MISCIBILITY EFFECTS OF OIL-BASE MUD AND IN-SITU GAS … · MISCIBILITY EFFECTS OF OIL-BASE MUD AND...

SPWLA 54th Annual Logging Symposium, June 22-26, 2013

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MISCIBILITY EFFECTS OF OIL-BASE MUD AND IN-SITU GAS ON CONVENTIONAL WELL LOGS

Hamid Hadibeik, Essi Kwabi, Carlos Torres-Verdín, and Kamy Sepehrnoori, The University of Texas at Austin

Copyright 2013, held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors. This paper was prepared for presentation at the SPWLA 54th Annual Logging Symposium held in New Orleans, Louisiana, June 22-26, 2013.

ABSTRACT Oil-base muds (OBMs) are often preferred over water-base muds for many applications, including hostile environments such as high-temperature, high-pressure drilling. However, because the base fluid in OBM is oil, OBM filtrate tends to mix readily with reservoir hydrocarbon during invasion. When reservoir hydrocarbon and OBM filtrate properties are not similar, as is in the case of gas-bearing formations, near wellbore fluid properties can be greatly affected by invasion. Consequently, wireline logs such as neutron, density, sonic, and nuclear magnetic resonance (NMR) can be affected by compositional fluid mixing. Recent field data collected in deepwater plays show that fluid miscibility effects could explain questionable nuclear-log readings across gas reservoirs. This study investigates and quantifies thermodynamic reservoir conditions that facilitate reservoir gas dissolution into OBM filtrate during invasion and the consequent effect on neutron-density logs. Phase behavior of hydrocarbon fluids indicates that any multi-component system, under given temperature and pressure conditions, would exist either in a single phase (liquid or gas) or in multiple phases (liquid and gas). During invasion, formation gas and OBM filtrate form a multi-component system which, under favorable conditions, can exist as a single liquid phase due to the dissolution of formation gas into OBM filtrate. As a result, the large cross-over between neutron-density logs, normally observed within a gas-bearing formation, is significantly reduced by gas-OBM miscibility. Other dynamic reservoir properties, such as wettability, have a less intuitive, yet significant effect on neutron-density logs, thereby requiring a more challenging petrophysical interpretation of well logs. This abnormal gas- OBM miscibility effect could have a measurable impact on formation-tester, NMR, and sonic measurements. We use the University of Texas at Austin’s Petrophysical and Well-Log Simulator (UTAPWeLS) to construct synthetic models to study OBM-gas miscibility effects under various reservoir conditions. The roles of pressure, temperature, overbalance pressure and invasion time, and wettability on OBM-gas miscibility are quantified to identify conditions that enable fluid miscibility. Results indicate that high reservoir pressure, low temperature, high overbalance pressure, and increased invasion time facilitate gas dissolution into OBM filtrate, hence a reduction in neutron-density cross-over. Water-wet systems also provide a favorable condition for the same phenomenon. It is therefore imperative to consider invasion and fluid miscibility during petrophysical interpretations of logs acquired in OBM-drilled wells. The integration of dynamic and static measurements prevents bypassing and/or misidentification of gas-bearing reservoirs for oil- or even water-bearing reservoirs.

INTRODUCTION Differential pressure between drilling fluid and rock formations during overbalance drilling causes mud filtrate to invade permeable rocks (Hadibeik et al., 2009). This invasion causes changes in the near-wellbore fluid properties as mud filtrate displaces in-situ fluid. Wireline logs acquired several hours after drilling can therefore be affected by changes in the invaded zone of reservoir rocks (Hadibeik et al., 2010; Frooqnia et al., 2011). However, conventional log-analysis techniques usually neglect the effects of drilling fluid invasion and, as a result, properties estimated with these techniques may not represent true physical reservoir properties (Mendoza et al., 2007). Interpretation of petrophysical measurements affected by mud-filtrate invasion poses significant technical challenges, especially in the case of gas-bearing reservoirs (Angeles et al., 2007; Malik et al., 2009; Odumosu et al., 2009; Hadibeik et al., 2012). Invasion of oil-based mud (OBM) into a gas reservoir is of particular interest for two reasons: (1) gas properties such as density and hydrogen index are very different from those of OBM filtrate, and (2) gas and OBM filtrate are both hydrocarbons, thus miscible depending on overbalanced or underbalanced drilling conditions


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(Hadibeik et al., 2012). Generally, a mixture of hydrocarbons would exist in a single phase or in multiple fluid phases, based on the phase envelope of the fluid mixture (Orr and Taber, 1987). Because OBM filtrate and reservoir gas are miscible, fluid phase behavior of the ‘reservoir gas - OBM filtrate’ system becomes an important factor to consider during invasion. Furthermore, dynamic reservoir properties such as relative permeability and capillary pressure directly correlate with porosity and permeability (Angeles et al., 2010; Corey et al., 1956; Fetkovich et al., 1986). These properties influence not only the radius of invasion but also the shape of the radial invasion front (Wu et al., 2004; Dussan et al., 2002). In this paper, we evaluate the effect of several static and dynamic reservoir properties on neutron-density logs with emphasis on fluid miscibility effects. Static properties include pressure, temperature, overbalance pressure and time of invasion, while dynamic properties include relative permeability and wettability. Nuclear measurements are simulated assuming generic wireline tools (Mendoza et al., 2007). Neutron porosity assumes a chemical americium-beryllium (AmBe) source while density measurements implement a gamma-gamma response. Numerical simulations are performed using flux sensitivity functions (FSFs) and the linear iterative refinement technique (Mendoza et al., 2007; 2010). Neutron and density porosity logs, reported in sandstone porosity units, are environmentally corrected for an 8-inch, OBM-filled borehole (such as is commonly done in field applications). METHOD A synthetic reservoir model was constructed to simulate neutron and density logs during OBM-filtrate invasion. The model assumes a 20ft gas-bearing siliciclastic formation at irreducible water saturation, positioned between two shale barriers. The sand unit is assumed homogeneous, with isotropic permeability. Table 1 summarizes the assumed rock, fluid, and mud properties; FC22 represents a group of lumped hydrocarbons present in both OBM filtrate and reservoir fluids. Table 2 describes the pressure-volume-temperature (PVT) properties of OBM and in-situ gas.

Reservoir fluid flow capacity depends on saturation-dependent capillary pressure and relative permeability. Capillary and relative permeability curves are assumed to follow Brooks-Corey’s relation (Corey et al., 1956). A three-phase (water-oil-gas) relative permeability and capillary pressure model was used to calculate dynamic petrophysical properties. The model is constructed based on the Stone II method (Stone, 1973; Blunt, 2000) and is defined as follows:

wo

23

0rw rw wtk k S

(1)

Table 1: Summary of the formation, fluid and OBM properties assumed for the simulation of OBM-filtrate invasion into a gas-bearing formation.

Variable Unit Value

Reservoir pressure [psi] 5000

Reservoir temperature [oF] 200

Reservoir porosity [ ] 0.22

Reservoir permeability [mD] 300

Reservoir fluid composition [%] CH4 : 93 FC22 : 7

Overbalance pressure [psi] 100

Days of invasion [days] 0.5

OBM filtrate composition [%] CH4 : 1

FC22 : 99

Table 2: Summary of assumed PVT properties of OBM and in-situ gas.

Parameter Unit CH4 FC22

Critical temperature

[°F] 190.4 804.4

Critical pressure [psi] 45.35 13.26

Acentric factor [ ] 0.008 0.878

Molecular weight

[lb/mole] 16 310


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in an oil-water fluid system , where krw is relative permeability to water, 0rwk is end-point for relative permeability

to water, wo is oil-water saturation exponent, and Swt is normalized water saturation defined as

w wrwt

wr or

S SS

1 S S

, (2)

where Sw is water saturation, Swr is irreducible water saturation, and Sor is residual oil saturation. Relative permeability to oil in the oil-water fluid system is given by

wo

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0row row wtk k (1 S )

, (3)

where krow is relative permeability to oil with respect to water and 0rowk is end-point for relative permeability to oil.

Capillary pressure for the oil-water mixture is defined as

wo

1

0cwo cwo wtP P S

, (4)

where 0cwoP is capillary entry pressure.

In an oil-gas system, relative permeability to oil with respect to gas is calculated as follows:

go

23

0rog rog gtk k (1 S )

, (5)

where krog is relative permeability to oil, 0rogk is end-point relative permeability to oil, go is saturation exponent,

and Sgt is normalized gas saturation given by

g grgt

wr or gr

S SS

1 S S S

, (6)

where Sg is gas saturation and Sgr is residual gas saturation. Relative permeability to gas is given by

go

21

0rg rg gtk k S

, (7)

where krg is relative permeability to gas and 0rgk is end-point for relative permeability to gas. Capillary pressure

between gas and liquid phases is defined as

go

1

0cgo cgo LtP P S

, (8)

where Pcgo is oil-gas capillary pressure, 0cgoP is capillary entry pressure, and SLt is normalized liquid phase

saturation such that

Lt gtS 1 S . (9)

Based on the afore-describe formulation, the UTAPWeLS fluid flow module calculates the interaction between gas and liquid phase in the reservoir. Table 3 summarizes the parameters utilized for the Stone II model. Once reservoir


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and mud properties are defined in the model, the UTAPWeLS wireline nuclear simulator calculates neutron and density tool responses. This simulator is based on Schlumberger’s nuclear parameter code SNUPAR (McKeon and Scott, 1989).

Table 3: Summary of assumed capillary pressure and relative permeability properties of the reservoir.

Variable Unit Value

0rgk [ ] 0.5

0rogk [ ] 0.45

0rowk [ ] 0.9

0rwk [ ] 0.5

0cgoP [psi] 1

0cwoP [psi] 0.5

Sgr [ ] 0.15

Sor [ ] 0.2

Swr [ ] 0.1

go [ ] 2

wo [ ] 5

OIL-BASE MUD IN A GAS RESERVOIR When reservoir gas dissolves in OBM filtrate, the observed neutron-density response can be misleading. The large cross-over between neutron-density logs, normally observed within a gas-bearing formation, is significantly reduced, thereby creating a false impression that the in-situ fluid is oil or water. The type of rock (water-wet, oil-wet or mix wet) can influence the degree of reduction of the neutron-density cross-over.

Effect of Pressure Pressure and temperature govern both material properties and phase. When a single component material exists at a given temperature and pressure, its phase is determined by the corresponding phase diagram. When there is a mixture of components, the phase of the mixture is determined by its corresponding phase envelope. Figure 1 shows a typical phase diagram for a single hydrocarbon component and that of a mixture of oil and gas. As highlighted in that figure, low temperatures and high pressures enable a single liquid phase for a mixture of oil and gas. At high pressures, reservoir gas dissolves into the oil included in OBM filtrate. When reservoir pressure is progressively increased from 2000 psi to 15000 psi, hydrogen index (HI) of the near borehole fluid increases as the fluid transitions from gas to liquid. This behavior translates into higher neutron porosity readings and a smaller neutron-density cross-overs. Figure 2 illustrates the decrease of neutron-density cross-over with increasing pressure. Analysis of the radial distributions of oil and gas saturation and mole fractions of oil and gas components provides a better understanding of the miscibility process. Figure 3 shows the radial distributions of saturation and mole fractions. Even though gas saturation is null in the near-wellbore region at high pressures, the mole fraction of methane is not. Equivalently, while oil saturation is at its maximal value of 1-Swirr, the mole fraction of FC22 is not. This discrepancy between saturation and mole fraction indicates that reservoir gas and OBM filtrate have combined to form a single liquid phase. For better illustration and for convergence of simulations at very high pressures, reservoir fluid composition was modified to 80% CH4 and 20% FC22 for the pressure simulation studies described in Figure 2.


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Figure 1: (a) Typical material phase diagram. (b) Typical phase envelope of an oil-gas system. The highlighted region indicates conditions at which oil and gas co-exist into a single liquid phase.

T = 200 [oF] T = 200 [oF] T = 200 [oF] T = 200 [oF] P = 2000 [psi] P = 5000 [psi] P = 8000 [psi] P = 15000 [psi] (a) (b) (c) (d)

Figure 2: Neutron-density response at (a) 2000 psi, (b) 5000 psi, (c) 8000 psi, and (d) 15000 psi. Track 1: relative depth. Track 2: simulated neutron (NPHI) and density porosity (DPHI) logs in sandstone porosity units. At constant overbalance pressure, an increase in pressure causes a reduction in the neutron-density cross-over. Initial mole fractions of gas and oil in the reservoir are 80% and 20%, respectively.

Effect of Temperature The change in neutron-density response is studied for reservoir temperatures of 100 oF, 200 oF, and 300 oF. Figure 4 shows that an increase in temperature causes a decrease in liquid phase (oil) saturation. Both liquid and gas phases (in this case, OBM filtrate and reservoir gas) are present at high reservoir temperatures. However, as indicated by Figure 5, the effect of temperature change on neutron-density cross-over is less noticeable because temperature has a lower effect on HI than pressure.

Single component (a)

Multi-component system (b)

Liquid+Gas region

Critical point

Liquid region

Gas region

Pre

ssu

re

Temperature

Pre

ssu

re

Temperature

SolidCritical

point

Liquid

Gas

Triple point


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(a) Gas saturation (b) Gas mole fraction

(c) Oil saturation (d) OBM filtrate mole fraction

Figure 3: Radial profiles of oil and gas saturation in the near-borehole region. The radial profiles of mole fraction indicate presence of both reservoir gas and OBM filtrate when gas saturation is null and oil saturation is at its maximal value at high pressures.

(a) Gas saturation (b) Gas mole fraction

(c) Oil saturation (d) OBM filtrate mole fraction Figure 4: Radial distributions of fluid saturation and mole fractions of fluid components at various reservoir temperatures.

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]

P = 2000 [psi] P = 5000 [psi] P = 8000 [psi] P = 15000 [psi] P = 2000 [psi]

P = 5000 [psi] P = 8000 [psi] P = 15000 [psi]

P = 2000 [psi] P = 5000 [psi] P = 8000 [psi] P = 15000 [psi]

P = 2000 [psi] P = 5000 [psi] P = 8000 [psi] P = 15000 [psi]

T = 100 [oF] T = 200 [oF] T = 300 [oF]

T = 100 [oF] T = 200 [oF] T = 300 [oF]

T = 100 [oF] T = 200 [oF] T = 300 [oF]

T = 100 [oF] T = 200 [oF] T = 300 [oF]


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T = 100 [oF] T = 200 [oF] T = 300 [oF] P = 5000 [psi] P = 5000 [psi] P = 5000 [psi] (a) (b) (c) Figure 5: Neutron-density response at (a) 100oF, (b) 200oF, and (c) 300oF. Track 1: relative depth; Track 2: simulated neutron (NPHI) and density porosity (DPHI) logs in sandstone porosity units. Lower temperatures show relatively lower neutron-density cross-over than at higher temperatures. Initial mole fractions of gas and oil in the reservoir are 93% and 7%, respectively.

Effect of Overbalance Pressure (OBP) and Invasion Time The effects of OBP and invasion time are studied simultaneously. Two cases were compared for this study: the first, a 0.5 day mud-filtrate invasion with 100 psi OBP; the second, a 2 day mud-filtrate invasion with 500 psi OBP. Invasion time and overbalance pressure measurably affect the volume of gas detectable with the neutron-density tool. Figure 6 shows that both OBM filtrate and reservoir gas coexist at low OBP and invasion time. Fluid saturations and mole fractions are non-null in the invaded zone. As illustrated in Figure 8 (b), presence of gas is detectable by the relatively large separation between neutron and density logs.

Figure 6: Radial distributions of fluid saturation and mole fractions of fluid components after 0.5 day of invasion at 100 psi OBP. The near-wellbore region shows presence of both reservoir gas and OBM filtrate.

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Mol

e fr

actio

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]Gas

Oil

Gas

OBM filtrate


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At higher OBP and longer invasion times, both gas saturation and mole fraction of gas are null. This phenomenon occurs because, as time progresses, not only does invasion become deeper but filtrate also dissolves any existing residual gas. Oil-base mud filtrate displaces gas further into the reservoir, beyond the radial length of investigation of neutron-density measurements. Therefore, measurements exclusively sense mud filtrate, whereby only a minor cross-over is observed in this case. Figure 7 illustrates the radial fluid distribution calculated for this case, while Figure 8 (c) shows the resulting neutron-density responses.

Figure 7: Radial distributions of fluid saturation and mole fractions of fluid components after 2 days of invasion at 500 psi OBP. The near-wellbore region shows that there is negligible volume of reservoir gas and that hydrocarbon present is mainly OBM filtrate. Oil saturation in the invaded zone reaches a maximum value of 1-Swirr.

Before Overbalance pressure = 100 [psi] Overbalance pressure = 500 [psi] Invasion Invasion time = 0.5 [day] Invasion time = 2 [days] (a) (b) (c)

Figure 8: Neutron-density response (a) before invasion, (b) after 0.5 day of invasion at 100 psi OBP, and (c) after 2 days of invasion at 500 psi OBP. Track 1: relative depth; Track 2: simulated neutron (NPHI) and density porosity (DPHI) logs in sandstone porosity units. Prolonged invasion times and high OBP render neutron-density measurements unable to detect reservoir gas.

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OBM filtrate


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Effect of Relative Permeability Three rock types, one oil-wet and two different water-wet rocks, were used to assess the impact of wettability and relative permeability on well logs. Figure 9 describes the relative permeability and capillary pressure curves for each rock type. Tables 4, 5, and 6 summarize the Stone II model parameters used to construct these rock types. A rock is oil-wet when relative permeability to oil (krow) is less than that of water (krw). The two water-wet rocks considered in this study are different in their preference to gas or oil. Water-wet rock 2 is more permeable to gas than water-wet rock 1. Figure 10 shows the neutron-density tool response calculated for the three rock types. When OBM invades a gas-bearing, oil-wet formation, the neutron-density cross-over remains large; this phenomenon indicates that gas is detectable in the formation. In a water-wet reservoir, however, the cross-over is much smaller, indicating dissolution of gas into filtrate. Therefore, water-wet rocks offer a more favorable condition for OBM and gas miscibility than oil-wet rocks. As a result, OBM filtrate is readily available to dissolve gas. When oil-phase relative permeability increases with respect to that of the gas phase (water-wet rock 2), it gives rise to an increase in oil mobility. Hence, the gas phase is displaced farther away from the wellbore during invasion causing neutron-density logs to detect only filtrate, with an evident decrease in the cross-over between the two logs.

Table 4: Summary of assumed capillary pressure and relative permeability properties of the oil-wet reservoir.

Variable Unit Value

0rgk [ ] 0.7

0rogk [ ] 0.4

0rowk [ ] 0.4

0rwk [ ] 0.65

0cgoP [psi] 2.0

0cwoP [psi] 1.5

Sgr [ ] 0.15

Sor [ ] 0.25

Swr [ ] 0.1

go [ ] 2

wo [ ] 5

Table 5: Summary of assumed capillary pressure and relative permeability properties of the first water-wet reservoir.

Variable Unit Value

0rgk [ ] 0.5

0rogk [ ] 0.4

0rowk [ ] 0.85

0rwk [ ] 0.4

0cgoP [psi] 3

0cwoP [psi] 1.5

Sgr [ ] 0.15

Sor [ ] 0.2

Swr [ ] 0.1

go [ ] 2

wo [ ] 5


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Table 6: Summary of assumed capillary pressure and relative permeability properties of the second water-wet reservoir.

Variable Unit Value

0rgk [ ] 0.3

0rogk [ ] 0.7

0rowk [ ] 0.85

0rwk [ ] 0.4

0cgoP [psi] 3

0cwoP [psi] 3

Sgr [ ] 0.15

Sor [ ] 0.2

Swr [ ] 0.1

go [ ] 10

wo [ ] 10

Oil-wet

Water-wet 1

Water-wet 2

Figure 9: Relative permeability and capillary pressure curves assumed for an oil-wet and two water-wet rocks. Relative permeability to water is high in the oil-wet rock. Water-wet rock 2 is more permeable to the oil phase than water-wet rock 1.

0 0.5 10

0.5

1

k r[ ]

Sw [ ]

krw

krow

0 0.5 10

0.5

1

k r[ ]

SL [ ]

krg

krog

0 0.5 11

2

3

4

Pc[p

si]

Sw [ ]

0 0.5 10

5

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15

20

Pc[p

si]

SL [ ]

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krow

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krog

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si]

Sw [ ]

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si]

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si]

Sw [ ]

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si]

SL [ ]


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Oil-wet Water-wet 1 Water-wet 2 (a) (b) (c)

Figure 10: Neutron-density response in (a) oil-wet rock, (b) water-wet rock 1, and (c) water-wet rock 2. Track 1: relative depth; Track 2: simulated neutron (NPHI) and density porosity (DPHI) logs in sandstone porosity units. Water-wet rocks enable reservoir gas dissolution into OBM.

CONCLUSIONS OBM invasion into gas-bearing reservoirs can give rise to dissolution of residual gas into OBM filtrate under favorable PVT conditions. Therefore, OBM invasion should not be ignored in static petrophysical analysis; a gas-bearing formation can be missed or mistaken for oil- or water-bearing because of the negligible neutron-density cross-over. High-pressure reservoirs and/or heavy OBMs are major factors that can measurably affect neutron-density logs. Combined interpretation of neutron-density logs with other well logs and fluid sampling can help to properly identify hydrocarbon-bearing zones. Simulations of invasion and fluid miscibility can also help to better predict reservoir/fluid properties. Oil-base mud filtrate invasion in gas reservoirs can substantially change a formation’s hydrogen index, thereby affecting neutron logs. The following conclusions stem from the fluid-miscibility studies considered in this paper:

1. An increase of formation pressure in gas reservoirs decreases the cross-over between neutron and density logs.

2. Increasing the overbalance pressure and time of mud-filtrate invasion increases the volume of in-situ gas that dissolves into OBM. This effect causes the neutron-density cross-over to decrease with respect to that at pre-invasion conditions.

3. An increase in reservoir temperature decreases the volume of gas that can be dissolved into OBM. 4. Neutron-density cross-over in gas reservoirs changes with wettability and relative permeability, with the

smallest cross-over measured in water-wet rocks. NOMENCLATURE

k : Absolute permeability, [mD]

0rgk : End point for relative permeability to gas, [ ]

0rogk : End point for relative permeability to oil in the presence of gas, [ ]

0rowk : End point for relative permeability to oil in the presence of water, [ ]


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0rwk : End point for relative permeability to water, [ ]

krg : Relative permeability to gas, [ ]

krog : Relative permeability to oil in the presence of gas, [ ]

krow : Relative permeability to oil in the presence of water, [ ]

krw : Relative permeability to water, [ ]

P : Pressure, [psi]

Pc : Reservoir capillary pressure, [psi]

0Pcgo : Capillary entry pressure between gas phase and oil phase, [psi]

0cwoP : Capillary entry pressure between oil phase and water phase, [psi]

T : Temperature, [oF]

Sgr : Residual gas saturation, [ ]

Sgt : Normalized gas saturation, [ ]

SL : Total liquid saturation, [ ]

SLt : Normalized liquid saturation, [ ]

Sor : Residual oil saturation, [ ]

Sw : Connate water saturation, [ ]

Swr : Residual water saturation, [ ]

go : Gas-oil saturation exponent, [ ]

wo : Water-oil saturation exponent, [ ]

ACRONYMS FSF : Flux Sensitivity Function OBM : Oil-Base Mud OBP : Overbalance Pressure PVT : Pressure-Volume-Temperature SNUPAR : Schlumberger Nuclear Parameter code UTAPWeLS : University of Texas at Austin’s Petrophysical and Well-Log Simulator ACKNOWLEDGEMENTS The work reported in this paper was funded by the University of Texas at Austin’s Research Consortium on Formation Evaluation, jointly sponsored by Afren, Anadarko, Apache, Aramco, Baker-Hughes, BG, BHP Billiton, BP, Chevron, ConocoPhillips, COSL, ENI, ExxonMobil, Halliburton, Hess, Maersk, Marathon Oil Company, Mexican Institute for Petroleum, Nexen, ONGC, OXY, Petrobras, Repsol, RWE, Schlumberger, Shell, Statoil, TOTAL, Weatherford, Wintershall, and Woodside Petroleum Limited.

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Relative Permeability from Formation-Tester Measurements using Design of Experiment and Data-Weighing Inversion: Synthetic and Field Examples”, Journal of Petroleum Science and Engineering, v. 75, Issues 1-2, pp. 19-32.


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Angeles, R., Torres-Verdin, C., Lee, H. J., Alpak, F. O., and Sheng, J., 2007, “Estimation of Permeability and Permeability Anisotropy from Straddle-Packer Formation-Tester Measurements Based on the Physics of Two-Phase Immiscible Flow and Invasion”, SPE Journal, v. 12, no. 3, pp. 339-354.

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Corey, A. T., 1986, “Mechanics of Immiscible Fluids in Porous Media”, Water Resources Publishing Co. Corey, A.T., Rathjens, C.H., Henderson, J.H., and Wyllie, M.R.J., 1956, “Three-Phase Relative Permeability”,

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Invasion in Horizontal Wells and Sensitivity Analysis of Array Induction Tools”, Paper presented at the SPWLA 43rd Annual Logging Symposium, Osio, Japan, June 2-5.

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ABOUT THE AUTHORS Hamid Hadibeik is a Ph.D. candidate in the formation evaluation research program with the Department of Petroleum and Geosystems Engineering at The University of Texas at Austin. He has more than six years of academic and industry experience in petrophysics, formation evaluation, and pore pressure estimation. Hamid has authored and co-authored ten conference and journal papers. He has filed three US patents on the development of unconventional reservoir and pore pressure assessment. His previous work experience was with Maersk Oil and Halliburton Energy Services. Essi Kwabi is a Master’s student with the Department of Petroleum Engineering at The University of Texas at Austin, where she has been working as graduate research assistant in the formation evaluation research group since 2011. She earned a Bachelor’s degree in Biology, with a minor in Chemistry at Worcester State College, MA in 2006 and has five years of industry experience in laboratory analysis of reservoir fluids. She has over two years of academic and industry experience in petrophysics and formation evaluation. Her current research interests include well log analysis in conventional and unconventional plays and formation evaluation. Carlos Torres-Verdín is currently the Zarrow Centennial Professor in Petroleum Engineering with The University of Texas at Austin and is Program Director and founder of the Formation Evaluation Joint Industry Research Consortium. He received a Ph.D. degree in Engineering Geoscience from the University of California, Berkeley, in 1991 and has published more than 114 articles in refereed technical journals, over 158 articles in international conferences, and two book chapters. Dr. Torres-Verdín is co-author of two US patents. Kamy Sepehrnoori is currently a Bank of America Centennial Professor with the Department of Petroleum and Geosystems Engineering at The University of Texas at Austin. He received a Ph.D. in petroleum engineering from The University of Texas at Austin in 1977, and is a world famous expert on computational methods, reservoir simulation, and numerical solutions of partial differential equations. Dr. Sepehrnoori has authored 2 books and published more than 300 technical articles and reports.

MISCIBILITY EFFECTS OF OIL-BASE MUD AND IN-SITU GAS … · MISCIBILITY EFFECTS OF OIL-BASE MUD AND...

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