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opm-data/spe9/SPE9_CP_SHORT_RESTART.DATA
Arne Morten Kvarving 241e708152 reduce length of restart test SPE9_CP_SHORT_RESTART 
cannot reduce the amount of time steps as the SPE9_CP_SHORT file
is used for other tests, but we can restart later in the simulation
to avoid redoing as many steps
2016-11-07 12:44:34 +01:00

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-- This reservoir simulation deck is made available under the Open Database
-- License: http://opendatacommons.org/licenses/odbl/1.0/. Any rights in
-- individual contents of the database are licensed under the Database Contents
-- License: http://opendatacommons.org/licenses/dbcl/1.0/
-- Copyright (C) 2015 Statoil
-- This simulation is based on the data given in
-- 'Ninth SPE Comparative Solution Project:
-- A Reexamination of Black-Oil Simulation',
-- by J.E. Killough,
-- Journal of Petroleum Technology, 1995
-- A dataset from one of the participants was supplied to the
-- participants of SPE 9. Some of the information in this
-- dataset has been used here as well.
-- The origin of information or data used in this simulation is
-- specified in comments. This does not include data whose origin
-- should be obvious to the reader.
-- NOTE: Changes should be made to the data entered in keywords PVTW and ROCK
-- See comments under these keywords
----------------------------------------------------------------
------------------------- SPE 9 --------------------------------
----------------------------------------------------------------
RUNSPEC
TITLE
SPE 9
DIMENS
24 25 15 /
OIL
WATER
GAS
DISGAS
-- From figure 7 in Killough's paper it is evident
-- that GOR is increasing with time, meaning
-- that there must be dissolved gas present
FIELD
START
1 'JAN' 2015 /
WELLDIMS
-- Item 1: maximum number of wells in the model
-- - there are 26 wells in SPE9; 1 injector and 25 producers
-- Item 2: maximum number of grid blocks connected to any one well
-- - the injector is completed in 5 layers
-- Item 3: maximum number of groups in the model
-- - only one group in model
-- Item 4: maximum number of wells in any one group
-- - this can definitetly not be more than 26
26 5 1 26 /
TABDIMS
-- The number of rows in SWOF exceeds the default maximum,
-- so item 3 in this keyword must be changed:
1* 1* 40 /
EQLDIMS
/
--NSTACK
-- 25 /
-- Eclipse suggested increasing NSTACK
UNIFOUT
UNIFIN
GRID
-- Killough says 'the grid was in conventional rectangular
-- coordinates without corner point geometry or local grid refinements'
NOECHO
INIT
INCLUDE
'SPE9.GRDECL' /
PORO
-- Porosity in each level is contant
-- The values are specified in table 1 in Killough's paper
600*0.087
600*0.097
600*0.111
600*0.16
600*0.13
600*0.17
600*0.17
600*0.08
600*0.14
600*0.13
600*0.12
600*0.105
600*0.12
600*0.116
600*0.157 /
-- PERMX, PERMY & PERMZ
INCLUDE
PERMVALUES.DATA /
ECHO
PROPS
PVTW
-- Item 1: pressure reference (psia)
-- Item 2: water FVF (rb per bbl or rb per stb)
-- Item 3: water compressibility (psi^{-1})
-- Item 4: water viscosity (cp)
-- Item 5: water 'viscosibility' (psi^{-1})
-- Item 1 and 2 are stated in Killough, and item 5 is assumed = zero
-- Item 3 and 4 are taken from SPE2
3600 1.0034 3e-6 0.96 0 /
--NOTE:
-- a) It is not explicitly stated in Killough that it is okay to use SPE2-values here.
-- b) I am not 100% sure if the given compressibility value is at ref. pres. 3600psia.
-- c) Item 3 and 4 can probably be explained on the basis of Killough's dataset. In
-- order to do that I need info about keywords in VIP
ROCK
-- Item 1: reference pressure (psia)
-- Item 2: rock compressibility (psi^{-1})
-- Using values from SPE2:
3600 4e-6 /
-- NOTE:
-- a) It is not explicitly stated in Killough that it is okay to use SPE2-values here.
-- a) I am not 100% sure if the given compressibility value is at 3600psia.
-- b) 'Comp. Methods for Multiphase Flow in Porous Media' states
-- that rock compr. is 1e-6 inverse psi. This is probably correct, as
-- I think this is based on Killough's dataset - to be sure, I need
-- more info about keywords in VIP.
DENSITY
-- Density (lb per ft³) at surface cond. of
-- oil, water and gas, respectively (in that order)
-- The values for oil and water are given by Killough to
-- be 0.7206 and 1.0095 gm per cc, or equivalently
-- 44.9856 and 63.0210 lb per ft³
-- A gas density of 0.07039 lb per ft³ was calculated using formula at
-- petrowiki.org/Calculating_gas_properties:
-- (28.967*Specific gravity*pressure)/(Z-factor*gas constant*temperature)
-- with the values given in Killough's table 2 at 14.7 psia (1 atm).
-- A temperature of 15C=59F was also used in the above formula.
44.9856 63.0210 0.07039 /
PVTO
-- Column 1: dissolved gas-oil ratio (Mscf per stb)
-- Column 2: bubble point pressure for oil (psia)
-- Column 3: oil FVF for saturated oil (rb per stb)
-- Column 4: oil viscosity for saturated oil (cP)
-- Using values from table 2 in Killough's paper:
0 14.7 1 1.20 /
0.165 400 1.0120 1.17 /
0.335 800 1.0255 1.14 /
0.500 1200 1.0380 1.11 /
0.665 1600 1.0510 1.08 /
0.828 2000 1.0630 1.06 /
0.985 2400 1.0750 1.03 /
1.130 2800 1.0870 1.00 /
1.270 3200 1.0985 0.98 /
1.390 3600 1.1100 0.95 /
1.500 4000 1.1200 0.94
4600 1.1089 0.94 /
-- 5000 1.1189 0.94 /
/
-- Comment in regards to the last row in PVTO:
-- Killough says that 'at 1000psi above the saturation
-- pressure the Bo is 0.999 times that of the Bo at Psat'
-- which means that the FVF (i.e. Bo) at 4600psia is 0.999*0.1100=1.1089
-- Killough also says that 'the oil viscosity does not
-- increase with increasing pressure in undersaturated conditions'
-- which explains why the oil viscosity is 0.94.
PVDG
-- Column 1: gas phase pressure (psia)
-- Column 2: gas formation volume factor (rb per Mscf)
-- - This is calculated using formula:
-- Bg=5.03676*Z*temperature(R)/pressure(psia) rb/Mscf
-- where a constant temperature=100F=559.67R has been used because
-- that is the initial reservoir temperature according to Killough's paper
-- The above formula is retrieved from
-- petrowiki.org/Gas_formation_volume_factor_and_density
-- Column 3: gas viscosity (cP)
-- Using values from table 2 in Killough's paper:
14.7 191.7443 0.0125
400 5.8979 0.0130
800 2.9493 0.0135
1200 1.9594 0.0140
1600 1.4695 0.0145
2000 1.1797 0.0150
2400 0.9796 0.0155
2800 0.8397 0.0160
3200 0.7398 0.0165
3600 0.6498 0.0170
4000 0.5849 0.0175 /
SGOF
-- Column 1: gas saturation
-- Column 2: gas relative permeability
-- Column 3: oil relative permeability when oil, gas and connate water are present
-- Column 4: corresponding oil-gas capillary pressure (psi)
-- Using values from table 3 in Killough's paper:
0 0 1 0
0.04 0 0.6 0.2
0.1 0.022 0.33 0.5
0.2 0.1 0.1 1.0
0.3 0.24 0.02 1.5
0.4 0.34 0 2.0
0.5 0.42 0 2.5
0.6 0.5 0 3.0
0.7 0.8125 0 3.5
0.84891 0.9635 0 3.82 /
--0.88491 1 0 3.9 /
-- Comment in regards to the last row in SGOF:
-- Changes have been made so that the last row
-- is at a gas sat. of Sg=1-Swc=1-0.151090=0.84891
-- The Krg and Pcog values corresponding to Sg=0.84891
-- have been approximated by assuming linear relation between
-- Krg/Pcog and Sg in the range Sg=0.7 to Sg=0.88491
SWOF
-- Column 1: water saturation
-- Column 2: water relative permeability
-- Column 3: oil relative permeability when only oil and water are present
-- Column 4: corresponding water-oil capillary pressure (psi)
-- These values are taken from Killough's dataset:
0.151090 0.0 1.0 400.0
0.151230 0.0 0.99997 359.190
0.151740 0.0 0.99993 257.920
0.152460 0.0 0.99991 186.310
0.156470 0.0 0.999510 79.060
0.165850 0.0 0.996290 40.010
0.178350 0.0 0.991590 27.930
0.203350 0.000010 0.978830 20.400
0.253350 0.000030 0.943730 15.550
0.350000 0.000280 0.830230 11.655
0.352000 0.002292 0.804277 8.720
0.354000 0.004304 0.778326 5.947
0.356000 0.006316 0.752374 3.317
0.358000 0.008328 0.726422 1.165
0.360000 0.010340 0.700470 0.463
0.364395 0.015548 0.642258 -0.499
0.368790 0.020756 0.584046 -1.139
0.370000 0.022190 0.568020 -1.194
0.380000 0.035890 0.434980 -1.547
0.400000 0.069530 0.171430 -1.604
0.433450 0.087900 0.125310 -1.710
0.461390 0.104910 0.094980 -1.780
0.489320 0.123290 0.070530 -1.860
0.517250 0.143030 0.051130 -1.930
0.573120 0.186590 0.024640 -2.070
0.601060 0.210380 0.016190 -2.130
0.656930 0.261900 0.005940 -2.260
0.712800 0.318650 0.001590 -2.380
0.811110 0.430920 0.000020 -2.600
0.881490 0.490000 0.000000 -2.750 /
-- These values are approximated by reading off the graphs
-- in figure 1 and 2 in Killough's paper:
-- $$$ 0.18 0 1 21
-- $$$ 0.25 0 0.95 16
-- $$$ 0.34 0.07 0.5 12
-- $$$ 0.345 0.08 0.4 9
-- $$$ 0.35 0.09 0.3 6
-- $$$ 0.355 0.095 0.2 0
-- $$$ 0.36 0.1 0.19 -2
-- $$$ 0.75 0.32 0.02 -2.5
-- $$$ 0.88149 0.5 0 -3 /
SOLUTION
-- ---------------------------------------------------------------------------
RESTART
SPE9_CP_SHORT 15 /
EQUIL
-- Item 1: datum depth (ft)
-- Item 2: pressure at datum depth (psia)
-- - Killough says initial oil phase pressure is
-- - 3600psia at depth 9035ft
-- Item 3: depth of water-oil contact (ft)
-- - Given to be 9950 ft in Killough's paper
-- Item 4: oil-water capillary pressure at the water oil contact (psi)
-- - Given to be 0 in Killough's dataset
-- - 0 in SPE2
-- Item 5: depth of gas-oil contact (ft)
-- - 8800ft in Killough's dataset
-- Item 6: gas-oil capillary pressure at gas-oil contact (psi)
-- - Given to be 0 in Killough's dataset
-- - 0 in SPE2
-- Item 7: RSVD-table
-- Item 8: RVVD-table
-- Item 9: OPM only supports item 9 equal to zero.
-- #: 1 2 3 4 5 6 7 8 9
9035 3600 9950 0 8800 0 1 0 0 /
RSVD
-- The initial oil phase pressure is given to be 3600psia, at
-- which the GOR is 1.39 Mscf per stb according to Killough's table 2.
-- Since there is no free gas initially present*, the oil
-- phase (with dissolved gas) must initially have a constant GOR as
-- a function of depth through the reservoir (at the given pressure)
8800 1.39
9950 1.39 /
-- *)
-- This is explicitly stated in Killough's paper.
-- Note that the initial oil phase pressure is the same as
-- the saturation (bubble point) pressure of the oil.
-- This should also imply that there is no free gas initially present.
-- Since there is no free gas initially present, the gas-oil
-- contact should lie above the reservoir, which it does (EQUIL, item 5)
SUMMARY
-- Killough's figure 7:
FGOR
-- Killough's figure 8:
FOPR
-- Killough's figure 9:
FGPR
-- Killough's figure 10:
FWPR
-- Killough's figure 11:
BPR
1 1 1 /
/
-- Killough's figure 12:
BGSAT
1 13 1 /
/
-- Killough's figure 13:
BWSAT
10 25 15 /
/
-- Killough's figure 14:
--WWIR
-- 'INJE1' /
-- Killough's figure 15:
--WOPR
-- 'PRODU21' /
-- In order to compare Eclipse with Flow:
WBHP
/
WGIR
/
--WGIT
--/
WGPR
/
WGPT
/
WOIR
/
--WOIT
--/
WOPR
/
WOPT
/
WWIR
/
--WWIT
--/
WWPR
/
WWPT
/
SCHEDULE
-- -----------------------------------------
SKIPREST
RPTRST
'BASIC=2' /
TUNING
4.0 60.0 0.1 /
/
12 2 15 /
WELSPECS
-- Column 3: I-value of well head or heel
-- Column 4: J-value of well head or heel
-- - these coordinates are listed in Killough's dataset
-- Column 5: ref. depth of BHP (ft)
-- - stated in the middle of the top perforated cell
-- - not anymore stated to be 9110ft in Killough
-- Column 6: preferred phase for well
-- - should be water for injector and oil for producers
-- Column 7: drainage radius for calc. of productivity or
-- injectivity indices (ft)
-- - stated to be 60ft in Killough
-- #: 1 2 3 4 5 6 7
'INJE1 ' 'P' 24 25 9110 'WATER' 60 /
'PRODU2 ' 'P' 5 1 9110 'OIL' 60 /
'PRODU3 ' 'P' 8 2 9110 'OIL' 60 /
'PRODU4 ' 'P' 11 3 9110 'OIL' 60 /
'PRODU5 ' 'P' 10 4 9110 'OIL' 60 /
'PRODU6 ' 'P' 12 5 9110 'OIL' 60 /
'PRODU7 ' 'P' 4 6 9110 'OIL' 60 /
'PRODU8 ' 'P' 8 7 9110 'OIL' 60 /
'PRODU9 ' 'P' 14 8 9110 'OIL' 60 /
'PRODU10' 'P' 11 9 9110 'OIL' 60 /
'PRODU11' 'P' 12 10 9110 'OIL' 60 /
'PRODU12' 'P' 10 11 9110 'OIL' 60 /
'PRODU13' 'P' 5 12 9110 'OIL' 60 /
'PRODU14' 'P' 8 13 9110 'OIL' 60 /
'PRODU15' 'P' 11 14 9110 'OIL' 60 /
'PRODU16' 'P' 13 15 9110 'OIL' 60 /
'PRODU17' 'P' 15 16 9110 'OIL' 60 /
'PRODU18' 'P' 11 17 9110 'OIL' 60 /
'PRODU19' 'P' 12 18 9110 'OIL' 60 /
'PRODU20' 'P' 5 19 9110 'OIL' 60 /
'PRODU21' 'P' 8 20 9110 'OIL' 60 /
'PRODU22' 'P' 11 21 9110 'OIL' 60 /
'PRODU23' 'P' 15 22 9110 'OIL' 60 /
'PRODU24' 'P' 12 23 9110 'OIL' 60 /
'PRODU25' 'P' 10 24 9110 'OIL' 60 /
'PRODU26' 'P' 17 25 9110 'OIL' 60 /
/
COMPDAT
-- Column 2: I-value of connecting grid block
-- Column 3: J-value of connecting grid block
-- Column 4: K-value of upper connecting grid block
-- Column 5: K-value of lower connecting grid block
-- - these coordinates are listed in Killough's dataset
-- Column 9: well bore diameter
-- - Killough says radius is 0.5ft
--Item 8 must be entered in order to get a match between Eclipse and Flow
--No match if item 8 is defaulted
-- #: 1 2 3 4 5 6 7 8 9
'INJE1' 24 25 11 15 'OPEN' 1* 1* 1 /
'PRODU2' 5 1 2 4 'OPEN' 1* 1* 1 /
'PRODU3' 8 2 2 4 'OPEN' 1* 1* 1 /
'PRODU4' 11 3 2 4 'OPEN' 1* 1* 1 /
'PRODU5' 10 4 2 4 'OPEN' 1* 1* 1 /
'PRODU6' 12 5 2 4 'OPEN' 1* 1* 1 /
'PRODU7' 4 6 2 4 'OPEN' 1* 1* 1 /
'PRODU8' 8 7 2 4 'OPEN' 1* 1* 1 /
'PRODU9' 14 8 2 4 'OPEN' 1* 1* 1 /
'PRODU10' 11 9 2 4 'OPEN' 1* 1* 1 /
'PRODU11' 12 10 2 4 'OPEN' 1* 1* 1 /
'PRODU12' 10 11 2 4 'OPEN' 1* 1* 1 /
'PRODU13' 5 12 2 4 'OPEN' 1* 1* 1 /
'PRODU14' 8 13 2 4 'OPEN' 1* 1* 1 /
'PRODU15' 11 14 2 4 'OPEN' 1* 1* 1 /
'PRODU16' 13 15 2 4 'OPEN' 1* 1* 1 /
'PRODU17' 15 16 2 4 'OPEN' 1* 1* 1 /
'PRODU18' 11 17 2 4 'OPEN' 1* 1* 1 /
'PRODU19' 12 18 2 4 'OPEN' 1* 1* 1 /
'PRODU20' 5 19 2 4 'OPEN' 1* 1* 1 /
'PRODU21' 8 20 2 4 'OPEN' 1* 1* 1 /
'PRODU22' 11 21 2 4 'OPEN' 1* 1* 1 /
'PRODU23' 15 22 2 4 'OPEN' 1* 1* 1 /
'PRODU24' 12 23 2 4 'OPEN' 1* 1* 1 /
'PRODU25' 10 24 2 4 'OPEN' 1* 1* 1 /
'PRODU26' 17 25 2 4 'OPEN' 1* 1* 1 /
/
WCONINJE
-- Killough says the water injector is set to a max rate of
-- 5000 STBW per D with a max BHP of 4000psia at a reference
-- depth of 9110ft subsea:
-- #: 1 2 3 4 5 7
'INJE1' 'WATER' 'OPEN' 'RATE' 5000 1* 4000 /
/
WCONPROD
-- Killough says the max oil rate for all producers is set to
-- 1500 STBO per D at time zero and that the min flowing BHP
-- is set to 1000psia (with a ref. depth of 9110ft
-- for this pressure in all wells):
-- #: 1 2 3 4 9
'PRODU*' 'OPEN' 'ORAT' 1500 4* 1000 /
-- Here, the wildcard '*' has been used to indicate that this applies
-- to all producers; PRODU1-PRODU25.
/
TSTEP
10*10 /
-- At 100 days, the max oil rate for all producers is lowered
-- to 100 STBO per D:
WCONPROD
-- #: 1 2 3 4 9
'PRODU*' 'OPEN' 'ORAT' 100 4* 1000 /
/
TSTEP
6*10 /
-- At 160 days, the max oil rate for all producers is changed
-- back to 1500 STBO per D:
WCONPROD
-- #: 1 2 3 4 9
'PRODU*' 'OPEN' 'ORAT' 1500 4* 1000 /
/
TSTEP
5*10 /
-- End of simulation at 210 days
END
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