Natural Gas Production

Natural Gas Production
Petroleum Professor Collins Nwaneri

Introduction Natural gas has been used mainly as a fuel source
Natural gas is also used as an energy supply source Associated gas from oil production in the oilfields can normally be used for: - Energy requirements - Gas re-injection Any remaining gas was flared (still present)

Introduction Why was gas flared? Not easy to store
Expensive to transport Why has natural gas use increased? Development of pipelines and compressor stations More environmentally friendly compared to other fossil fuel Cheaper price (per MSCF)

Introduction - Gas prices are not affected by global concerns (Price is controlled per region) - Development of new technologies with the use of natural gas - Used for hydrogen generation for fuel cells (energy supply)

Introduction Demand for Natural Gas: - Has increased steady TCF (2004) - Estimated to be about 162 TCF (2020) - By 2020 (Natural is provide about 28% of word energy demand).Oil will be constant at about 39% - Addition fuel cell technology will increase natural gas demand to 200 TCF (2020)

Introduction Supply of Natural Gas:
- Proven Reserve is about 6400 TCF (2005) - Reserves per production ration varies by region (Gas consumption indicator per region) - Most recent reserve data shows: About 30% (Russia), 30% (Middle east), 3.5% (U.S.) How can natural gas demand be globally available?

Introduction Transportation of Natural Gas: Methods 1. Pipelines
Main method for gas transportation 2. LNG (Liquefied Natural Gas) Factors to affect LNG projects: - Amount of producible natural gas at proposed LNG Location - LNG plant cost (expensive and associated with gas capacity) i.e. $225 - $625 million for 100 MMSCFD - LNG tanker cost (expensive and associated with gas capacity) i.e. one tanker is about $260 million for 3BCF - LNG re-gasification plant cost (expensive)

Introduction 3. GTL (Gas to Liquid)
Conversion of natural gas into synthetic hydrocarbon liquids (mainly middle distillates) First step- natural gas is reformed and converted to H2 and CO (mixture is called synthetic gas or syn gas) - same process of natural gas conversion into H2 - most expensive phase (consumes 50% of total GTL cost) Second step- syn gas is blown into a slurry reactor and is converted to liquids (called Fisher –Tropsch process) Benefits of GTL technology: - Help stop gas flaring - syn gas has no or very sulfur content - High tech jobs can be made available One disadvantage is the cost to build a GTL plant (may be about $11 billion per plant)

Introduction Characteristics of Natural Gas: 4. Gas hydrates pipelines
Involves the conversion of natural gas into hydrates and the gas is transported in a slurry form (still I experimental phase) Characteristics of Natural Gas: Consists of hydrocarbons (Methane (CH4) is the main component; others components (Ethane (CH4), Propane (C3H8), Butane (C4H10), and heavier more complex hydrocarbons Natural gas can also content impurities such as: nitrogen (N2, carbon dioxide (CO2), Hydrogen sulfide (H2S) and water vapor (H2O) Impurities can be neutral i.e. nitrogen or harmful i.e. water with CO2 (corrosive) or Hydrogen sulfide During gas processing, heavier hydrocarbons beyond butane are removed form gas as liquid and sold as liquids.

Introduction Unconventional Sources of Natural Gas: Tight sandstone
Tight shale Coal bed - Natural gas presence in coal (Methane) - Benefits: Known coal location, shallow well depth and low well completion cost, longer gas production years, potential CO2 sequestering and removal of gas for mining safety) NOTE: See diagram of a typical coal-bed methane well in text.

Introduction Gas Hydrates and high pressure (Deepwater)
- Formed from water and gas molecules at low temperature and high pressure (Deepwater) - Three methods for gas hydrates production: Use of injection steam or hot water to increase downhole temperature above stable temperature, Inject an inhibitor i.e. methanol or glycol to decrease hydrate stability, Decrease reservoir pressure below hydrate equilibrium (methane is released from clathrate) - The last method (also referred as depressurization) is the best method. - Challenges of gas hydrates production: Low permeability gas hydrate sediments (impedes gas flow), hydrates can cause sea-floor destabilization (landslides) and gas hydrates can re- form in tubing (results in flow restriction)

Properties of Natural Gas
Natural gas properties are used to evaluate natural gas reservoirs Natural gas properties are a function of Pressure and Temperature (This properties can be measured experimentally or estimated with empirical relationship (calculated) Examples of such properties: gravity, compressibility factor, density, formation volume factor, viscosity, compressibility and solubility in water The classification of a dry, wet or condensate gas reservoir is based on its behavior as a function of temperature and pressure

Hydrocarbon Phase Behavior as a function of Temperature and Pressure (Phase Diagrams): 1. One phase fluid (Liquid or Vapor) Phase diagram: Normally results when a liquid phase (unsaturated oil) changes from liquid to vapor (gas) and vise-versa with changes in pressure or temperature or both Above the critical temperature (Tc) and critical pressure (Pc) at a critical point (C) both liquid and gas cannot co-exit Single vapor pressure line represents bubble point line (liquid to gas) phase or dew point line (gas to liquid) phase See diagram Fig. A

Fig A: Single (One) component phase behavior

2. Multi-fluid phase: No single vapor pressure line Has a curved line with bubble point line on one side and dew point line on the other side (Referred to as a phase or saturation envelop) Reduction in pressure (at constant temperature) from liquid phase (unsaturated oil) to the bubble point results to initial vapor (gas) occurrence (liquid phase starts to decrease and vapor (gas) phase increases) Dew point exist at zero liquid phase with reduction in pressure (start of vapor phase only) Cricondentherm (CT) point (highest temperature) at which 2 phase can co-exist and Cricondenbar (Cb) point (highest pressure) at which 2 phase can co-exist At the critical point (C) all multi-fluid properties are identical See Diagram Fig. B

Fig B: Multi component (Multi-fluid) phase behavior

Gas Reservoir classification (Based on multi-fluid system phase diagram): Used to identify dry, wet and condensate reservoirs (3 types of gas reservoirs) Condensate and gas reservoirs are separated by two vertical lines from the critical point (C ) and cricondentherm point (CT) Wet and dry gas reservoirs are initially represented by point A. (The reservoir phase behavior with a decrease in pressure at constant temperature results to the presence of gas as the only reservoir fluid under isothermal conditions) Reservoir fluid flow from the reservoir to the surface is affected by changes in temperature Pressure and Temperature is reduced as fluid flows from the reservoir to the surface

A wet gas reservoir (represented by line AA”) Initial reservoir gas at the surface with reduced pressure and temperature results to liquid production. The surface liquid is transparent and light (high API gravity) Initial temperature is more than cricondentherm Initial fluid remains as single phase throughout depletion (No change in reservoir to surface fluid composition) Initial GOR greater than 50,000 SCF/STB A gas reservoir (represented by line AA”’) - Initial reservoir and surface conditions are outside 2-phase envelop (Only gas is present) - Gas is produced at the surface (No liquid) - Initial temperature is more than cricondentherm - Easiest reservoir type to produce - Recovery rate is about 80 to 90% - Mainly methane - Initial fluid remains as single phase (gas) throughout depletion

A condensate reservoir (represented by line BB”) - Initially present as single phase gas in a reservoir - Reservoir temperature higher than critical point temperature but lower than cricondentherm temperature - Liquid phase occurs as the pressure is reduced (retrograde condensation) - Liquid dropout in reservoir occurs pass the dew point pressure - Light liquid production (API gravity greater than 45) - Initial GOR between 3300 and 150,000 SCF/STB - Less than 12.5 % heptane

Two characteristics of condensate reservoir behavior: 1. Above the dew-point line, more valuable liquid than gas is produced at the surface and below dew-point line less valuable liquid is produced at the surface compared to gas (more liquid left in the reservoir) 2. As more liquid is left in the reservoir, the produced fluid contains lighter hydrocarbons and will result in increase in their the API gravity as a function of pressure

The loss of valuable liquid is common in condensate reservoirs (liquid dropout near the wellbore), where the pressure drop near the wellbore is lowest and below the dew-point pressure - This results in decreased productivity Two solutions to prevent liquid loss: 1. Dry gas re-injection into a reservoir to maintain reservoir pressure above dew-point 2. Injection of solvent into the producing well to dissolve accumulated liquid (i.e. solvents CO2, N2, methanol or natural gas) under high pressure. The well is shut-in for sometime and flowed back with the dissolved liquid.

FIG C: Distinction between Gas and Condensate Reservoirs

Natural Gas Reservoirs are grouped into 3 types: 1. Condensate reservoirs 2. Wet gas reservoirs 3. Dry gas reservoirs

Physical Properties: 1. Molecular weight of gas (pure gas or gas mixture) Pure Gas: See ideal gas law relationship i. pV=nRt ii. pV = (m/M)RT m = mass of pure gas M = molecular weight of gas (Known for pure gas and calculated for gas mixture). p= pressure V= Volume n= number of gas molecules R = gas constant See the table 1 below for some physical constants of pure substances:

Table 1: Physical Constant of Pure Substances

2. Specific gravity: Sg of gas= M/Mair (molecular wt. of air = 29) M= molecular wt. of a mixture Sg = specific gravity of a gas mixture Note: The relationship for SG of gas with non- hydrocarbons is different 3. Real gases: compressibility (z) is calculated for real gases at high pressure and temperature (z for ideal gas is 1) pV=znRt Note: z for ideal gas is 1 at room temperature and pressure

4. Compressibility factor: indicates ideal gas deviation to real gases (function of reduced pressure and temperature) - Reduced pressure and temperature can be calculated and compressibility factor can be estimated by graphical method (Standing and Katz). (Most common method) See Diagram below . Pr = P/Pc and Tr = T/Tc Note: Critical properties can be calculated as a function of gas gravity. Pc = – 57.5𝞬ghc (Psia) Tc = 𝞬ghc (deg. R) Pc and Tc can be expressed in other units.

Fig D: Natural Gas Compressibility as a function of reduced pressure and temperature

4. Formation volume of Gas: Ratio of volume of one mole of gas at a given pressure and temperature to volume of one mole of gas at standard conditions Based on the real gas law and assuming z- factor at standard condition is one. Bg = V/Vsc = Psc/Tsc x zT/P Using Psc = 14.7 psia and Tc = 520 deg R at standard condition, Bg can be expressed as: Bg = x zT/P (ft3/SCF) Bg can be expressed in other units

5. Gas Density: Defined as mass per unit volume Expressed as 𝝆g = 2.7 P𝞬g/zT 𝝆g (Ibm/ft3), P (psia) and T (deg. R) Gas density can be expressed in other units 6. Gas Viscosity: (unit is cp) 7. Gas Compressibility 8. Solubility of natural gas Gas properties are corrected for presence of impurities (i.e. H2S and CO2) Find the gas density (Ibm/ft3) from a dry gas reservoir (no impurities) with the given data? Note: Convert temperature in deg. F to Deg. R (add 460)

Liquid Production: Gas properties account for both the liquid and gas production at the surface Wet gas and Condensate reservoirs: Gas gravity at the surface is smaller than the gas gravity in the reservoir for a wet gas reservoir Gas Gravity in the reservoir is calculated for the presence of liquid at the surface before liquid is separated from the well stream Condensate reservoir gas properties varies with reservoir pressure at or below dew point pressure.

Experimental Procedures: Dry and wet gas: Gas properties can be determined with the knowledge of the Z-factor (graphical representation) as a function of reduced pressure and temperature No measurements of Z-factor is necessary Account for liquid production at the surface in wet reservoir for determination of gas properties

Condensate reservoirs: Experimental measurements are necessary due to liquid drop-off in the reservoir Changes in fluid composition results in fluid property changes Experimental data is used to predict reservoir behavior (fluid properties) for a condensate reservoir because of this changes in fluid composition Three experimental methods: Constant volume depletion (CVD) (Most common) Constant composition Expansion (CCE) Multi-stage Surface Separation (MSS) NOTE: Important to collect sample reservoir fluids when reservoir pressure is above dew point pressure (Early stages)

See CVD data illustration for a sample well: Table 2: Basic Properties Information

The data from table 2 shows: Initial reservoir pressure Formation temperature Stock tank liquid production measurements Standard pressure and temperature- used to note when liquid and gas volume measurements are taken 5. GOR (from Primary separator or stock tank) – used to combine fluid sample in a good proportion

After the fluid sample are collected and mixed in the right proportion in a CVD cell, the following data (Table 3) below are obtained at various pressures (starts with a dew-point reservoir pressure). It shows the produced gas composition (%) at various reservoir pressures and one liquid production composition (last column) at a particular pressure

Table3: Sample fluid analysis

The analysis result from table 3 shows: Produced fluid composition changes with pressure depletion Increase in lighter hydrocarbon mole fractions compared to decrease in heavier hydrocarbons mole fractions (i.e. methane vs heptanes-plus) Molecular weight of produced fluid decreases (i.e. heptane plus) as percentage of heavier components decreases One Z-factor for produced gas and one Z-fcator for 2 phase (gas and liquid) What other observations can be made from table 3?

Table 4: Recovered sample from well

Table 4 shows other information that can be obtained, such as: Type of liquid that will be produced at the surface and the volume in gallons from 2 separators: Ethane, Propane, Butane and Pentane Plus as the reservoir pressure is depleted Total volume of liquids that will be produced from all separators at the surface from the gas reservoir. (i.e. 1 MMSCF of gas in a reservoir will produce 2295 gallons of ethane, 1461 gallons of propane, 1104 gallons of butane, 7352 gallons of pentane plus) What other observations can be made from table 4?

Material Balance Analysis
Material balance technique: Used for Gas in Place (GIP) calculation in gas reservoir (also can be applied to oil reservoir) Material balance method calculates (GIP) like Volumetric analysis method and can also be used to estimate (GIP) with production data like reservoir simulation method Material balance method does not need such data as: 1. Reservoir dimension (Area and height) 2. Pore Volume properties (Porosity and Saturation) Material balance method is applied for an entire reservoir (not on individual wells)

Material balance method cannot be used to predict future performance (i.e. production forecast, e.tc) with time in current or altered conditions More accurate method compared to volumetric analysis method What are the differences between material balance method, and Volumetric and reservoir simulation methods?

Material balance methods application requirements: Condensate, water and gas production data Average reservoir pressure Reservoir fluid PVT data Material balance method assumptions: Reservoir fluids are in equilibrium Constant fluid saturation Uniform PVT data in entire reservoir

Basic Gas Reservoir Material Balance equation: Underground withdrawal = gas expansion + formation expansion + water influx This is based on the 3 main mechanism for gas production: Gas expansion Formation expansion (due to formation and connate (irreducible) water changes with pressure variation Water influx (due to aquifer expansion)

Each side of the equation represents: i) Underground withdrawal = GpBg + WpBw (Cumulative gas and water production converted from reservoir to surface conditions) Bg = Current gas formation volume factor(cu.ft/SCF or bbls/SCF) Bw = water formation volume factor (bbls/STB) Gp = Cumulative gas production in SCF or MSCF (MCF) or MMSCF (MMCF), e.tc. Wp = Cumulative water production (STB)

Gp is modified with Condensate production as equivalent gas production as Gp = Gp-dry + Np x Vo Np = condensate production Vo= equivalent gas per unit of condensate production Gp-dry = dry gas cumulative production ii) Gas Expansion = Original (initial) gas in place – remaining gas = (Gi – GiBgi/Bg) Gas expansion converted from reservoir to surface conditions: = Gi(Bg – Bgi)

Bgi = Initial gas formation volume factor (cu.ft/SCF or bbls/SCF) Bg = Current gas formation volume factor (cu.ft/SCF or bbls/SCF) Gi = Initial gas in place (SCF) or in MSCF (MCF) or MMSCF (MMCF), e.tc iii) Formation expansion (rock and water expansion) is equal to: GiBgi/1-Sw x (cwSwc + cf)𝜟P

iv) Water influx = WeBw We = cumulative water influx (bbls) Bw = water formation volume factor (bbls/STB) Equation (i) through (iv) can be combined and represented as: F = GiEg + GiEf,w+WeBw We and Bw are unknown terms and the rest can be calculated What does F, GiEg, GiEg and WeBw represent?

A general simplified equation can be used for the following reservoir conditions: 1. Active water drive Gi = GpBgi – We + BwWp (Bg – Bgi) 2. No active water drive Gi = GpBgi + BwWp 3. Gas Drive only Gi = GpBgi

Natural Gas Production

Similar presentations

Presentation on theme: "Natural Gas Production"— Presentation transcript:

Similar presentations

About project

Feedback

Log in

Auth with social network:

Natural Gas Production

Similar presentations

Presentation on theme: "Natural Gas Production"— Presentation transcript:

Similar presentations

About project

Feedback