Exam 1

Material Balance

"Accounting" concept of material balance. Requires all inflows/outflows/generations, avg reservoir pressure, rock, fluid and rock-fluid properties. Oil Material balance: less common than gas (pressure required) Gas material balance: Volumetric dry gas reservoir (p/z vs. Gp (straight line), abnormally-pressured dry gas reservoirs, waterdrive/influx Yields reservoir volume

4 things got from material balance calculations

1). Aquifer influx and strength - diagnostic plots (cole-gas, campbell-oil) 2). HCIP estimate 3). Reservoir compartmentalization 4). Fluid properties and compressibility

Sedimentary Classifications

1). Clastic or detrital: Rock formed from the consolidation of loose sediment derived from previously existing rocks 2). Chemical and biochemical: Rock formed by the precipitation of minerals from solution by either organic or inorganic processes

4 major components reservoir

1). Framework: Sand (and silt) Size Detrital grains 2). Matrix: Clay size detrital material 3). Cement: Material precipitated post-depositionally, during burial. Cements fill pores and replace framework grains 4). Pores: Voids between above components Engineers use term "matrix" referring to everything but pores

Asphaltenes

1). Polarizable 2). Polydisperse 3). Heavy fraction in crude oil

Operational definition

1). Soluble in aromatic solvents 2). Insoluble in light paraffinic solvents

Ternary diagrams for phase saturations

3 phase saturation of oil, water and gas to plot relative permeability as the independent variable. 2 of the 3 saturations are independent

Gas Viscosity

A measure of internal resistance to shear or angular deformation ( or to flow), ratio of shear stress and velocity gradient (or shear rate)

What is a fluid phase?

A portion of the system (body of matter with finite boundaries: physical or virtual) which has homogeneous intensive properties and it is bounded by a physical surface

Thermal Conductivity

Ability to conduct heat

To get the most representative hydrocarbon fluid characterization, which of the following is recommended

Acquire fluid samples from bottom-hole in single phase NOT: Acquire samples from commingled wells, separators or use production data to determine the fluid characterization

Oil-wet rock

Adhesive tension between oil and the rock surface exceeds that between water and the rock surface

Water-wet rock

Adhesive tension between water and the rock surface exceeds that between oil and the rock surface

Adhesion Tension

At = interfacial energy of oil and solid minus the interfacial energy between water and the solid Water-wet: At < 0 or 0 <= x <= 90deg Oil-wet: At > 0 or 90 <= x <= 180

Tars

Black substance, density < 10 API, viscosity > 10,000 cp, C7+ composition > 90%

Two Phase Formation Volume Factor

Bt=Bo+Bg(Rsb-Rs) (SCF/STB)

Chemical sedimentary classifications

Calcite (nonclastic: fine to coarse crystalline, Clastic: varying shells and fragments and levels of cementation) Quartz (nonclastic: very fine crystalline; chert) Gypsum (nonclastic: fine to coarse crystalline) Halite (nonclastic: fine to coarse crystalline; rock salt)

The height of the transition zone above the fluid contacts in a hydrocarbon reservoir mainly depend on....

Capillary Pressure NOT: Relative permeability, aquifer extent, kerogen

Compressibility

Change in volume due to change in pressure (inversely proportional to the bulk modulus)

Cole Plot

Cole plots are for gas reservoirs: Depletion drive: flat line (OGIP) Weak Waterdrive: shoots up fast then drops off as gas is produced, continues positive linear trend Moderate Waterdrive: parabola Strong Waterdrive: top line, dosen't drop off as gas is produced Campbell plot is used for oil reservoirs.

For near-critical fluids, which of the following will be valid

Compositional modeling formalism should be used to study near-critical fluids NOT: BO modeling formalism should be used to study near-critical fluids. Any fluid modeling formalism will yield equally accurate results.

3 phase relative permeability

Constant Krw: parallel to water saturation, Krw is function only of water saturation, for water wet, water is in the smallest pores. Constant Krg: approx parallel to gas saturation lines, Krg is primarily a function of gas saturation, gas is in the largest pores. Constant Kro: not parallel to any saturation lines, Kro is function of both water and gas saturation, pore size distribution: water-smallest, gas-largest, oil-intermediate size pores

Wetting Phase on Rock Surface

Contact angles measured through denser phase Water wet: > 90 deg angle Neutral: ~ 90 deg Oil Wet: > 90 deg Look at slide again

Surface tension

Contractile tendency of liquids surface when exposed to gas.

Interfacial tension

Contractile tendency that exists when two immiscible liquids are in contact. The energy per unit area (force per unit distance) at the surface between phases.

Why classify reservoir fluids?

Design fluid sampling, determine types and sizes of surface equipment, devise depletion strategy, select EOR method, determine techniques to predict oil & gas reserves, determine material balance calculations.

Which of the following parameters will NOT affect relative permeability or capillary pressure?

Diffusion coefficient of CH4 Will: Hysteresis, adhesion tension, injection of an active tracer

Reservoir Engineer Actions

Drill more wells, workover existing wells, provide pressure support, optimise artificial lift, link models

History Matching Applications

Drive mechanism (gas cap, solution, water drive) Aquifer modeling (geometry: radial, linear, bottom, - size, strength) OOIP determination Sensitivities (establishing ranges of OOIP)

Gas Cap Drive

Energy source for gas cap drives stems from gas expansion at the top of the reservoir. Can be from: Primary gas cap, secondary gas cap (results from gas migration out of the oil as pressure drops below the bubble-point). Gas cap drive recoveries range from 20%-40% of the original oil-in-place, averaging 30%.

MBE Sensitivity

Evaulate effect of varying parameters. Find best OOIP for given aquifer size, show likely range of results.

Black oil fluid models perform equally well as compositional models in near-critical region?

False

Viscosity of the hydrocarbon mixtures can be modeled using standard cubic Equation of State (EOS).

False

Leverett J-Function

Form of capillary pressure, accounts for different average pore size and interfacial tensions, good for classifying rock types that you'd expect in the reservoir, useful in scaling lab measurements to reservoir size

Saturation

Fraction of pore volume occupied by a given fluid. So - oil saturation Sg - gas saturation Sw - water saturation Sh - HC saturation (Sg+So)

Engineers matrix is comprised of all the following but.. Kaolinite Fractures Rock Fragments Calcite

Fractures

Fractional Flow Equation

From surface production and PVT, the reservoir condition fractional flow can be calculated as follows, the results plotted against water saturation. By combining the inflow equation and the fractional flow it can be shown that: fw = 1/(1+((kro*uw)/(krw*uo)))

Black Oil

GOR between 100 - 2,500 SCF/STB, density < 45 API, reservoir temperatures < 250 F, Oil FVF < 2 (low shrinkage oils), dark green to black in color, C7+ composition > 30%

Gas Condensate

GOR between 30,000-100,000 SCF/STB, density between 50-60 API, light in color, C7+ compositions < 12.5%

Fluid characterization in NOT required for which of the following oilfield activities?

Geosteering

Detrital sedimentary grain sizes

Gravel (Congolomerate or Breccia) X - 2 mm (2000 microns) Sand (Quartz, arenite, arkose) 2 - 0.0625 mm (62.5 mircons) Mud (Siltstone and Shale) 0.0625 - 0.00006 mm

Migration patterns

HC's found at high points (anticline), implies upward lateral movement. Petroleum fluids and water are stratified by density, stratification implies fluids are free to move

Volatile Oil

High-shrinkage crude, GOR between 1,000 - 8,000 SCF/STB, density between 45-60 API, oil FVF > 2, light brown to green in color, C7+ composition > 12.5%

In abnormally-pressured gas reservoirs, which of the following is true?

Initially rock expansion and connate-water expansion maintain the reservoir pressure NOT: Water encroachment from aquifer maintains the pressure, compressibility drive is non-existent in these reservoirs

Interfacial Tension

Is the energy per unit area (force per unit distance) at the surface between phases. Causes: imbalanced molecular forces at phase boundaries, boundary contracts to minimize size, and cohesive vs adhesion forces.

Segregation Drive

Is the tendency of oil, gas, and water to segregate in a reservoir during production due to their differing densities. Some characteristics: Permeability heterogeneity reduces recovery, high rate production is favorable for high permeability zone displacement, low perm zones are unfavorable (upsweep) and oil is left behind if production rate is high, Producing slowly alleviates these problems by allowing sufficient time for fluid displacement. Gravity drive recovery factors range from 5-85% of OOIP, averaging 50%.

Model Permeabilities

Kair - based on routine core analysis, corrected with gas slippage kilinkenberg correction and overburden pressure Koil@Swir - Based on PLT or PTT measurements, APERM method

Relative permeability

Krw=Kw/K rel perm water Kro=Ko/K rel perm oil 0 < Kr < 1

Types of chemical sedimentary rocks

Limestone - Carbonate Chert - Silicate Rock Salt - NaCl, KCl, K2SO4 Gypsum - CaSO4 Coal - Altered organic debis

Wet Gas

Liquid only at separator conditions, GOR > 100,000 SCF/STB, density between 60-70 API, No liquid is formed in the reservoir, Separator conditions lie within phase envelope and liquid is produced at the surface

Maximum Efficient Rate (MER)

MER - Recovery varies by production rate because of various drive mechanisms: partial water drive, gravitational segregation, permeability heterogeneity, stratification and impermeable barriers. Recovery peaks at a production rate termed MER.

Viscosity

Measure of internal resistance to shear or angular deformation (or to flow). Ratio of shear stress and velocity gradient (or shear rate).

Permeability

Measure of the ease with which fluids can flow through rock. Connectivity that exists between the pore spaces of the rock matrix influences the permeability. Rate of flow depends on pressure drop, fluid viscosity and permeability. Large grains->bigger pores->high permeability->large flow rates

Reservoir Engineer Objectives

Meet production targets, replace reserves, maximize oil/gas recovery, deliver cash, minimize cost, maximize NPV, avoid losses

Which of the following will be true for gaseous hydrocarbon fluid

Molecular fraction of methane will be large NOT: High viscosity, normal plus fraction of hydrocarbon, dark color alone

Secondary Migration

Movement of HC's through permeable carrier beds into reservoir rocks

Average Reservoir Pressure Key Issues

Must "average" pressures over volume or area (approx), pressure tests must be representative (p avg extrapolation valid), can average using cumulative production (surrogate for volume)

Material Balance Key Issues

Must have accurate production measurements (oil, water, gas), estimates of average reservoir pressure (from pressure tests), PVT data (oil, gas, water), reservoir properties: saturations, formation compressibility, etc.

Material balance key issues

Must have accurate production measurements (oil/water/gas), estimates of avg reservoir pressure (pressure tests), PVT data (O/G/W), reservoir properties (saturations, formation compressibility, etc.)

Material Balance Equation notes for history matching

Need good and early data, very hard to estimate reliably more than two parameters - m, N and U (simultaneously) are especially hard. MBE's rarely a substitute for good reservoir description if available. MBE's can be used to help support/justify a specific reservoir description.

Water-wetting characteristics of rock can be identified by...

Negative adhesion tension Contact angle of less than or equal to 90 degrees (Stress OS) =/< (Stress WS)

Water-wetting characteristics of rocks can be identified by which of the following condition

Negative adhesion tension, Contact angle < 90deg Stress(OS) <= Stress(ws)

Dry Gas

Never a liquid, GOR > 100,000 SCF/STB, No liquid produced at surface, Mostly methane

Poro-Perm Relationships

No direct relation, perm usually correlated with porosity. Varys with area, formations, and are empirical

3 types of dip-slip faults 2 types of strike-slip faults 1 other type of fault

Norman Reverse Thrust Left lateral Right lateral Oblique Slip Faults

Which of the following is NOT required in petroleum systems development? Stratigraphic Trap Outcrop exposure Kerogen Maturity

Outcrop exposure

Capillary pressure equation

P = 2(Stress)Cos(theta)/r in cm Ending units are psi

Wetting Phase

Preferentially wets the solid rock surface b/c attractive forces between rock and fluid, the wetting phase is drawn into smaller pore spaces of porous media. WP fluid often not very mobile. Attractive forces prohibit reduction in WP saturation below some irreducible value (called irred wetting phase saturation). HC reservoirs tend to be totally or partially water wet.

Capillary Pressure

Pressure difference existing across the interface separating two immiscible fluids, one of which wets the surfaces of the rock in preference to the other

Rate Sensitivity of Recovery

Production rates affect ultimate recovery. Factors that affect rate-sensitivity: viscous fingering, oil trapping, pore structure, variations in fluid properties, and capillary hysteresis. Solution-gas drive (rapid pressure decline) yields lower recovery than water drive.

Specific gravity

Ratio of the weight of a volume of liquid to the weight of an equal volume of water

Seal

Relatively impermeable lithology (shale, anhydrite, or salt) that forms a barrier above and around a reservoir rock within a trap so that entrapped petroleum fluids cannot migrate beyond the reservoir.

Primary Migration

Release of petroleum compounds from kerogen and their subsequent movement within the source rock and movement of HC's from source rocks into permeable carrier beds

Imbibition

Saturation change happens on its own because the rock wants to intake liquid at low saturation, req. little forces if any. Def: fluid flow process in which the saturation of the non-wetting phase increases as it increases the mobility of the non-wetting phase also increases.

Drainage

Saturation change requires force to pull out of rock because the fluid is held in by capillary pressures. Def: Fluid flow process in which the saturation of the wetting phase increases, mobility also inc with saturation increases of wetting phase

Petroleum system requires timely convergence of geologic factors...

Seal Reservoir Rock Hydrocarbon migration Mature source rock

Which of the following is NOT true for asphaltenes?

Soluble in ethane TRUE: Heavy-end components of the fluid affect asphaltenes content, soluble in benzene, insoluble in methane

Metamorphic

Source: Rocks under high temperature and pressures in deep crust Forming process: Recrystallization due to heat, pressure, or chemically active fluids

Sedimentary

Source: Weathering and erosion of rocks exposed at surface Forming process: Sedimentation, burial and lithification

Igneous

Source: molten materials in deep crust and upper mantel. Forming process: Crystallization (solidificaion of melt)

For two-phase oil-water system, which of the following is true...

Swir < Swcr Sorw is NOT a function of Swir Maximum relative permeability of oil is attained at Swir Water phase can be mobile at Sw > (1-Sorw)

Standard Conditions

T = 60 deg F P = 14.6 psi

Wettability

Tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids. (interaction between fluid and solid phases)

Heat Capacity

The amount of heat required to change the temperature by a degree.

Compositional Models

Thermodynamically more robust - based on PVT analysis and fluid composition. Fluid composition is characterized by an Equation of State. Generally more accurate than BO but calculations are slower in terms of computing.

Heavy Oil Reservoirs

Very viscous liquid, density between 10 - 25 API, black in color, C7+ composition > 70%

Wetting phase fluid preferentially wets the solid rock surface. Which of the following will NOT be a consequence of this phenomenon.

Wetting-phase fluid will occupy the innermost part of the void space. Will: Wetting phase becomes less mobile, wetting-phase saturation cannot be reduced below an irreducible saturation. Non-wetting-phase fluid will occupy the innermost part of the void space.

Diagnostic Plots

a). Energy Plot: displays contribution to Et from reservoir components. Oil, gas, water, formation b). W[D] function: Plot of W[D]vs t[D] distinguishes infinite acting/bounded aquifer response.

Non-wetting phase

does NOT preferentially wet the solid rock surface. Repulsive forces between rock and fluid cause non-wetting phase to occupy largest pore spaces of porous media. Most mobile. Natural gas always non-wetting phase in HC reservoirs.

Darcy's Law

k = (q(viscosity))*L)/(A*(P1-P2))

Phase Density

mass per unit volume

Critical water saturation is

the lowest water saturation above which water phase becomes mobile