment with the retarded emulsion, gas
production more than doubled, with a smaller but

Oilfield Review

9
8

500
450

Gas
Condensate

400

Emulsified-acid treatment
7

350

300

250

200

150

100

50

Condensate production, bbl/d

Slurry Reactor Tests

10

Gas production, MMcf/d

still significant increase in condensate production

(right). Two other nearby gas wells were also
treated with the retarded emulsion and experienced similar production increases.
Although acid-oil emulsions have been
employed for many years, additional focus on the
details of the technique has yielded significant

January
1996

July
1996

January
1997

July
1997

January
1998

> Smackover well production history. Gas and condensate production from this well declined steadily
over time reaching levels of 3.4 MMcf/d [96,200 m3/d] of gas and 150 bbl/d [23.8 m3/d] of condensate
in August 1997, immediately before treatment. After treatment with an acid-oil emulsion, gas production
increased to more than 9 MMcf/d [255,000 m3/d] while condensate rose to 200 bbl/d [31.7 m3/d]. Six
months after treatment, gas production had fallen off somewhat but was still more than twice the
value prior to treatment. In the same time period, condensate production fell slightly but retained
most of the treatment-related production increase.

Reservoir Coreflood Tests

Radial-Flow Simulations

> Reaction simulations in sandstone. Virtual Lab

software is a prediction system that determines
optimal acidizing parameters for sandstone
treatment. This semiempirical system is based on
laboratory data taken from samples of the
formation being considered for treatment. In the
first step, slurry reactor tests are carried out
using acid and crushed solids (top ). Analysis of
effluent solutions allows determination of
reaction kinetics and identification of
precipitates. In the second step, coreflood tests
determine permeability and porosity at reservoir
conditions (middle ). In the final step, all the data
are combined with radial-flow simulations to
determine the best acidizing treatment (bottom ).

Winter 2008/2009

improvements. A case in point is their use in

treating a group of deep, high-temperature wells
in the Middle East. These wells are located in
eastern Saudi Arabia and produce nonassociated
sour gas at a depth of about 3,500 m [11,500 ft].
The producing zone lies in the Khuff formation
and is composed of dolomite layers intermingled
with limestone. Bottomhole temperatures are in
the range of 127 to 135C [260 to 275F].
Stimulation efforts have been conducted on a
regular basis by the operator to enhance permeability and remove drilling mud damage. Both
straight HCl and acid-in-diesel emulsions have
been used for stimulation of gas wells in this
formation with varying results. HCl is an effective
stimulation agent but is highly corrosive at the
higher temperatures encountered in these wells.
An acid-oil emulsion was found to be effective in
providing stimulation without corrosion, but field
application showed the need for optimization of
the emulsifier formulation.19 Work to improve the
emulsifier was concentrated on two areas
reduced quantities and improved field operations.
Earlier field tests of acid-in-diesel emulsions
to stimulate wells in the Khuff formation used
28% by weight HCl in a 30% by volume acid and
70% by volume diesel emulsion. The emulsifier
was a cocoalkylamine at 0.08 to 0.11 m3 [0.48
to 0.71 bbl] per 3.78-m3 [23.8-bbl] emulsion
loading.20 The field application showed that
although the emulsion was effective at
stimulating production, further improvements

were needed. Emulsifier loadings were high, and

the emulsion often broke at ambient conditions
in the field, necessitating remixing and quality
control in the field before use. Both of these
cocoalkylamine emulsifier attributes meant
longer operation times and higher cost.
The operator, therefore, embarked on a
program to develop and test an improved
emulsion for use in stimulating the deep, hightemperature gas wells in this formation.21 Results
from laboratory testing of more than 10 different
emulsifiers showed that beef-tallow amine acetate
would be more effective than the cocoalkylamine
formulation.22 This new emulsifier could be used
at 25% of the previous loading to make stable
emulsions with no remixing at both ambient field
conditions and high temperatures. In a four-well
pilot campaign, the new tallow amine emulsifier
was successfully employed. Mixing times in the
field were reduced by 25% and poststimulation
production rates exceeded expectations.
Acid-in-oil emulsions are not the only option
for hot carbonate well stimulation; chelants can
also be used successfully, as illustrated by a well in
a Middle Eastern carbonate reservoir.23 After
completion, the well was not flowing, and drilling
mud filtrate damage in the formation was
suspected. Despite the need to stimulate the well
to start production flow, the operator had concerns
about the high bottomhole temperature110C
[230F]and the formation lithology at a
measured depth of 2,620 m [8,600 ft]. At this

59

depth, the limestone-dominated formation has

dolomite streaks containing significant amounts of
entrapped gas. Surface facilities were limited in
the amount of gas that could be handled to a
gas/oil ratio (GOR) of 440 m3/m3 [2,500 ft3/bbl].
Any stimulation to initiate flow in the well had
to avoid gas production and keep the GOR
below this limit by minimizing stimulation of the
dolomite streaks.
A chelant from the HACA family was the
obvious choice for the stimulation job. Chelants
in the HACA group exhibit enhanced reaction
rates with limestone and more limited reaction
with dolomitesan important factor for the
success of this treatment due to the entrapped
gas. A treatment plan for this well was developed
using the Schlumberger StimCADE software for
acid placement. This plan called for using coiled
tubing to place an HACA chelant into a narrow
zone of the limestone matrix at 2,620 m. The
software predicted a 1.5-m radial penetration by
the HACA chelant.
Stimulation treatment was carried out
without incident. A preflush of a solvent mixed
with water preceded the chelant to aid flowback
by making the formation water-wet. Treatment
pressure averaged 8.3 MPa [1,200 psi], and the
chelating injection rate was 0.056 m3/min
[0.35 bbl/min]. After treatment was complete,
the operator displaced the well with diesel and
pulled the coiled tubing. Positive results from the
treatment with the chelant were immediately
apparent. Oil production increased from the
initial nonflowing state to 96 m3/d [600 bbl/d].
This oil production increase was accompanied by
a GOR increase of only 264 to 299 m3/m3 [1,500 to
1,700 ft3/bbl]well within the operators limits.
Results from these cases confirm that
chelants are useful for stimulation of hot
carbonate reservoirs. This capability is also
present for sandstones.

Kepong/
Tiong/Bekok
MALAYSIA

Kerteh
Kepong

Kuala Lumpur
Tiong

Oil
Gas
Singapore

km 100

mi

Bekok

100

> Tiong field. The offshore Tiong field is located 260 km [162 mi] off the
coast of central Malaysia. This sandstone field covers an area of about
20 km2 [7.7 mi2] and, along with nearby Kepong and Bekok fields, produces
oil and associated gas (inset bottom). These fields send oil and gas by
pipeline to a gathering point at Kerteh on the mainland. From Kerteh, oil
and gas are sent by pipeline to Kuala Lumpur, Singapore and other
processing facilities (not shown).

400,000

80

300,000

Gas flow, m3/d

70

Gas flow
Oil flow

60

250,000

50

200,000

40

150,000

30

100,000

20

50,000

10
0

January 2007

April 2007

June 2007

> Tiong field stimulation results. The OneSTEP procedure performed on the Tiong well in April 2007
had immediate positive results from the chelant treatment. Oil production increased from about
16 m3/d [101 bbl/d] to more than 70 m3/d [440 bbl/d]. Similarly, gas production increased from less
than 20,000 m3/d [0.7 MMcf/d] to about 85,000 m3/d [3 MMcf/d].

60

Oil flow, m3/d

350,000

Acidizing High-Temperature Sandstone Wells

A West African well drilled in 1984 typifies the
choices an operator must make when confronting the need for acidizing a high-temperature
sandstone formation.24 This well, completed at a
depth of 2,360 m [7,743 ft] in a deltaic sandstone
formation with 15% carbonates, had a bottomhole
temperature of 128C [263F]. During a nearly
20-year period, oil production had declined from
490 m3/d [2,500 bbl/d] to 224 m3/d [1,408 bbl/d]
with a corresponding increase in water output.
The water, first noted in 1991, had increased to
30% by 2003. The effect of the water on completion equipment had been observed during a prior

Oilfield Review

well intervention to replace gas lift system

components. The scale deposits on the gas lift
mandrels were so severe that a 71-mm [2.8-in.]
gauge cutter could not pass below 875 m [2,870 ft].
Faced with concerns about corrosion and
possible damage to the formation using conventional acidizing, the operator chose to treat the
scale problem with an HACA chelant. The
treatment goal was to use a mild fluid that would
remove carbonate scale and not damage the
sandstone formation. The well was treated with
the HACA chelant using coiled tubing with a
rotating jet to spray and soak the areas
containing the gas lift components. Following
treatment, the fluids used in the operation were
displaced with water and the gas lift system was
restarted. A gauge cutter was run through the
entire length of the wellbore and encountered no
obstructions. After treatment, oil production
increased to 402 m3/d [2,528 bbl/d], indicating
removal of scale and possible stimulation of
the sandstone.
As illustrated by the treatment in this West
African well, using chelants in sandstones with
conventional fluid placement plans is often quite
effective. Schlumberger has extended the utility
of these new chemicals in sandstones with its
OneSTEP technology. This technology uses a
unique chelant fluid and simplified placement
techniques to stimulate production with less risk
of damage and precipitates. This fluid
substantially reduces the number of required
stages during acidizing. Petronas Carigali
recently employed this technology to stimulate
one of its offshore wells in Southeast Asia.
The Tiong field lies off the western coast of
Malaysia in 77 m [253 ft] of water (previous page,
top). Discovered in 1978, the field began
producing oil and gas in 1982. Tiong is a
sandstone formation with a high bottomhole
temperature109C [228F]. After experiencing
declining production and noting a high skin value
for the formation, Petronas evaluated several
Tiong wells as candidates for acidizing
treatment.25 Tests on core samples from the
24. Frenier et al, reference 10.
25. Skin is a dimensionless factor calculated to determine
the production efficiency of a well by comparing actual
conditions with theoretical or ideal conditions. A positive
skin value indicates some damage or influences that are
impairing well productivity. A negative skin value
indicates enhanced productivity, typically resulting
from stimulation.
26. Tuedor FE, Xiao Z, Fuller MJ, Fu D, Salamat G, Davies SN
and Lecerf B: A Breakthrough Fluid Technology in
Stimulation of Sandstone Reservoirs, paper SPE 98314,
presented at the SPE International Symposium and
Exhibition on Formation Damage Control, Lafayette,
Louisiana, February 1517, 2006.

Winter 2008/2009

candidate wells indicated formation damage from

kaolinite fines and calcite. Petronas selected a
well for the acidizing tests and chose the
OneSTEP system for its operational simplicity
and use of chelants (below).26 This combination
marries a low risk of secondary and tertiary
reactions that might cause precipitation with
fewer fluid stages and simplified logistics. Other
benefits accrue from low corrosion rates and a
good health, safety and environmental footprint.

Prior to carrying out the treatment,

Schlumberger calibrated the Virtual Lab model
using results from well testing before running
simulations. The well tests determined
formation dissolution kinetics, measured
physical properties of the rock and compared
treatment options in radial-flow tests. The final
choice for the treatment fluid at Tiong was a
chelant plus other additives. With this chelant
fluid, the OneSTEP treatment was carried out at
the Tiong well in April 2007. No operational
problems were encountered and the test was
successfuloil production increased by a factor
of four and gas production by a similar amount
(previous page, bottom).
For Petronas, stimulation of oil and gas
production was not the only benefit of the
OneSTEP technique. This simplified acidizing
operation saves significant rig time, resulting in
lower cost. In the Tiong treatment, the
operational time saved was measurable

Conventional Fluid Placement

Treatment Stage
Stage 1

Stage 2

Stage 3

Stage 4

Stage 5

Displacement

Step

Fluid Type

Brine preflush

Acid preflush

Main treatment

Overflush

Diverter

Brine preflush

Acid preflush

Main treatment

Overflush

10

Diverter

11

Brine preflush

12

Acid preflush

13

Main treatment

14

Overflush

15

Diverter

16

Brine preflush

17

Acid preflush

18

Main treatment

19

Overflush

20

Diverter

21

Brine preflush

22

Acid preflush

23

Main treatment

24

Overflush

25

Brine

OneSTEP Fluid Placement

Treatment Stage

Step

Fluid Type

Main treatment

Diverter

Main treatment

Diverter

Main treatment

Diverter

Main treatment

Diverter

Stage 5

Main treatment

Displacement

10

Brine

Stage 1
Stage 2
Stage 3
Stage 4

> OneSTEP technique. Conventional sandstone acidizingusually with HFis a complex process
involving several pieces of equipment and many sequential steps (left ). As many as six acid tanks and
two brine tanks may be employed, and five stages with 25 steps may be carried out, depending on the
type of diversion technique. In conventional treatment, brine preflush removes and dilutes acidincompatible components. Similarly, HCl preflushing removes calcites prior to the main HF treatment. In
contrast, OneSTEP treatment typically uses only two acid storage tanks and one brine tank and
requires significantly fewer treatment steps (right ). This treatment simplicity is a result of two
factorsuse of a chelant instead of HF and employment of Virtual Lab predictive software before the
job is started. The chelant eliminates problems with secondary and tertiary reactions, while Virtual Lab
testing ensures that any potential problems are addressed before the job begins.

61

600

West Java
500

Static reservoir temperature, F

Chelants

Deep Alex

400

Mobile Bay
Shearwater
Gulf of Thailand
E. Cameron, Sable

300

Egret, Heron
Asgard
Khuff
Brunei
Thunder Horse
Ursa

HCl-HF

200

100

> Acidizing deep, hot reservoirs. Acidizing with

HCl and HF is typically effective at reservoir
temperatures below 200F, and use of chelants
can extend this temperature range to about
400F. Recent deepwater gas discoveries are
good examples of hot reservoirs and can reach
temperatures of 250 to 550F [288C]. Chelants
could be considered for acidizing fields between
Ursa at 250F and Egret at 350F, but to acidize
fields above 400F, such as West Java, Deep Alex
and Mobile Bay, new technology will be required.

27. DeBruijn G, Skeates C, Greenaway R, Harrison D,

Parris M, James S, Mueller F, Ray S, Riding M,
Temple L and Wutherich K: High-Pressure, HighTemperature Technologies, Oilfield Review 20, no. 3
(Autumn 2008): 4660.
28. Aboud R, Smith K, Forero L and Kalfayan L: Effective
Matrix-Acidizing in High Temperature Environments,
paper SPE 109818, presented at the SPE Annual
Technical Conference and Exhibition, Anaheim,
California, November 1114, 2007.

62

conventional treatment was estimated at

45 hours in contrast to 24 hours for the OneSTEP
techniquea 21-hour savings. This time saving
is a direct result of fewer fluid stages and faster
flowback. Other benefits were also realized. Less
equipment and chemical inventory equates to
less deck space required, and fewer chemicals
reduce the operational risks of chemical spills
associated with handling and lifting.
New FieldsSevere Conditions
Great strides have been made in acidizing at high
temperature in the past few years. Treatment with
acid-oil emulsions and chelants allows operators
to acidize formations at elevated temperatures
with reduced corrosion rates and less risk of
secondary damage. As promising as this picture
seems for acidizing, more improvements in
treating agents and procedures will be required to
meet difficult conditions in the future.27
Current world demand for energy is expected
to growit is estimated that 40% more energy
will be required in 2020 than in 2007.28 As the
search for new reserves continues, exploration is
turning to deeper reservoirs; operations in the
USA illustrate this trend. In 2007, wells deeper
than 15,000 ft [4,572 m] accounted for about 7%
of domestic production; this is forecasted to grow
to 12% in 2010. The deep gas resource being
produced by this type of well is large and could
be as high as 29% of production in the future.
One defining characteristic of deeper basins
is that they are hot. Deep gas wells in the Gulf of
Mexico and Brazil have average bottomhole
temperatures of 204C [400F], and even higher
temperatures have been reported. To help operators focus on the implications of drilling and
operating deep, hot wells, several classification
systems have been developed.29 Many of these
deep, hot wells will require matrix acidizing at
some point in their life span, and current
technology covers only part of the temperature
range (above left). This trend toward increasingly
higher temperatures will demand improvements
in all aspects of acidizing, from corrosion rates to
treatment-fluid stability.

In spite of the difficulty in acidizing at

extreme conditions, some early successes have
been reported. For example, a South American
high-pressure, high-temperature sandstone well
with significant damage was treated with a
combination of acetic acid and HF, resulting in a
doubling of oil production.30 Keys to success in
this operation at high temperature included a
mild acidaceticassociated with HF, and
inclusion of a phosphonic acid stabilizer to keep
products in solution. Another example of
innovative solutions to acidizing in hightemperature environments is the use of an in situ
acid system.31 The treatment fluid in this system
contains an acid precursor that delivers timecontrolled release for long-interval wells.
In the final analysis, successful acidizing of
high-pressure, high-temperature wells will place
greater demands on both treatment fluids and
procedures. Fluids will be required that have
controlled reaction rates, low corrosion and
acceptable health, safety and environmental
footprintschelants are a good example of a
step in this direction. In addition to the
development of new fluids, treatments like the
OneSTEP technique that emphasize simplicity
and minimize operational time will be at a
premium. Taken together, future developments
in both treating fluids and procedures that
employ them will ensure that matrix acidizing
keeps pace with difficult conditions as new fields
are developed.
DA

29. Payne ML, Pattillo PD, Miller RA and Johnston CK:

Advanced Technology Solutions for Next Generation
HPHT Wells, paper IPTC 11463, presented at the
International Petroleum Technology Conference, Dubai,
December 47, 2007.
DeBruijn et al, reference 27.
30. Aboud et al, reference 28.
31. Al-Otaibi MB, Al-Moajil AM and Nasr-El-Din HA:
In-Situ Acid System to Clean up Drill-In-Fluid Damage
in High-Temperature Gas Wells, paper SPE 103846,
presented at the IADC/SPE Asia Pacific Drilling
Technology Conference and Exhibition, Bangkok,
Thailand, November 1315, 2006.

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