Mititigation of the Effect of Condensate Banking- A Critical Review

Mitigation of the Effects of CondensateBanking: A Critical Review

Mohammed A. Sayed, Aramco Services Company, and Ghaithan A. Al-Muntasheri, Aramco Services Companyand Saudi Aramco

Summary

With production from gas/condensate reservoirs, the flowing bot-tomhole pressure of the production well decreases. When theflowing bottomhole pressure decreases below the dewpoint, con-densate accumulates near the wellbore region and forms a con-densate bank. This results in a loss of productivity of both gas andcondensate, which becomes more serious in intermediate- andlow-permeability gas/condensate reservoirs, where the condensatebank reduces both the gas permeability and the well productivity.

Several techniques have been used to mitigate this problem.These methods include:

• Use of solvents and wettability-alteration chemicals toreduce the impact of condensate blockage

• Gas cycling and injection of nitrogen and supercritical car-bon dioxide as pressure-maintenance methods

• Drilling horizontal wells, hydraulic fracturing, and acidizingto improve the well productivity

Gas cycling aims to keep the reservoir pressure greater thanthe dewpoint pressure to reduce the condensation phenomena.The limited volumes of gas that can be recycled in the reservoircan hinder the application of this method. For an ideal gas-cyclingprocess, the volume of the gas injected into the reservoir will belarger than the total gas that can be produced from such a reser-voir. Other approaches are the drilling of horizontal wells and hy-draulic fracturing, during which the pressure drop around thewellbore region is lowered to allow for a longer production time,with only single-phase gas flow to the wellbore. These approachesare costly because they require drilling rigs. Another technique isthe use of solvents, which shows good treatment outcomes, butthe durability is a questionable issue in these treatments. More-over, wettability alteration needs to be approached very carefullyso as not to cause permanent damage to the reservoir. The use offluorinated polymers and surfactants dissolved in alcohol-basedsolvents for wettability-alteration treatments was reported inmany studies.

Each method has its own advantages and disadvantages, andcan be applied under certain conditions. This paper presents all ofthese methods, along with their advantages and disadvantages anddescription of some of their field applications and case studies.

Introduction

Gas/condensate reservoirs are very important because they con-tain large volumes of gas reserves that are critical to the increasedworldwide demand for energy sources. The Arun field in Indone-sia, the Cupiagua field in Colombia, the Karachaganak field inKazakhstan, the North field in Qatar, and the Shtokmanovskoyefield in Russia are examples of the largest gas/condensate reser-voirs in the world (Miller et al. 2010).

During the production life of the wells drilled in condensatereservoirs, the reservoir pressure declines isothermally from itsinitial value (Pi) to the upper dewpoint pressure (P2). As thisoccurs, liquid begins to condense in the pore space (Kniazeff and

Naville 1965; Gringarten et al. 2000; Hashemi et al. 2006). Thiscondensation process continues with decreasing pressure until theliquid dropout reaches its maximum at point pressure (P3) (Point3 in Fig. 1).

When production takes place from condensate reservoirs, andas the reservoir is depleted, pressure becomes less than the dew-point, liquid condensate starts to form, and the productivity ofwells often decreases rapidly. This could also affect investmentsin condensate-processing facilities (Havlena et al. 1967). Waterblocking is also a possible problem in gas reservoirs (Engineer1985; Cimolai et al. 1993). Among the main reasons to have sucha water-banking problem is the expansion of the connate water(Engineer 1985) or water production from the water-bearinglayers within the reservoir or even the presence of a water-bearingformation structurally connected to the gas reservoir (Engineer1985; Cimolai et al. 1993).

Compositional models were used to study the phenomena ofcondensate banking and its impact on the productivity of wells(Fussel 1973; Hinchman and Barree 1985; Clark 1985; McCainand Alexander 1992; Novosad 1996). These models showed thatthe liquid condensation and accumulation around the wellboreresults in a reduction in gas permeability and in a significantdecline in the production rates of wells (Hinchman and Barree1985; Clark 1985; Barnum et al. 1995; Ahmed et al. 1998). Bar-num et al. (1995) found a dramatic decline in the production ratesand hence reduction in gas recovery for wells with a permeabil-ity-thickness product of less than 1,000 md-ft. Takeda et al.(1997) claimed that gravity force and interfacial tension are im-portant factors in determining the relative permeability, and hencethe buildup of condensate, around the wellbore.

Barnum et al. (1995) reported that the higher the well capacity(well capacity is the kh product, where k is the rock permeabilityand h is the reservoir thickness, and is a measure of the reservoirquality), the less the impact of the condensate banking on theproductivity of wells drilled in condensate reservoirs. Simulationand laboratory studies have indicated that condensate saturationaround the wellbore may reach 70% (Marokane et al. 2002).

The reservoir region around the wellbore of a gas/condensatereservoir (Fig. 2a) can be subdivided into three or four regions(Marokane et al. 2002):

1. Single-phase gas flow far from the wellbore, where thepressure is still above the dewpoint.

2. Single-phase gas flow with the presence of low condensatesaturation (less than the residual or critical liquid satura-tion). In this region, liquid condensate is immobile andstarts to form condensate bank.

3. Two-phase flow (gas and liquid) occurs. This is the regionclose to the wellbore, where the liquid saturation is nowabove the critical values, and the liquid is able to flow inaddition to the gas.

4. Immediately beside the wellbore, where the high gas veloc-ity leads to decreased condensate saturation and increasedgas mobility through velocity stripping (Fevang and Whit-son 1996; Kalaydjian et al. 1996; Ali et al. 1997; Hendersonet al. 1998).

Fig. 2b shows the change in the pressure profile in the forma-tion and the different regions around the wellbore. Relative per-meability data in the second and third regions are the key factorsin determining the maximum productivity of the well. The radiusof the fourth region is neglected with respect to the liquid-bank

Copyright VC 2015 Society of Petroleum Engineers

This paper (SPE 168153) was accepted for presentation at the SPE InternationalSymposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 26–28February 2014, and revised for publication. Original manuscript received for review 2 June2014. Revised manuscript received for review 3 February 2015. Paper peer approved 5February 2015.

PO168153 DOI: 10.2118/168153-PA Date: 26-March-15 Stage: Page: 1 Total Pages: 18

ID: jaganm Time: 14:18 I Path: S:/3B2/PO##/Vol00000/150009/APPFile/SA-PO##150009

2015 SPE Production & Operations 1

region. Condensate and water banking will cause a reduction inthe well productivity, which in turn will affect both the economicsand the gas recovery.

Several methods have been studied to mitigate the problem ofcondensate banking in the region around the wellbore in gas/con-densate reservoirs. These techniques can be classified as follows:

• Chemical-injection techniques, such as the use of solvents,inhibited diesel, and inhibited dry gas, and wettability-alter-ation chemicals, which can be used to reduce the impact ofcondensate blocking in gas wells.

• Pressure-maintenance techniques, including gas cycling andinjection of carbon dioxide and nitrogen. These techniquescan be used to increase the reservoir pressure and to improveliquid recovery through reducing the liquid dropout.

• Productivity-improvement techniques, which may includedrilling horizontal wells, hydraulic fracturing, and matrix

acidizing, with a combination of two or more of the preced-ing techniques.

Some of these techniques depend on the increase in the vis-cous force, allowing better sweep efficiency and, therefore, highercondensate recovery (Boom et al. 1996; Li and Firoozabadi2000b). Methods such as the use of solvents depend on reducingthe interfacial tension (Ali et al. 1993), while the use of wettabil-ity-alteration chemicals depends on the change in the rock wett-ability (Li and Firoozabadi 2000a), as a remedial procedure forthe condensate-banking problem. The productivity-improvementtechniques depend mainly on creating higher-permeability flowpaths (wormholes or fractures) or increasing the contact areabetween the reservoir and the wellbore (horizontal drilling) toreduce the pressure drop and enhance the well productivity. Liq-uid loading can be problematic if liquid accumulates in the frac-tures or in the created wormholes, and this may affect the gasproductivity. A summary of these techniques is presented in Fig. 3.The main goal of the current study is to describe the different tech-niques used to overcome the water- and condensate-banking prob-lem that occurs in wells drilled in gas/condensate reservoirs. Theadvantages and disadvantages of each technique will be high-lighted. The paper shares advantages and disadvantages, case stud-ies, and field applications related to each method.

Drilling Horizontal Wells

Horizontal wells were drilled as early as 1927, and the majorthrust of drilling horizontal wells started in 1980 (Joshi 2003).Horizontal wells will create a larger contact area between the res-ervoir and the well, which can improve the productivity of thewell by reducing the pressure drop around the wellbore. As aresult, horizontal wells can delay the problem of condensate andliquid banking in gas/condensate reservoirs. Horizontal wells min-imize the occurrence of condensate banking by increasing the pro-ductivity index (PI), and therefore providing a remedial solutionto such a problem. The longer the length of the horizontal section,the less the drawdown. Horizontal wells are usually produced athigher rates than vertical wells. As a result, the pressure drop willbe higher, but it will be distributed over a larger area. Horizontal

Region 1: Single-phase gas

Region 2: Single-phase gasat low condensate saturation

Gas andliquid flow

Liqu

id b

ank

Liquid at residual saturation

(a)

(b)

Gas flowonly

Region 3: Two-phase flow

Region 4: Two-phase flow withreduced condensate saturation

Pwf

Pdew Pav

rw re

Fig. 2—(a) Regions around the wellbore of a well drilled in a gas/condensate reservoir [modified after Marokane et al. (2002)]; (b)pressure profile in the formation and the different regions around the wellbore.

Temperature

Separator

Dewpo

int l

ine

Dewpo

int l

ine

Two-Phase Region

G

C% Liquid

Pressure pathin reservoir

Retrograde gas

Criticalpoint

5

0

10

1520

3040

3

2

1

4

Pre

ssur

e

Tct

Fig. 1—A typical phase diagram of a retrograde system (Ahmed2006).



2 2015 SPE Production & Operations

wells will help reduce the impact of condensate banking on theproduction of gas from gas/condensate reservoirs, but it will notprevent the accumulation of liquids in the region around the well-bore. This section will proceed by simulation studies, field cases,and finally, a discussion about the technique.

Numerical-Simulation Studies. Hinchman and Barree (1985)indicated some of the applications of horizontal wells to increasethe productivity from condensate reservoirs. The Vuelta fielduses horizontal wells to improve the production and drainage effi-ciency, but the well performance was less than what wasexpected because of the abnormal stratigraphic characteristics ofthe producing formation. Fevang and Whitson (1996) found thatsimulation results of horizontal wells in condensate reservoirs arevery sensitive to the horizontal-/vertical-permeability ratio (kH/kV), and so it is very important to have an accurate determinationof this ratio.

Muladi and Pinczewski (1999) examined the difference in pro-duction performance between horizontal and vertical wells for dif-ferent heterogeneities in gas/condensate reservoirs. They used a3D Cartesian model with local grid refinement to model the near-wellbore regions. Muladi and Pinczewski (1999) found that theperformance of a horizontal well is better than that of a verticalwell when the average reservoir permeability is greater than 1 md,while the performance of a vertical well is better than that of ahorizontal well for reservoir rocks with average permeabilitiesless than or equal to 1 md. This is because fluid mobility is muchhigher in a high average-permeability reservoir, and the fluid caneasily move vertically to the horizontal well, making the effect ofheterogeneities less significant.

Dehane et al. (2000) investigated how the horizontal and verti-cal wells drilled in condensate reservoirs perform under variousdepletion schemes. They found that the drawdown pressures for ahorizontal well (for different drainhole lengths) are smaller thanthose for a vertical well in the same reservoir because of loweraccumulation of liquid near the horizontal-well section comparedwith the vertical well. In addition, they found that layers withhigh-capacity values (high permeability-thickness product) con-tain the most liquid accumulation, and as the drainhole lengthincreased, the productivity of the horizontal well increased.

Marir and Tiab (2006) conducted a modeling study to predictthe behavior of horizontal wells drilled in Hassi R’Mel field inAlgeria vs. water production and liquid-condensate recovery.They built a 3D Cartesian model, and found that the use of hori-

zontal wells delayed the water breakthrough and was useful inreducing water-influx problems. Also, the horizontal wells reducedthe condensate loss in the formation, resulting in improved recov-ery of the liquid condensate.

Field Cases. Miller et al. (2010) studied the application of hori-zontal wells in a giant gas/condensate reservoir to reduce conden-sate blockage in the North field in Qatar. They tried to determinethe fraction of production increase caused by the increased con-tact of well and reservoir and by the reduction of condensate accu-mulation. The North field in Qatar is an offshore gas/condensatereservoir with more than 900 Tcf of proven gas reserves. Themain lithology is carbonate: limestone and dolomite, with someinterbedded shale, claystone, sandstone, and anhydrite. The fieldproduces mainly from the Khuff formation. The field covers morethan 6000 km2. The initial reservoir pressure and temperature are5,300 psi and 220�F, respectively (Miller et al. 2010). The firstdelivery of condensate took place in 1996, while the first deliveryof liquefied natural gas occurred in 1997.

Miller et al. (2010) developed a numerical model to study theeffectiveness of horizontal wells in producing from the NorthField I Qatar with less condensate banking and higher gas andcondensate recovery. They used two well models—a vertical-wellmodel with radial coordinates and a horizontal-well model withCartesian coordinates. The drawdown comparison between thehorizontal and vertical well showed that the drawdown in the hor-izontal well was much less than that in the vertical well, resultingin a reduction in water coning and in the volume of condensatebanking around the wellbore.

Also, Miller et al. (2010) noticed that the liquid saturationaround the wellbore is less in the case of drilling horizontal wellsthan in vertical wells and the PIs of horizontal wells were higherthan those of vertical wells. Additionaly, the PIs of horizontalwells were only slightly impacted by pressure dropping below thedewpoint, while there was a significant reduction in the PIs of ver-tical wells for the same condition. There are two main reasons forthe better performance of horizontal wells in a gas/condensate res-ervoir: large contact area between the wellbore and the reservoir,and the ability of horizontal wells to reduce the condensate satura-tion and delay the formation of a liquid bank in the region aroundthe wellbore.

Discussion. Drilling horizontal wells aims to create a large con-tact area between the reservoir and the wellbore. An operatorwould like to operate the horizontal well at its maximum capacityand to increase the production rate to benefit from having such alarge contact area between the reservoir and the wellbore. Athigher production rates, the pressure drop will be higher. In hori-zontal wells, this high pressure drop will be distributed over alarge area. Drilling horizontal wells was found to delay the con-densate-banking problem as a result of the distribution of thepressure drop over a large area. Horizontal wells will not be apermanent solution to the condensate-banking problem. Thedelay in condensate banking takes place mainly as a direct resultof reducing the pressure drawdown through creating a large con-tact area between the wellbore and the reservoir. The condensateaccumulation is only delayed. So, after a certain time of produc-tion and with large drawdown in pressure, condensate will startto form and accumulate in the region around the wellbore.Besides, the cost of drilling horizontal wells can be high in cer-tain circumstances.

A combination of drilling horizontal wells and the wettability-alteration technique can be a good solution for enhancing the per-formance of horizontal wells because the performance will benefitfrom both mechanisms. In addition, horizontal wells are used todevelop unconventional oil and gas reservoirs. Unconventionalreservoirs may contain different types of fluids: black and volatileoil, gas condensate, or even dry gas. As an example, the EagleFord reservoir can contain all of these reservoir fluids (Orangiet al. 2011). Drilling horizontal wells in combination withmultistage fracturing increased the production rates from such

Gas Cycling

Pressure Maintenance

Productivity Improvement

Chemical Injection

Con

dens

ate

and

Wat

er B

anki

ng

Combined Methods

CO2 and N2 Injection

Solvent Injection

Wettability Alteration

Horizontal Wells

Hydraulic Fracturing

Acidizing

Fig. 3—A summary of the methods used to mitigate the prob-lem of condensate banking.




reservoirs to economic rates, which helps to decrease the gapbetween the energy demand and supply.

Hydraulic Fracturing

Hydraulic fracturing as a practice started more than 60 years ago.Since then, millions of fracturing treatments have been executedin many regions of the world (Montgomery and Smith 2010).Both acid fracturing and hydraulic fracturing are efficient techni-ques to enhance the performance of the wells drilled in conden-sate reservoirs (Sognesand 1991; Cannan et al. 1992; Afidicket al. 1994; Hsu et al. 1995; Carlson and Myer 1995; Settari et al.1996). The main objective of hydraulic fracturing is to create alonger conductive path between the reservoir and the well for thefluids to flow through from the reservoir to the wellbore. This con-ductive path will reduce the pressure drop and, hence, reduce theprobability of formation of condensate and a liquid ring (liquidbanking) around the wellbore. Hydraulic fracturing will createsuch conductive paths, but it will not prevent the condensate-banking problem. A hydraulically fractured well will be operatedat rates higher than those in the vertical well, and so the pressuredrop will be higher. This higher pressure drop will be distributedon a larger area between the wellbore and the reservoir. Hydraulicfracturing will delay the problem of liquid banking and reduce theeffect of liquid banking on gas-production rates by reducing the pres-sure drop and creating longer conductive paths between the wellboreand the reservoir.

Numerical Simulation Studies. Carlson and Myer (1995) andSettari et al. (1996) indicated that the productivity loss in wellsproducing from gas/condensate reservoirs because of condensateand water banking can be reduced by stimulating the wellsthrough hydraulic fracturing. Hydraulic fracturing in gas/conden-sate wells can reduce the pressure drawdown and thus reduce theliquid dropout. Settari et al. (1996) performed a study for theSmorbukk field in offshore Norway aimed at addressing the influ-ence of condensate banking on the productivity index (PI) ofhydraulically fractured wells producing from condensate reser-voirs. They used a 3D fracture with a 3D multiphase reservoirsimulator and two fracture models: the ideal rectangular fractureand the 3D propped fracture. They found that as the fracture con-ductivity increased, the productivity of gas and liquid increased.Also, as the fracture length increased, the benefits of a higher-con-ductivity fracture on the well productivity increased. One of themost important findings of Settari et al. (1996) is the effect ofmultiphase flow on the PI of the well. Multiphase flow (flow ofliquid and gas at pressures below the dewpoint) will cause a 50%reduction of the PI in an unfractured well, while fracturing thewell may be able to restore the PI to values similar to or evenhigher than the PI of the unfractured well before multiphase flowoccurs. The effectiveness of fracturing the well in restoring the PIdepends mainly on the volume of condensate in the pore spaceand on the reservoir heterogeneity.

Al-Hashim and Hashmi (2000) used a compositional simulatorto evaluate the improvement in the well’s productivity in conden-sate reservoirs by use of hydraulic-fracturing technology. The res-ervoir model consisted of a five-layer stratified formation withpermeabilities ranging from 0.08 to 115 md. In comparison todepleting the reservoir with no induced fracturing, hydraulic frac-turing was found to increase the time required for the pressure toreach the dewpoint and, hence, delay the condensate-banking phe-nomenon. The main reason for this observation is the large inflowarea to the wellbore created by hydraulic fracturing. When thedewpoint pressure is reached, the drop in pressure is sudden inboth cases, but is still less in the fractured case. Al-Hashim andHashmi (2000) found that gas- and liquid-production rates for thefractured case stabilize at a rate that is more than three times thatof the nonfractured stabilized rate, with extended duration of thepressure plateau above the dewpoint. One of the main problemsthat may result in poor performance of hydraulically fracturedwells is the accumulation of liquid condensate around the frac-ture’s walls. The main reason for fracture-face damage is the

impairment in the permeability normal to the fracture face causedby the accumulation of the liquid.

Aly et al. (2001) used both compositional simulation and frac-ture modeling to compare alternative development plans for alow-permeability, multilayered rich-gas/condensate formation.They found that hydraulic fracturing increased the production rateand extended the production-plateau period. Longer propped-frac-ture half-lengths extended the production-rate plateau. Indriatiet al. (2002) proposed a model that predicts the performance ofhydraulically fractured gas/condensate reservoirs and adjusts thefracture-treatment design. Indriati et al. (2002) found that for ev-ery bottomhole flowing pressure, there is an optimum fracture ge-ometry that maximizes the productivity of the well.

Orangi et al. (2011) found that one of the key parameters thatcontrols the performance of hydraulically fractured wells is thesurface contact area between the fracture and the matrix. Also, thefracture-permeability degradation, from which the fracture widthmay decrease with time during reservoir depletion, may have amajor impact on the cumulative production from the reservoir.Ataei et al. (2011) conducted a numerical simulation study on hy-draulic fracturing in a stacked, tight gas/condensate reservoir.They found that the productivity increase was not affected signifi-cantly by the fracture half-length, whereas the fracture heightimpacted it significantly.

Ignatyev et al. (2011) evaluated hydraulic fracturing in hori-zontal wells as a method for the effective development of gas/con-densate fields in the Arctic region (Russian). They found that theproductivity of horizontal wells with fractures was nine timesgreater than the production from horizontal wells without frac-tures and three times greater than vertical wells with fractures.Ignatyev et al. (2011) concluded that multistage fracturing in hori-zontal wells reduced the drawdown and condensate losses andraised the well PI.

Field Cases. Butula et al. (2005) analyzed the production per-formance of hydraulically fractured wells in a condensate reser-voir in Russia. The gas/condensate reserves in Neocomiandeposits contain more than 2 billion m3 of gas and 200 milliontons of condensate. The wells used to be completed by fracturing,but the performance was always lower than expected. The solu-tion suggested by Butula et al. (2005) was to create wide and con-ductive fractures and to better determine the volume of theproppant needed to obtain adequate fracture geometry. They con-cluded that the design of fracture treatments with water-basedfracturing fluids is more suitable to produce from such gas/con-densate reservoirs.

Delta field is a mature field that has been producing gas/con-densate from sandstone reservoirs. In this field and with produc-tion of gases, the average reservoir pressure declined to a valuebelow the dewpoint, resulting in the accumulation of condensatein the region around the wellbore (Khan et al. 2010). Hydraulicfracturing presented the most-economical solution to deplete thereservoir, where in one of the wells, the production increased bythree times after fracturing the well.

Franco et al. (2011) indicated that the majority of gas/conden-sate reserves currently being developed from fields in Saudi Ara-bia are developed in tight carbonate reservoirs. These tightreservoirs require acid stimulation to achieve the targeted produc-tion rate. These reservoirs were developed by drilling verticalwells that were acid fractured. The analysis of the production per-formance of these wells indicated excellent post-stimulationresults. Then, the development of these reservoirs was expandedto include an area with very low permeability, and the majority ofwells drilled to produce from these reservoirs were drilled as hori-zontal wells with single or dual laterals to achieve maximum pos-sible contact with the reservoir. These single or multilateral wellsmay be stimulated with acid fracturing or matrix acidizing toremove the formation damage and enhance the productivity ofthese wells. Also, horizontal-well drilling, completed by the mul-tistage-fracturing technique, was implemented in some cases as anew phase of development. Franco et al. (2011) concluded that a




single-lateral well with three acid-fracturing stages performed bet-ter than dual- and triple-lateral wells and better than vertical wellswith fracturing.

Discussion. Hydraulic fracturing is one of the interesting techni-ques that can be used to control the condensate-banking problem.Hydraulic fracturing will not prevent the condensate-bankingproblem; however, it will delay the problem and reduce the effectbecause hydraulic fracturing creates such longer conductive pathsbetween the wellbore and the reservoir. The conductivity of hy-draulic fractures is an important parameter that determines theeffect of condensate and water banking on the productivity ofwells drilled in gas/condensate reservoirs (Al-Anazi et al. 2005a).One of the main parameters that controls the fracture conductiv-ity, and hence the well’s productivity, is the chemistry of hydrau-lic-fracturing fluid. The optimum design of a fracturing treatmentand the best selection of fracturing fluids helps to minimize thefracture damage and enhance the post-treatment performance ofthe well (Rahim et al. 2012).

Also, the use of hydraulic-fracturing techniques to mitigate thecondensate-banking problem is not a permanent solution. Withtime and with more production, the drawdown increases and theprobability of formation of condensate banking increases. Devel-opment of unconventional resources requires the implementationof hydraulic-fracturing technology. These unconventional resour-ces have very low permeability, in the micro- and nanodarcyrange, and in these reservoirs, production at economical rates can-not be achieved without having conductive fractures. These con-ductive fractures are able to deliver the reservoir fluid from thereservoir to the wellbore.

Acidizing

Acid treatments have been used to stimulate wells drilled in bothgas and oil reservoirs (Fredd and Fogler 1998). For carbonate res-ervoirs, acids can be used to dissolve part of the rock and createfractures or wormholes (Hendrickson et al. 1965; Schechter andGidley 1969). For sandstone reservoirs, the main target of acidiz-ing and acid treatments is to remove the formation damage causedby drilling, workover, or completion processes, and thus to restorethe original permeability of the formation (Smith and Hendrick-son 1965; Gidley 1985).

Al-Anazi et al. (2006) examined the applications of alcoholicacids to stimulate both carbonate and sandstone gas reservoirs.Some of the wells required a period of up to 1 year to restore theinitial gas productivity following liquid injection into the forma-tion. They added methanol to the acid solutions, and performedcoreflood tests at 284�F and 1,500 psig by use of sandstone coresamples. The objective of adding alcohol was to enhance the gaspermeability after the stimulation treatment. They found that alco-holic acids have a slower reactivity with reservoir rocks than reg-ular acids. Also, addition of methanol to the acids resulted indeeper acid penetration. In addition, alcoholic acids achieved lowinterfacial tension, and as a result, they achieved deeper stimula-tion. Finally, alcohol can be added to stimulation fluid to expeditethe cleanup of spent acid and to prevent potential precipitation ofhydrofluoric acid silicate reaction products.

Trehan et al. (2012) presented a case study of two unconven-tional tight gas/condensate wells, in which they used a gas-assisted perforating process followed by foamed acidizing. Initial

attempts to hydraulically fracture the wells were made, but thefracturing pressure encountered was too high to safely continuethe job. The production rates of these wells declined to a levelthat seemed to be uneconomically viable at this point. Afterstudying the matrix of reservoir rocks, a decision was made to usea sandstone acidizing treatment to increase the productivity ofthese wells. A gas-assisted perforating process followed byfoamed matrix acidizing (solvent, acid, and nitrogen) was appliedin the two wells. Trehan et al. (2012) indicated that the treat-ment was successful and that the production rates increased afterthe treatment.

Matrix acidizing can represent a good solution to mitigate theproblem of condensate and water banking. Different acid systemsare available that can be used to stimulate both carbonates andsandstone reservoirs. The high temperature anticipated with thegas/condensate reservoirs may limit the application of some ofthese acid systems. For example, at temperatures higher than200�F, the reaction of hydrochloric acid (HCl) and carbonateswill be very fast, resulting in high acid consumption without cre-ating wormholes (face dissolution). Retarded acid systems arevital in such cases. Retarded acid systems include the use of emul-sified acid, viscoelastic surfactant, or in-situ gelled acid. Also, theuse of chelating agents at high temperatures can be a good alterna-tive to HCl systems, but the economics of the treatment mayhinder its applications.

Use of Solvents

The method of using low-molecular-weight alcohols and solventsaims to enhance the relative permeability to gas, which wasreduced as a result of the accumulation of liquid condensate in theregion around the wellbore. The mechanism by which solventsincrease the relative permeability of gas is of two pathways. First,the solvent could reduce the interfacial tension between the con-densate and gas. Second, the solvent could dissolve some of thecondensate into the main gas stream. Methanol is one example ofsolvents used for this purpose. Du et al. (2000) found that the meth-anol achieved a 1.2- to 2.5-fold increase in the endpoints of the gasrelative permeability as a result of the ability of methanol to dis-solve in and displace both water and condensate accumulations.

Al-Anazi et al. (2002) indicated that the delay in condensateformation when methanol was used as a solvent was a result of thepresence of an intermediate phase that was rich in methanol, inwhich this intermediate phase can dissolve both condensate andwater. Al-Anazi et al. (2005a) mentioned that methanol treatments,as a solvent injection method, displaced the liquid bank (liquidhydrocarbon or water) by the multicontact-miscible technique.Bang et al. (2010a) mentioned that adding methanol to a mixtureof water and condensate reduced the dewpoint, and hence, retardsthe phenomenon of condensate dropout. Different solvents andalcohols were investigated; among these chemicals are methanol,isopropyl alcohol (IPA), and ethanol. Table 1 shows a summary ofsome of the properties of these three solvents.

Experimental Studies. There were extensive experimental stud-ies performed to evaluate the use of solvents to remove the waterand condensate banking in gas/condensate reservoirs. Theseexperimental studies include testing several solvents such asmethanol, IPA, methanol/water mixture, and a mixture of metha-nol and IPA. Both sandstone and limestone samples of different

Table 1—Properties of solvents that are widely used to mitigate the condensate-banking problem.




permeabilities were used during these experiments. The followingis a summary of the findings in these experimental studies.

Al-Anazi et al. (2002) studied the use of methanol to mitigateboth water and condensate banks from low- (2- to 5-md lime-stone) and high- (250- to 380-md sandstone) permeability coresamples. They used synthetic gas/condensate mixture and per-formed coreflood experiments at a temperature of 145�F. The ini-tial water saturation ranged between 0 and 54%. Al-Anazi et al.(2002) followed a procedure that allows condensate accumulationin the core, which simulates what happens in the near-wellboreregion in the production well. Because of the accumulation ofcondensate in the core sample, there was a 95% reduction in therelative permeability of gases. Also, as the water saturationincreased, both gas and condensate relative permeabilities (krg

and kro, respectively) decreased. Al-Anazi et al. (2002) performedtwo stages of a methanol treatment (each of 20 pore volumes),and they noticed an improvement in the flow of gas after the firststage of the treatment, where the productivity index wasenhanced. But with time, and as the methanol was stripped by theflowing gas, methanol was produced, allowing for condensateaccumulation to take place again. They concluded that methanolenhanced the gas relative permeability for water saturation (Sw)from 0 to 54%, and that the volume of methanol and the man-ner in which it transfers to the gas stream control the success ofthe treatment.

In another study, Al-Anazi et al. (2005c) tested methanol,methanol/water mixture, isopropanol, and a mixture of isopropa-nol and methanol to evaluate their efficiency in removing the liq-uid bank. They concluded that methanol/water mixtures wereineffective in removing condensate bank, while methanol and themixture of isopropanol and methanol were effective in removingwater from core samples.

Alzate et al. (2006) performed compatibility tests between res-ervoir fluids, alcohol, and inhibited diesel-based treatments, andthey used formation cores from Cupiagua field. They found thatcompatibility is a function of the miscibility of alcohol in forma-tion fluids, volumetric concentration of alcohol in the mixture,and the composition of the fluids. If formation water has high sa-linity, mineral precipitation can occur when alcohol comes in con-tact with the water. Also, they excluded any solvent that has aflammability (flash) point less than 82�F. They conducted core-flood experiments with both Berea sandstone and Mirador forma-tion core samples and found that the degree of damage is higherin Berea sandstone than in Mirador formation cores, and the stim-ulation degree in Berea was lower than that of Mirador formation.Both alcohol-based and inhibited-diesel treatments were effectivein removing condensate and water bank, and the treatments inlower-permeability rocks were more efficient than in higher-per-meability rocks because alcohol-based treatments penetrate andremove both condensate and water from the smaller-diameterpore system and reduce the capillary pressure.

Field Cases. Al-Anazi et al. (2005b) described a successful fieldapplication that used methanol to remove a condensate bank inthe Hatter’s Pond field in Alabama. The well history indicatedthat gas- and condensate-production rates decreased from 2.7MMscf/D and 348 BOPD to 0.25 MMscf/D and 87 BOPD,respectively, as a result of condensate accumulation around thewellbore. The well was treated with 1,000 bbl of methanol, andthe gas- and condensate-production rates increased from 0.25MMscf/D and 87 BOBD to 0.5 MMscf/D and 157 BOPD, respec-tively, which indicates that methanol was effective in removingthe condensate bank. The production increased by a factor of twofor a period of 4 months, and then the production rate started todecrease again.

Numerical-Simulation Studies. The phase behavior of gas/con-densate mixtures has been studied and reported by many research-ers (Ahmed 1988; Bang 2005; Sarkar et al. 1991). The existenceof alcohols or water within the condensate bank increases thecomplexity of the phase behavior of the reservoir fluids (Kokal

et al. 2000; Pedersen and Milter 2004). The phase behavior ofhydrocarbon/water/methanol mixtures at reservoir conditions wasexamined by Bang et al. (2010a). They performed constant-com-position-expansion experiments at temperatures of up to 300�F.Also, they studied the effect of several parameters, such as pres-sure, temperature, and the concentration of water and methanol,on the phase behavior of reservoir fluids at reservoir conditions.When methanol was added to hydrocarbons, the dewpointincreased by 350 psig and the liquid dropout increased from 21.5to 29.9%, which indicates that methanol prefers the liquid-hydro-carbon phase to the vapor phase. When water was added to thehydrocarbon, a third aqueous phase composed mainly of waterwas formed with no significant effect on the dewpoint. Whenmethanol was added to a mixture of hydrocarbon and water, athird aqueous phase was formed and the dewpoint was reduced.The total liquid volume increased while the hydrocarbon volumewas not significantly changed. This indicated that methanol has apreference to mix with water (aqueous phase) more than mixingwith the liquid condensate (oleic phase). Bang et al. (2010a)found that when isopropanol was added to a mixture of hydrocar-bon and water, a small third aqueous phase was formed, and thehydrocarbon volume increased, indicating that isopropanol pre-ferred the hydrocarbon phase over the water.

Discussion. A summary of the experimental work performedwith methanol and IPA and the mixture of the two is presented inTables 2 and 3, respectively. Use of solvents, such as methanoland IPA or a mixture of both, is an efficient method to removethe condensate and water bank from condensate reservoirs. Theuse of solvents to mitigate the water- and condensate-bankingproblems was found to be effective in carbonate reservoirs andsandstone reservoirs. Furthermore, this method was effectivewith low- and high-permeability reservoirs. The main drawbackof this method is its temporary nature and the need to repeat thistreatment in the future when the liquid accumulates again aroundthe wellbore.

Wettability-Alteration Chemicals

Changing the wettability of the porous medium from oil- or water-wetting to gas-wetting can help increase the productivity of gaswells producing from condensate reservoirs. In general, wettabilityof the reservoir rock is a very important parameter that determinesthe success or failure of the waterflooding process as a secondary-recovery mechanism (Buckley and Leverett 1942). This is shownin the following equation (Leverett 1941; Liu et al. 2006):

Pc ¼ccosðhÞffiffiffiffi

k

/

r ; ð1Þ

where Pc is the capillary pressure, k is the rock permeability, / isthe rock porosity, c is the interfacial tension, and h is the contactangle (Zheng and Rao 2010). What controls the wettability of therock is the contact angle between the fluid and the surface of therock. If there are two immiscible fluids (A and B) in the porousmedium, the rock wettability can be determined on the basis ofthe value of the contact angle (h), measured in the denser phase(as an example, Fluid B is the denser phase), with the rock sur-face, as shown in Fig. 4 (which is a schematic of the manner inwhich liquids may spread over the surface of a solid). These con-tact angles are static contact angles; the contact angle can bemeasured dynamically by use of pendant-drop equipment, withadvancing and receding measurements. These types of measure-ments are not shown in Fig. 4; the static contact angle only isdescribed. The denser-phase, Fluid B, can be determined as a wet-ting phase if the contact angle (h) is less than 90�, as a nonwettingphase if the contact angle (h) is greater than 90�, and as a neutralwetting phase if the contact angle (h) is equal to 90� (Wu and Fir-oozabadi 2010a).

Fluoropolymers have monomers that are either partially orfully fluorinated (Ebnesajjad 2011). Fluorinated surfactants are

. . . . . . . . . . . . . . . . . . . . . . . . . . . . .




derived from the substitution of one or more hydrogen atomsalong the carbon backbone that makes up the hydrophobic part ofthe surfactant with fluorine (Pabon and Corpart 2002: Schultzet al. 2003; Lehmler 2005, 2008). The fluorinated polymers andsurfactants possess some unique properties, such as lowering sur-face tension in aqueous systems and high chemical and thermalstability. The chemistry of fluorinated surfactants (Fig. 5) includesthree distinct structural aspects: the hydrophobic/oleophobic“tail,” which contains a high proportion of fluorine; the hydro-philic group; and the spacer, which is an organic group linkingthese two portions of the surfactant together (Buck et al. 2012).

It has been reported that there are some potential health andsafety concerns with some of the fluorochemicals or theirdegraded products. Examples of the products resulting from thedegradation of fluorinated chemicals are perfluorooctane sulfonate(PFOS) and perfluorooctanoic acid (PFOA) (Key et al. 1997; Elliset al. 2004; Strazza et al. 2013), and both are toxic. In addition,PFOA has been identified as a possible hazard that may causecancer (Upham et al. 1998; Biegel et al. 2001). Martin et al.(2003) reported that both PFOA and PFOS are persistent and donot break down easily. The major global fluorochemical compa-nies in the US have agreed to eliminate PFOA by the year 2015,and the major manufacturer for fluorochemicals in the US has

stopped making PFOS and eliminated it from their products(Weber 2000). Weber (2000) indicated that PFOS has a tendencyto accumulate in human and animal tissues as a result of its envi-ronmental persistence. Seacat et al. (2002) reported an approxi-mate time of 200 days as a half-life time for PFOS. Olsen et al.(2007) conducted a study to measure the half-life of some fluoro-polymers and their degradable components in human beings.Olsen et al. (2007) found that PFOS needs an average time of 4.8to 7.8 years as a half-life elimination time.

Use of Fluorosurfactants and -Polymers for Wettability Alteration

To Mitigate the Condensate-Banking Problem. Wettability-alter-ation chemicals received an appreciable interest during the last 20years. Extensive laboratory work was performed by manyresearchers. The reported experimental studies started at roomtemperatures (Tang and Firoozabadi 2003), and then were contin-ued by many researchers at higher temperatures of up to 161�C(Fahes and Firoozabadi 2007; Noh and Firoozabadi 2008; Banget al. 2010b). Several fluorinated polymers and surfactants wereevaluated. The evaluation of the fluorinated chemicals includedmeasuring the contact angle, performing imbibition tests, and con-ducting coreflood experiments at high temperatures and pressures.The various studies used sandstone and carbonate cores from both

Wetting phase (θ < 90°) Nonwetting phase (θ > 90°) Neutral wettability (θ = 90°)

θ θ θFluid Fluid Fluid

Rock Rock Rock

Fig. 4—Determination of wettability through the use of the contact-angle concept [modified from Yuan and Lee (2013)].

k

Table 2—Summary of the experimental work performed with methanol.

Table 3—Summary of the experimental work performed with IPA and a mixture of IPA and methanol.




outcrop and reservoir sources and included both low- and medium-permeability samples. In general, wettability-alteration chemicalswere able to change the wettability of rock surfaces (sandstone andcarbonates) from oil- or water-wetting to intermediate-wettingwith liquids, or, sometimes, preferentially gas-wetting.

Wettability-alteration chemicals can represent a good solutionfor solving the problem of condensate and water banking in gas/condensate reservoirs. Currently missing from the literature arefield-case histories in which fluorinated chemicals were used.These field cases are very important to the evaluation of real per-formance and to better design more treatments in the future. Theonly work found in the SPE literature that discussed field trialswas that performed by Restrepo et al. (2012) and Al-Yami et al.(2013). There were a few field trials that used wettability-altera-tion chemicals in Latin America, but no data were publishedregarding the performance of these treatments1. Tables 4 and 5present a summary of the experimental work performed by use ofthe fluorosurfactants and fluoropolymers, respectively, as wett-ability-alteration chemicals.

Experimental Studies. Li and Firoozabadi (2000b) found thatwettability-alteration chemicals were effective in Berea sandstonein which n-decane imbibition was reduced significantly, whilewater imbibition decreased to approximately zero. Kumar et al.(2006a, b) found that the relative permeability to gas wasimproved and the residual oil saturation was reduced after treatingthe core samples with wettability-alteration chemicals. Wettabil-ity-alteration chemicals can reduce the high velocity (turbulent)coefficient as well as enhance the relative permeability to gas(Noh and Firoozabadi 2006). Also, wettability-alteration chemi-cals were found to be effective in modifying the wettability ofrock surfaces in propped fractures, hence increasing the gas-flowrate through improving the fracture conductivity (Bang 2007;Bang et al. 2008).

Fahes and Firoozabadi (2007) concluded that wettability alter-ation was permanent at 140�C and that the treatment resulted inimproved gas productivity. With the increase in the chemical con-centration, water imbibition decreased, and the permeability ofthe rock was not affected adversely after the treatment. Pangaet al. (2007) found that the solvent system itself used with the flu-orochemical may cause the chemical to be adsorbed on the coreface, resulting in loss of injectivity and nonuniform distribution ofthe chemical along the core length.

Noh and Firoozabadi (2008) found that the higher the chemicalconcentration, the higher the chemical adsorption in the rock.Extensive chemical adsorption caused significant reduction in thecore permeability, so they suggested a pretreatment process toavoid the reduction in the core permeability. The water andcondensate imbibition in the core was reduced significantly by 90and 50%, respectively, after the treatment that used thefluorochemicals.

Bang et al. (2009) found the pressure drop across the coredecreased after treating the core samples with fluoropolymer,which indicates that there was an increase in the relative perme-ability to gas (twofold increase) and the treatment was durableand efficient. In another study, Bang et al. (2010b) found that opti-mal solvents for wettability-alteration chemicals to stimulate theBerea sandstone were the mixture of 2-butoxyethanol and ethanoland the mixture of isopropyl alcohol (IPA) and propylene glycol.Bang et al. (2010b) and Wu and Firoozabadi (2010b) found thatthe water salinity and the type of salt in brine will influence theperformance of the fluorochemical and the final change in the

wettability of the rock surface. Fahimpour et al. (2012a, b) foundthat alcohol-based solvents were more effective than brine-basedsolvents for use with wettability-alteration chemicals. Also, theconcentration of the fluorinated chemical has to be optimized tomaximize the efficiency of the chemical treatment.

Zheng and Rao (2010, 2011) found that both anionic and non-ionic surfactants are effective in reducing the interfacial tensionfor a gas/water system and a condensate/water system, but theperformance of the anionic surfactant was better than that of thenonionic surfactant, especially at high pressures and temperatures.Anionic surfactant was effective in changing the wettability of thequartz surface from strongly oil-wetting to weakly oil-wetting orwater-wetting.

Ahmadi et al. (2011) found that, in the presence of brine, it isbetter to preflush the core with a solvent (such as IPA) followedby the chemical treatment, and the use of polyamine primer canimprove the treatment’s lifetime and increase the improvementfactor of the wettability-alteration-chemical treatment. Fernandezet al. (2011) found that there is an optimal concentration for thefluorochemical, and there was no more improvement in liquid mo-bility at concentrations above the optimum.

Simulation and Modeling. Li and Firoozabadi (2000a) simu-lated the relative permeabilities of both Liquid and gases in agas/condensate reservoir. Li and Firoozabadi (2000a) con-cluded that the deliverability of gas wells can be enhanced sig-nificantly through the use of wettability-alteration chemicals,which will help to change the wettability of the rock surfacesfrom oil- or water-wetting to gas-wetting. Kumar et al. (2006a)performed simulation studies to evaluate the use of wettability-alteration chemicals in stimulating the performance of wellsproducing from gas/condensate reservoirs. The simulationstudy considered two cases—single-layer and multilayered res-ervoirs. Kumar et al. (2006a) found that the relative permeabil-ity to gas was improved and the residual oil saturation wasreduced after treating the core samples with wettability-altera-tion chemicals. Also, the simulation study indicated that thegas rate increased proportionally with the increase in the treat-ment depth into the formation.

Case Studies. Restrepo et al. (2012) documented a field trial ofapplying a chemical treatment based on fluorinated polymer tochange the rock wettability and to enhance both oil and gas rela-tive permeabilities. Fluoropolymer solution was pumped and dis-placed with nitrogen followed by 17 hours of soaking followed byflowing back the well. The oil- and gas-production rates increasedby 20 and 50%, respectively. The oil rate returned to the basevalue after 25 days, indicating that the chemical distribution inthe region around the wellbore is limited.

Al-Yami et al. (2013) described a successful field treatmentin which they used polymeric fluorinated surfactant to mitigatethe condensate-banking problem in one of the wells in SaudiArabia. The well was put on production in October 2003, withan initial production rate of 20 MMscf/D. In 2009, the well suf-fered unstable wellhead conditions because of the accumulationof condensate in the wellbore and in the formation around thewellbore. The gas rate decreased to 1.56 MMscf/D, and the con-densate rate was 279 B/D, with a condensate/gas ratio of 178bbl/MMscf. The treatment included 257 bbl of preflush solvent(2-butoxyethanol and ethanol) followed by injection of 900 bblof the main chemical treatment (fluorinated polymeric surfac-tant). Al-Yami et al. (2013) indicated that after 3 months of pro-duction, the condensate rate increased to 1,152 B/D, which is anincrease of 313%, while gas rate increased to 2.85 MMscf/D,which is an increase of 83%. The payout time of the treatmentwas approximately 30 days. Also, the productivity of the welldid not decline after more than 2 years of production2. This

Fluorinated Tail (Hydro- and Oleophobic) Spacer Hydrophilic Group

Fig. 5—The chemistry of fluorinated surfactants (Buck et al.2012).

1 Personal Communication with Mukul M. Sharma, 2014, University of Texas at Austin,Austin, Texas, USA. 2 Personal Communication with Hamoud Al-Anazi, 2014, Saudi Aramco, Saudi Arabia.




indicates the stability of the fluorinated chemicals in the forma-tion under reservoir conditions.

Discussion. The use of wettability-alteration chemicals, such asfluorosurfactant and fluoropolymers, can present an effective solu-tion to the condensate- and water-banking phenomena in gas/con-densate reservoirs. Several parameters, such as the cost of the

treatment, its effectiveness and durability, flexibility of the designto accommodate varying reservoir conditions, rigless workover,and short payout time, may encourage the use of the wettability-alteration method over the other techniques to mitigate the prob-lem of condensate banking. This method can be combined withother techniques, such as horizontal wells or hydraulic fracturing,to maximize the benefits and the outcome of the treatment. Morefield trials are required to better understand and evaluate these

Table 4—Summary of the experimental work performed with fluorosurfactants.




chemicals. The rock mineralogy and the properties of formationwater, as well as the selection of the solvent and the fluorinatedchemical, are among the parameters that greatly affect the per-formance of wettability-alteration chemicals. The only publishedstudy on a field treatment that uses this method indicated that thetreatment lasted for 2 years and gave an indication of the perma-nency of the treatment.

Inhibited-Diesel (ID) and Inhibited-Dry-GasInjection

ID consists of a blend of diesel, surfactant, and mutual solvent.The use of ID aims to reduce the interfacial tension and mitigatethe problem of condensate banking. Sometimes xylene is added tothe ID. Franco et al. (2013) mentioned that ID achieved a verylow interfacial tension (c) of 0.09 dynes/cm with Cupiagua reser-voir brine compared with 72 dynes/cm for an air/water system, 48dynes/cm for an oil/water system, and 24 dynes/cm for a gas/oilsystem. The main problem with this system was its efficiency andsustainability at low reservoir pressures. Other than that, heavyfractions from the condensate started to precipitate and cause poreplugging. Alcohol and xylene were added to the ID to reduce theinterfacial tension and dissolve some of the organic materials pre-cipitated in the pores. By adding alcohol and xylene, the penetra-tion depth of the treatment fluid increased to 15 ft compared witha penetration depth of 5 to 10 ft upon the use of ID alone, withoutxylene. Addition of alcohols and xylene to the diesel achieved anaverage of 50 to 100% increase in the penetration depth of thetreatment fluids.

Garzon et al. (2006) conducted a laboratory study of conden-sate-bank removal in a gas/condensate reservoir by use of dieseland a combination of diesel, surfactant, and mutual solvents.They indicated that there was a 50% productivity enhancementwhen filtered diesel in combination with mutual solvent was used.There was no significant effect of the soaking time on the effi-ciency of the diesel and mutual-solvent solutions. Nonionicwater-wetting surfactants were added to the ID and tested by useof a coreflood setup. Garzon et al. (2006) found that surfactantswere ineffective and did not achieve a considerable enhancementin the relative permeability of gas. Also, the volume of theinjected slug must be designed to be equal to the volume of con-densate in the region around the wellbore. Furthermore, a fieldtrial to evaluate this technique was implemented on a gas welldrilled in a Permian carbonate formation. The reservoir was oneof the major nonassociated-gas reservoirs. This formation was

producing gas with high condensate content. A field trial was con-ducted with the filtered diesel in combination with mutual solvent.Before the treatment, the well was completely cleaned up by useof several stages of acid pickling jobs. A mixture of 695 bbl of fil-tered diesel and 1,045 bbl of mutual solvent was pumped into thewell, and finally, this treatment fluid was displaced to the top ofthe perforations by use of 307 bbl of filtered ID, with 10% mutualsolvent. The treatment was soaked in the formation for 2 weeks,and then the well was opened to produce. The production databefore and after the treatment indicated that the productivity indexincreased by 10% and the gas rate increased by 15%.

The inhibited-gas method involves the injection of a blend ofgas, alcohol, and spreading agent to remove the condensate bank.The inhibited gas is injected at high pressure and high rate in theproduction well, aiming to vaporize as much condensate as possi-ble. Franco et al. (2013) summarized the results of two field treat-ments performed on two wells in the Cupiagua field; thetreatment in both wells was performed with inhibited gas. WhenID was used, good results were observed in the early stages afterthe treatment took place, but with time and production, the con-densate production declined again. When inhibited gas was used,there was no decline after the job, and the gas production did notdecline in both wells after almost 1 year of post-treatment produc-tion. A summary of experimental work performed with ID isgiven in Table 6.

Gas Cycling

In gas/condensate reservoirs, gases, such as natural gas and nitro-gen (N2), are injected for pressure-maintenance purposes toimprove the condensate recovery from the reservoir. The gas-cycling techniques aim to keep the pressure in the reservoir at avalue that is higher than the dewpoint to prevent condensate for-mation. In addition, it can help revaporize any liquid condensatethat might have formed back to the gas phase. If the reservoir pres-sure can be maintained at or above the dewpoint, a 100% with-drawal of condensate should be possible (Aziz 1983). The flowcharacteristics of the reservoir and the phase behavior of the fluidare the two main parameters that determine the suitability of thegas-injection operations for a specific gas/condensate reservoir.

Aziz (1983) concluded that condensate-recovery factors canincrease to 75% by recycling dry gas into the reservoir. Severalfactors may impact the effectiveness of the gas-cycling processeswhen they are applied to mitigate the problem of condensatebanking. These factors may include sweep efficiencies (both areal

Table 5—Summary of the experimental work performed with fluoropolymers.




and vertical), and revaporization of the formed liquid-condensatebank (Havlena et al. 1967). Also, gas- and condensate-recoveryfactors in gas/condensate fields depend on initial condensate/gasratio, filtration properties of the reservoir (i.e., the ease with whichthe fluids can flow through the porous medium, which is greatlyaffected by the facies of the rock), well spacing and completion,development plan, economic indices, and final (abandoned) reser-voir pressure (Kolbikov 2010). Simulation studies of gas cyclingin gas/condensate reservoirs consider many parameters, such asgeological and petrophysical data, and can be used to predict theoptimal scenario to develop a gas/condensate reservoir and tomaximize the condensate recovery by use of gas-cycling techni-ques. Simulation studies were performed by many researchers ondifferent fields: Toual field in Algeria (Belaifa et al. 2003), HassiR’Mel South field, Algeria (Adel et al. 2006), and western Sibe-rian fields (Kolbikov 2010).

Kabir et al. (2005) performed a study that used data collectedfrom fields producing in west Africa. They concluded that theincremental liquid recovery over the depletion case is a functionof reservoir permeability, voidage-replacement ratio, and the pro-ducer/injector distance. Also, they found that improved conden-sate recovery is related to large reservoirs and delayed lean-gasbreakthrough. Additionally, they showed that the recovery factorincreases with the increase in the voidage-replacement ratio.

Case studies were presented by many researchers. Amongthese case studies is the gas cycling in Bodcaw reservoir, CottonValley field (Miller and Lents 1946). The reservoir-productioneffluent consisted of a single gaseous phase at initial conditions of4,000 psig and 238�F. The condensable liquid-hydrocarbon con-tent was 113.98 bbl/MMcf. The dewpoint was determined to be at3,975 psi and 238�F. Miller and Lents (1946) mentioned that it iseconomically feasible to recover 85% of the reserves of the Bod-caw sand, Cotton Valley field, by the production of approximately115% of these gas reserves. Another gas-cycling project in AbuDhabi was described by Saadawi (2001). The project aimed to de-velop two gas/condensate reservoirs in an onshore field. Saadawi(2001) tried to address the basic design concepts and to describethe surface facilities and the project-implementation strategy.

Use of Nitrogen (N2). N2 was used as an alternative to dry gas asa result of the economic drawbacks of reinjection of the produceddry gas into the reservoir. Donohoe and Buchanan (1981) pre-sented a comparison of lean-gas injection vs. N2 for three hypo-thetical fluids. They presented reservoir-gas- and condensate-recovery factors for each fluid, considering depletion, lean-gasinjection, and N2 injection. They also considered three ranges ofreservoir heterogeneity. Donohoe and Buchanan (1981) showedthat recovery factors with N2 injection for all cases were compa-rable with those of the lean-gas injection. They concluded thatreservoirs with streams richer than 100 bbl/MMcf of condensateshould be considered for N2 injection. Aziz (1983) mentionedthat N2 injection can be a viable cycling process in reservoirswith low heterogeneity and if the injection and production ratesare kept constant.

Renner et al. (1989) performed coreflood experiments andsimulation models to investigate the use of N2 to displace gascondensate. The coreflood experiments were performed at a tem-perature of 215�F and a pressure in the range of 4,500 to 5,700psia with N2 and separator gas. They used a compositional modelto simulate the laboratory coreflood experiments they performed.They found that there was a small improvement in recovery effi-ciency when separator gas was used compared with when N2 wasused. They concluded that displacement of condensate by N2 orseparator gas at pressures below the dewpoint will reduce theamount of recoverable condensate, and it is better to initiate theinjection process, as pressure maintenance, in the early life of agas/condensate reservoir. Siregar et al. (1992) used a composi-tional 1D model to compare the performance of injection of N2

vs. gas cycling to recover more condensate in gas/condensate res-ervoirs. They found that methane (as a natural gas) achievedlower liquid dropout and higher capacity to evaporate liquid con-densate than N2.

Linderman et al. (2008) presented the results of a joint studythat used a compositional full-field reservoir simulation to evalu-ate the suitability of N2 injection for gas cycling in a large gas/condensate reservoir. They found that injection of N2 alonereduced the condensate recovery, while the injection of a mixtureof N2 and lean gas increased the condensate recovery and reducedthe impact of condensate banking. Compared to carbon dioxide(CO2), N2 achieved higher gas recovery, but less liquid-conden-sate recovery. They found that N2 has a low impact on condensaterecovery, while it increased the gas recovery and the total hydro-carbon recovery (liquid plus gas). Abdulwahab and Belhaj (2010)investigated the use of N2 to recover gas and condensate from areservoir in Abu Dhabi. The N2 was used to replace the reinjec-tion of the produced natural gas and to avoid the problems relatedto the injection of CO2 and flue gases. They studied two scenariosfor the injection of N2: all-field scenario and isolated scenario.They found that the isolated scenario was better in terms of lim-ited effect on the final gas specification and also as a result ofreduced requirements for gas separation.

Injection of CO2. Because of the increase in the concentrationsof CO2 in the atmosphere and the greenhouse effect on the envi-ronment, researchers started to consider CO2 injection intodepleted gas reservoirs as a way to store CO2 (Oldenburg andBenson 2002). CO2 can be injected into oil reservoirs with thepurpose of enhancing the recovery of more crude oil (Stalkup1978; Gardner et al. 1981; Orr and Jenssen 1984; Blunt et al.1993). The key mechanism in CO2 injection in gas/condensatereservoirs is that CO2 is able to reduce the dewpoint (saturation)pressure of the oil/gas system (Odi 2012). Mamora and Seo(2002) found that CO2 can recover some of the unrecoverable gasreserves by improving the sweep efficiency and repressurizationof depleted gas fields. Monger and Khakoo (1981) noticed thatCO2 has the ability to lower the miscibility pressure for paraffinfluids. Jessen et al. (2004) indicated that CO2 injection in depletedreservoirs containing condensate can help in recovery of the

k

k

Table 6—Summary of the experimental work performed with ID to mitigate condensate-banking problem.




liquid condensate. Recovery efficiency of CO2 injection is deter-mined by the local displacement efficiency and the fluid flowwithin the reservoir (Seto et al. 2007).

Al-Abri and Amin (2009) investigated the fractional conden-sate recovery and relative permeability following supercritical-CO2 injection, methane injection, and the injection of a mixtureof both. The experimental work was performed at a pressure of5,900 psi and a temperature range of 203 to 320�F (95 to 160�C)at a constant velocity inside the cores (10 cm/h). Sandstone coresamples with a porosity range of 13.2 to 14.7% and a permeabilityrange of 22 to 92 md were used. Al-Abri and Amin (2009) foundthat the capacity (volume injected before breakthrough takesplace) of supercritical CO2 was 62% of pore volume (PV). Thiswas larger than the critical volume of the methane/supercriticalCO2 mixture (55% PV) and larger than that of methane only (27%PV). Also, the injection of supercritical CO2 improved the relativepermeability to gas and maximized the recovery of the liquid con-densates. Moradi et al. (2010) studied four scenarios of gas injec-tion in an Iranian condensate reservoir: methane injection, N2

injection, gas recycling, and CO2 injection. They concluded thatCO2 injection achieved the highest liquid and gas recovery amongall other scenarios.

Gachuz-Muro et al. (2011) performed laboratory studies toevaluate the effectiveness of CO2, N2, and dry lean gas in dis-placing condensate from naturally fractured gas/condensate res-ervoirs at a pressure of 8,455 psia and a temperature of 334�F.Test results indicated that CO2 achieved a higher recovery factorthan N2, but a lower recovery factor than natural gas. Soroushet al. (2012) found that CO2 can be used to recover condensatefrom dipping gas/condensate reservoirs, and CO2 injectionachieved higher recoveries than injection of pure methane ormixtures of methane and CO2. Odi (2012) studied the potentialfor CO2 “huff-‘n’-puff” technique to remove gas condensatefrom the near-wellbore region. They found that CO2 has the abil-ity to increase its diffusion into the condensate phase as its con-centration increases.

Kurdi et al. (2012) studied the impact of supercritical-CO2

injection on condensate-bank removal. They investigated thephysics behind the supercritical-CO2 injection through performinga numerical-simulation study by use of a compositional simulator.Kurdi et al. (2012) found that the injection of supercritical CO2

increases the density of gas, decreases the viscosity and density ofcondensate, and lowers the surface tension between the twophases, resulting in a lower capillary pressure. As a result, the re-sidual condensate saturation decreases and condensate recoveryincreases. Taheri et al. (2013) used numerical simulation to studythe performance of miscible and immiscible gas injection toremove the condensate banking in fractured gas/condensate reser-voirs. Under natural depletion, Taheri et al. (2013) found that ex-istence of fractures causes higher condensate saturation in thematrix block and higher condensate recovery. Also, miscible gasinjection resulted in higher condensate recovery than immisciblegas injection. Finally, enrichment of stock-tank gas with CO2

decreased the minimum miscibility pressure and, hence, morecondensate was recovered.

CO2 has some problems, which may include its source, stor-age, and transportation. The main source of CO2 is the differ-ent manufacturing processes that result in the emission of CO2

as a byproduct (Gale et al. 2005). The majority of CO2 is pro-duced mainly from the industries that involve the use of differ-ent fossil fuels (Lucci et al. 2011). During transportation ofsupercritical CO2, potential damage may occur to ferrous pipe-line as a direct result of the corrosion process. When the CO2

stream is contaminated by free water (H2O), CO2 will dissolvein water and form carbonic acid (H2CO3), as shown by the fol-lowing equation:

CO2 þ H2O() H2CO3: ð2Þ

Although H2CO3 is a weak acid, it is corrosive to mild steel (Rus-sick et al. 1996; George and Nesic 2007; McGrail et al. 2009).

Discussion. Although gas cycling appears to be an ideal solutionto the retrograde condensation problem, there are a number of fac-tors that affect this method of operation adversely: income fromgas sales is deferred, substantial initial investment for compres-sion and injection is required, makeup gas must be purchased, andprolonged project life with inefficient gas-plant usage resulting inhigh cumulative operating costs. Therefore, in evaluating the eco-nomics of exploiting any wet-gas reservoir by use of gas-cyclingprocesses, all the advantages and disadvantages must be evaluatedcarefully.

Theoretically, gas cycling to replace 100% of the produced flu-ids can be the optimum solution to prevent condensate banking ingas/condensate reservoirs. The reinjection of the produced naturalgas was a good solution when the gas prices were very low orwhen it is difficult to transfer the infrastructure of the power-con-suming systems from petroleum-based liquids to gases. Currently,natural gas is very important as a vital source of energy to feedthe factories and electricity-generation plants, making it less eco-nomical to inject in the reservoirs as a pressure-maintenance tech-nique to recover more liquids. The best solution in this case is tostudy the use of N2 and CO2 as alternatives to natural gas for gascycling and to find economic ways to define sources, transporta-tion, storage, and injection capabilities for such gases.

Combination of Different Methods

In the preceding sections of the paper, a review of the differentmethods used to mitigate the condensate-banking problem wasgiven. Table 7 gives a summary of each technique, correspondingworking principle (mechanism), implementation criteria, field(s)where the technique has been applied, and primary conclusions.

A combination of the techniques that were described previ-ously is also a possible technique to mitigate such a problem. Asan example, a combination of drilling horizontal wells andhydraulic fracturing was described by Ignatyev et al. (2011). Acombination of hydraulic fracturing and wettability-alterationchemicals is also one of the methods that can be applied in thefield. The main advantage of such a combination is to create cleanfractures, during which the wettability-alteration chemicals willenhance the flow of gas and increase the gas capacity to return allthe liquid introduced to the formation during the fracturing treat-ment to the wellbore and, hence, to the surface. This method willmaximize the conductivity through the creation of clean pathwaysfor the gas phase to flow through the fracture system toward thewellbore and then to the surface.

A combination of acidizing treatments and the additions ofsolvents (alcohols) was described before by Al-Anazi et al.(2006). The main objective of adding alcohol is to reduce theinterfacial tension between the spent acid and gas, which allowsfor better removal of the liquid that fills the wormhole, while atthe same time enhancing the gas permeability following the acid-stimulation treatment. A combination of wettability alteration andsolvents is another possible method (Al-Yami et al. 2013). Thecombined effect of changing the rock wettability to preferentialgas-wetting with the resulting enhancement in gas permeabilityand lowering the interfacial tension between gas and liquids givesa superior advantage to this combined system.

A combination of horizontal wells and wettability alterationcan provide maximum benefits and performance when the bestplacement techniques (coiled tubing or use of chemical diverter)are used. These placement techniques will be used to better dis-tribute the wettability-alteration chemicals throughout the hori-zontal section of the well, which is open to flow. A combinationof different methods can enhance the performance of the well. Itis very important to understand these different combinations byuse of numerical simulators and experimentally in laboratories, tooptimize the treatment and maximize the well performance.

Conclusions

Condensate banking in a gas/condensate reservoir can decreaseboth the gas- and liquid-production rates severely. After a

. . . . . . . . . . . . . . . . . . . . .




thorough review of the literature on the methods that were used tomitigate the condensate- and water-banking problems, the follow-ing conclusions can be made:1. Gas cycling can be used to increase the reservoir pressure

(pressure maintenance), which will enhance the condensate re-covery and also could help to mitigate the condensate-bankingproblem.

2. Drilling horizontal wells and hydraulic fracturing will increasethe contact area between the reservoir and the well, which willhelp to delay the condensate-banking problem and reduce itsimpact on well deliverability, but they will not be an effectivepermanent solution for condensate banking.

3. Wettability-alteration chemicals may present a robust solutionfor the condensate-banking problem. However, literaturereported only one successful case study.

4. The advantages of using wettability-alteration chemicals overother techniques include cost effectiveness, durability, andflexibility of design to accommodate varying reservoirconditions.

5. Solvents (such as methanol, isopropyl alcohol, or a mixture ofboth) were effective in removing condensate and water accu-mulation in laboratory and experimental tests on core samples,

but only gave a short-term improvement in the field trial. Thetreatment has to be repeated to remove the liquid bank fromthe region around the wellbore.

6. Use of carbon dioxide can represent a future technique that canbe used to mitigate the condensate-banking problem.

Nomenclature

h ¼ formation thickness, L, ftk ¼ rock permeability, L2 , md

kh ¼ formation capacity, L3, md-ftkH ¼ horizontal permeability, L2, mdkrg ¼ relative permeability to gas, dimensionlesskro ¼ relative permeability to oil, dimensionless

kV ¼ vertical permeability, L2, md

Pav ¼ average reservoir pressure, mL–1t–2, psiPc ¼ capillary pressure, mL–1t–2, psi

Pdew ¼ dewpoint pressure, mL–1t–2, psiPi ¼ initial reservoir pressure, mL–1t–2, psi

Pr ¼ average reservoir pressure, mL–1t–2, psi

Pwf ¼ flowing bottomhole pressure, mL–1t–2, psi

kH kV

krg

Table 7—Summary of the methods and techniques used to mitigate the condensate-banking problem.




P2 ¼ upper dewpoint pressure, mL–1t–2, psiP3 ¼ pressure at which condensation is maximum (point pres-

sure), mL–1t–2, psire ¼ well-drainage radius, L, ftrw ¼ wellbore radius, L, ftSo ¼ oil saturation, dimensionless

Sw ¼ water saturation, dimensionlessTC ¼ critical temperature, T, �F or �R

TCT ¼ cricondentherm temperature, T, �F or �Rc ¼ interfacial tension, mt–2, dyne/cmh ¼ contact angle, degrees/ ¼ rock porosity, dimensionless

Acknowledgment

The authors would like to thank Saudi Aramco for permission topublish this work.

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Mohammed A. Sayed is a research scientist in the ProductionTechnology Team at Aramco Services Company, AramcoResearch Center–Houston. His research interests include thedevelopment of fluids used in acidizing carbonate reservoirs,both matrix and fracturing; fluids for hydraulic fracturing; acid-izing additives; gel breakers; chemicals for scale and corrosioninhibition; and wettability-alteration chemicals. Sayed haspublished several SPE conference and journal papers on acid-izing, and he holds five patents. He holds BSc and MScdegrees in petroleum engineering from Cairo University and aPhD degree in petroleum engineering from Texas A&M Univer-sity. email: [email protected].

Ghaithan A. Al-Muntasheri is a petroleum engineer working forthe US subsidiary of Saudi Aramco, Aramco Services Com-pany, in Houston. He is the lead and founder of the ProductionTechnology Team of Aramco Research Center–Houston. Al-Muntasheri is still affiliated with the EXPEC Advanced ResearchCenter of Saudi Aramco in Dhahran, Saudi Arabia, and hasbeen working for Saudi Aramco for the last 13 years. He alsohas an adjunct associate professor appointment at Rice Uni-versity. Al-Muntasheri has published 45 papers in refereed jour-nals and international conferences. He holds BS and MSdegrees, both with honors, in chemical engineering from KingFahd University of Petroleum and Minerals, Dhahran, SaudiArabia, and a PhD degree in petroleum engineering, withhonors, from Delft University of Technology, The Netherlands.Al-Muntasheri served as the chair of the SPE Saudi Arabia Sec-tion for the 2011–12 term. He also served as the chair of the2011 Annual Technical Symposium & Exhibition. Al-Muntasherihas received several awards, including the 2014 SPE Outstand-ing Young Member Service Award, the 2011 SPE Century ClubAward, the 2011 SPE Outstanding Young Member RegionalAward, the 2011 World Oil Award for the Best ProductionChemical, the 2009 EXPEC ARC Award for the Best Mentor,and the 2008 EXPEC ARC Award for the Best Technical Presen-tation. He serves as a technical reviewer for SPE Journal, Jour-nal of Canadian Petroleum Technology, and for the ArabianJournal for Science and Engineering. Al-Muntasheri is a mem-ber of SPE.





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Mititigation of the Effect of Condensate Banking- A Critical Review

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