Virtual Testing: The Key to a

Stimulating Process

Matrix acid stimulation in a sandstone reservoir involves complex chemical reactions

that are strongly dependent on mineralogy. A new process includes a model for simu-
lating acid reactions to help operators choose an optimal treatment for a formation.

Syed Ali Matrix acidizing reestablishes productivity in Reacting to Damage

ChevronTexaco many damaged formations in a cost-effective Acid treatments for sandstones differ signifi-
Houston, Texas, USA way. The damage can be natural, an artifact of cantly from those for carbonate rocks.
produced reservoir fluids moving through a Carbonate rocks dissolve rapidly in hydrochloric
Wayne W. Frenier formation, or induced by fluids used in well acid [HCl], and the reaction products are solu-
Bruno Lecerf
operations, such as drilling, completions and ble in water. In carbonate rocks, a matrix acid
Murtaza Ziauddin
workovers, or stimulation. job is usually designed to bypass near-well
Sugar Land, Texas
Formation damage can be caused by fines damage by dissolving minerals and creating
Hans Kristian Kotlar migration, scale formation, deposition of paraf- channels, or wormholes, in the rock, providing a
Statoil fins, asphaltenes or other organic material, or flow path past the near-well damage. Acid-
Trondheim, Norway mixed organic and inorganic deposition. It can fracturing techniques in carbonates create a
also result from plugging by foreign particles in hydraulic fracture that has a differentially
Hisham A. Nasr-El-Din injected fluids, wettability changes, clay swelling, etched surface, so that the fracture maintains
Saudi Aramco Research and Development emulsions, precipitates or sludges caused by acid its conductivity during production.3
Dhahran, Saudi Arabia reactions, bacterial activity and water blocks.1 In contrast to acidizing reactions in carbon-
These damage mechanisms can be either natural ate rocks, the reaction chemistry for silicate
Olav Vikane
or induced. Wellbore cleanup, matrix stimulation rocks is quite complex. Sandstones comprise
Statoil
treatments or acid fracturing may be used to quartz grains, clays of various types, feldspars,
Stavanger, Norway
remove or bypass near-well damage. chert, micas, and carbonate materials as cement
This article focuses on sandstone matrix or overgrowths on grains, along with other
For help in preparation of this article, thanks to Ernie Brown,
Steve Davies and Vincent Dury, Sugar Land, Texas;
acidizing.2 A matrix acid treatment forces acid minerals (next page). HCl is not effective in dis-
Keng Seng Chan and Ray Tibbles, Kuala Lumpur, Malaysia; into a formation at a pressure below its fractur- solving most constituents of silicate rocks.
Matt Gillard and Richard Warren, Aberdeen, Scotland;
Abigail Matteson, Ridgefield, Connecticut, USA; and Carlos
ing pressure. The treatment often involves Sandstone acid jobs typically use hydrofluoric
Torres, Maturin, Venezuela. several stages that may be repeated. acid [HF] in combination with HCl, formic or
ClayACID, ELANPlus (Elemental Log Analysis), NODAL, A new matrix-treatment design process acetic acid.4 HF dissolves silica and silicates,
PLT (Production Logging Tool) and Virtual Lab are marks
of Schlumberger. includes use of the Virtual Lab software, a state- and HCl or organic acids are included to keep
of-the-art geochemical simulator that properly reaction products in solution.
accounts for secondary and tertiary reaction Sandstone matrix acidizing primarily targets
mechanisms. Field examples from the North Sea damage from migrating fines, swelling clay,
and from the Gulf of Thailand demonstrate the carbonate or hydroxide scales, and plugging par-
usefulness of this new process for evaluating ticles from drilling and completion operations.
treatment designs. Understanding formation mineralogy and the

58 Oilfield Review
 C

B
E

> Sandstone minerals and clays. Pore-filling and pore-lining minerals and clays in sandstones can decrease permeability. The minerals and clays have
different morphologies, such as pore-filling kaolinite books (A), fibrous illite (B), carbonate overgrowth (C), feldspar overgrowth (D) and quartz cement (E).

nature of the damage is critical for designing a If HF comes in contact with calcium carbon- minerals.5 The main treatment that follows is
proper acid treatment. An improperly formulated ate [CaCO3] during a treatment, then it leads to often either a mud acid, a combination of HF
acid treatment can precipitate reaction products calcium fluoride [CaF2] precipitation. For this and HCl, or a retarded formulation such as the
in the formation, reducing rock permeability. reason, a matrix treatment usually includes a ClayACID fines-control retarded acid, which is a
A primary objective of designing an acid preflush stage with an acid such as HCl or an combination of fluoboric acid [HBF4] and HCl.
treatment in sandstones is optimizing damage organic acid to dissolve most of the carbonate The HBF4 hydrolyzes slowly to form HF and also
removal, while minimizing formation of damag-
ing precipitates. The first 3 ft [0.9 m] into a 1. A water block is a production impairment that may occur 4. The acid formulation used in any specific instance is
when the formation matrix in the near-well area becomes dependent on formation mineralogy.
formation from a wellbore experiences the water-saturated, thereby decreasing the relative perme- 5. Organic acids are blended with ammonium chloride
greatest pressure drop during drawdown, and is ability to hydrocarbons. Water block may result from the [NH4Cl] brine to minimize clay swelling. For further infor-
invasion of water-base drilling or completion fluids or mation: Thomas RL, Nasr-El-Din HA, Mehta S, Hilab V and
critical for flow. This region, sometimes called from fingering or coning of formation water. Lynn JD: “The Impact of HCl to HF Ratio on Hydrated Silica
the critical matrix, is the volume that matrix 2. For more on matrix acidizing: Crowe C, Masmonteil J, Formation During the Acidizing of a High Temperature
Touboul E and Thomas R: “Trends in Matrix Acidizing,” Sandstone Reservoir in Saudi Arabia,” paper SPE 77370,
acidizing treatments target for cleanup. Oilfield Review 4, no. 4 (October 1992): 24–40. presented at the SPE Annual Technical Conference
3. Al-Anzi E, Al-Mutawa M, Al-Habib N, Al-Mumen A, and Exhibition, San Antonio, Texas, USA, September 29–
Nasr-El-Din H, Alvarado O, Brady M, Davies S, Fredd C, October 2, 2002.
Fu D, Lungwitz B, Chang F, Huidobro E, Jemmali M,
Samuel M and Sandhu D “Positive Reactions in Carbonate
Reservoir Stimulation,” Oilfield Review 15, no. 4
(Winter 2003/2004): 28–45.

Spring 2004 59
reacts with clays, leaving behind a glassy borosil- The primary reaction between aluminosili- Simulated Reactions
icate coating that cements and stabilizes clay cates and HF from ClayACID and mud-acid The reaction of HF with minerals in sandstones
particles.6 Acid treatments are often followed by treatments yields fluosilicic acid [H2SiF6], along is slow, and the secondary and tertiary reactions
an overflush, either diluted HCl or ammonium with several aluminum-fluorine complexes. In that generate precipitates are even slower. The
chloride [NH 4 Cl], to remove the treatment- the presence of sodium and potassium, and outcome of an acid treatment depends strongly
reaction products from the near-well volume. A under certain conditions of temperature and on the amount and location of the precipitates.
treatment normally includes injection of a acid concentration, precipitation of compounds Therefore, predicting the results of a treatment
diverter followed by a repetition of these such as sodium fluosilicate [Na2SiF6] and potas- requires knowledge not only of the equilibrium
three stages. sium fluosilicate [K 2 SiF 6 ] can occur. In the reaction products, but also of the reaction
A wide variety of acid formulations is presence of additional aluminosilicates, H2SiF6 kinetics of the acid in the formation.
available, and the best treatment for a given can react to produce amorphous silica [H4SiO4] Reaction kinetics determine the rate at
formation depends on the characteristics of that as a secondary reaction. Amorphous silica can which the concentrations change as the system
formation.7 The new Virtual Lab geochemical also result from tertiary reactions of aluminum approaches equilibrium. The composition at
simulator provides a tool that helps guide the fluorides with aluminosilicates.8 equilibrium depends on the stability of the
selection based on formation parameters and Amorphous silica and the other compounds species at the given conditions and is calculated
treatment chemicals. The simulator models reac- listed above can block pores when they precipi- from thermodynamic data. Both kinetic and
tions and indicates the amount and location of tate. A successful treatment design must thermodynamic parameters must be known for
dissolution and precipitation of mineral species. minimize the precipitation of these compounds in all reactive fluids and minerals to predict the
the formation, particularly in the critical matrix.9 amount and the location of dissolved and
precipitated minerals around the wellbore.
Past practice has been to obtain specific
reaction information through core-plug tests.
Ideally, a core should come from the well and
6 formation that is to be acidized, but it often
comes from a nearby well. Outcrop samples and
5
Retarded acid
samples formed of packed sand mixed with clay
12/3 mud acid 4
minerals have also been used, but matching a
Wellbore

specific formation mineralogy and sedimentol-

k/k0

3 ogy may be difficult.

Although a core-flow test can provide vital
2 information for designing an acid job, there are
two inherent problems with such tests: the
1
core plug is too short and the radial geometry
0
around a wellbore is not honored (left).
0 0.5 1.0 1.5 Most core plugs are only a few inches long.
Radius, m
Reaction products flow out of the core before the
secondary and tertiary reactions can occur and
can generate precipitates. Use of 3-ft long cores
has been recommended to alleviate this prob-
Model parameters:
lem.10 However, obtaining sufficient formation
149°C Quartz, 87%
Kaolinite, 10% Porosity, 20% material for long cores is difficult. Analog outcrops
Calcite, 3% or sandpacks can provide sufficient material, but
at the expense of potentially poor matches to for-
mation mineralogy and sedimentology.
Long linear cores do not address the geome-
try problem. As injected fluid flows out from a
wellbore, the cross-sectional area that it flows
through increases proportionally to the radius.
With the same volume flowing through a larger
> Acid cleanup in core and near-well formation. A short core plug cross section, the flow rate decreases away from
represents a small part of a treatment volume in a formation. At the the wellbore. For an 8-in. diameter wellbore, the
length scale of a short core, the permeability appears to improve after flow rate 3 ft into the formation is only 10% of the
a 12% HCL and 3% HF (12/3) mud-acid treatment, but reprecipitation
damages formation permeability just beyond that length. The retarded rate at the sandface. This slower flow rate
acid results in better permeability over the treatment volume extending strongly impacts the location of precipitates from
0.9 m [3 ft] or more. Permeability (k) is plotted as a ratio to the far-field, secondary and tertiary reactions (next page).
undamaged permeability (k0), which is shown for comparison with the
treated permeabilities (dashed line).

60 Oilfield Review
 The flow test on a core sample from the
0.6 Heidrun field was typical of the procedure.14 A
small formation-core plug, 3.73 by 6.4 cm [1.47

Concentration, mol/kg
0.4 by 2.5 in.], obtained from a well near the one to
Al be treated, was saturated with simulated forma-
Al and Si without secondary tion brine and flushed alternately with
0.2
Si and tertiary reactions laboratory oil and brine until the effluent was
clear. A laboratory engineer heated the core to
0 reservoir temperature and flowed prefiltered
0 100 200 300
Time, min test fluids through the core with a 1,000-psi
[6.9-MPa] backpressure. This pressure kept any
generated carbon dioxide [CO2] in solution.
0.6
Al and Si without secondary The Heidrun field study used a 9/1 mud-
and tertiary reactions
Concentration, mol/kg acid—9% HCl and 1% HF—and a ClayACID
0.4 treatment. Flow rate and differential pressure
data recorded every 30 s allowed calculation of
Al
0.2 permeability throughout the test. The engineer
Si collected effluent in 10-mL plastic tubes on a
regular schedule and noted any fines in the sam-
0
0 100 200 300 ple. After filtering and diluting with nitric acid
Time, min (continued on page 64)

> Reaction time. Longer reaction time increases aluminum [Al] concentration
6. Thomas RL and Crowe CW: “Matrix Treatment Employs
in the effluent, but silicon [Si] concentration first increases from zero, then New Acid System for Stimulation and Control of Fines
decreases, for both mud-acid (top) and ClayACID treatments (bottom). The Migration in Sandstone Formations,” paper SPE 7566,
model curves show that excluding secondary and tertiary reactions, as could presented at the 53rd SPE Annual Technical Conference
happen in a short core test, could lead to incorrect predictions. and Exhibition, Houston, Texas, October 1–3, 1978; also in
Journal of Petroleum Technology 33, no. 8 (August 1981):
1491–1500.
7. Al-Dahlan MN, Nasr-El-Din HA and Al-Qahtani AA:
“Evaluation of Retarded HF Acid Systems,” paper SPE
65032, presented at the SPE International Symposium
on Oilfield Chemistry, Houston, Texas, USA, February
The new Virtual Lab simulator overcomes the reactions using the Virtual Lab simulator. 12 13–16, 2001.
problem of unrepresentative geometry and pro- Numerous treatment designs can be tested in 8. Nasr-El-Din HA, Hopkins JA, Shuchart CE and Wilkinson T:
vides guidance for successful matrix acidizing in the simulator, and Virtual Lab results will indi- “Aluminum Scaling and Formation Damage Due to Regu-
lar Mud Acid Treatment,” paper SPE 39483, presented at
sandstone reservoirs. It is the foundation of a cate the best design for field conditions. the SPE International Symposium on Formation Damage
system for designing acid treatments that prop- Control, Lafayette, Louisiana, USA, February 18–19, 1998.
9. Thomas et al, reference 5.
erly accounts for the cylindrical geometry From Laboratory to Field
10. Gdanski R: “Fractional Pore Volume Acidizing Flow
around a wellbore (see “A New Stimulation Central to any successful acidizing treatment is Experiments,” paper SPE 30100, presented at the SPE
Process,” page 62).11 In addition, Schlumberger accurate information about the reaction European Formation Damage Conference, The Hague,
The Netherlands, May 15–16, 1995.
has created a large, proprietary database of chemistry relating to formation minerals. The 11. Ziauddin M and Robert J: “Method of Optimizing
reaction kinetics and thermodynamics to use literature contains much of the relevant thermo- the Design, Stimulation and Evaluation of Matrix
Treatment in a Reservoir,” U.S. Patent No. 6,668,992 B2
with this simulator. This database saves clients dynamic-equilibrium data. However, most (December 30, 2003).
time and money because additional tests are publicly available reaction-kinetics data are 12. Ziauddin M, Gillard M, Lecerf B, Frenier W, Archibald I
necessary only when a formation or a new acid from tests obtained at temperatures below field and Healey D: “Method for Characterizing Secondary
and Tertiary Reactions Using Short Reservoir Cores,”
formulation contains compounds that are not in matrix acidizing conditions. Schlumberger labo- paper SPE 86520, presented at the SPE International
the database. The need for new tests has ratories performed batch-reactor tests at a wide Symposium and Exhibition on Formation Damage Control,
Lafayette, Louisiana, USA, February 18–20, 2004.
become less common as the database has filled range of temperatures to create an extensive 13. Ziauddin M, Frenier W and Lecerf B: “Evaluation of
with reaction parameters. proprietary database.13 Kaolinite Clay Dissolution by Various Mud Acid Systems
(Regular, Organic and Retarded),” presented at the 5th
Formation mineralogy can be obtained from The database of reaction-kinetics data International Conference and Exhibition on Chemistry in
either whole core or sidewall cores. A short-core reduces the number of fluid formulations that Industry, Manama, Bahrain, October 14–16, 2002.
flow test gives an estimate of the surface area of it is necessary to test. However, usually at least Hartman RL, Lecerf B, Frenier W and Ziauddin M: “Acid
Sensitive Aluminosilicates: Dissolution Kinetics and
the reacting minerals in a formation. This test one core-flow test is recommended to determine Fluid Selection for Matrix Stimulation Treatments,” paper
also provides information about core permeabil- the reactive surface area of minerals in the SPE 82267, presented at the SPE European Formation
Damage Conference, The Hague, The Netherlands,
ity and the effect of an acid on permeability as formation represented by the core. More than May 13–14, 2003.
pore-blocking material dissolves. Short-core 50 core-flow tests have been performed to 14. Ziauddin M, Kotlar HK, Vikane O, Frenier W and
Poitrenaud H: “The Use of a Virtual Chemistry Laboratory
tests alone do not provide sufficient information validate the Virtual Lab software. This database for the Design of Matrix Stimulation Treatments in the
for determining an acid treatment, but a short- also provides analogs for future cases in which Heidrun Field,” paper SPE 78314, presented at the
SPE 13th European Petroleum Conference, Aberdeen,
core test provides data necessary to model core material is not available. Scotland, October 29–31, 2002.

Spring 2004 61
 A New Stimulation Process

A new process for matrix acid stimulation A stimulation expert selects a few treatment the treatment redesigned. Once the design
relies heavily on the Virtual Lab software. fluids based on the information obtained for and the operational parameters agree, the
Mineral-fluid reactions are simulated quickly constructing the model. Each treatment real-time data of bottomhole pressure, injec-
and efficiently, so the best treatment option option is simulated. Various injection volumes, tion rates and fluids injected can be compared
can be selected. Schlumberger has developed rates and shut-in periods can also be evaluated. with model expectations. If there is a significant
several databases in a proprietary data Uncertainties in the data can be checked by discrepancy, the model assumptions are reex-
archive to use with the simulator. running a sensitivity analysis, which Virtual amined. For example, the real-time data may
The design process starts with a collection Lab software can do automatically. provide a new insight into the type, quantity
of well data (next page). Mineralogy, which is With an optimal treatment schedule deter- or location of damage, or may suggest that the
an important parameter for proper stimula- mined, an operator can now perform the permeability-porosity relationship in the for-
tion design, can be obtained from X-ray recommended treatment. mation differs from that measured in the core.
diffraction of core material. The other data If real-time bottomhole pressure data are After the model is adjusted, the redesigned
include well completion, formation tempera- available during the operation, the treatment treatment can continue. This ability to adjust
ture, porosity, permeability, evidence relating design can be adjusted while in progress the model in real time provides a great benefit
to formation damage, and well history. (below). If operational constraints prevent in helping operators optimize stimulation jobs.
Schlumberger has created an extensive the treatment from proceeding as planned, After the treatment, flowback and produc-
database of reaction kinetics and thermo- the constraints can be put into the model and tion data can be used to adjust the model one
dynamics, but occasionally some specific last time. The updated model for that field
kinetics parameters are not available. In that Begin treatment and reservoir is then available to optimize
case, reactions monitored in a controlled envi- future treatment jobs.
ronment, a batch-reactor, provide necessary
data. The new results are added to the database. Read real-time data
As the next step, experts recommend per- • Bottomhole pressure
• Injection rate
forming at least one flow test using core
• Fluid type and volume injected
material relevant for each formation to be
stimulated. These core tests are also stored
in the database, so a new test is not necessary
if results are already available. If they are not
Do operational
available, and suitable core material can be Yes
constraints prevent the
obtained, then a flow test should be per- treatment from being Redesign treatment
formed to provide data for the Virtual Lab executed as
planned?
simulator to match mineral surface area and
the permeability-porosity relationship for the Adjust model
No
specific formation. Only for cases in which
core tests or core material are not available
should an analog to the formation be used.
The core-flow database is the first place to Check model assumptions
Do the real-time data No • Formation-damage type, quantity
look for such an analog. match expectations from and location
With all this information collected, a Virtual the model? • Permeability-porosity relationship
Lab model can be built for the formation. It
includes the effect of radial flow from the
wellbore. The model can perform sensitivity Yes

studies when the well-log data indicate

heterogeneity in the formation-mineral compo- > Real-time feedback loop from process to model. When real-time bottomhole
sition. Data selected from the reaction and pressure data are available, the model can be adjusted to update the process
core databases feed into the model. while it is under way. This feedback loop continues until the job is complete.

62 Oilfield Review
 Select reaction data
Is reservoir core Yes
test available in Select formation data
database?

Yes No

Are reaction kinetics Is it feasible Estimate mineral surface

No
of minerals available to obtain and test areas and permeability-
in database? reservoir core? porosity relationship

No Yes

Calibrate parameters from

Conduct batch-
core-flow test
reactor tests to
• Mineral surface areas Build model for reservoir
measure kinetics
• Permeability-porosity relationship treatment, accounting for
Collect well data • Radial flow
• Mineralogy • Heterogeneities in permeability
• Temperature and mineralogy from well-log data
• Porosity and permeability
• Formation damage
• Well history
• Well completion Reaction kinetics
Core-flow tests
and thermodynamics Determine treatment using model
Begin • Optimize for fluid type, volume
Proprietary data archive and injection rate
• Examine sensitivity to data uncertainty
• Examine treatment scenarios
Fluid database Reservoir models

Update model assumptions

End Client report • Formation damage type, quantity and location Perform treatment
• Permeability-porosity relationship

Examine treatment from postjob data

• Flowback
• Production

> The stimulation process using Virtual Lab simulation and the proprietary data archive. The process begins on the left and proceeds clockwise.
Solid lines are the process steps and dashed lines are data transfers into, out of, or within the data archive. A real-time feedback loop can update
the model while the crew performs the treatment.

Spring 2004 63
to prevent further precipitation, the fluid First Use of Simulator for Stimulation The first use of the Virtual Lab geochemical
samples were analyzed to determine the Statoil operates the Heidrun field, located in the simulator was for a treatment in the Heidrun
concentration of aluminum and silicon (below). Haltenbanken area of the Norwegian Sea, A-48 well. The software simulated both batch-
Changes in effluent composition provided infor- 120 km [75 miles] south of the Arctic Circle. The reactor and core-flow tests specific to the Tilje
mation about the type and morphology of target well, A-48, had a deviation angle of 48° formation and provided the parameters needed
reactive minerals in the core. The Virtual Lab across the producing interval in the Tilje forma- for a stimulation model. The team simulated sev-
simulator matched the flow-test results, providing tion and was completed with an openhole gravel eral treatment scenarios and several acid
the mineral surface area and permeability- pack.16 Productivity in this zone declined after formulations to optimize the fluid types,
porosity relationship. formation-water breakthrough, and worsened sequences, volumes and injection rates.17
The acid treatment did not deconsolidate the after a scale-inhibitor squeeze treatment. The core test described earlier in “From
Heidrun field core and did not form precipitates, Design of a matrix-stimulation job was difficult Laboratory to Field” showed that permeability
indicating that this treatment fluid was compati- because this was the first well in the Tilje forma- increased during the ammonium chloride flush
ble with the native mineralogy.15 It also provided tion to be acidized. The formation was that followed injection of the 9/1 mud acid. This
the desired permeability improvement. heterogeneous, with high clay content and large indicated continuing movement of fines out of
clay clasts (bottom). the core. However, in the field, continued flush-
ing would move those fines deeper into the
formation, causing damage when the flow slowed
or stopped and the fines settled. A flowback
0.25
stage was included after the mud-acid stage to
clear the mobile fines out of the formation.
Concentration, mol/kg

0.20
Fe Al The treatment design was based on the core
0.15
and reactor tests.18 During the treatment, Statoil
Si
0.10 captured samples from all fluid returns and
determined the profile of ions in these fluids at
0.05
Na each stage. With this information, Virtual Lab
0 software confirmed that fines migration was the
300 most likely primary damage mechanism and
allowed the operator to examine the possibilities
Permeability, mD
200 of combined damage mechanisms. This simula-
tion showed that the final design improved
100 permeability while limiting mineral precipitation
Brine HCI-acetic acid 9/1 mud-acid stage Brine ClayACID stage (next page, top). The model recommended injec-
0
10 15 20 25 30 35 40 tion rates that could not be maintained during
Injected volume, pore volumes execution because of operational difficulties. A
second run of the model using actual flow rates
> Core-flow test. The permeability response to treatment acids is measured during a Heidrun field and fluid volumes indicated that the difference
core test. The increasing permeability during the NH4Cl brine flush following the 9/1 mud-acid in fluid placement between the recommended
treatment indicates movement of fines out of the core (bottom). The upper plot shows elemental and executed procedures was minor.
concentrations in the effluent. After changing injection fluids, the permeability change is seen before Before the stimulation treatment, the well
an effluent effect because the new fluid has to pass through the core. All the solid lines are best-fit
results from the Virtual Lab model, providing essential parameters for modeling the treatment. productivity index was 20 m3/bar-d [9 bbl/psi-D]
and reached 55 m3/bar-d [24 bbl/psi-D] immedi-
ately after the treatment. The productivity index
over the next seven-month period averaged
42 m3/bar-d [18 bbl/psi-D]. The acid treatment
successfully removed the near-well damage and
controlled fines migration (next page, bottom).
A
The Virtual Lab model optimized after treating
A’

15. An acid treatment normally dissolves some cement;

deconsolidation indicates that so much cement dissolved
that the core matrix was no longer competent.
B B’ 16. Ziauddin et al, reference 14.
17. Ziauddin et al, reference 14.
18. Ziauddin et al, reference 14.

AA’ BB’
> Clay clasts. The Tilje formation in the Heidrun field contains large clay clasts, apparent in the
computed tomographic image (left). The section AA’ includes large, dark, clay clasts (center). The
lower section BB’ shows clay laminae (right).

64 Oilfield Review
 Treatment phase 1 Volume, m Rate, L/min
100 Initial
Phase 1–before flowback Reservoir gas 200 1,200
Phase 1–after flowback NH4CI 5 1,200
10 Phase 2–before shut-in HCI–acetic acid 15 1,200
Phase 2–after shut-in 9/1 mud acid 30 1,200

Wellbore
k/k0
1 HCI–acetic acid 5 1,200
NH4CI 5 1,200
Diesel oil 12 1,200
0.10
Flowback stage
0.01
Treatment phase 2 Volume, m Rate, L/min
0 0.5 1.0 1.5 2.0
Radius, m Reservoir gas 200 1,200
NH4CI 5 1,200
3 Phase 1–before flowback
HCI–acetic acid 14 1,200
Phase 1–after flowback
Fluoboric acid 34 1,200
Phase 2–before shut-in
Phase 2–after shut-in NH4CI 5 1,200
Silica volume, %

2 Diesel oil 70 1,200

Wellbore

Well shut-in for six hours

1 Flowback stage

< Matrix acid-treatment model results. The

0 two-phase Heidrun field treatment started
0 0.5 1.0 1.5 2.0 with a mud-acid treatment, then a flow-
Radius, m back stage, followed by a ClayACID
fluoboric phase (table). The geochemical
3 Amorphous silica model predicted that the treatment would
Borosilicate improve near-well permeability (top). The
total silica mineral precipitation was low,
less than 2.5% of the formation volume
Silica volume, %

2
(middle). Borosilicate precipitation, useful
Wellbore

for stabilizing clays, peaks near the well-

bore, while amorphous silica peaks farther
1 away (bottom).

0
0 0.5 1.0 1.5 2.0
Radius, m

6,000 150
Injection-water Scale-inhibitor Acid-stimulation
breakthrough squeeze treatment
5,000 125
Productivity index (PI), m3/bar-d

Oil rate
4,000 PI 100
Oil rate, m3/d

Water cut, %

Water cut
3,000 75

2,000 50

1,000 25

0 0
7/1/99 1/17/00 8/4/00 2/20/01 9/8/01 3/27/02 10/13/02
Date

> Production data for Heidrun field Well A-48. Productivity declined when water broke through, and
further productivity was lost after a scale-inhibitor squeeze treatment. The acid-stimulation treatment
in September 2001 restored productivity without significantly increasing the amount of produced water.

Spring 2004 65
 1
Volume
vol/vol

Water
Shale
Sand
Oil
0

Gamma Ray MD,

API 200 ft 7,400 7,500 7,600 7,700 7,800 7,900 8,000

Zones 1 2 3
0

> Galley field well G5 log and production history.

8,000 800 The horizontal section of this well passes through
a channel, then a shale section and three
7,000 700 productive zones (top). The shale section from
Water production 7,440- to 7,570-ft [2,267- to 2,307-m] measured
6,000 600 depth (MD) collapsed during completion operations.
Wellhead pressure, psi

Oil production

Water production, B/D

Oil production declined steadily starting in
Oil production, B/D

5,000 500
January 2002, with water production increasing
4,000 400
beginning in April 2002 (left). This well later had a
matrix acidizing treatment.
3,000 300

2,000 200
Wellhead pressure
1,000 100

0 0
10/29/01 11/28/01 12/28/01 1/27/02 2/26/02 3/28/02 4/27/02 5/27/02 6/26/02 7/26/02
Date

the Heidrun A-48 well provided vital information of water. Significant recoverable reserves Water-holdup problems—NODAL production
to shorten the learning curve for treatment of remained within the well’s drainage area. system analysis results showed that water cut in
other wells in this complex, clay-rich formation. The combined ChevronTexaco and this field must exceed 50% to create a significant
Schlumberger stimulation team examined impediment to production. The measured value of
Damage Mechanisms in the Galley Field several possible damage mechanisms to explain 20% shows this is an unlikely damage mechanism.
Operator ChevronTexaco used the new acid- the loss of oil production. Fines migration—X-ray diffraction results
stimulation process in the Galley field on the UK Drilling-induced damage—Filtrate inva- indicated the presence of migratory clays such
continental shelf. The G5 well was completed sion; invasion of a calcium carbonate bridging as chlorite and illite along with mobile quartzite
horizontally with a 650-ft [200-m] openhole agent, polymer, starch and drilled solids; and fil- particles. A pump-in test supported fines as a
section in the late Paleocene-age Cromarty tercake plugging of the screen and sandface damage source. Permeability increased during
formation, which comprises fine to very could go unnoticed initially in a horizontal well. the pump-in—that is, reverse-flow—period, as
fine-grained, poorly consolidated, turbiditic However, such damage can create localized pro- compared with the permeability during produc-
sandstone (above). Most of the productive sec- duction areas, which can eventually lead to early tion. Further evidence of fines migration was
tion has a 100-mm mesh screen in place that water breakthrough, loss of screens and acceler- found in the decreasing oil production with
was originally intended for a gravel pack, but a ated fines production. increasing water production, since water can
shale section about a quarter of the way along Completion damage—The collapse of the destabilize fines and cause them to migrate.20
the horizontal section collapsed. Although pro- shale section prevented a complete gravel pack, Finally, the formation is unconsolidated,
ductive sand channels beyond the collapsed so the filtercake and mud removal in the section and other wells in the area had experienced
shale are accessible for flow into the wellbore, beyond the damage was probably extremely poor. fines migration.
those sections could not be gravel packed.19 Swelling clays—X-ray diffraction mineral- This analysis indicated that the treatment
Oil production declined steadily from an ini- ogy from a core sample showed that the volume had to remove damage possibly caused by
tial 7,000 B/D [1,100 m3/d], but the oil decline of swelling clays, such as smectite, was too low drilling, inorganic scale and migration of clays
rate accelerated when water production to be a damage mechanism. and quartzite particles. The proposed treatment
increased in April 2002. Before the stimulation Inorganic scale—Damage from barium started with jetting a chelating agent using a
treatment, the well produced about 1.1 million sulfate [BaSO4] was expected to be small, but coiled tubing string with a high-pressure noz-
bbl [175,000 m3] of oil and 979 MMcf [28 million CaCO3 scale could be a major source of damage. zle.21 This treatment, which stabilized iron and
m3] of gas, along with about 31,000 bbl [4,900 m3] Limited data were available to quantify the also removed CaCO 3 scale, was followed by
volumes of scale.

66 Oilfield Review
acetic acid to help remove additional CaCO3 and The complete treatment increased oil pro- illite-smectite mixtures. These clays can either
to provide a preflush for the final treatment, duction to 3,000 B/D [480 m3/d], 15 times the line or fill pore spaces.
which was a 9/1 organic mud acid.22 The Virtual pretreatment production rate. The water cut Conventional matrix acidizing—using mud-
Lab process provided a means to test the effec- increased slightly to 45%. After three months of acid and ClayACID treatments—was ineffective
tiveness of this treatment schedule. production, the well produced oil steadily at in restoring well productivity in this area.24 In
Reaction kinetic parameters were available 1,500 B/D [240 m3/d]. April 2002, Schlumberger used a new clay-
in the database. A core-flow test on a small plug The productivity increase was better than stabilizing acid in this field, a ClayACID formula-
from the Cromarty formation provided an esti- that predicted by the geochemical simulation. tion using an organic acid in place of the HCl. The
mation of mineral surface areas and parameters The model had assumed that the main cause of clay-stabilizing acid is designed to permanently
for the permeability and porosity correlation. damage was fines migration, but it is possible stabilize a formation containing high percentages
The test showed that treatment fluids were com- that the dominant damage came instead from of silt and clay, while minimizing secondary and
patible with the native mineralogy and that they CaCO3 scale or residual drilling and completion tertiary reactions. The treatment deposits a layer
increased permeability within the core sample. fluids. Real-time bottomhole-pressure readings of borosilicate glass that immobilizes the clays.
The next step was to simulate the reservoir and an analysis of the flowback fluids were not The formulation was successful in four of six
geometry using the Virtual Lab software. In this available. Had they been, the Virtual Lab simula- treatments, and the production increase was
simulation, damage was assumed to be due only tor could have estimated the contributions of stable for at least six months after treatment.
to fines migration. The model showed that well- the various damage mechanisms, further Nevertheless, a posttreatment analysis indicated
bore skin factor declined steadily with the improving future jobs in the field. that a better methodology for selecting candidate
treatment, and a small quantity of amorphous wells could yield improved results.
silica reprecipitated near the wellbore (below). Sensitive Clays in the Gulf of Thailand The second stimulation campaign, carried
A PLT Production Logging Tool run just Several fields operated by ChevronTexaco in the out in 2003, used the Virtual Lab software for
before the main stimulation treatment was ana- Gulf of Thailand have similar lithologies. The prestimulation analysis to improve results. The
lyzed in real time and indicated no production productive sandstone formations have HCl-sensi- geochemical model inputs included a mineral
from the gravel-packed channel sand. The first tive clays in proportions greater than 15%, and composition of 9% carbonate minerals, 18%
half of the productive interval beyond the shale the reservoir temperature exceeds 250°F clay—illite, mixed illite and smectite, kaolinite
section produced oil with a 50% water cut, and [120°C]. The formation also contains carbonate and chlorite—and 6% feldspar. The large propor-
the second half produced dry oil at a low rate. minerals.23 The primary damage mechanisms are tions of these minerals, in conjunction with the
Since water was not coming from an isolated swelling of smectite and other clays and migra- high reservoir temperature, make treatment
zone, it was not possible to stimulate oil produc- tion of clays such as kaolinite-illite and design difficult.
tion alone.
The first treatment stage was jetting a
chelating agent along the entire wellbore. This
stage mechanically cleaned the wellbore and
increased the oil production rate to 1,000 B/D 1.0
[160 m3/d] with a water cut of 40%. Flowback
after the treatment was slower than planned Critical matrix Treatment with shut-in
because of operational problems. A postjob Treatment without shut-in
Silica volume, %

Virtual Lab simulation showed that the effect of

Wellbore

this additional fluid-residence time was a small 0.5

increase in silica precipitation that would have
minimal effect on productivity.

19. Ziauddin et al, reference 12.

20. Relative permeability effects also can cause decreased
oil production with increased water production. It is the 0
combination of this effect and the pump-in tests that 0 0.5 1.0 1.5 2.0
support a conclusion of fines migration. Radius, m
21. A chelating agent stabilizes metal compounds, preventing
them from precipitating. > Model results for amorphous silica. The originally planned treatment using
22. An organic mud acid uses formic acid in place of HCl, organic mud acid produced less than 0.5% of amorphous silica, as a
so a 9/1 organic mud acid is 9% formic acid and 1% HF.
percentage of the formation volume, in the critical volume of the matrix near
23. Torres C, Ziauddin M, Suntonbura N, Xiao J and Tibbles R:
“Application of a Unique Clay Stabilizing Acid in the Gulf
the wellbore (green). Operational difficulties forced a delay in the flowback
of Thailand,” presented at the PetroMin Deepwater stage, so the model was rerun using the actual times. The silica deposited
Technology Conference, Kuala Lumpur, Malaysia, with this additional soak time was still small (blue).
July 14–17, 2003.
24. Torres et al, reference 23.

Spring 2004 67
 10 400
Damaged zone
8
300
Carbonate volume, %

6
Wellbore

Fluid

Skin
invasion 200
4 75 gal/ft 3.6 ft
100 gal/ft 4.2 ft
125 gal/ft 4.7 ft 100
2
150 gal/ft 5.2 ft 10% acetic- Clay-stabilizing acid NH4CI brine
acid preflush
0 0
0 1 2 3 4 0 50 100 150 200 250 300 350 400
Radius, ft Volume, gal/ft

> Optimizing treatment volumes. The geochemical model accounts for acetic acid spending, or weakening, as it interacts with formation carbonate
minerals. Far from the wellbore, the carbonate is 7% of the formation volume. The radius of formation that is cleaned of carbonate material is much smaller
than the invaded radius. Injecting 100 gal/ft [1.2 m3/m] of perforated height cleared carbonate to a greater radius than did a volume of 75 gal/ft [0.9 m3/m]
(left). However, additional injection did not significantly increase the cleared radius. Using a 100 gal/ft preflush, the model indicated an optimal treatment
using clay-stabilizing acid of 75 gal/ft (right). Beyond that quantity of injected clay-stabilizing acid, skin increased because permeability was destroyed.

The geochemical simulation tested pre-

flushes of both 10% acetic and 5% formic acid to
remove near-well carbonate minerals from the
formation. The two formulations provided simi-
500 5.0
lar skin reduction, so acetic acid was used
450 4.5
because it was more readily available at the
time. The model indicated the optimal preflush 400 4.0

volume and the optimal clay-stabilizing acid vol- 350 3.5

Gas production, MMcf/D

Oil production, B/D

ume (above). The simulation showed that the 300 3.0

borosilicate coating that stabilizes clays 250 2.5
extended about 1 ft [0.3 m] into the formation 200 2.0
with the optimal clay-stabilizing acid treatment, 150 1.5
but that additional clay-stabilizing acid did not
100 1.0
extend the protected zone significantly.
50 0.5
ChevronTexaco planned the second phase
0 0
of clay-stabilizing acid stimulations based on
B-1 B-2 B-3 B-4
optimized acid volumes from the Virtual Lab
simulator. Stimulation jobs on one oil-producing > Production improvement in Gulf of Thailand wells. Matrix acidizing increased
well and three gas producers were successful oil production in Well B-1 from 0 to 442 B/D [70 m3/d] (green). A comparison of
and showed significant production increases pretreatment (pink) and posttreatment (red) production from three gas wells
(right). This use of the new stimulation design also shows significant improvement.
process increased profitability from the stimu-
lated wells. The fluid system, customized for the
specific lithology in the Gulf of Thailand wells,
provided a lasting solution.

Reacting to the Future Determining formation mineralogy is an restricted to solving for matrix acidizing in
The new stimulation process, including the important first step in the process. If data such sandstones. The tool could be used for carbonate
Virtual Lab simulator, provides a tool to improve as the ELANPlus Elemental Log Analysis are acidizing, carbon dioxide sequestration and
well performance in sandstone formations. available, they can be used with the Virtual Lab water-compatibility testing. Schlumberger
Sandstone matrix acid treatments are complex, software. In addition, the growing databases for continues to expand the reaction database,
and the success rates are historically low. The geochemistry and flow properties will provide increasing the variety of problems that
new process with the software and proprietary more analogs for locations lacking core material. this geochemical software can solve for
databases as its basis assures a much higher The Virtual Lab software is a general- the industry. —MAA
ratio of successful matrix acid treatments. purpose geochemical simulator and is not

68 Oilfield Review