6th International Conference on Gas Hydrates

PRODUCTION STRATEGIES FOR MARINE HYDRATE RESERVOIRS Phirani, J.; Mohanty, K. K. 2008

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   PRODUCTION STRATEGIES FOR MARINE HYDRATE RESERVOIRS  J. Phirani and K. K. Mohanty Department of Chemical & Biomolecular Engineering University of Houston 4800 Calhoun Road, Houston, TX 77204-4004, USA  ABSTRACT Large quantities of natural gas hydrate are present in marine sediments along the coastlines of many  countries  as  well  as in  arctic regions.  This  research  is  aimed at  assessing production of natural gas from the marine deposits. We had developed a multiphase, multicomponent, thermal, 3D  simulator  in  the  past,  which  can  simulate  production  of  hydrates  both  in  equilibrium  and kinetic modes. Four components (hydrate, methane, water and salt) and five phases (hydrate, gas, aqueous-phase, ice and salt precipitate) are considered in the simulator. In this work, we simulate depressurization and warm water flooding for hydrate production in a hydrate reservoir underlain by a water layer. Water flooding has been studied as a function of injection temperature, injection pressure and production pressure. For high injection temperature, the higher pressure increases the flow  of  warm  water  (heat)  in  the  reservoir  making  the  production  rate  faster,  but  if  injection temperature  is  not  high  then  only  depressurization  is  the  best  method  of  production.  At intermediate  injection  temperature,  the  production  rate  changes  non-monotonically  with  the injection pressure.   Keywords: Gas hydrates, Injection Temperature, Injection Pressure, Production Pressure  NOMENCLATURE  SA = aqueous saturation SH = hydrate saturation  INTRODUCTION Gas  hydrates  are  ice-like  compounds  formed  by trapping  of  gas  molecules  in  clathrates  of  water molecules  under  high  pressure  and  low temperature  [1].  Three  types  of  crystalline structure of gas hydrates have been found so far, Structure  I  (SI),  Structure  II  (SII),  Structure  H (SH), in the order of increasing clathrate size. The properties associated with the crystalline structures have  been  studied  in  details  by  Sloan  [1].  SI methane hydrate is very common and will be the focus of present study. The hydrate reservoirs can be  classified  into  3  types  [2]:  Class  1  reservoirs have  a  hydrate  layer  overlying  a  free  gas  layer, Class 2 reservoirs have hydrates overlying a water saturated layer and Class 3 reservoirs have a single layer  containing  hydrates  bounded  by  two impermeable  shale  layers.  Class  2  reservoirs  are studied in the present work.    Four  methods  and  their  combinations  have  been proposed to produce gas from hydrate reservoirs: depressurization,  thermal  stimulation,  inhibitor injection,  and  CO2  injection  [1,3].  In depressurization,  the  pressure  is  lowered  at  the production  well  below  the  hydrate  stability pressure  and  the  dissociated  gas  flows  into  the production  well.  In  thermal  stimulation  either wells  are  heated  or  warm  water  or  steam  is injected raising the temperature above the hydrate stability  temperature.  In  the  inhibitor  process, chemicals  that  inhibit  hydrate  injection  are injected along with water in injection wells. In the CO2  process,  CO2  replaces  methane  in  clathrate cages  giving  rise  to  methane  production  and simultaneous CO2 sequestration.   In this work, we are considering injection of warm water  and  depressurization  for  production  from Class  2  hydrate  reservoirs.  The  source  of  warm water  could  be  a  nearby  oil  reservoir  or  an underlying  water  aquifer.  Gas  production  from  a Proceedings of the 6th International Conference on Gas Hydrates (ICGH 2008), Vancouver, British Columbia, CANADA, July 6-10, 2008.  hydrate  reservoir  is  studied  through  numerical simulation.   The  numerical  model  used  is  a  finite-volume simulator  that  takes  into  account  heat  transfer, multiphase  fluid  flow  and  equilibrium thermodynamics of hydrates [4]. Four components (hydrate, methane, water and salt) and five phases (hydrate,  gas,  aqueous-phase,  ice  and  salt precipitate) are considered in the simulator. Water freezing and ice melting are tracked with primary variable  switch  method  (PVSM)  by  assuming equilibrium  phase  transition.  Equilibrium simulation method is used here because kinetics of hydrate  formation  and  dissociation  are  relatively fast  in  the  field-scale.  This  simulator  has  been validated  against  several  other  simulators  for  the problems in the code comparison study conducted by US DOE.          Figure 1: Domain considered for the base case  The objective of this study is to identify optimum production  strategies  for  gas  production  from Class  2  hydrate  reservoirs  through  numerical simulation. The domain selected as the base case is a  quarter  five-spot  of  size  120m  x120m  x10m (Figure  1).  Initial  temperature  and  pressure  are assumed  to  be  7.5?C  and  9MPa,  respectively, which lie in the hydrate  stable  zone. The bottom 2m of the domain is an aquifer layer (SA=1.0) and the  top  8m  is  a  hydrate  layer  with  a  hydrate saturation, SH of 0.6 and aqueous saturation, SA of 0.4. There is no heat and mass transfer though the side  boundaries  due  to  symmetry.  There  is  only heat transfer, but no mass flow through the top and bottom  boundaries  due  to  impermeable  shale layers.  The  effect  of  injection  temperature, injection pressure and production well pressure on gas and water production is studied.  RESULTS Simulations  were  run  for  different  injection pressures,  injection  temperatures  and  production pressures for 3000 days and total production of gas was compared for the above parameters.  For the case of no injection, the dissociation is due to  pressure  falling  below  the  hydrate  stable pressure due to depressurization at the production well.  The  heat  of  dissociation  comes  from surroundings,  decreasing  the  temperature  of  the reservoir.  Ice  starts forming if the pressure goes below  quadruple  point  pressure.  After  all  the hydrates  dissociate,  the  temperature  again  starts rising by the heat from surroundings.   For the case of warm water injection, the pressure of  injection  has  to  be  higher  than  the  reservoir pressure  for  the  hot  water  to  go  in.  The temperature  rise  is  higher  for  higher  temperature and  higher  injection  pressure  (injection  flow  rate increases).  But  if  injection  pressure  is  high  the average  pressure  in  the  reservoir  increases, slowing  the  dissociation  of  hydrates  (and  even formation of additional hydrates) before the warm water  reaches  a  certain  region.  If  production pressure and temperature are both high, the rate of production  of  gas increases.  The  total  production of  gas  also  depends  on  the  production  pressure, and for different production pressure the optimum injection conditions vary.  Figure 2 shows total production for the production well pressure of 2MPa. The injection temperature was  kept  constant  at  20C  and  injection  pressure was varied. The results were compared against the no  injection  or  depressurization  only  case.  When warm water is injected at a higher pressure but at a relatively  low  temperature  (20C  in  the  present case)  the  gas  production  rate  decreases  with increasing  injection  pressure.  This  is  because  the average  pressure  of  the  reservoir  domain increases; dissociation of hydrate slows down. In case  of  5MPa  of  injection  pressure,  the  total production  of  gas  increases  because  water occupies  some  pore  space  that  would  have  been occupied by gas during depressurization. At higher injection  pressure  the  hydrate  dissociation  is  not complete in 3000 days. For low temperature water injection, only depressurization seems to be better than warm water injection.  Warm water  Gas production (2MPa) Hydrate  layer (8m) Aquifer layer (2m)  7.5?C, 9MPa 120m 120m Sh=0.6, Sa=0.4    Aquifer Production Pressure 2MPaInjection Temperature 20C0.00E+005.00E+051.00E+061.50E+062.00E+062.50E+063.00E+063.50E+060.00E+00 5.00E+07 1.00E+08 1.50E+08 2.00E+08 2.50E+08 3.0 08Time (s)Cumulative production STDCMNoInj5MPa10MPa20MPa30MPa40MPa Figure  2:  Cumulative  production  of  gas  with varying  injection  pressure,  20?C  of  injection temperature and 2MPa of production pressure  Figure 3 shows the cumulative production of gas when  production  well  pressure  is  kept  at  4MPa and  injection  temperature  is  80?C.  The  injection pressure  is  varied.  In  this  case,  only depressurization is slow and does not dissociate all the hydrates present in 3000 days. With increasing injection  pressure  the  gas  production  rate increases. With an injection water of 80?C, as the injection pressure increases more of the reservoir gets  to  this  high  temperature  which  helps  in hydrate dissociation.  Production Pressure 4MPaInjection Temperature 80C-5.00E+050.00E+005.00E+051.00E+061.50E+062.00E+062.50E+063.00E+063.50E+060.00E+00 5.00E+07 1.00E+08 1.50E+08 2.00E+08 2.50E+08 3.0 08Time(s)Cumulative production (STDCM)NoInj5MPa10MPa20MPa30MPa40MPa Figure  3:  Cumulative  production  of  gas  with varying  injection  pressure  at  80?C  of  injection temperature and 4MPa of production pressure.  If injection temperature is in medium range (50?C) then  injection  pressure  and  production  pressure play an important role. Figure 4 and 5 are plots for 2MPa  and  4MPa  of  production  pressure, respectively, at 50?C of injection temperature with varying  injection  well  pressures.  If  Injection pressure rises from 5MPa to 10MPa the production almost  remains  same  for  the  case  of  production pressure 2MPa but decreases drastically in the case of  production  pressure  4MPa.  This  can  be attributed  to  higher  average  pressure  in  the reservoir  domain  which  hinders  hydrate dissociation.  In  case  of  injection  pressure  of 30MPa and 40MPa the total production and rate of production  increases  (Figure  4  and  5),  though initial  rate  of  production  falls  due  to  increase  in average  reservoir  pressure  which  assists  hydrate formation while temperature is still not high. The gas  production  rate  is  non-monotonic  with  the increase in injection pressure.   50C Injection Temperature4MPa Production Pressure0.00E+005.00E+051.00E+061.50E+062.00E+062.50E+063.00E+063.50E+060.00E+00 5.00E+07 1.00E+08 1.50E+08 2.00E+08 2.50E+08 3.00E+08Time(s)Cumulative Gas Production (STDCM)5MPa10MPa30MPa40MPa Figure 4: Cumulative gas production with varying injection  pressure  and  2MPa  of  production pressure and 50?C of injection temperature.  Production pressure 4MPaInjection Temperature 50C0.00E+005.00E+051.00E+061.50E+062.00E+062.50E+063.00E+063.50E+060.00E+00 5.00E+07 1.00E+08 1.50E+08 2.00E+08 2.50E+08 3.0 E+08Time(s)Cumulative Gas Production(STDCM)I(5MPa)I(10MPa)I(30MPa)I(40MPa) Figure 5: Cumulative gas production with varying injection  pressure  and  4MPa  of  production pressure and 50?C of injection temperature.   CONCLUSIONS The  production  well  pressure,  injection temperature and pressure play an important role in the  production  of  gas  from  hydrate  deposits.  For high  injection  temperature,  the  higher  pressure increases  the  flow  of  warm  water  (heat)  in  the reservoir making the production rate faster, but if injection  temperature  is  not  high  then  only depressurization is the best method of production. At  intermediate  injection  temperature,  the production  rate  changes  non-monotonically  with the injection pressure. These parameters should be chosen  carefully  to  optimize  recovery  and recovery rate of gas. This paper addresses a very simple homogeneous domain. Realistic reservoirs would have heterogeneity in sediments as well as hydrate  distribution,  which  need to  be taken  into account.  Models  are  being  developed  to  address the  variation  in  hydrate  saturation  in  marine sediments [5].  ACKNOWLEDGEMENT We thank NETL of the US Department of Energy for  funding  and  Prof.  George  J.  Hirasaki  for collaboration in hydrate research.   REFERENCES [1]  Sloan,  E.D.  (1998).  Clathrate  Hydrates  of Natural  Gases.  2nd  edition,  Marcel  Dekker  Inc. New York. [2] Moridis, G.J. (2005). Depressurization-Induced Gas  Production  from  Class  1  Hydrate  Deposits, SPE 97266, presented at SPE ATCE, Dallas, Oct. 9-12. [3]  Graue,  A.,  Kvamme,  B.,  Baldwin,  B.A., Stevens,  J.,  Howard,  J.  Ersland,  G.,  Husebo,  J. (2006). Magnetic Resonance Imaging of Methane-CO2 Hydrate Reactions in Sandstone Pores, SPE 102915, Proceedings of SPE ATCE, San Antonio, 24-27 Sept. [4]  Sun,  X.  &  Mohanty,  K.  K.  (2006)  Kinetic Simulation  of  Methane  Hydrate  Formation  and Dissociation  in  Porous  Media.  Chem.  Eng.  Sci., 61, 3476-3495. [5] Bhatnagar, G., Chapman, W.G., Dickens, G.R., Dugan,  B.  and  Hirasaki,  G.J.  (2006)  Scaling  of Thermodynamic  and  Transport  Processes  for Predicting Methane Hydrate Saturation in Marine Sediments  Worldwide.  SPE  106519,  Proceedings of SPE ATCE, San Antonio, 24-27 Sept.   

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