Dandina N. Rao and Watheq Al-Mudhafar - NorTex...
Transcript of Dandina N. Rao and Watheq Al-Mudhafar - NorTex...
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Dandina N. Rao and Watheq Al-Mudhafar
Craft & Hawkins Department of Petroleum Engineering Louisiana State University
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USA-DOE Chevron Innovative Research Fund LSU-Lift Fund
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LOUISIANA STATE UNIVERSITY 3
Acknowledgments
United States Department of Energy, Louisiana Board of Regents,
Marathon Oil Co., ConocoPhilips, Anadarko Petroleum, Sasol North
America, ….. for financial support and project participation
Previous & Present Graduate Students:
Zahid Mohamad, Chandra Vijapurapu, Subhash Ayirala (Shell),
Madhav Kulkarni (Marathon), Amit Sharma (Cairn Energy,
India), Thaer Mahmoud (ConocoPhillips), Daryl Sequeira (Core
labs, Australia), Wei Xu (Shell), Ayodeji Abe (Occi), Chandra
Busireddy, Ruiz Paidin (Suriname), Dayanand Saini (CA), Yu
Zheng (Dallas Tx)), Satyajit Mondal (Uof Alaska) Leela madhav
Gullapalli, Mohamed Abdelrahim (Shell), Azadeh Kafili (Houston,
Tx), Bikash Saikia (LSU), Paulina Mwangi (LSU), Mohamad Al-
Riyami (Oman), Watheq Al-Mudhafar (LSU), Sandeep Gupta
(LSU), Foad Haeri (LSU), Alok Shah (LSU), Iskandar
Dzulkarnain, Masoud Mohandessi, Dawood Munawar, Khadhr
Altarabulsi….
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LOUISIANA STATE UNIVERSITY 4
Water injected in WAG floods, blocks part of the oil from gas contact reducing displacement efficiency (ED < 1).
Present Industry Practice – Water Alternating Gas Floods
(Ref: US-DOE)
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LOUISIANA STATE UNIVERSITY 5
59 Field projects report recoveries from 5 to 10%!
A more realistic view of a WAG flood might be like this
Gravity segregation of gas and water can be seen even in core level displacement tests
To overcome these limitations of WAG process, we have developed the gas-assisted gravity drainage (GAGD) process in the EOR labs of LSU-Pet-Eng. Dept.
Water
Unswept Region
CO2
Water CO2
Oil Bank Miscible Zone
Present Limitation of WAG
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Figure 1: Schematic Drawing of GAGD process (Rao, 2012)
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Advantages of the GAGD Process
(Rao et al., SPE 89357) Gas does not compete with oil for flow to producer - CO2
segregates at the top – delaying gas breakthrough
Horizontal wells can produce at very low drawdown and high
rates
No increase in water saturation, which mitigates water-shielding
and increases gas injectivity
Increased volumetric sweep as CO2 chamber grows downward
and sideways
Utilizes existing vertical wells for gas injection - lowering cost
Reservoir heterogeneities (fractures), while detrimental to WAG,
may even be beneficial in GAGD
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Miscible GAGD Process
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S.
No:
Similarity Groups Formulation References
1. Geometric Aspect Ratio (RL)
H
V
LK
K
H
LR
Shook et al, 1992
2. Capillary Number (Nc)
Ratio of viscous forces to capillary
forces
Grattoni et al, 2000
3. Bond Number (NB)
Ratio of Gravity forces to capillary
forces
Kg
Grattoni et al, 2000
4. Fluid property group ( Kantzas et al, 1988 and Blunt
et al, 1995.
5. Gravity Number (NG)
Ratio of gravity forces to viscous
forces
do
Gv
Kg
N
Shook et al, 1992.
6. Dimensionless Time (td)
tSSh
ggkk
wioro
c
o
ro
)1(
/
Miguel et al., 2004
)(
)(
owgo
goow
v
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Protocol Dimensional Analysis
Darcy Velocity
NB
Geologic Parameters
Characteristic Length
Reservoir Map(s) & Well Logs
Field Petrophysical & Fluid Properties
Injectant / Reservoir PVT Properties
PVT Simulation(s)
NC NDB NG N
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The objective of this research are:-
I. Investigate the feasibility of GAGD process to improve oil recovery in a Field-scale application.
II. Effective Comparison of GAGD process through CO2 and Flue Gas injection in terms of reservoir oil and gas flow responses.
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GAGD Reservoir Simulation
Gridding: 69 in I-direction, 66 in J-direction, and 12 in K-direction.
20 vertical injector are installed at the top two layers & 10 horizontal producers are proposed at the middle zone above the oil water contact.
The Immiscible GAGD-CO2 was conducted through EOS-Compositional reservoir simulator (CMG-GEM) and Peng-Robenson EOS was employed for phase equilibrium calculation in (CMG-WinProp).
Horizontal producers of 3000 m length were placed through the reservoir at sand and shaly-sand lithology zones.
The simulation period includes 61 yeas history (1954-2015) and the GAGD prediction period is 10 years (2016-2026).
Initial reservoir pressure=5186 psi, Pb=2660 psi, and MMP=3500 psi.
Table: GAGD Base Case Setting of Operational Design Parameters
Table: Reservoir Fluid Properties
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Table: Initial & Current Fluid in Place in Main Sector
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Figure 2 : Geographical Location of South Rumaila Field, Al-Ameri, 2009
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Figure 3 : Field Production History, Al-Mudhafar, 2013
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General Work Flow for Integrated Reservoir Studies, Al-Mudhafar, 2014
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Production and Injection Well Locations in Sand and Shaly Sand Zones, Al-Mudhafar, 2015
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Production and Injection Well Locations in High Permeable Zones, Al-Mudhafar, 2015
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Production and Injection History Matching, Al-Mudhafar, 2015
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Table 1: Initial & Current Fluid In Place of Rumaila Oil Field (Main Sector)
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3D Spatial-Temporal Oil Saturation of GAGD CO2 Flooding
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3D Spatial-Temporal Oil Saturation of GAGD Flue Flooding
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3D Spatial-Temporal Gas Saturation of GAGD CO2 Flooding
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Reservoir Oil Response Comparison between CO2 and Flue Gas Flooding
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NPV is defined as the revenues from produced oil and gas sales, after subtracting the costs of disposing produced water and the cost of injecting water and the initial costs. The initial costs represent the capital expenditures. The result is the net cash flow: Net Cash Flow (t) =Oil Production (t) Oil Price+ Gas Production (t) Gas Price –Water Production (t) Water Handling Cost- Water Injection (t) Water Injection Cost-OPEX-CAPEX Oil price: ($ per STB). Table: NPV Calculation of GAGD Process Evaluation Gas price: ($ per MSCf). Water handling cost: ($ per bbl). Water Injection Cost: ($ per bbl). Where: - NPV: net present value. NCF: net cash flow. FV: future income value. PV: present income value. i: interest rate.
NPV =NCF t( )
1+ i( )t
t
å
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GAGD EOR process was implemented in a well-characterized large reservoir (19.5 B bbl OOIP) using a compositional simulator.
In the GAGD simulation, 20 vertical gas injectors were installed at the top along with 10 horizontal wells for production.
The CO2-GAGD case led to significant incremental oil recovery of approximately 330 million STB more than the primary production to the end of the prediction period.
FlueGas-GAGD performed almost on par with CO2-GAGD.