588 lines
16 KiB
Plaintext
588 lines
16 KiB
Plaintext
-- This reservoir simulation deck is made available under the Open Database
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-- License: http://opendatacommons.org/licenses/odbl/1.0/. Any rights in
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-- individual contents of the database are licensed under the Database Contents
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-- License: http://opendatacommons.org/licenses/dbcl/1.0/
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-- Copyright (C) 2015 Statoil
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-- This simulation is based on the data given in
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-- 'Ninth SPE Comparative Solution Project:
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-- A Reexamination of Black-Oil Simulation',
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-- by J.E. Killough,
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-- Journal of Petroleum Technology, 1995
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-- A dataset from one of the participants was supplied to the
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-- participants of SPE 9. Some of the information in this
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-- dataset has been used here as well.
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-- The origin of information or data used in this simulation is
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-- specified in comments. This does not include data whose origin
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-- should be obvious to the reader.
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-- NOTE: Changes should be made to the data entered in keywords PVTW and ROCK
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-- See comments under these keywords
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----------------------------------------------------------------
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------------------------- SPE 9 --------------------------------
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----------------------------------------------------------------
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RUNSPEC
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TITLE
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SPE 9
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DIMENS
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24 25 15 /
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OIL
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WATER
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GAS
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DISGAS
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-- From figure 7 in Killough's paper it is evident
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-- that GOR is increasing with time, meaning
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-- that there must be dissolved gas present
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FIELD
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START
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1 'JAN' 2015 /
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WELLDIMS
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-- Item 1: maximum number of wells in the model
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-- - there are 26 wells in SPE9; 1 injector and 25 producers
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-- Item 2: maximum number of grid blocks connected to any one well
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-- - the injector is completed in 5 layers
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-- Item 3: maximum number of groups in the model
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-- - only one group in model
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-- Item 4: maximum number of wells in any one group
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-- - this can definitetly not be more than 26
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26 5 10 26 /
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TABDIMS
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-- The number of rows in SWOF exceeds the default maximum,
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-- so item 3 in this keyword must be changed:
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1* 1* 40 /
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EQLDIMS
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/
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--NSTACK
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-- 25 /
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-- Eclipse suggested increasing NSTACK
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UNIFOUT
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GRID
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-- Killough says 'the grid was in conventional rectangular
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-- coordinates without corner point geometry or local grid refinements'
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NOECHO
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INIT
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INCLUDE
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'SPE9.GRDECL' /
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PORO
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-- Porosity in each level is contant
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-- The values are specified in table 1 in Killough's paper
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600*0.087
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600*0.097
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600*0.111
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600*0.16
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600*0.13
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600*0.17
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600*0.17
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600*0.08
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600*0.14
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600*0.13
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600*0.12
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600*0.105
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600*0.12
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600*0.116
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600*0.157 /
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-- PERMX, PERMY & PERMZ
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INCLUDE
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PERMVALUES.DATA /
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ECHO
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PROPS
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PVTW
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-- Item 1: pressure reference (psia)
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-- Item 2: water FVF (rb per bbl or rb per stb)
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-- Item 3: water compressibility (psi^{-1})
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-- Item 4: water viscosity (cp)
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-- Item 5: water 'viscosibility' (psi^{-1})
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-- Item 1 and 2 are stated in Killough, and item 5 is assumed = zero
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-- Item 3 and 4 are taken from SPE2
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3600 1.0034 3e-6 0.96 0 /
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--NOTE:
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-- a) It is not explicitly stated in Killough that it is okay to use SPE2-values here.
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-- b) I am not 100% sure if the given compressibility value is at ref. pres. 3600psia.
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-- c) Item 3 and 4 can probably be explained on the basis of Killough's dataset. In
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-- order to do that I need info about keywords in VIP
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ROCK
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-- Item 1: reference pressure (psia)
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-- Item 2: rock compressibility (psi^{-1})
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-- Using values from SPE2:
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3600 4e-6 /
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-- NOTE:
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-- a) It is not explicitly stated in Killough that it is okay to use SPE2-values here.
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-- a) I am not 100% sure if the given compressibility value is at 3600psia.
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-- b) 'Comp. Methods for Multiphase Flow in Porous Media' states
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-- that rock compr. is 1e-6 inverse psi. This is probably correct, as
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-- I think this is based on Killough's dataset - to be sure, I need
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-- more info about keywords in VIP.
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DENSITY
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-- Density (lb per ft³) at surface cond. of
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-- oil, water and gas, respectively (in that order)
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-- The values for oil and water are given by Killough to
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-- be 0.7206 and 1.0095 gm per cc, or equivalently
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-- 44.9856 and 63.0210 lb per ft³
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-- A gas density of 0.07039 lb per ft³ was calculated using formula at
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-- petrowiki.org/Calculating_gas_properties:
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-- (28.967*Specific gravity*pressure)/(Z-factor*gas constant*temperature)
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-- with the values given in Killough's table 2 at 14.7 psia (1 atm).
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-- A temperature of 15C=59F was also used in the above formula.
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44.9856 63.0210 0.07039 /
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PVTO
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-- Column 1: dissolved gas-oil ratio (Mscf per stb)
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-- Column 2: bubble point pressure for oil (psia)
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-- Column 3: oil FVF for saturated oil (rb per stb)
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-- Column 4: oil viscosity for saturated oil (cP)
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-- Using values from table 2 in Killough's paper:
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0 14.7 1 1.20 /
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0.165 400 1.0120 1.17 /
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0.335 800 1.0255 1.14 /
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0.500 1200 1.0380 1.11 /
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0.665 1600 1.0510 1.08 /
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0.828 2000 1.0630 1.06 /
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0.985 2400 1.0750 1.03 /
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1.130 2800 1.0870 1.00 /
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1.270 3200 1.0985 0.98 /
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1.390 3600 1.1100 0.95 /
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1.500 4000 1.1200 0.94
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4600 1.1089 0.94 /
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-- 5000 1.1189 0.94 /
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/
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-- Comment in regards to the last row in PVTO:
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-- Killough says that 'at 1000psi above the saturation
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-- pressure the Bo is 0.999 times that of the Bo at Psat'
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-- which means that the FVF (i.e. Bo) at 4600psia is 0.999*0.1100=1.1089
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-- Killough also says that 'the oil viscosity does not
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-- increase with increasing pressure in undersaturated conditions'
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-- which explains why the oil viscosity is 0.94.
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PVDG
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-- Column 1: gas phase pressure (psia)
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-- Column 2: gas formation volume factor (rb per Mscf)
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-- - This is calculated using formula:
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-- Bg=5.03676*Z*temperature(R)/pressure(psia) rb/Mscf
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-- where a constant temperature=100F=559.67R has been used because
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-- that is the initial reservoir temperature according to Killough's paper
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-- The above formula is retrieved from
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-- petrowiki.org/Gas_formation_volume_factor_and_density
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-- Column 3: gas viscosity (cP)
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-- Using values from table 2 in Killough's paper:
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14.7 191.7443 0.0125
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400 5.8979 0.0130
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800 2.9493 0.0135
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1200 1.9594 0.0140
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1600 1.4695 0.0145
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2000 1.1797 0.0150
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2400 0.9796 0.0155
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2800 0.8397 0.0160
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3200 0.7398 0.0165
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3600 0.6498 0.0170
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4000 0.5849 0.0175 /
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SGOF
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-- Column 1: gas saturation
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-- Column 2: gas relative permeability
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-- Column 3: oil relative permeability when oil, gas and connate water are present
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-- Column 4: corresponding oil-gas capillary pressure (psi)
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-- Using values from table 3 in Killough's paper:
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0 0 1 0
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0.04 0 0.6 0.2
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0.1 0.022 0.33 0.5
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0.2 0.1 0.1 1.0
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0.3 0.24 0.02 1.5
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0.4 0.34 0 2.0
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0.5 0.42 0 2.5
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0.6 0.5 0 3.0
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0.7 0.8125 0 3.5
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0.84891 0.9635 0 3.82 /
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--0.88491 1 0 3.9 /
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-- Comment in regards to the last row in SGOF:
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-- Changes have been made so that the last row
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-- is at a gas sat. of Sg=1-Swc=1-0.151090=0.84891
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-- The Krg and Pcog values corresponding to Sg=0.84891
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-- have been approximated by assuming linear relation between
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-- Krg/Pcog and Sg in the range Sg=0.7 to Sg=0.88491
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SWOF
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-- Column 1: water saturation
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-- Column 2: water relative permeability
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-- Column 3: oil relative permeability when only oil and water are present
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-- Column 4: corresponding water-oil capillary pressure (psi)
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-- These values are taken from Killough's dataset:
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0.151090 0.0 1.0 400.0
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0.151230 0.0 0.99997 359.190
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0.151740 0.0 0.99993 257.920
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0.152460 0.0 0.99991 186.310
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0.156470 0.0 0.999510 79.060
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0.165850 0.0 0.996290 40.010
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0.178350 0.0 0.991590 27.930
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0.203350 0.000010 0.978830 20.400
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0.253350 0.000030 0.943730 15.550
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0.350000 0.000280 0.830230 11.655
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0.352000 0.002292 0.804277 8.720
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0.354000 0.004304 0.778326 5.947
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0.356000 0.006316 0.752374 3.317
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0.358000 0.008328 0.726422 1.165
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0.360000 0.010340 0.700470 0.463
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0.364395 0.015548 0.642258 -0.499
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0.368790 0.020756 0.584046 -1.139
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0.370000 0.022190 0.568020 -1.194
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0.380000 0.035890 0.434980 -1.547
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0.400000 0.069530 0.171430 -1.604
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0.433450 0.087900 0.125310 -1.710
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0.461390 0.104910 0.094980 -1.780
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0.489320 0.123290 0.070530 -1.860
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0.517250 0.143030 0.051130 -1.930
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0.573120 0.186590 0.024640 -2.070
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0.601060 0.210380 0.016190 -2.130
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0.656930 0.261900 0.005940 -2.260
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0.712800 0.318650 0.001590 -2.380
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0.811110 0.430920 0.000020 -2.600
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0.881490 0.490000 0.000000 -2.750 /
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-- These values are approximated by reading off the graphs
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-- in figure 1 and 2 in Killough's paper:
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-- $$$ 0.18 0 1 21
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-- $$$ 0.25 0 0.95 16
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-- $$$ 0.34 0.07 0.5 12
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-- $$$ 0.345 0.08 0.4 9
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-- $$$ 0.35 0.09 0.3 6
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-- $$$ 0.355 0.095 0.2 0
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-- $$$ 0.36 0.1 0.19 -2
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-- $$$ 0.75 0.32 0.02 -2.5
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-- $$$ 0.88149 0.5 0 -3 /
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SOLUTION
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EQUIL
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-- Item 1: datum depth (ft)
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-- Item 2: pressure at datum depth (psia)
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-- - Killough says initial oil phase pressure is
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-- - 3600psia at depth 9035ft
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-- Item 3: depth of water-oil contact (ft)
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-- - Given to be 9950 ft in Killough's paper
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-- Item 4: oil-water capillary pressure at the water oil contact (psi)
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-- - Given to be 0 in Killough's dataset
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-- - 0 in SPE2
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-- Item 5: depth of gas-oil contact (ft)
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-- - 8800ft in Killough's dataset
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-- Item 6: gas-oil capillary pressure at gas-oil contact (psi)
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-- - Given to be 0 in Killough's dataset
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-- - 0 in SPE2
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-- Item 7: RSVD-table
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-- Item 8: RVVD-table
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-- Item 9: OPM only supports item 9 equal to zero.
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-- #: 1 2 3 4 5 6 7 8 9
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9035 3600 9950 0 8800 0 1 0 0 /
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RSVD
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-- The initial oil phase pressure is given to be 3600psia, at
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-- which the GOR is 1.39 Mscf per stb according to Killough's table 2.
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-- Since there is no free gas initially present*, the oil
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-- phase (with dissolved gas) must initially have a constant GOR as
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-- a function of depth through the reservoir (at the given pressure)
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8800 1.39
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9950 1.39 /
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-- *)
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-- This is explicitly stated in Killough's paper.
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-- Note that the initial oil phase pressure is the same as
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-- the saturation (bubble point) pressure of the oil.
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-- This should also imply that there is no free gas initially present.
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-- Since there is no free gas initially present, the gas-oil
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-- contact should lie above the reservoir, which it does (EQUIL, item 5)
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SUMMARY
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-- Killough's figure 7:
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FGOR
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-- Killough's figure 8:
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FOPR
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-- Killough's figure 9:
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FGPR
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-- Killough's figure 10:
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FWPR
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-- Killough's figure 11:
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BPR
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1 1 1 /
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/
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-- Killough's figure 12:
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BGSAT
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1 13 1 /
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/
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-- Killough's figure 13:
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BWSAT
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10 25 15 /
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/
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-- Killough's figure 14:
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--WWIR
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-- 'INJE1' /
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-- Killough's figure 15:
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--WOPR
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-- 'PRODU21' /
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-- In order to compare Eclipse with Flow:
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WBHP
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/
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WGIR
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/
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--WGIT
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--/
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WGPR
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/
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WGPT
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/
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WOIR
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/
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--WOIT
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--/
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WOPR
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/
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WOPT
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/
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WWIR
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/
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--WWIT
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--/
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WWPR
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/
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WWPT
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/
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WOPP
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/
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WWPP
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/
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WGPP
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/
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SCHEDULE
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RPTRST
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'BASIC=2' /
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TUNING
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4.0 60.0 0.1 /
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/
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12 2 15 /
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WELSPECS
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-- Column 3: I-value of well head or heel
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-- Column 4: J-value of well head or heel
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-- - these coordinates are listed in Killough's dataset
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-- Column 5: ref. depth of BHP (ft)
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-- - stated in the middle of the top perforated cell
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-- - not anymore stated to be 9110ft in Killough
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-- Column 6: preferred phase for well
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-- - should be water for injector and oil for producers
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-- Column 7: drainage radius for calc. of productivity or
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-- injectivity indices (ft)
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-- - stated to be 60ft in Killough
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-- #: 1 2 3 4 5 6 7
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'INJE1 ' 'I' 24 25 9110 'WATER' 60 /
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'PRODU2 ' 'P' 5 1 9110 'OIL' 60 /
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'PRODU3 ' 'P' 8 2 9110 'OIL' 60 /
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'PRODU4 ' 'P' 11 3 9110 'OIL' 60 /
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'PRODU5 ' 'P' 10 4 9110 'OIL' 60 /
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'PRODU6 ' 'P' 12 5 9110 'OIL' 60 /
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'PRODU7 ' 'P' 4 6 9110 'OIL' 60 /
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'PRODU8 ' 'P' 8 7 9110 'OIL' 60 /
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'PRODU9 ' 'P' 14 8 9110 'OIL' 60 /
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'PRODU10' 'P' 11 9 9110 'OIL' 60 /
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'PRODU11' 'P' 12 10 9110 'OIL' 60 /
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'PRODU12' 'P' 10 11 9110 'OIL' 60 /
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'PRODU13' 'P' 5 12 9110 'OIL' 60 /
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'PRODU14' 'P' 8 13 9110 'OIL' 60 /
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'PRODU15' 'P' 11 14 9110 'OIL' 60 /
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'PRODU16' 'P' 13 15 9110 'OIL' 60 /
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'PRODU17' 'P' 15 16 9110 'OIL' 60 /
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'PRODU18' 'P' 11 17 9110 'OIL' 60 /
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'PRODU19' 'P' 12 18 9110 'OIL' 60 /
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'PRODU20' 'P' 5 19 9110 'OIL' 60 /
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'PRODU21' 'P' 8 20 9110 'OIL' 60 /
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'PRODU22' 'P' 11 21 9110 'OIL' 60 /
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'PRODU23' 'P' 15 22 9110 'OIL' 60 /
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'PRODU24' 'P' 12 23 9110 'OIL' 60 /
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'PRODU25' 'P' 10 24 9110 'OIL' 60 /
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'PRODU26' 'P' 17 25 9110 'OIL' 60 /
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/
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COMPDAT
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-- Column 2: I-value of connecting grid block
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-- Column 3: J-value of connecting grid block
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-- Column 4: K-value of upper connecting grid block
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-- Column 5: K-value of lower connecting grid block
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-- - these coordinates are listed in Killough's dataset
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-- Column 9: well bore diameter
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-- - Killough says radius is 0.5ft
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--Item 8 must be entered in order to get a match between Eclipse and Flow
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--No match if item 8 is defaulted
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-- #: 1 2 3 4 5 6 7 8 9
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'INJE1' 24 25 11 15 'OPEN' 1* 1* 1 /
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'PRODU2' 5 1 2 4 'OPEN' 1* 1* 1 /
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'PRODU3' 8 2 2 4 'OPEN' 1* 1* 1 /
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'PRODU4' 11 3 2 4 'OPEN' 1* 1* 1 /
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'PRODU5' 10 4 2 4 'OPEN' 1* 1* 1 /
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'PRODU6' 12 5 2 4 'OPEN' 1* 1* 1 /
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'PRODU7' 4 6 2 4 'OPEN' 1* 1* 1 /
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'PRODU8' 8 7 2 4 'OPEN' 1* 1* 1 /
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'PRODU9' 14 8 2 4 'OPEN' 1* 1* 1 /
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'PRODU10' 11 9 2 4 'OPEN' 1* 1* 1 /
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'PRODU11' 12 10 2 4 'OPEN' 1* 1* 1 /
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'PRODU12' 10 11 2 4 'OPEN' 1* 1* 1 /
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'PRODU13' 5 12 2 4 'OPEN' 1* 1* 1 /
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'PRODU14' 8 13 2 4 'OPEN' 1* 1* 1 /
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'PRODU15' 11 14 2 4 'OPEN' 1* 1* 1 /
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'PRODU16' 13 15 2 4 'OPEN' 1* 1* 1 /
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'PRODU17' 15 16 2 4 'OPEN' 1* 1* 1 /
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'PRODU18' 11 17 2 4 'OPEN' 1* 1* 1 /
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'PRODU19' 12 18 2 4 'OPEN' 1* 1* 1 /
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'PRODU20' 5 19 2 4 'OPEN' 1* 1* 1 /
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'PRODU21' 8 20 2 4 'OPEN' 1* 1* 1 /
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'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 /
|
|
/
|
|
-- The guiderates are calculated using well potentials
|
|
-- i.e WGRUPCON is not specified/
|
|
--WGRUPCON
|
|
--'PRODU2' 'YES' 2 'OIL' /
|
|
--'PRODU3' 'YES' 2 'OIL' /
|
|
--'PRODU4' 'YES' 2 'OIL' /
|
|
--'PRODU5' 'YES' 2 'OIL' /
|
|
--'PRODU6' 'YES' 2 'OIL' /
|
|
--'PRODU7' 'YES' 1 'OIL' /
|
|
--'PRODU8' 'YES' 1 'OIL' /
|
|
--'PRODU9' 'YES' 1 'OIL' /
|
|
--'PRODU10' 'YES' 1 'OIL' /
|
|
--'PRODU11' 'YES' 1 'OIL' /
|
|
--'PRODU12' 'YES' 1 'OIL' /
|
|
--'PRODU13' 'YES' 1 'OIL' /
|
|
--'PRODU14' 'YES' 1 'OIL' /
|
|
--'PRODU15' 'YES' 1 'OIL' /
|
|
--'PRODU16' 'YES' 1 'OIL' /
|
|
--'PRODU17' 'YES' 1 'OIL' /
|
|
--'PRODU18' 'YES' 1 'OIL' /
|
|
--'PRODU19' 'YES' 1 'OIL' /
|
|
--'PRODU20' 'YES' 1 'OIL' /
|
|
--'PRODU21' 'YES' 1 'OIL' /
|
|
--'PRODU22' 'YES' 1 'OIL' /
|
|
--'PRODU23' 'YES' 1 'OIL' /
|
|
--'PRODU24' 'YES' 1 'OIL' /
|
|
--'PRODU25' 'YES' 1 'OIL' /
|
|
--'PRODU26' 'YES' 1 'OIL' /
|
|
--/
|
|
|
|
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
|
|
30*10 /
|
|
|
|
|
|
-- At 300 days, the max oil rate for all producers is lowered
|
|
-- to 100 STBO and all wells set to GRUP controll:
|
|
|
|
WCONPROD
|
|
-- #: 1 2 3 4 9
|
|
'PRODU*' 'OPEN' 'GRUP' 100 4* 1000 /
|
|
/
|
|
|
|
-- The total rates is set to 1500 STBO
|
|
GCONPROD
|
|
-- oil water gas
|
|
'P' 'ORAT' 1500 /
|
|
/
|
|
|
|
|
|
TSTEP
|
|
6*10 /
|
|
|
|
|
|
-- At 360 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 /
|
|
/
|
|
|
|
-- GCONPROD must be set to 'NONE' for FLOW to not throw
|
|
GCONPROD
|
|
-- oil water gas
|
|
'P' 'NONE' 1500 /
|
|
/
|
|
|
|
|
|
TSTEP
|
|
54*10 /
|
|
-- End of simulation at 900 days
|
|
|
|
END
|
|
|
|
|
|
|