IPTC 16545-MS

Field Implementation of Condensate Bank Removal Using Chemical Treatment Bander N. Al Ghamdi, Bandar H. Al-Malki, Adnan Al-Kanaan, Zillur Rahim, and Hasan D. Al-Anazi, Saudi Aramco Oil Company

Copyright 2013, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26–28 March 2013. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax +1-972-952-9435

Abstract

Productivity of gas-condensate wells decrease as bottomhole pressure drops below dew point and condensate starts

accumulating surrounding the wellbore. The deliverability of gas-condensate reservoirs is controlled by transport properties,

mainly capillary pressure and relative permeabilities between the fluids in a pore-scale. When condensate drops out in the

reservoir, the relative permeability to gas decreases and affects the flow rate.

The productivity of gas-condensate reservoirs can be effectively enhanced by creating hydraulic fractures to reduce draw-

down pressure near wellbore. This helps maintaining the flowing bottom-hole pressure above dew point and consequently

delays condensate accumulation. In rich gas reservoirs where condensate to gas ratio (CGR) is high, it becomes challenging

to keep the pressure above the dew point. Other approach to enhance relative permeability to gas is by altering the system

wettability and making it preferential to gas flow. Recently, a chemical treatment was developed by 3M company (3M) in

collaboration with the University of Texas at Austin (UT) to remove condensate banking effect. The treatment fluid was

tested in the United States and showed promising results.

In this work, Saudi Aramco participated with 3M and the University of Texas Austin to implement a field trial of the

chemical treatment on one of Saudi Arabian gas wells that declined in productivity over its production life due to sever

condensate banking. The treatment aimed to enhance the relative permeability of the least-wetting phase of the fluids in-

place and reduce the effect of condensate-banking was successfully pumped in the candidate well. The initial results of the

field implementation demonstrated a significant improvement of gas flow rate and a simultaneous increase in the flowing

wellhead pressure.

Key results were consolidated with a Pressure Build-up Test conducted six months later, proving effectiveness of chemical

treatment on reducing condensate saturation, increasing relative permeabilities to gas, and modifying wetting conditions to

make it preferential to gas, which significantly enhances recovery from such high CGR gas reservoirs.

Introduction

Gas-condensate fluids are mixtures of hydrocarbon molecules that are initially present as a gaseous phase at reservoir

conditions. During the depletion of the reservoir fluids as the reservoir pressure falls below the dew point pressure, the liquid

phase comes out of the single phase hydrocarbon. When the pressure crosses the dew point pressure, the bonding between

the light components and heavy components of the single phase fluid in the reservoir are weakened causing a split between

the light and heavy components (Ahmed, 2000). The result of the split enhances the bonding among the heavy components

and makes it stronger forming condensate. The condensate thereby keeps accumulating until a maximum liquid dropout is

reached. The condensate accumulation takes long time before it reaches the critical condensate saturation allowing the fluid

movement. During this time, reduction in gas flow is sensed and is directly reflected on the production performance.

For a typical gas-condensate reservoir, the water is the most wetting phase and the condensate is the least wetting phase,

while the gas is always considered the non-wetting phase (Fanchi, 2006). In most cases, the porous medium is considered to

be wetted by condensate and very little quantity of naturally occurring water film inside the pores. Once condensate appears

2 IPTC 16545-MS

in the reservoir, the condensate and gas will start to compete for flow paths. As two immiscible fluids come in contact with

each other, a discontinuity in pressure occurs at the interface resulting in imbalance forces (Ahmed, 2000). The difference in

pressure depends on the curvature separating the two fluids, and is referred to as the capillary pressure. Gomes et al. (1992)

confirmed that the capillary forces depend on the interfacial tension between gas-oil systems, and the geometry and

dimensions of the porous network.

In a reservoir with pressure above dew-point pressure the fluids-in-place are in its gaseous form; the situation is different near

the wellbore where pressure is low due to production. Figure 1, is a schematic of the near-wellbore region where multiphase

flow occurs as the bottom-hole pressure reaches below dew-point pressure. In this situation, the fluid distribution depends on

the wettability of the rock and the adhesiveness to a particular phase of fluid. Since liquids constitute the most wetting phase,

the gas flow highly depends on the amount of fluid filling the pore spaces and chemistry of that fluid.

Another fact about the near-wellbore region is the reduction in the relative permeability due to the condensate dropout, which

makes it difficult for the fluids-in place to flow. The condensate accumulates until it reaches the condensate critical

saturation before it starts moving at a flowing velocity that depends on viscosity and composition of the condensate. The

accumulation period usually is not known, and it depends on the size of the envelope below the dew-point curve of a typical

phase behavior chart, that represents the amount of liquid drop-out to be expected. This period could range from days to

several years depending on the concentration of heptane-plus components as opposed to the lighter components such as

methane and ethane. Generally, reservoirs are assumed to be stacked-matrices as shown in Figure 2, a concept that was

introduced by Warren and Root (1963), to depict the behavior of the complex system of the fractured reservoir. In this

model, the condensate will accumulate first in the edges of the stacked-matrices causing a reduction in the productivity of the

in-situ fluids. Between 40 and 80% of productivity could be lost because of this phenomenon (Ayyalasomayajula et al.

2003). Even in the cases of lean gases with liquid drop-out of around 1-2%, the flow performance near the wellbore could be

severely impacted due to the increase in condensate saturation (Boom et al, 1996).

The depletion is highly dependent on the thermodynamic behavior of the fluids in place and the exchange of energies

between the fluids. In addition, the deliverability of gas-condensate reservoirs is controlled by transport properties, the

relative permeabilities and capillary pressure, and the wetting characteristics. The overall recovery of such reservoirs is

highly dependent on the changes of compositions and the concentration of the heavier components.

Attempts to enhance the performance of gas-condensate reservoirs subject to condensate banking have been many; some of

which consist of gas cycling, hydraulic fracturing, drilling horizontal wells, and using methanol as a treating solvent. All of

these trials have had some success but sometimes limited. For example; pressure can be maintained about dew-point

pressure using gas-cycling but studies have indicated that many times it is economically not feasible especially in reservoirs

that are already below dew-point pressure (Aziz, 1983). Mohan (2005), Wang (2000), and Dhane (2000), suggest that

common approaches are to go with either hydraulic fracturing or drilling horizontal wells. These methods increase reservoir

contact and enhance flow area but at the same time create channels where pressure drops during to production and becomes

prone to condensate accumulation. In the case of using methanol as a solvent, researcher have found that methanol

reestablishes the production performance by increasing liquid vaporization rate but appeared to be effective only for a short

period of time (Al-Anazi et al., 2007).

Current studies have focused on changing transport properties and wettability characteristics since they are the primary

control factors of the flow of fluids in two-phase conditions. The use of chemical treatments to alter wettability and favor gas

flow over liquid has showed promising results (Li and Firoozabadi, 2000). Investigations continued to test various chemical

and the effect on improving transport properties. Using a synthetic gas-condensate fluid, Kumar et al (2006) found that using

a fluoromonomer such as fluorsurfactant can enhance relative permeability by a factor of 2.

In the absence of chemical treatment, reservoirs showing higher relative permeability meets either or both of the following

conditions; higher capillary number accompiend with higher permeability zones, and/or lower condensate critical saturation

(Kumar, 2006). Vital results, point out that lowering condensate effect is highly dependent on the reduction of condensate

saturation, increasing relative permeabilities, and favoring wettability toward gas-wetting conditions.

The goal of this paper is to review current implementation of condensate bank removal using flurosurfactant and

consequently increasing flow of gas and condensate by enhancing transport properties and altering rock wettability.

IPTC 16545-MS 3

Treatment Candidate

In the selection of a candidate for the trial treatment, several criteria were considered. Reservoirs with high CGR are the best

to evaluate the trial test, since most of these reservoir experience a reduction in production due to condensate blockage. The

study considered one of the fields containing high CGR of about 300-500 stb/MMscf. This field experiences production

impairment as a result of the condensate dropout and blockage.

The selection criteria for the well included the following:

– Liquid-wet reservoir favoring liquid flow

– Liquid drop-out above 10%

– Permeable rock allowing injecting the treatment fluid

– Limited number of layers

– Mechanical integrity of the wellbore

– Surveillance data

Several wells were carefully selected based on condensate blockage, reservoir formation, permeability, water saturation,

reservoir pressure, fluids characterization, and dew point pressure. After thorough analysis, Well-A was Selected as the

candidate that met all the treatment criteria and reservoir conditions.

Well-A was drilled as a gas development well in January 2003 and worked over in the same year and completed as a vertical

Frac&Pack producer. The well was put on production in October 2003 with an initial gas rate of 20 MMscfd at a flowing

wellhead pressure (FWHP) of 4,535 psi. The well rate declined with time and later in 2009, an attempt to flow the well

through a test separator during a deliverability test failed. The well was experiencing severe rate and pressure loss due to

condensate blockage. Consequently, the well was chocked down and restrained at a producing rate of about 5 MMscfd.

Well-A was thoroughly analyzed and evaluated with proper data and simulation model. Analysis of pressure build-up (PBU)

tests on Well-A confirmed that a near wellbore treatment could be used although some data were masked by fluid

segregation. Experimental work on the selected core samples was conducted and used in the University of Texas laboratories

to confirm the applicability of the chemical treatment. The relative permeability of gas to liquid was measured before and

after the treatment. Results showed increase in gas relative permeability compared to condensate indicating that gas is

expected to move faster after the treatment. Simulations runs were performed that showed a significant increase of gas and

condensate flow.

Laboratory Experiments

Significant amount of work was done to design the apparatus and experimental procedures to pre-evaluate the chemical

treatment on a core sample from the selected well. The experimental procedures were designed to measure the change in

relative permeabilities of the fluids before and after the chemical treatment injected in the core. The aim of this approach is

to trigger the movement of the gas over the liquid by reducing the adhesiveness of the liquid to the rock. The experimental

treatment confirmed reduction of the condensate critical saturation. The condensate accumulation was lesser and both

condensate and gas flowed through the network much easier.

The experiment starts by obtaining a core sample from the selected well and injecting a pre-flush of methane until steady

state is reached to introduce initial water saturation and measure gas permeability. To mimic reservoir conditions, a synthetic

gas-condensate was injected in the core which was mixed to create a two-phase fluid. The condensate accumulates with time

and reduces the relative permeability to gas. After reaching steady state condition and collection of data, the pseudo pressure

method was applied to evaluate the relative permeabilities in the core at reservoir temperature and pressure.

Afterward, about 20 pore volumes of surfactant treatment solution injected into the core to alter the rock conditions, 24 hour

shut-in time was applied to assure complete interaction between the treating fluid and the rock. Subsequently, the synthetic

gas-condensate sample was injected in the core to measure the relative permeabilities after the treatment in order to estimate

effectiveness and evaluate changes in flow mechanism.

Field Implementation

The chemical treatment procedure designed in collaboration with 3M was to ensure the effective placement of the treatment

in the well. The procedure incorporates a low pressure pumping of the treatment fluid followed by nitrogen flush. PVT and

liquid samples were obtained to evaluate the effect of the treatment on the well performance. Based on the condition of the

candidate well, the treatment started with 253 bbls of 3M pre-flush fluid, 900 bbls of the main treatment fluid (isopropyl

4 IPTC 16545-MS

alcohol), and approximately 29,000 gal of N2 displacement fluid.

The chemical treatment was pumped at 1-2 bpm while not exceeding bottom-hole pressure. Detailed steps of the treatment

procedure are described next.

1. Obtained pre-treatment production data and fluid samples.

2. Pump 253 bbls of 3M pre-flush fluid at 1-2 bpm after ensuring no fluid in the wellbore.

3. Pump 900 bbls of 3M chemical treatment fluid (isopropyl alcohol) at 1-2 bpm.

4. Check to ensure the volumes were accurately injected by checking the tanks volumes.

5. Displace treatment from tubing to the perforations with nitrogen at pressure below fracturing pressure.

6. Shut in the well for 12 hrs. to allow the chemical interact with the formation.

7. Overflush with the treatment with nitrogen in order to displace the treatment further in the formation. A total of

29,000 gal of N2 was pumped in the well.

8. The well was shut-in for 12 hours after the second nitrogen overflush to allow further interaction with the formation.

9. Open the well for production.

10. Obtain fluid samples every day during the flow back period.

11. Gather production flow rates through separator.

12. Return the well to production after nitrogen content was out of gas stream.

13. Return the well to pre-treatment choke settings to compare performances.

To capture the effectiveness of the treatment, data were collected to verify the change in performance and compositional

content of the return fluid. The most important data needed for the evaluation are production rate and fluid samples before

and after the treatment. A 3-phase test separator was connected to collect flow data before the test. In addition, gas-

condensate samples were collected daily before and after the treatment to conduct PVT and chromotogrophical analysis.

These samples also served as an indicator for the presence of the active chemical and solvent in the samples to prove the

absorption of treating chemical in the formation.

Results

Table 1 shows the relative permeability parameters before and after the treatment. These values were measured to indicate

the change in relative permeability of the fluids as a result of the chemical treatment. Comparing the pre and post values

indicated that the relative permeability values of both the gas and condensate have increased, indicating that both fluids will

have more tendencies to flow. Figure 3 shows an increase in gas relative permeability by a factor of 2. It is apparent that the

wettability and the adhesiveness of the rock to the liquid have been reduced, favoring gas over liquid phase. Figure 4

presents a schematic of the effect of the condensate treatment inside the pores. The treating chemical consists of an active

chemical (treatment solution) and carried by a solvent. The active chemical is a non-ionic polymeric fluorinated surfactant

that is non-reactive, but interacts with the medium under reservoir conditions to alter the wettability of the surface. The

solvent (isopropyl alcohol) influences the bonding to the surface of the rock. Once the treating chemical settles inside the

pores, it ties itself and creates a flow tunnel to ease the flow of gas and condensate by reducing the wettability and the critical

saturation of the condensate.

The reduction in the critical condensate saturation is represented by Figure 5 suggests less blocking of condensate.

Moreover, the effect of the treatment is also proven by the increase in the productivity index shown in Figure 6.

Influenced by the promising results of the experimental treatment, a field implementation was carried on after the verification

process has been proven by Saudi Aramco using cores from the candidate well. As per the designed protocol, the treatment

started with 253 bbls of 3M pre-flush fluid, 900 bbls of the main 3M treatment fluid (isopropyl alcohol), and approximately

29,000 gal of N2 displacement were pumped into the well in order to assure the displacement of chemical treatment further

inside the formation.

After the final 12 hours shut-in period, the well was opened to flow while monitoring the flowing wellhead pressure (FWHP),

bottom-hole pressure (BHP), gas rate, and condensate rate. The well was opened to choke size 16/64” and beaned up until

FWHP reached around 2000 psi. The well was then connected to a test separator to capture actual flowing rates to assess the

success of the treatment.

Figure 7 shows the performance of the well after the treatment. The increase of FWHP at the beginning is the result of the

shut-in period after pumping the final N2 behind the treatment. The two following spikes in the FWHP are a result of the

capillary effect between the fluids flowing toward the production channels; the pressure increases when liquid pushes gas,

and reduces when liquid is pushing liquid. At the two-phase flow period, a steep increase in the gas and condensate rate due

IPTC 16545-MS 5

to beaning up the choke size. Once stabilization was reached and the well was connected to the test separator, stable rates

and FWHP were measured. Table 2 shows the flow rates and FWHP before and after the treatment. A significant

improvement in the gas and condensate rates and the FWHP was observed. There was a gain in gas rate by 75%, condensate

rate by 300%, and FWHP by 90%.

Separator and liquid samples were collected every day to preform PVT analysis and study the gas and condensate reservoir

fluids. Figure 8 reflects the gas-chromatography (GC) from the PVT analysis. It indicates an increase in the content of N2

since a great amount was pumped after the treatment as flush fluid. Overall, the recovered samples indicate an increase in the

composision of the heavy components. This means the treatment caused the heavy components flow instead of staying

behind.

The chemical treatment was analyzed to verify the presence of the treatment solution in the samples retrieved. The report

analyzes how much of the solvent has been retrieved compared to how much of the active chemical was left behind in the

formation. The report indicated the following:

1. A large portion of the treatment solvents were quickly produced back within the first 3 days after the treatment.

2. Around 97% of the active ingredient remained in the formation after the first days.

3. The results are consistent with 3M’s experience in other treated wells, where more than 85% of the active ingredient

remained in the formation after the treatment.

In view of that, the initial results, PVT analysis, and the reservoir fluid evaluation, indicate an improvement in the gas-

condensate production and FWHP. Close monitoring of the well performance was essential to examine the lastability of the

effect of chemical treatment.

Six months later, a pressure build-up (PBU) test was carried on the well at different rates with a test separator. The results as

indicated by Figure 9, reflects an improvement in reservoir response in oppose to a pre-treatment PBU, which indicates that

the condensate banking was partially removed. It is very difficult to compare the post and pre PBU tests thoroughly, since

the quality of data for the earlier PBU was quite unreliable due to the constant variation in rate, which is attributed to the high

condensate banking effect resulting in frequent changes in bottom-hole pressure.

The results still indicate skin damage due to the condensate blockage suggesting another chemical treatment for further

enhancement. However, the initial results were maintained at the same gain rate in comparison to the pre-treatment

performance proving the success of the 3M chemical treatment. Thus, it is highly encouraged to implement the same

technology on other wells suffering condensate blockage.

Conclusion

In gas-condensate reservoirs, the release of condensate near the production channels and wellbore region impairs the

productivity and reduces the overall flow of fluids to the surface. The accumulation of condensate reduces the relative

permeability to gas.

Recent techniques to enhance relative permeabilities of the fluids in-place by altering the wettability to increase the flow rate

of fluids have been studied. A chemical treatment was developed by 3M in collaboration in collaboration with Saudi Aramco

and the University of Texas at Austin to remove condensate banking effect, which was tested in the United States and

showed good results.

In this work, Saudi Aramco has participated with 3M and the University of Texas Austin to implement a field trial of the

chemical treatment on one of the development wells with high CGR. The initial results of the field implementation were

reported in this paper which demonstrated a promising improvement in gas flow rate and an increase in the flowing wellhead

pressure.

Key results indicate the following:

– An increase in transport properties of both oil and gas (Kro and Krg)

– A decrease in Sor and Sgr.

– Promising results showing the effectiveness of treatment, with favorable gas flow.

– An increase in gas rate by 75%, condensate rate by 300%, and FWHP by 90% was obtained.

Close monitoring of the well while flowing through a test separator was carried at the end of 6 months period after the

treatment which assured the higher gas rate is sustainable. In addition, the PBU results indicated improvement of near

6 IPTC 16545-MS

wellbore reservoir characteristics. Based on the results of the evaluation period, implementation of the chemical treatment

will be considered to mitigate condensate-banking problems on other candidate wells with high CGR and declining

productivity.

Nomenclature

Krg = Gas relative permeability

Kro = Oil relative permeability

Sor = Residual oil saturation

Sgr = Residual gas saturation

Acknowledgments

We would like to extend our gratitude to our counterparts in 3M and the University of Texas for their extended support and

research work to make this project a successful one. Our sincere appreciations goes to Gas Production Engineering

Department, EXPEC-ARC, and Well-Services Operation of Saudi Aramco for their excellent and safe execution of the

designed trial-test.

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IPTC 16545-MS 7

Table 1—Parameters of treatment

Relative Permeabilities & Saturations

Pre-treatment Post-treatment

Swr 0 0

Sor 0.3 0.15

Sgr 0.25 0.1

Kro 0.3 0.55

Krg 0.45 0.7

Table 2—Table of results

Pre-Treatment Post-Treatment

Gas Rate

(MMscfD) 1.5 2.7 + 75 %

Condensate

(Bbl) 240 1030 + 300 %

FWHP

(psig) 1700 3196 + 90%

Fig. 1—A schematic of the near-wellbore region flow

Fig. 2—Representation of stacked-matrices (after Warren

and Root, 1963)

Fig. 3—Gas relative permeability improvement

Fig. 4—Schematic of the effect of chemical treatment on the

pores’ integrity

Fig. 5—Critical oil saturation improvement

8 IPTC 16545-MS

Fig. 6—Productivity index improves significantly

Fig. 7—Performance of the well throughout the treatment

Fig. 8—Gas chromotographical analysis

Fig 9—PBU test results after the treatment

0.01 0.1 1 10 100 1000Time [hr]

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