spe 121649 observations on gas permeability measurements under hpht conditions in reservoir core...

SPE 121649 Observations on Gas Permeability

Measurements under HPHT Conditions in Reservoir Core Materials Exposed to

Cesium Formate Brine

John Downs

Cabot Specialty Fluids

2009 SPE European Formation Damage Conference

Water vapour in natural gas

•Natural gas is saturated with water vapour at reservoir conditions

•Equilbrium water vapour content of gas: - Increases with temperature (and acid gas content)

- Decreases with pressure (and salt content of reservoir fluids)Gas pressure

(psi)

Equilibrium water content of methane* (ppm)

20oC 75oC 125oC 175oC 200oC

100 3,498 57,198 342,907 - -

1,000 465 6,849 39,176 147,234 254,610

5,000 238 2,545 12,293 41,762 61,183

15,000 - - - - 34,902


* Source: AQUAlibrium 3.1

Water vapour in HPHT natural gas – Field example (ref. SPE 114079, Wat et al., 2008)

•Kristin field, offshore Norway- Reservoir temperature 170°C

- Reservoir pressure 13,400 psi

•Prior to formation water production: 1 million Sm3 of produced

gas yields 25 m3 of condensed water (i.e. 25 grams/m3 gas)

•AQUAlibrium prediction for water content of pure methane under

similar conditions: 18 grams water /m3 gas

•Difference: Acid gas content of Kristin gas, and drawdown effect?


Drawdown pressure gradients in gas wells drive vaporisation of water from the formation

Reduction in pore pressure makes gas into a flowing dessicant in vicinity of the wellbore

•Removes water-blocks from tight gas reservoirs - May take weeks, but should stimulate gas production

•Potential for salt precipitation from any fluid residues in gas path?

- Most likely in HPHT gas reservoirs?

- High-salinity connate fluids

- High-salinity brine filtrates if clear completion fluids used

- Likely in tight sandstones/limestones requiring high drawdowns?

See SPE 10779, 13246, 30719, 63161, 84829


Water vapour content of nitrogen gas used in laboratory core flooding test

•Water content of nitrogen gas:- Increases with temperature

- Decreases with pressure

•Risk of dehydrating the fluid in the core* if gas not fully humidified

at test conditions, or if large drawdown pressure applied?

Gas pressure

(psi)

Equilibrium water content of nitrogen gas (ppm)

20oC 75oC 125oC 175oC 200oC

100 3,479 56,997 342,429 - -

1,000 432 6,543 37,914 143,983 250,102

4,000 185 2,324 12,206 54,984 74,362

8,000 - - - 25,799 43,125


* See Zuluaga and Monsalve, 2003 – SPE 84829

Consequences of fluid dessication by gas in laboratory core flooding tests

Possible reduction in permeability to gas as a result of fluid immobilisation (viscosity increase) or crystallisation?


Viscosity of a completion brine at 25°C

- Brine viscosity rises sharply as it is dehydrated to < 50 % v/v water content

- Possibility of immobilisation of dehydrated viscous brine in smaller pores?

Factors that might increase risk of perm impairment of core by fluid dessication

•Gas not fully saturated with water at test T/P conditions

•High-salinity connate water and high-density brine filtrates*

•Large pressure drops across core plugs during clean-up phase

•Throughput of > 1,000 pore volumes of gas during clean-up

phase prior to measuring return perm

* High-density brines may contain < 50% v/v water, meaning that water volume in a brine-saturated core plug

is already < 1 ml before any dessication processes get to work...


Does fluid dessication ever happen in laboratory core flooding tests with gas?

High-drawdown HPHT tests with cesium formate brine on North Sea field core samples

• Flood: 25 PV of brine followed by 96-hour soak period

• Drawdown: > 1,000 PV of nitrogen humidified at room temperature

• Permeabilities measured under HPHT test conditions

• Cryogenic SEM showed some evidence of filtrate retention

Lower perm core with higher drawdown showed greatest reduction in return permeability 2009 SPE European Formation Damage Conference

Brine density(s.g.)

Test temperature

(oC)

Initial permeability

(mD)

Drawdownpressure

(psi)

Final permeability

(mD)

Reduction inpermeability

(%)

2.30 190 25.8 2,000 23.3 10

1.98 178 0.35 2,500 0.22 37

Does fluid dessication ever occur and cause impairment in HPHT gas wells?

•No reported formation damage from > 200 applications of cesium

formate brine in HPHT wells over past ten years

•PIs generally exceed expectations after cesium formate brine use:- “Well performance was above expectation with initial rates of 33 MMscf/d and

12,000 bopd @ 31% choke” (SPE 103244)

- “Use of cesium/potassium formate brine… has resulted in highly productive

gas wells with low skin” (SPE 105733)

- “The well is flowing significantly above expectation… The expected production rate

was 40–50 MM scf/day but the well is actually flowing at 79 MM scf/day” (SPE 97694)


Could gas humidification levels be influencing results of

HPHT core flooding tests with cesium formate brine?


HPHT laboratory core flooding test to determine effect of gas humidification on return permeability

Key features of methodology:

•HPHT reservoir core sample – gentle clean out with solvents

•Saturated with reservoir water and centrifuged to irreducible

•Measure permeability to gas under HPHT conditions

•Forward flow of test brine, followed by soak period

•Realistic drawdown build-up, simulating production start-up

•Flow large volume of gas under drawdown to achieve clean-up

•Measure permeability under HPHT conditions with humidified gas

- HPHT humidified gas

- LTHP humidified gas

•Complete SEM on core samples to identify source of any damage


Effect of gas humidification on HPHT core flood test results with cesium formate brine

•Programme - Measure initial permeability to gas at Swi under HPHT conditions

- 10 PV flush with 2.2 s.g. cesium formate brine at 1 ml/minute

- Soak for 48 hours at balance

- Drawdown ramped up in stages to 100 psi (5,700 psi in wellbore)

using > 1,000 PV of humidified gas

- Measure return permeability to gas under HPHT conditions

- Examine core (dry/cryo SEM) for any signs of damage

•Test conditions - 200°C - 5,800 psi pore pressure

- North Sea reservoir core flooded with reservoir water and then centrifuged to irreducible saturation



* Core from major HPHT field in UK North Sea where cesium formate brine has been used as the

completion/workover fluid since 1999

Core sample

Coring depth

(m)

Length (cm)

Volume (cc)

Pore volume

(cc)

Porosity (%)

Grain density (g/cc)

Gas permeability

(mD)

2B 6,242.39 4.77 22.176 2.902 13.1 2.61 3.73

3B 6,242.42 4.732 23.866 3.518 14.7 2.64 4.95


Core source*, dimensions and properties



Core face under SEM – before exposure to Cs formate brine

•Coarse silt and fine-grained sand, with moderately abundant

grain-coating and pore-filling illite clay. Also grain-coating

Quartz and pore-filling dolomite

Ionic composition of the reservoir water

Ion concentration (mg/l)

Na K Ca Mg Ba Fe Cl HCO3

31,190 300 2,300 350 1,000 10 53,500 610




24-carat gold film wrapped around circumference of core to createa barrier to gas diffusion/leakage under hydrothermal conditions

•Encased with layers of PTFE tape, heat-shrink tubing and

an outer Kalrez sleeve before mounting in core holder

HPHT humidifier for gas used in core flooding

2.75"

22.50"

•Dry nitrogen gas enters base of

humidifier, passes through column

filled with high surface area spheres

saturated with water, and exits from top

•Pressure vessel mounted vertically in

oven at test temperature/pressure

•Materials all in Hastelloy C-276




Pressure development across core during injection of 10 PV ofcesium formate brine @ 1ml/min (frontal advance rate of 80 cm/hour)

•Pressure stabilised after approx. 1.7 PV ( 5 minutes=5 ml)


Drawdown pressure (psi)

Cumulative gas throughput

(ml)

Cumulative gas throughput

(PV)

Stabilised flow rate (ml/min)

1 25 8.61 0.3

5 50 17.2 0.44

10 250 86.1 0.95

25 1,000 345 5.0

50 2,000 689 15.0

75 2,750 948 20.0

100 4,000 1,378 26.0


Drawdown pressure ramping, gas volume throughput and stabilised flow rate – gas humidified at HPHT



Gas flow rates and cumulative throughput during the drawdown sequence – gas humidified at HPHT

•1,378 PV of gas pulled through core in 650 minutes – 400 PV

at high drawdown



Gas flow rates and cumulative throughput during the drawdown sequence – gas humidified at HPLT

•Shorter, more aggressive drawdown: 1,137 PV of gas pulled

through core in 146 minutes – 1,000 PV at high drawdown


Gas humidification system

Test temperature

(oC)

Initial permeability

(mD)

Final permeability

(mD)

Change in permeability

(%)

LT/HP humidifier

200 2.36 2.01 -14.8

HT/HPhumidifier

200 1.62 1.66 +2.47


Humidification at room temperature resulted in permeability impairment



Appearance of wellbore core face under SEM – after exposure to Cs formate brine and gas drawdown

•Both cores showed some evidence of cleaner pore throats –reduction in size and amount of illite clay and dolomite particles.No unusual fluid retention



Appearance of formation core face under SEM – after exposure to Cs formate brine and gas drawdown

•Both cores showed evidence of some reduction in the number

of clear pore throats – indications of illite clay and dolomitefines being re-injected into core

Effect of gas humidification levels on HPHT core flood test results with cesium formate

•Full HPHT humidification resulted in no reduction in return perm

•Room temperature humidification gave 15% reduction in return perm - No obvious fluid/crystal retention to explain reduction

- Some clay fines movement in both experiments

- Shorter, more intense drawdown period in LTHP experiment

• Cannot categorically say that lower humidification level was source of

perm reduction, but prudent to use HPHT humidifier in future

•Perm reduction effect by dessication cores


Conclusions

Effect of gas humidification levels on HPHT core flood test results with cesium formate

•I would like to acknowledge and thank Ian Patey, Murdo Munro

and the laboratory staff of Corex who planned, managed and

executed the experimental programme described in this paper


Acknowledgements

spe 121649 observations on gas permeability measurements under hpht conditions in reservoir core...

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