18 Journal of Canadian Petroleum Technology

Gas Condensate Reservoir Performance

F.B. THOMAS Hycal Energy Research Laboratories Ltd.

G. ANDERSEN Chevron/Texaco

D.B. BENNION Hycal Energy Research Laboratories Ltd.

Peer reviewed PaPer (“review and Publication Process” can be found on our website)

BackgroundThis paper discusses performance of gas condensate reservoirs.

These reservoirs have a reservoir temperature located between the critical point and the cricondentherm on the reservoir fluid’s pres-sure-temperature diagram. This is the only unique and accurate means of identifying gas condensate reservoirs; any other defini-tion [condensate-gas ratio, C7+ molecular weight (MW) or C7+ API gravity] is specious and ersatz.

In these reservoirs, as the pressure drops, vapour and liquid phases result. Capillary pressure causes phase interference which usually reduces gas productivity. A cross-section of interesting topics that show the complexities of gas-condensate reservoir pro-duction have been reported in the literature(1-7). All of the relevant parameters, if well understood, will lead to more accurate evalu-ation of the amount of hydrocarbon in place, the rate at which the resource can be produced and the optimization strategies as the reservoir matures.

IntroductionIn this paper, retrograde condensate characterization and proper-

ties measurement, explicit relative permeability and two-phase dy-namic steady-state measurements are discussed. Notwithstanding

AbstractGas condensate reservoirs exhibit complex coupling between

phase behaviour, interfacial tension, velocity and pore size dis-tribution. Appropriate characterization of the in situ fluids and relevant flow testing can provide valuable insight into gas con-densate reservoir forecasting. The following insights were ob-tained during the course of this testing:

1. The importance of path dependence was shown to be sig-nificant when creating equilibrium phases below saturation pressure for use in quantifying phase interference. Differ-ences, due to compositional path, in API gravity of liquids in solution were quantified to be as much as 10 degrees, with molecular weight differences over 110 daltons.

2. End-point saturations, such as trapped gas and residual con-densate saturation, are sensitive to the level of interfacial tension (IFT). Critical condensate saturation was less sensi-tive to IFT (pressure).

3. The two-phase injection approach and the protocol whereby explicit measurement of relative permeability is performed provide a very thorough gas-condensate reservoir data set, which are amenable for use in simulation and reservoir pro-duction forecasting.

the very specific nature of this paper in quantifying phase behav-iour-fluid flow coupling in the laboratory, it was considered impor-tant to provide a short commentary on sampling of gas condensate fluids that form the foundation on which experimental gas conden-sate testing is built. Extensive treatment of this theme was beyond the scope of the current paper.

Retrograde Condensate SamplingThe bottomhole flowing pressure (PBHF) must be lower than res-

ervoir pressure to induce flow. If the PBHF is less than dew point pressure then liquids drop out in the porous media around the pro-duction well. The gas is much more mobile than the condensate and, therefore, the gas-condensate ratios (GCR) exhibited at sur-face are commonly higher than that of the reservoir fluid.

A further complication of this problem is that the composition of the surface liquid also changes. When the PBHF is above dew point, the MW of the surface liquid is the highest. Figure 1 shows the change in composition incident to decreasing bottomhole pressure. The heaviest components are the first to leave the vapour phase; this may occur at pressures just below the dew point pressure. The consequence of the compositional change is that the lower the MW of the surface liquid used in the recombination, the lower the ap-parent dew point pressure. Relative to the reservoir pressure, this trend can indicate an increasing degree of under-saturation. How-ever, this is commonly offset by the high GCR mentioned above. For these reasons, multi-rate sampling helps to identify trends in surface-separator fluid properties as a function of changes in PBHF and, therefore, approaches representative reservoir fluid properties by appropriate recombination techniques.

The ideal time to sample is before the PBHF has fallen below the dew point. In this case, slow flow bottomhole sampling (BHS) will capture a representative fluid. The experience of the authors

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C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23

Component

Mo

le F

ract

ion

2 Months 4 Months 7 Months

FIGURE 1: Heavy-end compositional changes.

July 2009, Volume 48, No. 7 19

is that this scenario (PBHF > PDEW) is unusual, however. Typically, sufficient production to induce two-phase near-wellbore flow is encountered before sampling is considered; the earlier the sam-pling occurs, and the lower the drawdown during the sampling, the better.

When some bottomhole samplers are opened, particularly in low-permeability rock, two-phase separation can be induced, de-pending on the degree of under-saturation. Bottomhole sampling is not a panacea for problematic fluid characterization. The one reason for which the authors always recommend BHS along with multi-rate surface sampling however, is due to the fact that there may be solid-liquid separation (waxes). Inclusion of these com-ponents in the characterization can impact the dew point pressure significantly. The authors often see differences in the plus fraction comparing bottomhole samples and surface liquids due to solid separation on the trip up the wellbore. A recent example showed a flashed liquid-phase MW at the separator of 206 and the flashed liquid MW from a BHS at 216 (a 4.6% difference).

Properties Measurements and Equilibrium Fluid Characterization

Once the fluids have been sampled and appropriately charac-terized, then fluid properties need to be measured. Standard vis-cosity and density measurements need to be done along with liquid separation characteristics. Oft times more specialized parameters also need to be measured, including interfacial tension (IFT) and plus-fraction properties. Moreover, if phase interference tests are to be performed, quantities of the fluids large enough to run core floods are required; depending upon the nature of the fluids this can present serious challenges.

This section reports some parameters that were measured on a high-pressure – high-temperature (HPHT) reservoir where the sur-face liquid possessed an API gravity of 39.7 degrees. Reservoir pressure was 82,909 kPa at 119°C (12,025 psi at a temperature of 246°F). The composition of the fluid is shown in Table 1 and Figure 2 presents the liquid drop-out characteristics of the fluid at 119°C (246°F).

TABlE 1: Sample validation compositional analysis of recombined fluid.

Boiling Point Component Chemical Mole Mass (˚F) Name Symbol Fraction Fraction Calculated Properties

-320.4 Nitrogen N2 0.0024 0.0026 Total Sample -109.3 Carbon Dioxide CO2 0.0201 0.0334 -76.6 Hydrogen Sulphide H2S 0.0000 0.0000 Molecular Weight 26.48 -259.1 Methane C1 0.8243 0.4997 -128.0 Ethane C2 0.0509 0.0578 -44.0 Propane C3 0.0346 0.0576 C6+ Fraction 10.9 i-Butane i-C4 0.0067 0.0146 30.9 n-Butane n-C4 0.0106 0.0234 Molecular Weight 176.28 82.0 i-Pentane i-C5 0.0036 0.0098 Mole Fraction 0.0442 97.0 n-Pentane n-C5 0.0025 0.0069 Density (g/cc) 0.8303 97 - 156 Hexanes C6 0.0016 0.0053 156 - 208.9 Heptanes C7 0.0022 0.0084 C7+ Fraction 208.9 - 258.1 Octanes C8 0.0058 0.0248 258.1 - 303.1 Nonanes C9 0.0036 0.0175 Molecular Weight 172.08 303.1 - 345 Decanes C10 0.0027 0.0146 Mole Fraction 0.0423 345 - 385 Undecanes C11 0.0024 0.0132 Density (g/cc) 0.8338 385 - 419 Dodecanes C12 0.0019 0.0116 419 - 455 Tridecanes C13 0.0022 0.0148 C12+ Fraction 455 - 486 Tetradecanes C14 0.0023 0.0162 486 - 519.1 Pentadecanes C15 0.0015 0.0116 Molecular Weight 270.68 519.1 - 550 Hexadecanes C16 0.0013 0.0109 Mole Fraction 0.0179 550 - 557 Heptadecanes C17 0.0011 0.0097 Density (g/cc) 0.8746 557 - 603 Octadecanes C18 0.0010 0.0093 603 - 626 Nonadecanes C19 0.0006 0.0064 C30+ Fraction 626 - 651.9 Eicosanes C20 0.0006 0.0061 651.9 - 675 Heneicosanes C21 0.0005 0.0050 Molecular Weight 554.15 675 - 696.9 Docosanes C22 0.0004 0.0050 Mole Fraction 0.0020 696.9 - 716 Tricosanes C23 0.0004 0.0044 Density (g/cc) 0.9807 716 - 736 Tetracosanes C24 0.0004 0.0044 736 - 755.1 Pentacosanes C25 0.0004 0.0047 755.1 - 774 Hexacosanes C26 0.0003 0.0043 Recombination Parameters 774.1 - 792 Heptacosanes C27 0.0003 0.0045 792.1 - 809.1 Octacosanes C28 0.0004 0.0053 Gas-Oil Ratio (cc/cc) 2324.56 809.1 - 826 Nonacosanes C29 0.0004 0.0060 Dead Oil Density (g/cc) 0.8265 Above 826 Tricontanes Plus C30+ 0.0020 0.0428 Dead Oil MW (g/mol) 167.84

NAPHTHENES

120.0 Cyclopentane C5H10 0.0003 0.0007 162.0 Methylcyclopentane C6H12 0.0012 0.0039 178.0 Cyclohexane C6H12 0.0015 0.0048 214.0 Methylcyclohexane C7H14 0.0022 0.0082

AROMATICS

176.0 Benzene C6H6 0.0015 0.0045 231.1 Toluene C7H8 0.0001 0.0003 277 - 282 Ethylbenzene & p,m-Xylene C8H10 0.0006 0.0024 291.9 o-Xylene C8H10 0.0002 0.0009 336.0 1, 2, 4-Trimethylbenzene C9H12 0.0004 0.0017 Total 1.0000 1.0000

Note: Physical properties are calculated based on GPA 2145-00 physical constants. ID.: 433-174

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CO2

H2S C1

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+

20 Journal of Canadian Petroleum Technology

Two discrete levels of pressure were used in subsequent flow quantification (61,363 and 19,995 kPa – 8,900 and 2,900 psi) and, consequently, enough of each phase had to be produced at these pressures for measurement. With retrograde condensation of 2.2 volume% at 61,363 kPa, it was difficult to create sufficient liquid volume for analysis. The high pressures required to reach dew point (73,084 kPa) necessitated the use of smaller HPHT cylin-ders, and yet 2.2% drop-out yielded only about 13 cc of live liquid at 61,363 kPa from the 700 cc HPHT recombination cylinder. Mul-tiple recombinations had to be done to yield sufficient liquid at 61,363 kPa for analysis.

For HPHT fluids, it is usually not possible to synthesize the equilibrium liquid phase directly. Figure 3 shows the MW data of the liquid that is vapourized in the gas phase (after flashing to STP) as a function of pressure at reservoir temperature, as well as the overall MW of the lower phase.

The MW of the equilibrium liquid at the highest pressure can be approximated by the trend line in Figure 4. The linear trend in-dicates that, at a pressure just below the dew point pressure (73 MPa), the liquid that would first leave the vapour phase would have an MW of 279.1 – an MW very close to that of C20.

The correlation of API gravity indicates that the API of the first liquids to drop out of the vapour phase, just below dew point pres-sure, would be 28.9 degrees (density of 0.882 g/cc). Remember that the API of the flashed separator liquid was about 40 degrees. It is therefore impossible to create representative equilibrium lower phase, at the higher pressures, simply by using the separator liquid and synthetic gases for direct recombination. The amount of liquid that would drop out of solution with this character would be less than 0.10 volume%. To measure the properties and flow charac-teristics at high pressure would require a minimum of 30 ml of equilibrium liquid. With 0.10% liquid drop-out and the HPHT dew point condition, it could require as many as 43 sequential recombi-nations in a 700 cc HPHT cylinder and would necessitate as much as 4,300 cc of separator liquid in the recombinations. The path fol-lowed to prepare the representative lower phase includes recom-bining 100 cc of separator liquid with the corresponding gas phase volume, equilibrating at or above dew point pressure and reser-voir temperature and then subsequent equilibration at a pressure below dew point, followed by collection of the lower phase. The separator liquid is vapourized and then the equilibration step below dew point causes the heavier compounds to condense; the heaviest components can not exist as a vapour at pressures just below the dew point. This is the path that must be followed to create the rep-resentative liquid phase. If phase interference testing were to be performed then the fluid volumes would have to be at least 10

times this volume or, in other words, 430 sequential recombina-tions of 700 cc and 43 l of separator liquid would be required.

As seen from Figure 3, the separator liquid possesses an MW of 165 and, as shown, simply adding gas to the separator con-densate in order to increase the bubblepoint of the condensate phase to 40,679 kPa results in a MW of 164 instead of 228; essen-tially no significant selection has occurred in the components that drop out. If one approaches the creation of the equilibrium lower phase by trying to synthesize directly from the separator liquid without complete vapourization and selective condensation, then the lower phase will not be representative. The synthetic liquid at 40,679 kPa and 119°C exhibited an IFT 25% lower than the actual value, and the synthetic liquid had a GOR of 491 m3/m3 instead of 249 m3/m3.

Table 2 reports the properties that were measured for the phases generated from the appropriate recombination and subsequent de-pletion path.

Gas Condensate Relative Permeability Testing

Is retrograde condensation going to severely impact gas produc-tion? To answer this question, experimental testing was done using two separate core stacks, each comprised of four core plugs of 3.81 cm in diameter. The properties of the stacks are shown in Table 3.

The stacks were prepared with the relevant water saturations and then a baseline permeability to humidified methane was mea-sured. The methane permeabilities for the two stacks at Swi were 122.1 and 28.4 mD, respectively, at a pore pressure of 62,053 kPag at 119°C (9,000 psi at 246°F). Compared to the single-phase gas permeabilities of 136.1 and 36.0 mD, this decrease in gas permea-bility in the presence of water would be expected since it is thought that most of the water would be associated with the smaller pores which contribute little to the overall permeability of the samples. The core stack was then mounted in an oven at reservoir tempera-ture with two pressure control valves (PCV): one on the injection end and one on the production end. With the PCV in place, the pressure of the injection fluid could be maintained above dew point pressure and the pore pressure of the core could be maintained at specific pressures in the two-phase region. Thus, single phase fluid would enter the first valve, flash into two phases and then liquid and gas flow into the stack. The liquid drop-out characteris-tics were previously measured, and a pore pressure corresponding to 5.9% liquid drop-out of 20,684 kPag (3,000 psi) was chosen; condensate saturation is dictated by the volume of dew point fluid

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Ret

rog

rad

e Li

qui

dA

ccum

ulat

ion

(%)

V/Vtot V/Vdp

FIGURE 2: Constant composition expansion at 119˚C.

82.2 74.0 113.3

48.6 57.8

259.7 228.08199.13

163.61 165.01

050

100150200250300

61.4 40.7 20 Syn 40.7 Sep Liq

Fluid Type (Equilibrium Pressure)

MW

MW low Flashed

FIGURE 3: Summary of lower phases.

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45MW API Gravity Linear (API Gravity) Linear (MW)

MOLECULAR MASSAPI Gravity

y = 0.001573x + 164.171257 R2 = 0.996099

y = -0.0001477x + 39.6578907R2 = 0.9932095

FIGURE 4: Lower phase MW and API gravity.

TABlE 2: Properties of fluids measured.

liquid Gas

Pressure Viscosity Viscosity IFT

Psia kPa (mPa•s) (mPa•s) (mN/m)

2,900 19,995 0.620 0.031 3.40 5,900 40,679 0.400 0.050 0.95 8,900 61,363 0.350 0.066 0.25 10,600 73,084 0.076 0.076 0.00 12,000 82,737 0.083 13,000 89,632 0.087

July 2009, Volume 48, No. 7 21

injected into the core. The pressure of 20,684 kPag (3,000 psi) was thought to be conservative from a bottomhole flowing pres-sure over the first years of the field project. It was also thought that phase interference effects would not be expected to be this se-rious for many years [reservoir pressure of 82,909 kPag (12,025 psi)]. Although there would be an initial distribution of condensate along the stack, eventually the condensate would reach a critical saturation above which it would start to flow. It was considered that, due to the relatively homogeneous stack, the average critical condensate saturation (CCS) measured would be representative of the overall stack. Once the specific volume of dew point fluid was injected, with its corresponding volume of condensate, equilibrium gas was injected and the end-point permeability to equilibrium gas was measured. Figure 5 shows the relative permeability relation-ship for the second stack. It shows a critical condensate saturation of about 19% at which point the gas permeability had decreased to 17% of its original value. This Scc was considered high, but some porous media has been reported with Scc values well in excess of this(1).

Once the Scc had been attained, the stack was then flooded with equilibrium condensate at 3,000 psi and the displacement history-matched with a two-phase compressible relative permea-bility model. The trapped gas saturation was 12.6% of the pore volume or 16.6% of the initial hydrocarbon in place. Following the condensate saturation the equilibrium gas was then injected at increasing rates up to a rate corresponding to field rates of 1274 E3M3 STP [45 MMscfD; wellbore of 21.6 cm (8.5 inches) and a completion interval of 61 m (200 feet) – 309 m3/ m2-day (1,013 scf/ft2-day)]. The residual condensate saturation to this high rate was 43.3% of the trapped gas end-point condensate saturation. The high-rate gas permeability was Forchheimer corrected to provide a value of 24.8 mD or a regain permeability of 87.5% of the ini-tial Kg value. Figure 6 shows the same relationship, but at 62,053

kPag (9,000 psi). Very little change was observed from the per-spective of gas permeability reduction. For the higher pressure regime, however, with only 2.2% liquid drop out, insufficient sep-arator liquid was available and so a synthetic liquid was prepared. It had properties that were not representative (GOR too high, IFT too low). This synthetic liquid resulted, when flooded into the core stack, in a high mass transfer displacement and was not deemed as representative of hydrocarbon liquid imbibition.

Similar testing was done for the higher permeability stack. The results from this testing are summarized as follows:

1. The high and low permeability stacks exhibited Scc values of 14 and 19% respectively. Critical condensate saturation changed very little as a function of IFT change from 3.4 to 0.25 mN/m (20,684 and 62,053 kPag – 3,000 and 9,000 psi). This is not unexpected since the larger porous features are thought to govern the first condensate mobilized and is not expected to be a strong function of IFT. Residual conden-sate saturation is considered to be a strong function of IFT, although the data measured herein were insufficient to judge conclusively (lack of available low IFT condensate phase).

2. The gas phase permeability at critical condensate saturation (Scc) decreased by 60 and 84% for the high and low perme-ability stacks, respectively.

3. Trapped gas saturations were 13.5% PV for the high perme-ability stack at 20,684 kPag (3,000 psi) and 12.6% PV for the low permeability stack. This may appear to be counterintui-tive, but if the condensate phase is more wetting than the gas, then the smaller porous features might exhibit a degree of spontaneous imbibition that could reduce trapped gas more than a more permeable core. The higher pressure trapped gas saturations were not measured since the synthetic liquid

TABlE 3: Routine permeability and porosity results.

Stack 1

Provided After Cleaning Target Swi length

Plug# Φ, % K, mD Φ, % K, mD (%) (cm) Order*

203A 18.4 151 18.9 169 15.0 6.31 2 209A 17.9 101 18.6 116 15.0 6.33 1 210AH 18.5 120 19.4 118 15.0 6.50 4 212AH 18.5 166 19.2 157 15.0 6.44 3 Khavg 25.58 136.06

Stack 2

Provided After Cleaning Target Swi length

Plug# Φ, % K, mD Φ, % K, mD (%) (cm) Order*

216A 17.3 32.2 18.0 39.9 25.0 6.49 3 224B 17.0 25.0 17.6 34.4 25.0 6.23 4 225 17.1 31.0 17.8 40.7 25.0 6.34 1 225AH 16.3 25.3 17.7 32.7 25.0 6.35 2

Khavg 25.41 36.63 * Huppler Ordering - 1 at injection and 4 at production end.

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Gas Saturation

Gas

Per

mea

bili

ty (m

D)

Gas Permeability 1-Swi Hysteresis Gas Liquid Perm

Scc = 19.4%

Scr

FIGURE 5: Results of condensate interference testing; Stack #2 - Temperature = 246˚F and Pressure = 20,684 kPa.

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Gas Saturation

Gas

Per

mea

bili

ty (m

D)

Gas Permeability 1-Swi Liq. Perm Hyst. Kg

Scc = 19.3%

FIGURE 6: Results of condensate interference testing; Stack #2 - Temperature = 246˚F and Pressure = 62,053 kPa.

22 Journal of Canadian Petroleum Technology

phase had excessive mass transfer and trapped gas values were unrealistic (apparent value of 3% was determined).

4. The importance of using representative equilibrium fluids became paramount since subtle changes in IFT could affect the displacement efficiency significantly; analogue fluids that possess the viscosity, density and IFT characteristics of the true equilibrium phases are very difficult to create.

Two-Phase Steady-State Injection

Some authors(8) have suggested that the high rates experienced near production wells clean up any condensate that might drop out contrary to what has been measured here and elsewhere. To simu-late more directly what might happen in the field, the experimental protocol was modified so that multiple volumes of dew point fluid could be injected until a dynamic steady-state was observed. Once stable differential pressure was attained, the permeability of each phase was calculated based on the volume fraction condensed, as measured in the constant composition expansion. Figure 2 showed the liquid drop-out as a function of pressure below the dew point and Figure 7 shows an example of the differential pressure history from fluid injection into the second core stack at different rates.

A number of rates were examined corresponding to a range of capillary number from 6.99 × 10-7 to 4.44 × 10-5. Appendix A shows the way the authors calculated the capillary number.

Tables 4 and 5 show the results of the two-phase injection and include the calculated end-point permeabilities, the back pressure,

fluid type, differential pressure, and superficial and pore-scale cap-illary numbers. The superficial capillary numbers were corrected for porosity and immobile water saturation to reflect pore-scale velocities; this corresponds to the columns of pore-scale capil-lary numbers. The viscosities of the phases were reported earlier in Table 2.

Contrasting the permeabilities for the gas to those measured as part of the critical condensate experimentation provides corrob-oration of the different methods. Figure 5 shows the gas-phase permeability to be approximately 5 mD at the critical condensate saturation, whereas Table 2 reports gas-phase permeabilities of 1 to 3 mD. The value of 2.9 mD would be expected to occur at about 25% condensate saturation from Figure 5, which may be the equi-librium saturation at which the accumulation of condensate ceased. This would be expected since the residual condensate saturation is always higher than the critical condensate saturation and the re-sidual condensate saturation will largely dictate the end-point gas permeability. The two techniques agree very well with each other. On the basis of flux calculations, the highest capillary number that was possible to run in the laboratory corresponded to rates of 318 E3m3 (11.25 MMscfD) compared to 1,274 E3m3 (45 MMscfD) which was contemplated as the expected production rate at which the operator would produce the well. Figure 8 shows the plot of permeability as a function of capillary number. This relationship suggests that, although rate may be increased, the permeability to gas is already approaching asymptotic and, therefore, the rate used in the experimentation is thought to yield gas permeabilities that would be representative.

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refill pump

FIGURE 7: Differential pressure history - injection at 10,400 psi and BPR at 6,000 psi.

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Eff

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erm

eab

ility

(mD

)

y = 0.7541711Ln(x) + 12.0105453

R2 = 0.5342982

FIGURE 8: Gas permeability vs. capillary number.

TABlE 4: Calculations for two-phase injection at 20,684 kpa (3,000 psi) back pressure.

Pore level Pore level Rate (cc/hr) Kg (mD) Kc (mD) Fluid Type dP (psi) Nca Gas Nca liquid Nca Gas Nca liquid

150 1.046709901 Gas 85 6.996E-07 4.910E-06 150 1.515201521 Condensate 85 1.013E-06 7.107E-06 2,000 2.647926833 Gas 448 9.328E-06 6.546E-05 2,000 3.833099087 Condensate 448 1.350E-05 9.476E-05 150 1.482839027 Gas 60 6.996E-07 4.910E-06 150 2.146535489 Condensate 60 1.013E-06 7.107E-06 2,800 2.913648614 Gas 570 1.306E-05 9.165E-05 2,800 4.217753943 Condensate 570 1.891E-05 1.327E-04 1,000 2.118341466 Gas 280 4.664E-06 3.273E-05 1,000 3.06647927 Condensate 280 6.752E-06 4.738E-05 500 1.577488326 Gas 188 2.332E-06 1.637E-05 500 2.283548392 Condensate 188 3.376E-06 2.369E-05 2,000 2.67178203 Gas 444 9.328E-06 6.546E-05 2,000 3.867631511 Condensate 444 1.350E-05 9.476E-05 2,800 2.94987515 Gas 563 1.306E-05 9.165E-05 2,800 4.270194933 Condensate 563 1.891E-05 1.327E-04 1,000 2.118341466 Gas 280 4.664E-06 3.273E-05 1,000 3.06647927 Condensate 280 6.752E-06 4.738E-05 500 1.579168292 Gas 187.8 2.332E-06 1.637E-05 500 2.285980286 Condensate 187.8 3.376E-06 2.369E-05 150 1.034538856 Gas 86 6.996E-07 4.910E-06 150 1.497582899 Condensate 86 1.013E-06 7.107E-06

July 2009, Volume 48, No. 7 23

Figure 9 shows the condensate permeability as a function of capillary number. The values again appear to be approaching as-ymptotic behaviour at the rates reached in the laboratory. Figure 10 shows all of the data on the same figure with an R2 value of 0.54.

DiscussionThe values that derive from this plot place the permeabilities

in the range of gas-phase permeabilities that were observed just above critical condensate saturation in the critical condensate testing. This seems intuitively consistent and corroborates both ex-perimental procedures.

Ultimately, flow in porous media should yield to quantification by use of an expression, such as Equation (1). However, the func-tion K(r) is not known and appears to be relatively specific to each fluid and rock system. Some simulators use explicit relative per-meability curves such as those in Figures 5 and 6, whereas others use permeability as a function of capillary number (Figures 8 to 10).

dQPL

K r f r rdrO

RMax

= ( ) ( )∫∆µ

π2............................................................... (1)

The relatively close agreement between the two techniques used in this work is pleasing from a forecasting perspective. The explicit relative permeability measurements allow for a more complete set of data to be measured, including trapped gas, residual conden-sate and critical condensate saturations, providing that fluids can be created which represent those experienced in situ. However, the two-phase continuous flow approach provides empirical evidence of what permeability reduction may be experienced. The two data sets, when taken together, are conclusive as to what productivity challenges will be experienced during pressure depletion.

SummaryThe results of this work can be summarized as follows:1. For explicit measurement of relative permeability in retro-

grade condensate reservoirs, the compositional path of the flowing fluid in the reservoir must be followed in the prepa-ration of fluids for the experiments.

2. Retrograde condensate resulted in a very rapid decrease in gas permeability – 60 and 84% reduction in Krg by the attain-ment of critical condensate saturation.

3. End-point saturations, such as trapped gas and residual con-densate saturation, are sensitive to the level of interfacial ten-sion (therefore, pressure). Critical condensate saturation was much less sensitive to levels of IFT (pressure).

4. Two-phase testing as a function of capillary number indicated an effective gas permeability very close to that measured by the explicit relative permeability measurements at saturations just higher than the critical condensate saturation.

5. The condensate and gas permeabilities measured during the gas-phase hysteresis injection did not agree with those mea-sured during the two-phase injection.

6. The two-phase injection approach and the protocol whereby explicit measurements of relative permeability are performed provide a very thorough gas-condensate reservoir data set which are amenable for use in simulation and reservoir pro-duction forecasting.

NomeNClaTureGCR = gas condensate ratio (m3 gas/ m3 liquid)GOR = Gas Oil Ratio (m3 gas/ m3 liquid)PBHF = bottomhole flowing pressureScc = critical condensate saturation

TABlE 5: Calculations for two-phase injection at 41368 kpa (6000 psi) back pressure. Pore level Pore levelRate (cc/hr) Kg (mD) Kc (mD) Fluid Type dP (psi) Nca Gas Nca liquid Nca Gas Nca liquid

160 6.076439975 Gas 14.8 2.542E-06 1.784E-05 160 3.498076011 Condensate 14.8 1.464E-06 1.027E-05 300 2.897271638 Gas 58.2 4.767E-06 3.345E-05 300 1.667897067 Condensate 58.2 2.744E-06 1.926E-05 2,000 5.098146918 Gas 220.5 3.178E-05 2.230E-04 2,000 2.934893706 Condensate 220.5 1.830E-05 1.284E-04 2,800 5.245993179 Gas 300 4.449E-05 3.122E-04 2,800 3.020005623 Condensate 300 2.561E-05 1.797E-04 160 2.366613464 Gas 38 2.542E-06 1.784E-05 160 1.362408552 Condensate 38 1.464E-06 1.027E-05 300 2.989737754 Gas 56.4 4.767E-06 3.345E-05 300 1.721127825 Condensate 56.4 2.744E-06 1.926E-05 2,000 5.168466186 Gas 217.5 3.178E-05 2.230E-04 2,000 2.975374998 Condensate 217.5 1.830E-05 1.284E-04 2,800 5.377748005 Gas 292.65 4.449E-05 3.122E-04 2,800 3.095854047 Condensate 292.65 2.561E-05 1.797E-04

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

0.000E+00 5.000E-06 1.000E-05 1.500E-05 2.000E-05 2.500E-05 3.000E-05

Capillary Number

Liq

uid

Per

mea

bili

ty

Condensate - 3000 PSI Condensate - 6000 PSI

FIGURE 9: Condensate permeability vs. capillary number.

0

1

2

3

4

5

6

7

0.00

E+00

5.00

E-06

1.00

E-05

1.50

E-05

2.00

E-05

2.50

E-05

3.00

E-05

3.50

E-05

4.00

E-05

4.50

E-05

5.00

E-05

Nca

Per

mea

bili

ty (m

D)

GAS - 3000 PSI LIQUID - 3000 PSI

GAS - 6000 PSI LIQUID - 6000 PSI

FIGURE 10: Permeability vs. capillary number.

24 Journal of Canadian Petroleum Technology

reFereNCeS 1. CHEN, H.L., WILSON, S.D. and MONGER-MCCLURE, T.G., De-

termination of Relative Permeability and Recovery for North Sea Gas-Condensate Reservoirs; SPE Reservoir Evaluation & Engi-neering, Vol. 2, No. 4, pp. 393-402, August 1999.

2. MELEAN, Y., BUREAU, N. and BROSETA, D., Interfacial Effects in Gas-Condensate Recovery and Gas-Injection Processes; SPE Res-ervoir Evaluation & Engineering, Vol. 6, No. 4, pp. 244-254, August 2003.

3. MOTT, R., Engineering Calculations of Gas-Condensate-Well Pro-ductivity; SPE Reservoir Evaluation & Engineering, Vol. 6, No. 5, pp. 298-306, October 2003.

4. KOKAL, S., AL-DOKHI, M. and SAYEGH, S., Phase Behavior of a Gas-Condensate/Water System; SPE Reservoir Evaluation & Engi-neering, Vol. 6, No. 6, pp. 412-420, December 2003.

5. JESSEN, K. and ORR, JR., F.M., Gas Cycling and the Development of Miscibility in Condensate Reservoirs; SPE Reservoir Evaluation & Engineering, Vol. 7, No. 5, pp. 334-341, October 2004.

6. FEVANG, O. and WHITSON, C.H., Modeling Gas-Condensate Well Deliverability; SPE Reservoir Engineering, Vol. 11, No. 4, pp. 221-230, November 1996.

7. SAEVAREID, A., WHITSON, C.H. and FEVANG, O., An En-gineering Approach to Measuring and Modeling Gas Condensate Relative Permeabilities; paper SCA 9930 presented at the Interna-tional Symposium for the Society of Core Analysts, Golden, CO, 1-4 August 1999..

8. CARLSON, M.R. and MYER, J.W.G., Reduced Productivity Im-pairment for Fracture Stimulated Gas Condensate Wells; Journal of Canadian Petroleum Technology, Special Edition, Vol. 38, No. 13, Paper 97-10-19, pp. 1-9, 1999.

Appendix ACalculation of Capillary Number

Nvelocity vis ityInterfacial TensionCA = cos

where units are v = cm/s, μ = mPa – s = 0.001 kg

m s− and σ =

mN/m = 0.001 kg

s2 .

Using the data from Table 4, Item 1, the following capillary number is calculated:

Ncchr

hr

cm

mcmCA = (150

136 005

1

11 401

1100

2 2532, .

. )) ( ) ×0 9322 0 031 0 001

3 401 0 0012

. . .

. .

kgm s

mNm

kg

s

mNNm

= 6 9963 10 7. -×

Provenance—Provenance—Original Petroleum Society manuscripts, Gas Condensate Reservoir Performance: Part I –Fluid Character-ization (2006-100) and Gas-Condensate Reservoir Performance: Part II—Flow Characterization (2006-101), first presented at the 7th Ca-nadian International Petroleum Conference (the 57th Annual Technical Meeting of the Petroleum Society), June 13-15, 2006, in Calgary, Alberta. Abstracts submitted for review December 1, 2005; editorial comments sent to the author(s) December 17, 2008; revised manuscript received April 21, 2009; paper approved for pre-press April 21, 2009; final approval June 9, 2009.

Authors’ BiographiesBrent Thomas is Director of Phase Be-haviour and EOR Research for Hycal En-ergy Research Laboratories Ltd., and a Project Engineer working in the area of nu-merical analysis, phase interference in po-rous media and gas injection. He received his Ph.D. from Washington University in chemical engineering. Brent has over 25 years of domestic and international expe-rience in the area of numerical simulation, gas injection, phase behaviour, solids pre-

cipitation and chemical and thermal applications. He has authored/co-authored numerous technical papers and received the 1992 “Best Technical Paper of the Year” award from the Petroleum So-ciety (Experimental and Theoretical Studies of Solids Precipitation from Reservoir Fluids). He was selected as a Distinguished Author for the Petroleum Society in 1995. Brent was chosen to be a Dis-tinguished Lecturer for the SPE in the area of gas condensate res-ervoirs in 2003/2004. G. Andersen – biography and photo not available.

Brant Bennion received his B.Sc. and Ph.D. degrees in chemical and petroleum engineering from the University of Calgary. He has served in the Petroleum Society in a number of capacities over the last two de-cades, including having been a Director of the Petroleum Society on both the Calgary Section and National Boards, and holding various positions such as Continuing Ed uca-tion Director, Student Affairs Director, Sec-retary, CIPC Technical Program Chairman,

CIPC General Co-Chairman and Chairman, Chairman-Elect and 2002 Chairman of the Society. He is the former Chairman of the Editorial Review Board of the JCPT and currently serves as a member of the Board of Directors of the Petroleum Society Edu-cational Trust Fund. He has served as a Distinguished Lecturer for the Petroleum Society in 2003 and also as a Distinguished Lec-turer for the SPE in 2001-2002. Brant has presented/co-authored/published over 200 technical papers on a variety of topics related to formation damage, flow in porous media, phase behaviour, over and underbalanced drilling and enhanced oil recovery over the last two decades. He received Best JCPT Published Technical Paper of the Year awards from the Petroleum Society in 1993, 1995 and 2001 and also several Best Presented Paper awards from the CIPC. Brant has lectured at the University of Calgary, as well as taught courses on a worldwide basis in the petroleum industry in over 40 different countries.