GEOL40310_LectureA09_Development1_2023.pdf

Geol 40310 Fossil Fuels and Carbon Capture & Storage (CCS) Lecture A9: Reservoir Development and Production 1 Drive mechanisms and recovery factors T Manzocchi, University College Dublin Autumn 2023-24 1 Lecture A9: Production 1: Drive mechanisms and recovery factors Primary Drive mechanisms. Gas...

Geol 40310 Fossil Fuels and Carbon Capture & Storage (CCS) Lecture A9: Reservoir Development and Production 1 Drive mechanisms and recovery factors T Manzocchi, University College Dublin Autumn 2023-24 1 Lecture A9: Production 1: Drive mechanisms and recovery factors Primary Drive mechanisms. Gas: Pressure depletion. Oil: Pressure depletion / Solution Gas Drive Gas Cap Drive Water-drive Secondary drive mechanism: Immiscible Water and/or Gas injection Recovery factors and water-flood recovery process Pore-scale displacement efficiency Mobility ratio and sweep efficiency Macroscopic displacement efficiency 2 Geol 40310 Lecture A9 1 Primary, Secondary and Tertiary Recovery Primary Recovery Use the reservoir’s own energy Secondary Recovery Tertiary Recovery (Change the flow paths) (Change the fluid properties) Increase the reservoir’s energy Reduce Hydrocarbon viscosity Water Injection. Gas Injection. Water Alternating Gas Injection Thermal methods Deletion drive Solution gas Drive Improve Sweep and Drainage efficiency Gas Cap Drive Water Drive Improve porescale efficiency Miscible flooding (solvents) Waterflood design. Infill drilling. Horizontal wells. Compaction Drive Chemical flooding Foams, surfactants 3 25 years of production from Ula, Norwegian North Sea Primary depletion Secondary Recovery: Waterflooding Tertiary Recovery (EOR): Miscible Gas Inection, foam injection Oil production rate (mbbls/d) Plateau 2 Plateau 1 STOIIP ca. 1 Billion Bbls. 2012 2006 GOR (scf/stb) Start Foam Assisted WAG Extend WAG Scheme First Gas returns Sttart decline Water breakthrough Increased injection rate Start miscible WAG 1996 1986 Gas Injection rate (mmscf/d) Start water injection Watercut (%) Water Injection rate (mbbls/d) Arrested decline Zhang et al. (2013) 4 Geol 40310 Lecture A9 2 Primary, secondary and tertiary recovery Primary Recovery Lecture A9 Use the reservoir’s own energy Deletion drive Solution gas Drive Gas Cap Drive Water Drive Compaction Drive Secondary Recovery (Improved oil Recovery) Enhanced Oil Recovery (Tertiary Recovery) Lecture A9 Increase the reservoir’s energy Lecture A12 (unconventionals) Reduce Hydrocarbon viscosity Water Injection. Gas Injection. Immiscible WAG (water alternating gas) Lecture A11 Improve Sweep and Drainage efficiency Waterflood design. Infill drilling. Horizontal wells. Thermal methods Lecture D2 (CO2-EOR) Improve porescale efficiency Miscible flooding (solvents, miscible WAG) Chemical flooding Foams, surfactants Lecture A10: Ekofisk Field example 5 5 Depletion drive for gas production • • • • Gas reservoirs are produced by the expansion of gas. Gas is much more compressible than water, hence depressurisation of the reservoir increases the volume of gas, which is released up the well. Typical gas-field recovery factors range from 50-80%, and depend on the final abandonment pressure. Main challenge in gas field development is to ensure a long, sustainable (10+ years) plateau production rate required for a good sales price. Initial conditions Production path 6 Geol 40310 Lecture A9 3 Gas reservoir production Gas reservoir production is greatly aided by favourable mobility and compressibility Compressibility is fractional change in volume per unit change in pressure. The speed at which fluid model is controlled by its mobility: Mobility = 𝑘 𝜇 A typical gas compressibility is 5x10-4 psi-1 Water is ca. 200 times lower: 3x10-6 psi-1 (Oil is ca. 10-5 psi-1) This is straight from Darcy’s law: 𝑘 Δ𝑃 𝐴 𝜇 𝐿 A typical gas viscosity is ca 0.01cp; 50 times lower than oil or water. Therefore gas moves 50 times quicker for the same pressure drop than water. Because of this favourable mobility, gas production at 0% water-cut is common. q= • This means that there is only a small change in reservoir pressure when a volume of gas is produced. The extraction of gas is accommodated by expansion of gas, rather than by movement of the aquifer. Between them, these two factors imply that gas reservoirs can be efficiently produced (50-80%) by simple pressure depletion – the reservoir is “blown down”. 7 Gas Formation Volume Factor BG: Gas formation volume factor: The volume in barrels that one standard cubic feet of gas occupies as free gas in the reservoir. (rbl/scf) Gas Formation Volume Factor (BG) = Volume of gas in Reservoir Volume of gas at surface (rbl/scf) NB: note units conversion in this ratio – Reservoirs volumes are often measured in barrels (rbl), but stock-tank gas volumes are measures in cubic feet (scf). BG A typical value of BG is 1000: i.e 1 bbl in the reservoir expands to fill 1000 ft3 at surface Pressure 8 8 Geol 40310 Lecture A9 4 Kinsale Head and adjoining gas fields – North Celtic Sea Basin 24’’ pipeline 9 Gas production: Kinsale Head and adjoining fields 1991: Ballycotton 1999: SW Kinsale 2006: SW Kinsale modified for gas storage July 2020: End of production and start of decommissioning Reservoir pressure at datum depth psi) Gas Production rate: Billion cubic feet / year 2003: Seven Heads 1978: Kinsale Head • Kinsale Head gas field produced over 2 TCF of gas during its 42-year production life. • A number of smaller satellite gas fields were also developed through the Kinsale Head infrastructure. • SW Kinsale was used for gas storage from 2006 – 2017, with a working volume of 8 BCF and a maximum withdrawal rate of 0.1 BCF/day (ca. 20% of Irish consumption). • Kinsale gas field currently discussed as a potential CO2 sequestration site and/or storage site for green hydrogen. 10 Geol 40310 Lecture A9 5 Primary and secondary drive mechanisms Drive mechanism: Gas reservoirs Deletion drive Solution gas Drive Principal mechanisms for oil reservoirs Initial Condition: High Compressibility fluid (i.e. best for gas) Undersaturated oil (no gas cap) Gas Cap Drive Saturated oil with a gas cap. Often produced gas is injected to enhance the drive (secondary recovery) Water Drive Saturated or unsaturated oil. Water is either from a larger underlying aquifer (primary recovery) or is injected (secondary recovery) Compaction Drive Compressible rock fabric. Unusual. Combination drive: In many cases, more than one drive mechanism is active. A common example is an initial gas cap combined with active water drive. 11 Depletion drive and Solution gas drive for oil production PB • • • • Initial oil production via pressure depletion is inefficient due to low oil compressibility. Once pressure falls below PB, dissolution of gas provides main energy and oil production rates increase. The producer wells should be positioned low down in the structure so that the liberated gas flows towards the reservoir crest under buoyancy to form a secondary gas cap (which will provide additional energy). Abandonment typically occurs due to low pressures and high GOR, with primary recovery factors of 5-30%. Secondary recovery (water or gas injection) may increase this. 12 Geol 40310 Lecture A9 6 Gas cap drive for oil production • • • • • Requires a saturated reservoir with an initial gas cap that expands as the pressure drops. Energy is also provided by gas released from the depressurising oil column (i.e. solution drive). Because both phases start on the saturation line, only small pressure decreases are required to provide large volume increases. Because of this, primary recovery factors are greater than for solution drive, at 20-50%. The same considerations concerning well placement and rates, and management of gas movement, are required as for solution-drive reservoirs. 13 Water Drive for oil reservoirs • • • • • • Requires a reservoir in communication with an aquifer that provides the bulk of the energy. As oil is produced, the aquifer expands to fill up the space vacated by the oil. Attainable production rate and pressure decline depend on the strength of the aquifer. The geometry of the reservoir determines whether a bottom-drive or edge-drive configuration exists. Production wells are place at the top of the structure, to ensure later water break-through. Primary water-drive recoveries can range from 35-75% Edge-drive Bottom-drive 14 Geol 40310 Lecture A9 7 Secondary Recovery Inject fluid into the reservoir to enhance the drive mechanism May be initiated at various states of the reservoirs life 15 Lecture A9: Production 1: Drive mechanisms and recovery factors Primary Drive mechanisms. Gas: Pressure depletion. Oil: Pressure depletion / Solution Gas Drive Gas Cap Drive Water-drive Secondary drive mechanism: Immiscible Water and/or Gas injection Recovery factors and water-flood recovery process Pore-scale displacement efficiency Mobility ratio and sweep efficiency Macroscopic displacement efficiency 16 Geol 40310 Lecture A9 8 Oil recovery factor Ultimate Recovery UR= STOIIP * RECOVERY FACTOR Gross Rock Volume Stock tank Oil Initially In Place Porosity Formation Volume Factor STOIIP = GRV * NTG * φ* SO * (1/BO) Net:Gross Ratio Oil saturation 17 17 Recovery factor for a waterflood Recovery factor = Microscopic displacement * macroscopic sweep 18 Geol 40310 Lecture A9 9 Microscopic displacement efficiency: a function of the Imbibition capillary pressure curve For a water-wet oil reservoir, reservoir production follows the imbibition capillary pressure curve, leaving irreducible oil at zero capillary pressure. A. water Migration and trapping: DRAINAGE B. water C. B. Capillary pressure oil Drainage oil Imbibition Oil Recovery: IMBIBITION (if water-wet reservoir) 0 A. C. 1 Water saturation Unrecoverable oil 19 Darcy’s law for two-phase flow – relative permeability SWI Caillary pressure Po Pw Po + Po Pw + Pw qw qo A SWOR Reservoir production along imbibition capillary pressure curves 0 0 0.25 0.5 0.75 1.0 Water Saturation L kkro Po A o L qw = kkrw Pw A w L PC = Po − Pw Relative permeability qo = SWI SWOR 1 krw kro 0 0 0.25 0.5 0.75 1.0 Water Saturation 20 Geol 40310 Lecture A9 10 Mobility ratio Mobility = SWI 𝑘 𝜇 Relative permeability The speed at which fluid moves is controlled by its mobility: Different fluids has different mobilities in the same rock since they have different viscosities and relative permeabilities. Therefore the mobility of fluid phase p is given by: 1 kro krw 0 0 𝑘𝑘𝑟𝑝 Mobility𝑝 = 𝜇𝑝 The mobility ratio M is defined as the ratio between the replacing fluid (water or gas) and the replaced fluid (oil). SWOR 0.25 0.5 0.75 1.0 Water Saturation For a waterflood: Sw = 0.75 𝑘𝑟𝑤 Τ𝜇𝑤 𝑀= 𝑘𝑟𝑜 Τ𝜇𝑜 Sw = 0.2 M < 1 Oil will flow preferentially: stable displacement front M > 1 Water will flow preferentially: unstable displacement front 21 Control of Mobility ratio on areal sweep efficiency Stable fronts at low Mobility ratios. Mobility = 0.15 Break-through at 0.8 PV Mobility = 1.0 Break-through at 0.7 PV Viscous fingering at high Mobility ratios. Mobility = 2.4 Break-through at 0.4 PV Mobility = 71 Break-through at 0.1 PV Oil recovery (%) Areal sweep in a quarter- five-point pattern. Curves of different pore volumes of injected gas M = 0.15 M = 1.0 M = 2.4 M = 71 Pore volumes Injected water 22 Geol 40310 Lecture A9 11 Reservoir Heterogeneity: geological control on macroscopic sweep efficiency Allen and Allen (2013), after Gluyas and Swarbrick (2004) 23 macroscopic sweep efficiency on the order of 1km Weber (1986) 24 Geol 40310 Lecture A9 12 Recovery from the largest Norwegian oil fields. Billion barrels of oil The 25 largest Norwegian oilfields have expected recovery factors averaging 47%. Norwegian Petroleum Directorate (2019) 25 Geol 40310 Lecture A9 13