PVT Short Course for Cairo University SPE Student Chapter Ahmed Muaz Khalda Petroleum Company April 23, 2011

Contents Why Study PVT? Objectives of PVT Analysis Types of Reservoir Fluids Differentiation Between the Different Types of Reservoir Fluids Fluid Sampling Laboratory Experiments PVT Reports

Why Study PVT? Transport Sep. Gas Stock Tank Oil Diff. Flow Regime

Objectives of PVT Analysis Need to understand PVT analysis for: Determination of reservoir fluid type Knowledge of physical properties of reservoir fluids Match an EOS to the measured data Creation of PVT models Ultimate recoveries of different components Amounts and composition of liquids left behind Determination of well stream composition

Objectives of PVT Analysis – Cont. Completion design Separator/NGL plant specifications Product values Vs. time Prediction compositional gradient

The Five Reservoir Fluids BlackVolatileRetrogradeWetDry OilOilGasGasGas

Reservoir Fluid Type Identification Analyzing a representative sample in the lab Production data 1.Initial GOR 2.API 3.Oil color 4.C7+

Black Oil An initial GOR, 1750 SCF/STB or less A 45 API initial stock tank oil gravity or less A dark color of stock tank oil C7+ > 20 mole % Initial Bo of 2 res bbl/STB or less

Black Oil Phase Diagram The initial reservoir conditions (P&T) are much lower than the critical conditions The heavy molecules concentration is high

Volatile Oil An initial GOR, 1750 SCF/STB or greater A 51.2 API initial stock tank oil gravity A medium orange stock tank oil color C7+ concentration between 19 and 22 mole % Bo 2.0 res bbl/STB or greater

Volatile Oil Phase Diagram The initial reservoir conditions (P&T) are close to the critical conditions Have fewer heavy molecules than black oil

Retrograde Gas Condensate An initial GOR > 3200 SCF/STB API > 45 initial stock tank oil gravity A light stock tank oil color C7+ concentration <12.5 mole %

Retrograde Gas Phase Diagram The initial reservoir conditions (P&T) are higher than the critical conditions Have fewer heavy molecules than volatile oils The overall composition of the reservoir fluid becomes heavier as the lighter gas is produced and the heavier condensate remains behind

Wet Gas An initial GOR > 15,000 SCF/STB API up to 70 initial stock tank oil gravity Water white of tank oil color C7+ concentration <4 mole %

Wet Gas Phase Diagram Reservoir Temperature above Cricondentherm (pressure path not enter phase envelope) The reservoir fluid is gas throughout the life of the reservoir The separator condition is two phases Gravity of stock tank liquid same as retrograde gas - constant during life of field Pressure Temperature % Liquid 2 1 Pressure path in reservoir Wet gas Critical point Bubblepoint line Separator Dewpoint line

Dry Gas An initial GOR > 1000,000 SCF/STB Almost no liquid C7+ concentration < 0.7 mole %

Dry Gas Phase Diagram Primarily methane and some intermediates The reservoir fluid is gas throughout the life of the reservoir No liquids formed either in reservoir or at surface Pressure Temperature % Liquid 2 1 Pressure path in reservoir Dry gas Separator Dewpoint line 1 50

RetrogradeRegion Two Phase Region Temperature Pressure OIL OIL GAS Heavy Oil Black Oil Volatile Critical Critical Gas Wet Dry Oil Oil Gas Condens. Gas Gas Cricondenterm Dew Point Loci Bubble Point Loci Critical Point Cricondenbar A B C Reservoir Fluids Phase Diagram Window

C7+ & GOR for Reservoir Fluids

Reservoir Fluid Types Classification

Composition of Reservoir Fluids

Differences Between Black and Volatile Oil Black Oil The evolved gas is a dry gas. The solution gases remain gas phase in the reservoir, tubulars and separator. As reservoir pressure decreases, the gas leaving solution, becomes richer in intermediate components. API gradually decreases during the reservoir life.

Phase Diagram of Black Oil and Associated Gas

Production Processes for a Black Oil

Differences Between Black and Volatile Oil Volatile Oil The evolved gas is a retrograde gas. The evolved retrograde gases release a large amount of. condensate at surface conditions. Often over one half of the stock tank liquid produced during the reservoirs life. API steadily increases with time.

Phase Diagram of Volatile Oil and Associated Gas

Production Processes for a Volatile Oil

Analysis and Prediction Tool Black Oil Mbal Assume free gas in the reservoir remains gas in the separator Treat a multi component black oil mixture as a two-component mixture: gas and oil Volatile Oil Mbal Treat mixture as a multi-component mixture Total composition of the production stream is known

Effect of Using Black Oil Mbal for Volatile Oil

Differentiation between Volatile and Retrograde A GOR of 3200 SCF/STB is a good cut-off A value of 12.5 mole % of C7+ is a useful dividing line

Differences between Volatile Oil and Retrograde Gas Retrograde Gas GOR increases with time as condensate dropout API increases with time Compositional Mbal should be used in reservoir calculations Conventional gas Mbal can be used above dew point Also, it can be used below dew point if two phase Z-factors are used

Differences between Retrograde and Wet Gas An initial GOR of 15,000 SCF/STB can be a cutoff A value of 4 mole% or less can be useful dividing line

Field and Laboratory Identification of Reservoir Fluids

Reservoir Fluid Sampling Open Hole Sampling: RFT, small sample volume and often contaminated MDT, allows controlled drawdown and multiple sample chambers Optical MDT, allows to identify the type of fluid being sampled Cased Hole Sampling: Surface Sampling Subsurface Sampling

Surface & Subsurface Sampling

Well Conditioning during Sampling Small perforation is preferable Limiting drawdown Large tubing diameter in case of high rates Better well cleaning Stable production No liquid slugging Small amount of produced fluid prior to sampling

Laboratory Tests Primary tests Routine laboratory tests Special laboratory PVT tests

Primary Tests API Gas specific gravity Separator gas composition GOR

Routine Laboratory Tests Constant-Composition Expansion - CCE Differential Liberation Constant-Volume Depletion – CVD Separator Test

Constant Composition Expansion - CCE Test The test is conducted for the purposes of determining: Saturation pressure (bubble-point or dew-point pressure) Isothermal compressibility coefficients of the single-phase fluid in excess of saturation pressure Compressibility factors of the gas phase Total hydrocarbon volume as a function of pressure

CCE Test Procedures Gas Liquid Hg Second Step Liquid Hg Liquid Hg First Step Hg Third Step Hg Fourth Step Liquid Gas VtVt Liquid VtVt VtVt VtVt VtVt pbpb

CCE Test Data

Differential Liberation Test The experimental data obtained from the test include: Amount of gas in solution as a function of pressure The shrinkage in the oil volume as a function of pressure Properties of the evolved gas including the composition of the liberated gas, the gas compressibility factor, and the gas specific gravity Density of the remaining oil as a function of pressure

VoVo Liquid Hg Gas Hg Liquid Gas First step Hg Liquid Gas Liquid Hg VoVo Gas VoVo Hg Liquid pbpb Differential Liberation Expansion Test Procedures

Differential Liberation Test Data

Separator Test Procedures Liquid Hg Liquid Stock tank Gas Liquid Separator Hg pbpb resbbl STB resbbl STB B ob = scf R sb = scf STB

Separator Test Data

CVD Test Procedures

Constant Volume Depletion – CVD Test

PVT Reports

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