SPE 95010

Chemical Water Shutoff Interventions in the Tunu Gas Field: Optimisation of the
Treatment Fluids, Well Interventions, and Operational Challenges
P. Chenevière, Total; P. Falxa, Total Indonesia; J. Alfenore, SPE, Total; D. Poirault, Total Indonesia; and P. Enkababian,
SPE, and K.S. Chan, SPE, Schlumberger

Copyright 2005, Society of Petroleum Engineers

them, pointing out the need for finely filtered fluids, low
This paper was prepared for presentation at the SPE European Formation Damage viscosity fluids and robust selective placement tools.
Conference held in Scheveningen, The Netherlands, 25-27 May 2005.

This paper was selected for presentation by an SPE Program Committee following review of
information contained in a proposal submitted by the author(s). Contents of the paper, as
Introduction
presented, have not been reviewed by the Society of Petroleum Engineers and are subject to The Tunu field operated by Total Indonesia is a north-south
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Society of Petroleum Engineers, its officers, or members. Papers presented at elongated structure of 80 km long in the shallow swampy
SPE meetings are subject to publication review by Editorial Committees of the Society of
Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper
outer edge of the Mahakam delta region of East Kalimantan. It
for commercial purposes without the written consent of the Society of Petroleum Engineers is is a giant field of approximately 70x20x25 km size.
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KERINDINGAN

NON T.I. FIELDS MELAHIN

Abstract ATTAKA SERANG

Several Indonesian gas fields such as the Tunu field exhibit a SEMBERAH SANTAN

specific behavior which causes a rapid decrease of the gas BADAK

SA
LIK
production. At shut in conditions, cross-flows from watered LAMPAKE
IP
SC

out layers to gas producing layers, were clearly identified as TUNU

M
NILAM

KA
EXPAN
EXPAN

HA

AH
the major cause for gas production impairment. SANGA-SANGA

MA

NG
TE
The offloading of water from wells is performed at TAMBORA
SISI
the preliminary stage of water production and often allows PAMAGUAN

restarting the wells, but in a second stage it is ineffective. The MUTIARA

HANDIL
SENIPAH BEKAPAI
NUBI

nature of the damage in the gas-producing zones is not entirely SAMBOJA

understood but it seems to be a combination of at least two PECIKO

phenomena: (i) water adsorption on the high amount of clays

present in these highly water sensitive layers (15 to 40 wt %)
WAILAWI
BALIKPAPAN W
AK
MAHAKAM RA
SEPINGGAN SE

and (ii) water imbibition due to some capillary pressure YAKIN SEMANLU
KALIMANTAN

experienced in the tightest layers (0.1 to 10 mD). Clay S. MAHAKAM

swelling or migration seems also to contribute for this damage

but to a lesser extent.
Unwanted water along with gas and condensate
Reservoirs are multi layers of unconsolidated sandstones
production from several layers were quantified from multi-rate
composed of 80-90% quartz plus clays (Kaolinite, Illite): see
PLT, to define a strategy for well candidate selection and
Figs 1 and 2. Pay zones, of 1 to 30 m thick, have Kh ranging
water shut off interventions. An inorganic gel was then
from 50 to 3000 mD (permeability is approximately in the
selected to be selectively squeezed into the water-producing
range between 1 to 100 mD). There are different reservoir
layers. The optimization of this fluid and of the preflush fluid
connectivities and different pressure regimes (lateral –
required a complete qualification program which aimed at
vertical).
three main objectives: (a) maintain injectivity during the
This specific structure has led to the identification of 62 layers
squeeze to allow an entire placement of the fluid, (b) provide,
and 400 geological pressure units1. There is no evidence that
once set an extrusion pressure sufficient to withstand a
any of the 62 layers defined by the deltaic flooding cycles are
significant drawdown and (c) gives a treatment’s lifetime of
vertically connected. Many of the mature producing reservoir
one year minimum.
layers are at low pressure today; but the presence of certain
Three wells were treated in 2004, following the
over-pressured intervals producing water means that water
qualification of the fluids, the selection of candidate wells and
control is essential. The field is produced for more than 14
the implementation of a complete treatment setup on a barge.
years and 199 wells are producing, 70 wells are dead and 5
This article describes the successes and the failures of some of
temporary shut in. Today, it is estimated that, if no specific
2 SPE 95010

action is taken, approximately 7% of recovery will be lost constraints. The targeted layers for WSO are often
because of water production and associated damage. intermediate layers with heights exceeding the longest patches
The production scheme is commingled but 40% of the net pay available, e.g. approximately 10 meters. Two patches cannot
is still not perforated. Reservoirs are depleted and the access to be set easily and efficiently on the same interval. In addition,
the completion is limited to preserve the gas production rate, restrictions of internal diameter caused by the installation of
because of sand production and water production risks. The casing or tubing patches, do not permit additional mechanical
current strategy on existing wells is to continuously add isolation in lower zones. These constraints are obviously more
perforations, but delaying them to acquire data. or less severe, depending on the well configuration and the
Even with all these precautions, there are concerns about the localization of the watered-out layer. In the Tunu field, many
wells because of severe water-related productivity watered out layers are positioned in the upper part of the pay
impairments resulting from 5 potential causes: zone, which is not favorable to mechanical WSO solutions.
By the end of year 2003, Total Indonesia planned a
• Insufficient water lifting (Vertical Lift
preliminary campaign of chemical WSO interventions, which
Performance curve).
targeted about 10 candidate wells with limited risks. The
• Shut-in related damages induced by cross flow candidate selection involved both the contractor and Total
between reservoirs. Indonesia, in a partnership which went on with the other steps
• Formation of water/condensate blocks or/and of the qualification process.
water/condensate emulsions in slightly tight gas
reservoirs. Selection and optimization of the WSO treatment
• Formation damage due to clay sensitivity fluids
(migration, swelling) to lower salinity from The selection and optimisation of a WSO fluid adequate for
upper formation waters the Tunu formation was one of the main challenges because of
• Scaling, caused by the mixing of incompatible the strong sensitivity of the rock matrix to various fluids used
reservoir waters during cross flow. in well stimulation. For years, this sensitivity has limited the
number of well interventions because of unexpected, rapid and
severe loss of injectivity, which was frequently observed
Tunu is also a challenging field in term of well interventions, during various types of squeeze treatments: previous WSO,
because of reservoir complexity, depth, temperature, acidising, injectivity testing for example. It is worth to note
permeability, and matrix sensitivity to water. that failures happened in spite of the precautions (inhibited
By early 2004, the status of the field in term of water fluids, compatibility tests) taken for sensitive formations with
production was the following: there is a large population of a high clay content.
watered out wells (44% have a WGR > 5%), which are Because a previous WSO intervention had been performed in
immediate candidate for WSO intervention because they are year 2002 with the Delayed Gelation System² proposed by the
either dying or dead (40-50 wells). Approximately 50 contractor, and resulted in a partial success (Tunu-A30 well),
producing units (reservoir layers) are producing each more it was decided to select the same fluid and to improve it for
than 100 bwpd, 30 are present in wells equipped with further interventions.
monobore completion strings and 20 in wells equipped with Therefore, the Delayed Gelation System was improved to
“standard” completion strings (see Figs. 3 and 4). satisfy the following criteria:
Today, 40 to 50 interventions are envisaged. All of the
• Full compatibility with rock matrices from the
selected wells produce less than 10 MMscftd gas production,
targeted zones, in Tunu reservoir conditions
60% of them produce less than 5 MMscftd and 75% of them
(260-280 °F).
produce less than 2 MMscftd.
• Water-like viscosity, to allow the treatment of
zones with a permeability range in between 1 to
Currently, three types of interventions are either performed or
100 mD.
planned in the Tunu field:
• Sufficient extrusion pressure, to withstand a
• Mechanical or Chemical Water Shut Off minimum of 3000-3500 psi drawdown.
(performed): Patch, Bridge plug, Gel + Cement
squeeze). To meet these requirements an inorganic fluid3, 4, the Delayed
Gelation System was submitted to an extensive qualification
• Water Block/emulsion remedial treatment
programme. In the course of the qualification, fluid injectivity
(planned) by cleaning damaged gas layers with
and extrusion pressure were progressively improved, which
the help of solvent-based fluids.
required a complete reengineering of the WSO fluid. In
• Water Block Prevention (planned) by squeeze of addition, it was decided to add a final step to the WSO
liquids repellent chemicals, to protect gas layer treatment, with a squeeze of a micro-cement, in the
of new-drilled wells against future water blocks. perforations of the treated interval. The objective was to
ensure the setting of the Delayed Gelation system in the rock
The need for chemical WSO treatments is mainly related to matrix and improve the shut off of the interval.
well configurations, development strategy and field
SPE 95010 3

The Delayed Gelation System formulated delayed gelation system. The result implied that
This system was selected for deep reservoir formation low pH environment caused by the presence of acid could
penetration and plugging, primarily because of its reduce and further impede the initial gel aggregation and
comparatively higher injectivity for the tight reservoir particle size growth. Figure 10 shows also a comparison of
formations. gel fluid permeability during injection for injection sequence
with or without an organic acid preflush
Figure 5 shows the initial viscosity of a high concentration
formulation as a function of temperature. The solution was Filtration of all fluids involved in the treatment and the use of
prepared using synthetic formation brine. At the reservoir organic acid preflush were then recommended for treatment of
temperature of 260 oF, the apparent viscosity is about 0.4 cP. this tight shally sandstone. Following these tests, it was
The viscosity remains low until the gel started to set. Figure 6 verified that the extrusion pressure obtained with this sequence
shows a typical right angle set behavior. The gel working time of fluid injection was satisfactory.
is the time when the fluid viscosity starts to increase
drastically. Micro-cement
Compatibility testing between micro-cement and the Delayed
Upon reservoir heating, the fluid can undergo a series of
Gelation System showed that although the high pH of the
physicochemical changes. The pH of the fluid increases
cement would accelerate the DGS, the contaminate cement
gradually from about 4. Closer to the set time, the pH
slurry was not significantly affected. A 3bbl fresh water spacer
approaches 5.5 and its turbidity increases. When gel sets and
was pumped on each treatment to prevent early gelation of the
turns into a solid mass, the viscosity measurement using
DGS in contact with the cement while still in the coiled
conventional rheometer cannot be performed. Figure 7 shows
tubing.
the nature and state of the solid gels for an optimized
formulation. With time increases, the solid gel will continue
WSO interventions
to change. Solid mass continues to condense and expel some
Three candidates wells: TN-A33, TN-A31 and TN-E13, were
excess water. The working time and gel state can be adjusted
selected on the basis of Multi-Rate Production Logging
and optimized depending on treatment pumping and water
(MRPL) or Single-Rate Production Logging (SRPL)
shut-off performance requirement.
interpretations.
More than 27 reservoir core plugs were prepared and used to
evaluate the injectivity of various fluids involved in the • TN-A33 has a monobore completion and water is
treatment. These cores generally had low Nitrogen gas produced from an intermediate perforated interval
permeability ranging from 0.2 to about 300 mD. Their liquid P200 (4148-4158 m MD).
permeability was much lower. Figure 8 shows as an example, • TN-A-31 has a monobore completion and water is
a step-rate injectivity test using synthetic brine and a produced from the top perforated interval N201
composite core plug (3.28” in total length) having Nitrogen (3239-3248.5 m MD).
gas permeability of about 3 mD. The test results implied that • TN-E13 has a monobore completion and water is
the formation rock contain significant amount of silts and fines produced from the top perforated interval O200
but the brine permeability can still be determined as about 1.5 (3425.5-3427.5 m MD).
mD using the step-rate injection method. However, the
observed brine injectivity was extremely low and was at about Only the WSO intervention performed on TN-A31 is
0.01 ml/min/psi. described hereafter.
Subsequent tests for the Delayed Gelation System yielded
even lower injectivity and the observed injectivity continued General characteristics of the WSO treatments
to decrease as more gel volume was injected. Additional The three interventions were conducted using a 1.3/4 in.
studies revealed that both the synthetic brine and the Coiled Tubing for TN-A33 and a 2.3/8 in. Coiled Tubing for
formulated Delayed Gelation System fluid contain very fines TN-A31, TN-E13, in a similar way, as summarized below (see
particles with sizes ranging from 0.2 to 200 µm. For the Fig. 11):
Delayed Gelation System, the particle size could even grow as
the fluid is approaching the gel setting time. • Isolate the lower part of the targeted interval, by setting
a millable bridge plug, cover it with cement.
Figure 9 shows a series of injecting tests with the filtered gel • Set a millable cement retainer above the targeted
fluids prepared by various degree of filtration. Constant interval
injectivity can be maintained for fluids filtered by 0.5 and 2 • Run in hole the coiled tubing equipped a stinger to
µm filter papers. stab into the retainer.
For the Delayed Gelation System, an organic acid preflush can • Squeeze the treatment fluids and end up by squeezing
further enhance the injectivity of the gellant. Figure 10 shows few barrels (2-3) of micro-cement in front of the
a typical core flow test at 260 oF temperature, simulating the interval.
proposed pumping procedure. The core was first saturated • Unstab the coiled tubing packer and pull out of hole
with synthetic brine. The injection sequence entailed an to surface.
organic acid preflush with a brine spacer before injecting the • Drill out the retainer, cement and bridge plug, offload
the brine with nitrogen to re-start the well.
4 SPE 95010

The first treatment was placed with a tension set packer set on penetration) in the watered N201 reservoir and the prevention
coiled tubing instead of the millable cement retainer. of post squeeze cross flow. Although the packers and cement
Limitations in terms of available weight when at bottom and had to be subsequently milled out, the bridge plug / retainer
the possibility of cross flow after the gel placement for the combination were identified as the most conservative
subsequent 2 treatments led to the redesign of the treatment approach to ensure that the adjacent gas layers would not be
using the millable retainer. damaged by cross flow. Other options such as straddle packers
and CT run retainer were rejected due to risks related to depth
Treatment design correlation and post squeeze cross flow.
The following rules were used for the design of the treatment
volumes: N201 Reservoir and Treatment Parameters
• Organic acid preflush: its volume was estimated from • Reservoir position: top layer with open intervals
the amount of carbonate present in the 6 feet around below.
the wellbore and the dissolution capacity of the acid. • Top perforation 3239.0 mMD
• KCl spacer volume: Designed to flush the acid away • Bottom perforation 3248.5 mMD
from the gel, its volume was based both on the reel • Perforated length 9.5 m
volume (no gel is pumped until injectivity has been • Net pay 8.8 m
established) and a 1 foot separation in the matrix. • Porosity 22.2 %
• Treatment Volume was deduced from treatment • Bottom hole static pressure 2815 psi
depth (WSO fluid), which was calculated from both • Bottom hole static temperature 244 °F
the determined gel resistance to extrusion pressure
(350 psi/ft) and considering a maximum drawdown of Injectivity Data
3500 psi in the treated layer. A volume of 200 gal/ft • Injectivity Index (estimated) 1.82 bwpd/psi
of Delayed Gelation System was used.
• Drawdown 855 psi
• Micro-cement: the volume was estimated from bailed • Darcy Permeability (skin = 0) 22.2 mD
cement top, target top of cement and estimate of the
leak-off.
Fracturing Limitations
• Fracturing gradient estimate 0.63 psi/ft
Stimulation setup
• Fracturing BHP 5931 psi
To achieve a satisfactory fluid quality, it was decided to
improve and adapt the initial stimulation setup on board the • MABHP (500 psi safety) 5431 psi
stimulation barge. Series filtering was implemented and it was • MAWHP 968 psi
constituted of coarse filter bags followed by two D.E.
(Diatomaceous Earth) filters in parallel (alternate functioning) Operational Sequence
and followed by two pods of filtration with 2µm cartridges: The operational sequence of events depicted in Fig. 14 is
see Fig. 12. summarized below:
In addition, a specific attention was given to the mixing water
used for preparing the fluids, to avoid the excessive • Stab the 2.3/8 in. Coiled Tubing stinger into the
consumption of filtering material (diatomaceous earth). The composite cement retainer (A)
water well used to provide the mixing water was disqualified • Pressure up the CT/tubing annulus with 500psi to
and another one was recommended, along with a QC confirm isolation. (B)
procedure before delivering the mixing water to the barge. The • Re-circulate and control the quality (QC) of the
QC procedure was based on a turbidity measurement, which is fluids.
a qualitative method frequently used because it is easy to run, • Pump 30bbl of acetic acid preflush. (C)
thereby allowing frequent testing. However, a gravimetric • Pump 50bbl of 6% KCl spacer.
analysis is a more accurate method, which, with experience, • Perform injectivity test
can be correlated with turbidity measurements. After a good • Pump 139bbl of DGS.
correlation was achieved, turbidity measurement was used to • Place 1.9bbl of micro-cement and 3bbl FW
estimate mg/L solids in all fluids. spacer in the Coiled Tubing. (D)
The quality control was implemented to verify that all brines • Displace the cement with 6% KCl brine. (E)
are filtered to achieve less than 5 NTU of turbidity. The fluid • Squeeze the micro-cement. (F)
quality was continuously monitored by sampling, both • Unstab stinger from composite packer and pull
upstream and downstream from the filters. Laboratory the Coiled Tubing to surface. (G)
personnel was trained to use the hand held turbidity meter,
which was available on board the stimulation barge. TN-A31 treatment evaluation from well Test and daily
production data
WSO of the N201 watered out layer of well TN-A31
The treatment on TN-A31 well (see completion string in Fig. Daily production data
13) was designed with 2 objectives: the accurate placement of The raw data (see Fig. 15) seems to indicate that the WGR has
approximately 140 bbl of Delayed Gelation System (7ft risen back to pre-job level. It must be noted however that the
SPE 95010 5

PLT was done after the well was shut-in for several days. Post Table 1. Comparative pre and post production data of treated
wells
offload PLT often indicate higher levels of WGR than
Production data Production data % reduction of
stabilized data. Today (January 2005), the WGR has returned before treatment after treatment the Water
to pre shut-in level, i.e., approximately 500. Well
production

Log Comparison and Interpretation 3 mmscftd Not restarted

TN-A33 -
500 bwpd yet
N201 – watered zone: from the examination of the open hole 7 mmscftd 4.7 mmscftd
log, 3 zones were identified (see Fig. 16): TN-A31 65%
6000 bwpd 2100 bwpd
1-2 mmscftd 0.64 mmscfd
TN-E-13 77%
• A tight top zone (higher Vsh, lower porosity, 200 bwpd 45 bwpd
shallower filtrate penetration)
• A middle zone. Data indicated in Table 1 were obtained at the test separator,
• A clean bottom zone (lower Vsh, higher porosity, approximately one month before treatment and three months
deeper filtrate penetration) after the treatment, respectively.
Gas producing layers of TN-A31 and TN-E13 wells, were
In both pre and post log, the top zone (20% of the interval) undoubtedly impaired from subsequent milling with water and
does not produce water (not temperature and capacitance potential water damage from crossflows with lower intervals.
effect). In both logs, the middle section (35%) produces water Both wells required an offloading with nitrogen, to evacuate
(temperature and capacitance effect). water from the well and expel part of the water from the gas-
For the bottom section (45%), the 2 logs are different. On the producing layers. With time, the two wells also regained some
pre-treatment log (see Fig. 17), the bottom section contributes gas production from self-cleaning but a residual damage was
to the flow as both the temperature and capacitance are clearly remaining.
affected when the tool is facing the zone. On the post-
treatment log (see Fig. 18), both the temperature and the Operational Challenges
capacitance are not affected anymore when the tool is pulled Several important operational issues appeared progressively
across this section. This would indicate that this part of N201 during the WSO interventions:
has been shut.
N205 gas zone, positioned below the N201 interval, was not • Several Coil Tubing packer failures, because of
producing post-treatment. This may be caused by water lack of robustness and inadequate design.
damage from the subsequent milling operation. This may also • Impairment of gas producing layers caused by
be because the well was not fully cleaned up when the post the water pumped to allow the milling of cement
treatment log was performed. Neither the pre-treatment nor the and bridge plug.
post-treatment logs were multi-rate PLT. Single rate PLT can • Limited time access to the wells, because of
neither give a correct estimation of reservoir pressures nor of simultaneous operations in the neighbourhood.
the extent of the depletion. The fact that gas production
doubled after the log may indicate that the N205 gas- Conclusions
producing layer, had cleaned-up part of the water that cross Three Chemical Water Shut Off interventions were conducted
flowed into it during well shut-in. in the Tunu field in 2004, which can be considered as partly
effective, on a technical viewpoint. Several lessons have been
TN-A31 well status after the WSO intervention learnt from these operations:
The treatment appears to be a partial success with
approximately half of the producing interval being shut off. • Watered out formation layers from Tunu
N201 had an 8.8m pay height. This height is significant and formations have been treated with an inorganic
the placement of the gel on the entire interval might not have Delayed Gelation System, with a satisfactory
been excellent. injectivity all along the injection time.
Injectivity being one of the major concerns during this • Partial water shut off has been obtained, but was
campaign, no diversion was used and it is possible that most of accompanied by gas production impairment,
the gel entered the bottom zone leaving the middle zone with a essentially because of post-interventions in wells
limited penetration radius. Under the high drawdown pressures with water (milling) and subsequent shut-in.
exerted on the well after the treatment, the insufficient amount • Partial water shut off is probably resulting from
of gel placed in the middle section could have gradually failed the presence of significant permeability contrasts
leading to the production of water from N201. The usefulness in the treated intervals.
of the micro-cement is at stake. The micro-cement on its own • This paper shows key factors in implementation
can not be used as a shut-off treatment as it is very likely that (injectivity and coverage, brine / fluid
subsequent milling (vibrations) affects the cement nodes and displacement and pumping procedure) for
bonds. achieving the success of the WSO treatment.
• Placing the WSO treatment at 4500-5000 meters
Results of the WSO treatments depth represents a challenge for placement tools,
Results of these interventions are summarized in Table 1. whose robustness has to be improved.
below.
6 SPE 95010

• There is a strong need for a robust and reliable 5. Boussa, M.: “Production Optimization of Gas Wells: Problem of
squeeze straddle packer, to allow the sequential Water Influx”, SPE 86942, California (2004).
treatment of several watered out zones in the 6. Susilo, Y.; Hendarwin; Wibowo, W.; Tobing, B.L.; Arbai, I.;
Hendra, Y.S.: “Thru-Tubing Zonal Isolation and Water Shut-Off
same well (multi-setting).
Utilizing Coiled Tubing in the Java Sea: Operational Challenge
& Treatment Strategy”, SPE 88013, Malaysia (2004).
Future work 7. Susilo, Y.; Wibowo, W.; Hendarwin, Tobing, B.L.; Arbai, I.;
To improve the efficiency of the water shut off treatments and Hendra, Y.S.: “Thru-Tubing Zonal Isolation and Water Shut-Off
lower the risk related to water circulation in the well5, several Utilizing Coiled Tubing in the Java Sea”, SPE 89613, Houston,
actions have been initiated: Texas (2004).

• Placement tools: improvement of the current squeeze

packer and the search for a complete squeeze straddle packer,
are both on going6, 7.

• Diversion: the use of chemical diversion is risky as too

much diverter could lead to the blocking of the entire interval.

• Hesitation squeeze: hesitation squeeze would consist of

squeezing slowly two third of the WSO treatment and then
wait until the tip of the treatment which entered the high
permeability zone, viscosifies. Once this happens, the rest of
the treatment can be squeezed in the lower permeability zone.

• Gel Strength: from recent improved laboratory testing it

seems that the Delayed Gelation System needs to be improved
in term of gel strength. This would allow to treat several
intervals in one well without squeezing the micro-cement over
each interval and would ease the use of a multi-setting
squeezing tool.

Acknowledgment
The authors acknowledge Total Indonesia and
Schlumberger Indonesia for the permission to publish this
paper. These operations could not have been carried out
without the active participation of Total Well Services, Well
Performance (K. Orski) and Reservoir management (R.
Gauchet) teams. The authors would also like to thank all the
operators and supervisors involved in these treatments as well
as the laboratory personnel involved in the validation of the
treatment design.

Nomenclature
Vsh shale fraction; %

References
1. Ferment, D.; Gautama, Y.; Rourke, M.; Guergueb, N.; Singh, J.:
“Downhole Formation Fluid Identification in a Mature Multi-
Layer Reservoir: A Case Study of an Advanced Wireline
Formation Tester and Operational Practices for Highly Depleted
Reservoir Evaluation”, SPE 88634 Australia (2004).
2. Kabir, A.H.: “Chemical Water & Gas Shutoff Technology – An
Overview”, SPE 72119, Malaysia (2001).
3. Fragachan, F.E.; Cazares-Robles, F.: “Controlling Water
Production In Naturally Fractured Reservoirs With Inorganic
Gel”, SPE 35325, Mexico (1996).
4. Lakatos, I.; Lakatos-Szabo, J.; Tiszai, Gy.; Palasthy, Gy.;
Kosztin, B.; Trömböczky, S.; Bodola, M.; Patterman-Farkas,
Gy.: “Application of Silicate-Based Well Treatment Techniques
at the Hungarian Oil Fields”, SPE 56739, Houston, Texas
(1999).
SPE 95010 7

Figure 2: Densely packed authigenic kaolinite restricting pores.

Illite and partially developed quartz overgrowths are also
recognized. plug sample Tunu E-2 (depth 4032.18m)

Figure 1: Typical example of core from the Tunu pay zone

8 SPE 95010

standard
1.60

1.40
4 1/2” TUBING
1.20

(c P )
9 5/8” CASING

is c o s it y cp
1.00
ZONE #1

VViscosity,
0.80

0.60

ZONE #2 0.40

0.20

3 1/2” TAIL PIPE 0.00

ZONE #3 0 50 100 150 200 250 300

Temp (deg F) °F
Temperature,
7” LINER
Figure 5: Viscosity versus Temperature for the Delayed Gelation
System formulated using a synthetic formation brine.

Figure 3: Standard Completion String

6 70
monobore Viscosity pH 60
5.5
50

V is c o s it ycp
5 40

Viscosity,
pH

4 1/2” TUBING 4.5 30

20
9 5/8” CASING 4
or 10
7” CASING 3.5 0
0 5 10 15
Time,
Timehour
(hour)
Figure 6: Viscosity change with time for a typical delayed gelation
system, showing a right-angle set behavior.
4 1/2” CASING

Figure 4: Monobore Completion String

SPE 95010 9

10
none
none
0.5-micron
0.5-micron
2-microns
5-microns
5-microns
1

/ K(brine)
K(DGS)/K(Brine)
K(DGS)
0.1

Figure 7: Nature and state of the solid Dellayed Gelation System,

once gelled, for an optimized formulation. 0.01
0 5 10 15 20 25 30 35
Pore Volumes
Pore volumes
4 350
Figure 9: Measured permeability ratio between the Delayed
Permeability (mD) Gelation System and the synthetic brine using filtered fluids.
3.5 300
Injection Rate (ml/min)
Differential Pressure (psi)

3
Differential Pressure (psi) 250
Permeability (mD)

100
Rate (ml/min)

2.5
200 No Organic Acid Preflush
2 With Organic Acid Preflush

150 10
1.5
(Dm D )
y , ym mD

100
1
Permeability, b ilit

1
P ePr emrema eb ailit

0.5 50

0 0
0 10 20 30 40 50 60 70 80 90 100 0.1

Pore Volume
Figure 8: Determination of a proper core injection rate for
evaluation of reservoir core injectivity. 0.01
0 2 4 6 8 10 12 14 16 18 20
Pore Volume
Pore volumes

Figure 10: Injection permeability comparison for injection

procedure with and without organic acid preflush.
10 SPE 95010

Figure 11: Schematic of the WSO treatment sequence with the Delayed Gelation System followed by the micro-cement

Sampling Point
Low Pressure Line Well
High Pressure Line

CoiledTubing Reel

Header Tank 3 Header Tank 2 Header Tank 1

25-
microns
Cement Mixing
pre- Twin Pump Unit
Tub
filtration
pods

Batch Mixer
Manifold

Crane
Nitrogen Tanks Pedestal

DE unit and 2- Figure 13: TN-A31 completion string

micron Filtration
Pods Nitrogen Converter

Figure 12: Water Shut Off setup and equipments on board the
stimulation barge.
SPE 95010 11

500 10000
G
CT pressure (psi) F
Pump rate (lpm)
WHP (psi)
400 8000

WHP (psi) / CT weight (kg) / CT depth (m)

CT weight (kg)
CT Pressure (psi) / Pump rate (lpm)

CT depth (m)

300 6000

A D E
200 4000
C

100 2000

0 0
18:00 19:00 20:00 21:00 22:00 23:00 0:00 1:00 2:00
Time, hours

Figure 14: TN-A31 WSO treatment pumping chart

25.00 1200
Gas Rate (Daily)
Gas Rate (welltest)
WGR (welltest)
WSO intervention 1000
20.00

800
Well offloading with Nitrogen
15.00

WGR after offloading 600 N201 layer

10.00

400

5.00 Figure 16: Open Hole log of the N201 layer.

200

0.00 0
1/1/2004 4/1/2004 7/1/2004 10/1/2004 12/31/2004

Fig 15: Well Test and Daily Production Data.

12 SPE 95010

Fig 17: Pre treatment PLT raw data.

Fig 18: Post treatment PLT raw data.