System to Loss fluid control

1. SPE 164580
Successful Field Implementation of a Novel Solids-Free System to Control
Fluid Loss during Overbalanced Workover Operations in Southern
Argentina
Julio Vasquez, Juan Bonapace, and Javier Gonzalez, Halliburton; Rodrigo Quintavalla, Pan American Energy LLC
Copyright 2013, Society of Petroleum Engineers
This paper was prepared for presentation at the North Africa Technical Conference & Exhibition held in Cairo, Egypt, 15–17 April 2013.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
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Abstract
During workover and completion operations, even a small overbalanced hydrostatic pressure can result in a significant loss of
fluid to the formation, especially in high-permeability formations. This situation becomes even more drastic in depleted
reservoirs, horizontal wells, or in zones that have been previously fractured and packed. Controlling fluid loss into the
formation is of critical importance during overbalanced workover operations to minimize near-wellbore (NWB) damage
invasion by the completion fluid, which can yield problems associated with poor wellbore cleanout and loss of hydrocarbon
reserves. In addition, fluid loss can increase costs associated with rig time and treatments devoted to restore the initial
condition of the formation. In many hydrocarbon fields in southern Argentina, controlling fluid loss before NWB cleanout
treatments is challenging because it can cause pressure differential sticking of the coiled tubing (CT) and/or inability to pump
the treatment into the desired interval. This paper presents the successful field application of a novel solids-free fluid-loss
(SFFL) system during wellbore cleanouts in the Cerro Dragon oilfield, which is located on the west side of San Jorge Gulf
(SJG) basin in the Chubut Province of Argentina.
The SFFL system relies on water-soluble polymer that decreases matrix permeability to aqueous fluids, limiting leakoff
into treated zones. This polymer immediately adsorbs to the surface of the rock, eliminating the need to shut the well in. In
addition, this system does not require the use of breakers or a cleanup stage to reestablish hydrocarbon production once the
workover operation has been performed. Laboratory test data show the capability of the material to control fluid leakoff and
achieve high levels of regained permeability to hydrocarbons. Traditional techniques to minimize fluid loss use solids or
viscous pills, although it has been amply documented that these systems can damage the formation if not properly removed
after the treatment.
To date, about 200 treatments have been performed with this novel SFFL system. The paper discusses field results from
the application of this system during overbalanced workover operations in Argentina, including the job design and post-
treatment results. This system has been proposed for returning partial and total loss to full circulation in overbalanced
operations, such as (1) lost-circulation events occurring during cementing, fracturing and drilling, (2) well intervention
cleanouts by CT and hydraulic workover (HWO), (3) gravel packing, (4) replacement of artificial lift equipment (i.e.,
electrical submersible pumps), and (5) overbalanced tubing-conveyed perforating (UTCP).
Introduction
Fluid-loss control has been long recognized as a major concern when determining completion costs and assessing well
management, thus the need within the oil industry for an effective fluid-loss-control method (mechanical devices or chemical
systems). Mechanical fluid-loss-control systems (installed downhole) include devices that can temporarily or permanently
block fluid flow into the formation. These mechanical systems can be separated into discrete devices or multicomponent
installations. The discrete devices are usually downhole valves or some type of plug that can be removed later during the life
of the wellbore. The multicomponent installations are completion systems designed to eliminate, or at least minimize, fluid
loss into the formation (Ross et al. 1999). The chemical methods can be further classified as linear gels, crosslinked gels, and
bridging particulate systems. Provided next is a brief general description of these chemical systems commonly used to control
fluid loss into the formation:
Linear gels are typically hydroxyethel cellulose (HEC), xanthan, and/or succinoglycan (Kippie et al. 2002).
These systems help reduce fluid loss to the formation by viscosity. These gels must enter the permeability of the

2. 2 SPE 164580
formation to develop the resistance to fluid flow. Linear gels do not completely stop fluid loss, but reduce the
rates to an acceptable level. In addition, linear gels require removal by either an internal breaker (a chemical that
breaks down the polymer chain) or by an external wash (i.e., acid treatment) (Ross et al. 1999).
Crosslinked gels are generally HEC derivative (Chang et al. 1998) or CMHEC-based systems (Cole et al. 1995).
They function by forming a filter cake at the formation or by entering the permeability of the formation and stop
losses by plugging the pore throats with the crosslinked, gelled structure. Similar to linear gels, crosslinked fluids
also require the aid of an internal or external breaker. However, in some cases, there is some degree of
permeability damage (depending on factors, such as polymer type and concentration, overbalance pressure,
permeability, and temperature, etc.) (Ross et al. 1999; Hardy 1997).
Bridging particulate systems allow fluid-loss control by having a range of particle sizes sufficient enough to
bridge on the pore throat and, with the smaller particulates, bridge on themselves to eventually form a relatively
impermeable filter cake. These particulate systems can be pumped as a slurry formed with a polymer-based
fluid. Most of these pills require an external wash with breakers, wellbore cleanout pills, or can be removed once
production is resumed.
The system described in this paper is a novel solids-free, noncrosslinked, low-viscosity system for fluid-loss control. This
innovative technology does not fit in any of the previously described chemical fluid-loss categories because the system relies
on a water-soluble polymer that decreases matrix permeability to aqueous fluids, which immediately limits leakoff into the
treated zones.
Description of the SFFL System
This solids-free, fluid-loss (SFFL) system uses a hydrophobically modified polymer that was initially developed for water-
control applications in hydrocarbon-producing wells (Vasquez, 2010). The polymer attaches to the surface of the rock
immediately as it encounters the formation face by simple electrostatic attraction. The polymer attached to the rock
diminishes the flow path of any aqueous-based fluid (i.e., completion brine, formation water, or acid) providing leakoff
control properties without significantly affecting the flow path of hydrocarbons. Treating solutions of the SFFL system
exhibit low viscosity, typically less than 2 cP. The hydrophobic modification of the water-soluble polymer allows multiple
layers of the polymer to build up because of the association of the hydrophobic groups, as illustrated in Fig. 1.
Fig. 1—SFFL system base polymer: the hydrophobic modifications allow the polymer to build up on the rock surface because of the
association of the hydrophobic groups.
As previously published (Eoff et al. 2003, 2004), numerous laboratory tests have demonstrated the capability of the SFFL
system to reduce water-effective permeability with little or no effect on hydrocarbon-effective permeability. In many of the
early tests, when this system was injected into cores, a rapid pressure increase was observed. This led to the conclusion that
this kind of chemistry might function as a diverter for water-based fluids (Eoff et al. 2003) and also as a fluid-loss-control
agent. Fig. 2 illustrates the typical pressure increase observed when pumping the SFFL system into a core, and, in this case, a
carbonate core was used. In this test, the following sequence was used: water – oil – water – SFFL – water. The evaluation
water was API brine (9% NaCl and 1% CaCl2), and evaluation oil was kerosene. Fig. 2 shows the water stage before the
SFFL treatment and the SFFL treatment stage. Note that the water-stage flow rate was 10 mL/min, while the SFFL-treatment
flow rate was 2 mL/min. Even with this lower flow rate, the differential pressure across the core increased rapidly from 200
to more than 500 psi when the SFFL treatment began entering the core.

3. SPE 164580 3
Fig. 2—SFFL system: immediate pressure buildup during the treatment stage (carbonate core at 175°F).
Following this, additional tests were conducted examining specifically the capability of the polymer to provide fluid-loss
control. Leakoff tests were performed in several different types of setups, including the use of cylindrical and hollow cores.
Fig. 3 shows results for leakoff through a more standard set up. In this test, the filter medium was an approximately 1-in.
thick layer of 70- to 170-mesh sand. As shown, this system provides excellent leakoff control when compared to fresh water
under the same conditions. Based on this test and many others not reported in this publication, it was concluded that the
SFFL system was able to provide excellent and immediate leakoff control properties for aqueous fluids in numerous
applications and yet would not damage hydrocarbon permeability.
Fig. 3—SFFL system: leakoff test through 70- to 170-mesh sand.
Fig. 4 illustrates a core flow test designed to mimic a leakoff situation in a well in which fluid is lost to the formation
followed by oil production from the same zone. In this test, regained permeability to water and oil were evaluated using an
aloxite core with the following test sequence: water – oil – water – SFFL system (1 PV injected at 500 psi) – water – oil. The
evaluation water was API brine (9% NaCl and 1% CaCl2), and the evaluation oil was kerosene. The test was conducted at
120°F. The second water stage mimics a situation where brine is leaking off into a particular zone, followed by a treatment
with the SFFL system. In this case, the treatment was pumped in at a constant differential pressure, rather than at a specific
rate, which seems to better mimic a real-life scenario. Following the treatment, brine was once again pumped through the
core, mimicking that wellbore fluid might continue to leak off, although now at a lower rate than before the treatment. The
treatment resulted in 96% reduction to water permeability (4% regain), illustrating that some measure of leakoff control was

4. 4 SPE 164580
obtained. This was maintained for two days following the treatment. After this stage, oil flow was resumed and resulted in
95% regained oil permeability.
Fig. 4—SFFL system regained-permeability test (2,000 ppm SFFL at 120°F).
Case Histories—Southern Argentina
Field Description. The Cerro Dragon is a sandstone oilfield that belongs to the SJG basin and is located in southern
Argentina, as Fig. 5 illustrates. The SJG basin has an irregular shape with greater east-west elongation, having its main
development in the onshore part (65%) and the rest in the offshore area. Its genesis is of an extensional type in the Mesozoic
age; the main filling occurred in a stage of rifting from the late Jurassic to early Cretaceous period, and the nature of the
sediments is predominantly lakes and rivers. The hydrocarbon traps are mostly combined (sedimentary and structural). Sand
bodies have thicknesses of 2 to 10 m, with porosities varying from 17 to 27%, decreasing in depth, and permeability values
fluctuate. In general, permeability values average 50 md. The Cerro Dragon area is located on the western flank of the SJG
basin. The Cerro Dragon field has been under development and exploitation since 1959; therefore, it is considered a mature
and depleted reservoir with marginal oil production. The field is currently under waterflooding.
Fig. 5—Cerro Dragon field geographic location.

5. SPE 164580 5
Workover Campaign Description. Throughout the productive life of Cerro Dragon field, production decline was observed
in many wells attributed to obstruction of perforations, scale generation, fine-sediment production, deposition of organic
material (asphaltenes and paraffins), and/or water blocking, etc. To sustain production over time, several alternatives have
been employed to maintain or increase oil production and decrease water production. Some typical workover interventions
performed to increase hydrocarbon production in this field are: (1) hydraulic fracturing (approximately 800 treatments per
year), (2) matrix acidizing treatments, (3) adding new perforations, (4) isolation of water production intervals with
mechanical packers, cement, or conformance treatments, (5) reperforation of the same pay zone to overcome scale deposition
NWB damage, and (6) artificial lift equipment repair (Bonapace et al. 2011).
The Cerro Dragon field consists of approximately 30 different units. A workover stimulation campaign was implemented
in four marginal and mature units with two main objectives: cleaning casing of scale or paraffin deposition and NWB
formation damage removal. Intervention cost was one of the main drivers in this campaign because of the wells’ marginal oil
production in this depleted mature field. Considering the background and characteristics of this type of reservoir
(multilayered) as well as the low availability of workover equipment, CT was employed in this campaign. Additionally, a
fluid oscillator tool (FOT) was used at the end of the CT to enhance the effect of the stimulation treatments. The FOT creates
pulsating pressure waves within the wellbore and formation fluids. These pressure waves can help break up NWB damage
and restore the permeability of the rock. The FOT generates an oscillation frequency range of 300 to 600 Hz (Webb et al.
2006). Typically, these wells have an average of six perforated intervals, which significantly increases the risk of
encountering fluid loss to the formation during workover interventions because of the high degree permeability and depletion
contrast among the perforated intervals. This type of NWB stimulation campaign with CT was implemented as a low-cost
alternative to hydraulic fracturing because of the unavailability of a workover rig. In addition, the budget was another
constraint.
During the first stage of this workover campaign, 35% of these wells showed significant circulation problems caused by
significant fluid loss to the formation before the main treatment. Most of these jobs with circulation problems resulted in no
incremental fluid production (oil or water); therefore, these treatments were considered unsuccessful. Because of the
circulation problems encountered, it was decided to implement the SFFL system in subsequent treatments. Two of those
treatments are presented in this paper. A typical workover intervention consisted of the following sequence:
Rig in with CT unit to TD and perform circulation test (back side was open to receive returns to surface). If
formation losses were present, a fluid-loss control pill was deployed until full circulation was regained or at least
losses were decreased to an acceptable level.
Perform casing cleanup treatment.
Perform NWB matrix formation damage removal treatment.
Fluid-loss control agent: The SFFL system was used to control fluid loss into the formation before the casing cleanup
treatment and the NWB formation damage removal treatment. The SFFL treatment was pumped in stages (5- or 10-bbl pills)
until losses were decreased to an acceptable level.
Casing cleanup treatment: The objective of this treatment was to remove any type of scale or paraffin deposition in the
tubulars before injection of the NWB stimulation treatment in the matrix of the rock. Volumes varied according to the
thickness of the intervals to be treated. The casing cleanup treatment was a solvent-based solution consisting of the following
components: aromatic solvent, mutual solvent, paraffin inhibitor agent, paraffin removal agent, and a dispersant. The back
side was open to receive returns to surface.
NWB formation damage removal treatment: These treatments were designed to remove NWB (2- to 3-ft radial
penetration) formation damage and were pumped at matrix rates. An average volume of 17 gal/ft of perforation was used.
Laboratory testing performed on scale samples revealed that a solution consisting of 10% HCl and 5% mutual solvent could
be implemented as an optimum formulation. This formulation was also combined with a corrosion inhibitor, surfactant, clay
stabilizer, iron control agent, and a pH buffering agent. This formulation was used for Well 1. For Well 2, the HCl acid was
omitted.
Case History 1. Well 1 is a cased-hole and perforated oil producer (5 1/2-in. casing and 2 7/8-in. production tubing). Fig. 6
illustrates the wellbore diagram. This well had eight perforated intervals from 4,762 to 6,142 ft, a gross interval of 1,408 ft
with 53 ft of net perforations. The treatment was intended to mainly stimulate only five intervals by reciprocating the CT unit
at these depths (Fig. 6). The workover intervention was designed as follows:
CT unit was rigged in to total depth (TD). A circulation test was performed resulting in intermittent circulation.
The pumping rate was increased, yielding similar fluid-loss rates to the formation. A 5-bbl SFFL pill was
deployed using CT. Once pumping was resumed, full circulation was regained immediately.
Once the losses were controlled, 47 bbl of the solvent-based treatment were deployed for casing cleanup.
Approximately 75 bbl of brine were recirculated in the wellbore back to surface to remove any type of residue
created by the first treatment.

6. 6 SPE 164580
Once the wellbore had been cleaned out, 22 bbl of another solvent-based treatment were injected into the
formation, followed by 22 bbl of an acid solution for NWB stimulation.
Once these last two treatments were in place, the well was circulated out once again with CT and was put back in
production with the goal of recovering all the fluids pumped as quickly as possible.
.
Fig. 6—Well 1 wellbore schematic.
As Fig. 7 illustrates, the workover intervention positively affected the decline curve of the well with an increase in oil
production while maintaining the level of water production, making this treatment an economic success.

7. SPE 164580 7
Fig. 7—Well 1 production history before and after workover intervention.
Case History 2. Well 2 is a cased-hole and perforated oil producer (5 1/2-in. casing and 2 7/8-in. production tubing). Fig. 8
illustrates the wellbore diagram. This well had 10 perforated intervals from 2,117 to 2,936 ft, a gross interval of 819 ft with
95 ft of net perforations. The treatment was intended to mainly stimulate nine of these intervals by reciprocating the CT unit
at these depths (Fig. 8). It is important to mention that seven out of these nine intervals were previously hydraulically
fractured, making the fluid-loss-control environment even more challenging. The workover intervention was designed as
follows:
The CT unit was rigged and run in hole to TD. A circulation test was performed, resulting in no circulation to
surface. The pumping rate was increased, resulting again in total fluid loss. A 10-bbl SFFL pill was deployed
using CT. Once pumping was resumed, full circulation was regained immediately.
Once full circulation was achieved, 30 bbls of the solvent-based treatment were deployed for casing cleanup.
Approximately 40 bbls of brine were recirculated in the wellbore back to surface to remove any type of residue
created by the first treatment.
Once wellbore had been cleaned out, 60 bbls of another solvent-based treatment were injected for NWB
formation damage removal.
The well was then circulated out once again with CT and put back in production with the goal of recovering all
the fluids pumped as quickly as possible. Fig. 9 shows the pumping chart for this workover intervention.
As Fig. 10 illustrates, the workover intervention positively affected the decline curve of the well by increasing oil
production by almost twice as much. This treatment was considered successful.
Subsequent to these treatments, the SFFL has been commonly used in other workover interventions in this field to control
fluid loss. Considering the marginal production of these oil producers, the SFFL provides a cost-effective alternative to
control losses due to its simplicity of deployment and because no cleanup stage is required to reestablish production.

8. 8 SPE 164580
Fig. 8—Well 2 wellbore schematic.

9. SPE 164580 9
Fig. 9—Well 2 workover intervention pumping chart.
Fig. 10—Well 2 production history before and after workover intervention.
Conclusions
The following conclusions are a result of this work.
This SFFL system is a low-viscosity solution that does not rely on solids or viscosity to provide fluid-loss
control. It immediately decreases formation permeability to aqueous fluids, limiting leakoff into the rock matrix.
This system selectively decreases formation permeability to aqueous fluids without significantly affecting
hydrocarbon permeability.
This system does not require a breaker or shut-in time.

10. 10 SPE 164580
Based on the workover campaign performed in the Cerro Dragon field, the SFFL provides a cost-effective
alternative to control losses attributed to its simplicity of deployment and because no cleanup stage is required to
reestablish production.
This system has successfully restored partial and total losses to full circulation in overbalanced operations, such
as (1) lost-circulation events occurring during fracturing, (2) well-intervention cleanouts by CT and HWO, (3)
gravel packing, and (4) replacement of artificial-lift equipment (i.e., electrical submersible pumps).
To date, about 200 jobs have been performed with this novel SFFL system during overbalanced workover
operations and other applications where maintenance of a hydrostatic column is necessary for well control.
Nomenclature
API brine 9% NaCl and 1% CaCl2
CaCl2 Calcium chloride
CT Coiled tubing
FOT Fluid oscillator tool
NaCl Sodium chloride
NWB Near-wellbore
SFFL Solids-free fluid-loss system
SJG San Jorge Gulf basin
Acknowledgements
The authors thank Pan American Energy LLC and Halliburton for support and permission to publish this paper.
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