John Downs Cabot Specialty Fluids SPE European Formation Damage Conference

Transcription

1 John Downs Cabot Specialty Fluids

2 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) 20 o C 75 o C 125 o C 175 o C 200 o C 100 3,498 57, , , ,849 39, , ,610 5, ,545 12,293 41,762 61,183 15, ,902 * Source: AQUAlibrium 3.1

3 Water vapour in HPHT natural gas Field example (ref. SPE , Wat et al., 2008) Kristin field, offshore Norway - Reservoir temperature 170 C - Reservoir pressure 13,400 psi Prior to formation water production: 1 million Sm 3 of produced gas yields 25 m 3 of condensed water (i.e. 25 grams/m 3 gas) AQUAlibrium prediction for water content of pure methane under similar conditions: 18 grams water /m 3 gas Difference: Acid gas content of Kristin gas, and drawdown effect?

4 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

5 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) 20 o C 75 o C 125 o C 175 o C 200 o C 100 3,479 56, , , ,543 37, , ,102 4, ,324 12,206 54,984 74,362 8, ,799 43,125 * See Zuluaga and Monsalve, 2003 SPE 84829

6 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? Brine viscosity (cp) ,1 1,2 1,3 1,4 1,5 1,6 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? Brine density (s.g.)

7 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...

8 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 Brine density (s.g.) Test temperature ( o C) Initial permeability (md) Drawdown pressure (psi) Final permeability (md) Reduction in permeability (%) , , 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

9 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 31% choke (SPE ) - Use of cesium/potassium formate brine has resulted in highly productive gas wells with low skin (SPE ) - The well is flowing significantly above expectation The expected production rate was MM scf/day but the well is actually flowing at 79 MM scf/day (SPE 97694)

10 Could gas humidification levels be influencing results of HPHT core flooding tests with cesium formate brine?

11 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

12 Effect of gas humidification on HPHT core flood test results with cesium formate brine Test conditions C - 5,800 psi pore pressure - North Sea reservoir core flooded with reservoir water and then centrifuged to irreducible saturation 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

13 Effect of gas humidification on HPHT core flood test results with cesium formate brine Core source*, dimensions and properties Core sample Coring depth (m) Length (cm) Volume (cc) Pore volume (cc) Porosity (%) Grain density (g/cc) Gas permeability (md) 2B 6, B 6, * Core from major HPHT field in UK North Sea where cesium formate brine has been used as the completion/workover fluid since 1999

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

15 Ionic composition of the reservoir water Ion concentration (mg/l) Na K Ca Mg Ba Fe Cl HCO 3 31, , , ,

16 Effect of gas humidification on HPHT core flood test results with cesium formate brine 24-carat gold film wrapped around circumference of core to create a 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

17 HPHT humidifier for gas used in core flooding 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

18 Effect of gas humidification on HPHT core flood test results with cesium formate brine Pressure development across core during injection of 10 PV of cesium formate 1ml/min (frontal advance rate of 80 cm/hour) 140 Differential Pressure (psi) Cumulative throughput (ml) Pressure stabilised after approx. 1.7 PV ( 5 minutes=5 ml)

19 Effect of gas humidification on HPHT core flood test results with cesium formate brine Drawdown pressure ramping, gas volume throughput and stabilised flow rate gas humidified at HPHT Drawdown pressure (psi) Cumulative gas throughput (ml) Cumulative gas throughput (PV) Stabilised flow rate (ml/min) , , , ,000 1,

20 Effect of gas humidification on HPHT core flood test results with cesium formate brine Gas flow rates and cumulative throughput during the drawdown sequence gas humidified at HPHT Gas flow rate (ml/min) Cumulative gas throughput (pore volumes) 1,378 PV of gas pulled through core in 650 minutes 400 PV at high drawdown

21 Effect of gas humidification on HPHT core flood test results with cesium formate brine Gas flow rates and cumulative throughput during the drawdown sequence gas humidified at HPLT Gas flow rate ( ml/min) Cumulative gas throughput (pore volumes) Shorter, more aggressive drawdown: 1,137 PV of gas pulled through core in 146 minutes 1,000 PV at high drawdown

22 Effect of gas humidification on HPHT core flood test results with cesium formate brine Humidification at room temperature resulted in permeability impairment Gas humidification system LT/HP humidifier HT/HP humidifier Test temperature ( o C) Initial permeability (md) Final permeability (md) Change in permeability (%)

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

24 Effect of gas humidification on HPHT core flood test results with cesium formate brine 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 dolomite fines being re-injected into core

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

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