Dear expert,
i would like some guidance in simulate the GOR in oil + gas +water mixture.
i have oil composition and gas composition measured at 15 psig and 180 F.
The stream consist of oil, water, and gas. For oil and water there has been a flowrate basis,
but for the gas, it shall be calculate based on GOR value. oil is 7100 bOPD and water 199000 BWPD.
The GOR itself is measured at 160 F and 150 psig and the value is 65 SCF/bbl oil.
in simulation i put the GOR measurement after the oil , gas and water stream mixed.
and i found the gas increasing to be 2.6 MMSFCD.
if we calculate it just using excel, we will find that the gas will be only 0.4 MMSCFD.
please give some guidance, where shall the GOR measured, before or after mixed up the
the oil, water and gas stream? i will also attached the simulation file (HYSYS).
please change the extension before run it.
Full Version: Gor Ratio In Process Simulation
Excel file is completely in chaos, or something is wrong with my MS Office 
.
The confusion related to GOR, GLR, CGR and other volume ratios in Oil&Gas production comes from - based on my observations - insufficient information about conditions at which these values are re-calculated. GOR of any gas/oil/water mixture at, let's say 25bar and 50C, should be equal to the ratio of volumetric flowrates of separated gas (vapor) and separated oil (hydrocarbon liquid), but translated into standard conditions. In other words, actual volumetric flows of gas and oil at 25bar/50C should be translated into actual volumetric flows of gas and liquid at 1bar/15C (or any other reference standard condition in your company), and then these numbers are divided. This is your GOR at 25bar and 50C.
Confusion is avoided simply by always using the reference to standard conditions, regardless of actual parameters where separation of gas and oil took place. Re-check your calculations by applying this approach and let us know if there is any change in the results you obtain.
.The confusion related to GOR, GLR, CGR and other volume ratios in Oil&Gas production comes from - based on my observations - insufficient information about conditions at which these values are re-calculated. GOR of any gas/oil/water mixture at, let's say 25bar and 50C, should be equal to the ratio of volumetric flowrates of separated gas (vapor) and separated oil (hydrocarbon liquid), but translated into standard conditions. In other words, actual volumetric flows of gas and oil at 25bar/50C should be translated into actual volumetric flows of gas and liquid at 1bar/15C (or any other reference standard condition in your company), and then these numbers are divided. This is your GOR at 25bar and 50C.
Confusion is avoided simply by always using the reference to standard conditions, regardless of actual parameters where separation of gas and oil took place. Re-check your calculations by applying this approach and let us know if there is any change in the results you obtain.
P.S. You are running Hysys case with total 10 Adjust operations (6 in the main flowsheet and 2 in each sub-flowsheet). Even when using Simultaneous Adjustment, it is very hard for software engine to solve this puzzle, especially if initial guesses are far from convergence values. In cases when it is not possible to reach set point of target variable(s) with a given ranges of independent variables, you'll start receiving material balance error messages.
Try to narrow down the number of Adjuster operations by simply specifying the value of flow(s) of independent variables. Once when you reach convergence, tune them manually. Or increase the tolerance of existing Adjust operators.
Try to narrow down the number of Adjuster operations by simply specifying the value of flow(s) of independent variables. Once when you reach convergence, tune them manually. Or increase the tolerance of existing Adjust operators.
The field production profile is determined by reservoirs engineer together with engineer taking care Flow ansurance studies. The profiles and reference subject to their defintion. Sometime it refer to production separator at certain P&T, sometime at slugcatcher, sometime at stocktank and standard condition.
You may interprete it from their unit i.e. condensate at 10000 stbopd signify stock tank barrel oil per day, gas at 100 mmscfd signify million standard cubic feet per day, GOR of 200 scf/stbbl, etc.
You have to clarify with the reservoir engineer on the basis of their table. Don't guess.
By the way, when you discuss with them, please also clearly define the real meaning of stock tank (st) and standard (std). They may read st as 1 ATM at 37.8 degC and you may read as 1 ATM 25 degC. They may read standard (std) as 1 ATM at 15 deg C, you may read as 1 ATM, 25 degC.
You may interprete it from their unit i.e. condensate at 10000 stbopd signify stock tank barrel oil per day, gas at 100 mmscfd signify million standard cubic feet per day, GOR of 200 scf/stbbl, etc.
You have to clarify with the reservoir engineer on the basis of their table. Don't guess.
By the way, when you discuss with them, please also clearly define the real meaning of stock tank (st) and standard (std). They may read st as 1 ATM at 37.8 degC and you may read as 1 ATM 25 degC. They may read standard (std) as 1 ATM at 15 deg C, you may read as 1 ATM, 25 degC.
QUOTE (JoeWong @ Aug 20 2008, 06:14 AM) 
The field production profile is determined by reservoirs engineer together with engineer taking care Flow ansurance studies. The profiles and reference subject to their defintion. Sometime it refer to production separator at certain P&T, sometime at slugcatcher, sometime at stocktank and standard condition.
You may interprete it from their unit i.e. condensate at 10000 stbopd signify stock tank barrel oil per day, gas at 100 mmscfd signify million standard cubic feet per day, GOR of 200 scf/stbbl, etc.
You have to clarify with the reservoir engineer on the basis of their table. Don't guess.
By the way, when you discuss with them, please also clearly define the real meaning of stock tank (st) and standard (std). They may read st as 1 ATM at 37.8 degC and you may read as 1 ATM 25 degC. They may read standard (std) as 1 ATM at 15 deg C, you may read as 1 ATM, 25 degC.
You may interprete it from their unit i.e. condensate at 10000 stbopd signify stock tank barrel oil per day, gas at 100 mmscfd signify million standard cubic feet per day, GOR of 200 scf/stbbl, etc.
You have to clarify with the reservoir engineer on the basis of their table. Don't guess.
By the way, when you discuss with them, please also clearly define the real meaning of stock tank (st) and standard (std). They may read st as 1 ATM at 37.8 degC and you may read as 1 ATM 25 degC. They may read standard (std) as 1 ATM at 15 deg C, you may read as 1 ATM, 25 degC.
if i have GOR 65 SCF/bbl oil at 160 oF and 150 psig, does it mean that i have 65 SCF of oil and 1 bbl oil at this state?
for instance i have gas with certain composition at 180 F and 15 psig, then i' ve told the GOR is 65 measuring at 160 F and 150 psg. does GOR mean [gas measued at 160F and 150psig/oil measured at 160F and 150 psig], so i separately count them?
Or gas/oil in [mixture of oil+water+gas] measued at 160 F and 150 psig.
These two definition gives really significant differences.
Please see file that i attached before..
regards,
QUOTE (RZD_Tripatra @ Aug 21 2008, 12:59 PM)
if i have GOR 65 SCF/bbl oil at 160 oF and 150 psig, does it mean that i have 65 SCF of oil and 1 bbl oil at this state?
It shouldn't be the case. GOR at 160F and 150psig is obtained by division of gas volume flow (separated at 160F and 150psig but expressed/recalculated at standard conditions) with liquid hydrocarbon volume separated at same conditions (160F, 150psig) but also expressed as standard liquid volume flow.
GOR 65 SCF/bbl oil at 160 oF and 150 psig...
I would read it as a fluid separated at 160°F and 150 psig, it is a ratio of vapor volumetric flow expressed at Standard Condition* (unit in SCF) and liquid hydrocarbon (condensate only) volumetric flow at 160°F & 150 psig (unit in BBL).
*Standard condition shall be defined accorinding to project definition
HOWEVER, in many events the reservoir engineer might have considered at stock tank condition or standard condition but written as BBL... that's why i strongly recommend you to confirm with reservoir engineer.
I would read it as a fluid separated at 160°F and 150 psig, it is a ratio of vapor volumetric flow expressed at Standard Condition* (unit in SCF) and liquid hydrocarbon (condensate only) volumetric flow at 160°F & 150 psig (unit in BBL).
*Standard condition shall be defined accorinding to project definition
HOWEVER, in many events the reservoir engineer might have considered at stock tank condition or standard condition but written as BBL... that's why i strongly recommend you to confirm with reservoir engineer.
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