Reservoir Management Background OOIP, OGIP Determination and Production Forecast Tool Kit Recovery Factor ( R.F.) Tool Kit

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1 Reservoir Management Background 1. OOIP, OGIP Determination and Production Forecast Tool Kit A. Volumetrics Drainage radius assumption. B. Material Balance Inaccurate when recovery factor ( R.F.) < 5 to 10 % C. Mathematical Models. D. Analogies. E. Decline Curve Analysis Assumes field conditions remain constant and production is not constrained due to existing wellbore or facility construction. F. Nodal Analysis Calibrate model with measured bottom hole flowing pressure ( BHFP ) and surface production rates. 2. Recovery Factor ( R.F.) Tool Kit A. Oil Reservoir Drive Mechanism R.F. ( % ) i. Formation Compaction 2 to 10 ii. Solution Gas Drive 10 to 20 iii. Gas Cap Expansion 20 to 40 iv. Natural Water Drive 40 to 60 v. Gravity Drive 60 to 80 B. Gas Reservoir Drive Mechanism R.F. ( % ) i. Pressure Depletion 70 to 90 ii. Natural Water Drive 50 to 60 iii. Pressure Depletion Condensate 20 to 40 iv. Gas Cycling Condensate 30 to Waterflood Recovery Tool Kit. Lithology Primary. Secondary Total Secondary :: Primary R.F. % R.F.% R.F. % Ratio A. Sand Stone :: 1 B. Carbonate :: 1 4. Pressure Transient Analysis. A. Superposition ( Horner plot ), Log-Log, and Derivative analysis. When derivative plot flattens out you can calculate: Skin, KH, and Average Reservoir Pressure. i. KH (permeability * height). ii. Skin a Wellbore Damage, Positive Skin. b Wellbore Improvement, Negative Skin. iii. Average reservoir pressure ( P AVG ) a Steady State Flow : P AVG = P* b Un-Steady State Flow : P AVG Does Not Equal P* iv. Radius Investigation. v. Reservoir heterogeneities. a Multiple Faults. b Leaky Fault. c Constant Pressure Boundary. d Closed (Limited) Reservoir. e Well Interference. f Fluid Contacts (Gas-Water Contact). 1

2 g h i Radial Composite Model. Dual Porosity / Permeability Model. Partial Penetration. 5. Depositional Environments. A. Fluvial Deltaic Deposits Mitsue Gilwood Sand Background i. Main distributary channel High energy environment (good rock quality). a b Water Injection in southwest portion of field. Formation Micro Imager ( FMI. ) - Bedding plane angle could be used to delineate up-dip development drilling opportunities in the main distributary channel. ii. Transitional deltaic zone Medium energy environment. iii. Pro-Delta Low energy environment (poor rock quality). B. Meander Point Bar Abandoned channels (compartmentalization). C. Distributary Mouth Bar Abandoned channels (compartmentalization). 6. Reservoir Compartmentalization Tool Kit. A. Absolute proof that reservoir is in communication. i. Interference tests not practical for gas reservoirs due to gas compressibility. ii. Reservoir tracers. B. Insufficient proof that reservoir is in communication. i. Static reservoir pressure. ii. Pressure transient analysis (PTA), DST s, RFT, MDT. iii. Geochemistry Oil, Gas, and Water properties. iv. PVT analysis Fluid Characterization. v. Fault seal analysis. vi. Residual salt analysis 87 SR / 86 SR ratio. vii. Original fluid contacts Tilted and Perched oil/water contacts. viii. Geologic interpretation Depositional environments and Paleontology. ix. 2D, 3D, 4D, and Cross-well Seismic. 7. Plan Opportuntities A. Prioritize Opportunities. B. Perform Analysis. C. Prepare for Surprises. D. Plan for Alternatives. E. Project Implementation. 2

3 Reservoir Management Background II 1. Recovery Factor ( R.F. ) A. R.F. = Ultimate Oil or Gas R e (UOR, UGR) / (OOIP, OGIP) B. R.F. = Sweep Efficiency (S.E.) * Displacement Efficiency (D.E.) 2. Displacement Efficiency ( D.E.) A. D.E. = Movable Oil / OOIP B. D.E. = [ Initial Oil Saturation (S oi ) Residual Oil Saturation (S or ) ] / S oi 3. Sweep Efficiency = function (x) A. S.E. = S.E. Vertical * S.E. Arial B. Well Spacing C. Reservoir Heterogeneities D. Fluid Densities E. Mobility Ratio 4. Critical Rock Properties. A. Relative Permeability B. Capillary Pressure ( P c ) C. Permeability ( K ) D. Porosity 5. Relative Permeability. A. K Absolute (Does Not Equal) Relative Perm Oil (K ro ) + Relative Perm H 2 O (K rw ) B. K Absolute > K ro + K rw C. K Irreducible Water Saturation (S wirr ) = 0.7 to 0.85 * K Absolute D. K S or = 0.3 to 0.5 * K ro 6. Capillary Pressure ( P c ). A. Mercury Injection Inexpensive & quick, must correct to reservoir conditions, correction factor approximately 500 % B. Core Floods Small pressure drop across core plug must utilize a bump end of the core flood, reservoir closure < 400 ft for oil/water systems. C. Centrifuge method Preferred laboratory method when reservoir closure > 400 ft for oil/water systems. D. Maximum P c (oil/water = Closure (Gradient Water Gradient Oil ) E. Maximum P c (gas/water = Closure (Gradient Water Gradient Gas ) 7. Mobility Ratio = function (x). A. Relative Permeability. B. Viscosity. C. [(K rw ) / Viscosity Water ] / [(K ro ) / Viscosity Oil ] 8. Methods for Measuring Initial Saturations. A. Capillary Pressure Tests B. Open Hole Logs 9. Reservoir Characterization = function (X) A. Depositional Environment B. Digenesis C. Structure 3

4 Reservoir Management Background III 1. Decline Curve Analysis Tool Kit. Requires unconstrained production rates and assumes all conditions in the field remain the same in the future. A. Exponential Decline. i. Straight line on Log rate versus linear time plot.. ii. Straight line on linear rate versus linear cumulative production plot. a Used when shut-in periods exist throughout the production history. iii. Solution gas drive mechanism. iv. Pressure depletion drive mechanism for a gas well. B. Hyperbolic Decline. i. No straight line on Log rate versus linear time plot. High initial exponential decline rate followed by a gradual reduction in production decline rate. ii. Displacement drive process. a Natural water drive b Waterflood c Gas cap expansion iii. Low permeability reservoirs. iv. Dual porosity or fractured reservoirs. v. Porportional to production rate. C. Coning / Cusping. i. Negative slope on WOR, WGR and GOR derivative plot. ii. Water cone will stop growing with the existence of vertical flow barriers. iii. Water cut is proportional to production rate. D. Gas over-running, or Water under-running, water or gas is traveling a long distance aerially to the producing well. 2. Water Coning Diagnostic Tool Kit. A. Review production rate and water cut behavior. B. Calculate critical coning rates. C. Generate water oil ratio derivative plots. D. Compare to analogy fields and wells. E. Interpret reservoir heterogeneities and identify vertical flow barriers. F. Change production rate and monitor water cut. G. Run and interpret time lapsed cased hole logs. H. Conduct single well reservoir simulation study. 4

5 Reservoir Management Background IV 1. Geological and Geophysical Work Flow Tool Kit. A. Map Structure B. Define Reservoir Facies Using Log and Core. i. Core examination. ii. Scanning Electron Microscope (SEM), pore throat identification. iii. Bedding Plane Angle. iv. Picket plots - Log Resistivity versus porosity. v. Ichno Facies. vi. Electro Facies. C. Map gross thickness of reservoir facies. D. Map net sand or Net to Gross ratio by facies. E. Map porosity and permeability by facies. F. Integrate fluid contacts. G. Generate Net Oil Isopach and Net gas isopach maps. 5

6 Reservoir Management Background V 1. Material Balance Tool Kit. A. Quality Control. i. Average pressure data should be calculated using a single datum preferably at the top of structure. ii. Tank model with constant pressure and fluid properties throughout tank. B. Gas Reservoirs. i. P/Z Plot. a b c Pressure Depletion, straight line. Over-Pressured Reservoir. 1 Pressure gradient >.6 psi/ft account for formation compressibility effects C f 2 Extrapolation of P/z plot when pressure gradient is greater than a normal pressure gradient (.45 psi/ft) will result in over estimating OGIP by a factor of four. 3 Formation collapse occurs when reservoir pressure reaches normal pressure gradient. Hyperbolic P/z plot. 1 Water Drive. 2 Low Permeability Reservoir, Transient P/Z Method. 3 Dual porosity / fractured reservoir. 4 Offset drilling opportunities. C. Oil Reservoirs i. FE Method. ii. Campbell Method. iii. Cole Plot. iv. Gas Cap Expansion Model. v. Havlena Odeh Model (Aquifer Model). vi. Tehrani Method (Aquifer Model). vii. Tarners Solution Gas Drive Method. 6

7 Reservoir Management Background VI 1. Fracture Identification Tool Kit. A. Surface Lineaments. B. Indirect Seismic Indicators (Dunham Salt). C. FMI / FMS (Micro-Resistivity Image Log). D. Coherency Seismic Interpretation. E. Wellbore Elipticity. F. Orientated Core. G. Pressure Transient Analysis, (valley in derivative curve). H. Hyperbolic Production Decline, Log rate versus linear time plot. I. Production from well patterns (Rapid breakthrough of water or gas) J. Drilling Penetration Increases. K. Mud Loss, Sudden Gas Shows. L. Derivative Structure Map. M. Spectral Gamma Ray. 2. Dual Porosity (Matrix and Fractures) A. Reservoirs typically limestone & dolomite, however could be sandstone. B. Flow in Fractures Oil Storage in Matrix, (Larger reserves than single porosity reservoirs, unless aquifer is present). C. Flow and Oil Storage in Fractures only, (Bakken Case Study) D. No Flow between matrix to matrix blocks. 3. Difference between Dual & Single porosity reservoirs. A. Capillary Pressure Forces (No transition zone) D. Relative Permeability characteristics, vertical equilibrium (Straight line K ro and K rw Curves.) 4. Triple Porosity(Matrix, Fractures, Vugs) 5. Fracture Types A. Tectonic Fractures B. Fractures Generated By Folding i. Longitudinal Fractures. ii. Transverse Fractures. iii. Diagonal Fractures. C. Fractures Sandwiched between Un-Fractured Beds. Alternating layers of permeable and tight layers. D. Stylolite Fractures Vertical flow barriers. 7

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