Principles of Reservoir Engineering

Principles of Reservoir Engineering
Petroleum Professor Collins Nwaneri

Introduction What is a Reservoir?
It is a formation of one or more rock formations that contains liquid and/or gaseous hydrocarbons. It is mostly of sedimentary rock origin, with few exceptions. - Reservoir rocks are porous and permeable; and bounded by impermeable barriers which trap hydrocarbons. - Vertical arrangement of fluids in a reservoir is governed by gravitational forces i.e. Gas-Oil-Water.

Introduction What is Reservoir Engineering?
A reservoir is also defined as an invisible and complex physical system (porous medium) that must be thoroughly analyzed for vital information. What is Reservoir Engineering? It starts with the discovery of a productive reservoir and aims to optimize hydrocarbon recovery. The optimization of hydrocarbon recovery process starts from an initial reservoir development project for a field and a reservoir study that continues throughout the life of the field to derive information required for optimal production from the reservoir.

Introduction The following must be estimated from reservoirs, with the aim of optimal profitability for a given project. Hydrocarbon (Oil and/or gas) in place. Recoverable reserves (estimated on the basis of several alternative production methods). Well production potential (Initial productivity, and changes). Reservoir engineering can involve the use of partial data, furnished by wells and therefore is incomplete and insufficient. This data is extrapolated over an extended area to compile a synthetic image of the reservoir. Fairly reliable production forecast can be made from this reservoir image in the near future and much less for a distant future. The forecast are then used to make an optimum development scheme.

Introduction Below is a diagram that shows the different steps in reservoir engineering. (Fig. 1)

Introduction Reservoir Image:
This is defined when the forms, boundaries, internal architecture (heterogeneities), and distribution and volumes of fluids contained in a reservoir are known or at least, to start with approximated. The methods used to define a reservoir image are based on petroleum geology and geophysics. The following techniques are used in drawing up a reservoir image: Direct analysis: Core and PVT analysis of fluids (pressure, volume, temperature). The measurements are done in a laboratory.

Introduction 2. Indirect analysis: Well logging. (Recorded during drilling and production to obtain vital data on lithology, porosity and fluid saturations. Note: Indirect analysis has a larger surface area of investigation compared to core analysis (direct analysis). Well Characteristics: A well production potential is another way to assess the value of a discovered reservoir. Well testing is used to asses the production potential of a reservoir and it involves the measurement of: Surface flow rates; and surface and downhole fluid pressures.

Introduction Well testing can also be used to get reservoir information such as: average permeability. (up to several hundred meters around a well). In addition, different layers, fractured formations or barriers may be found in a reservoir. Note: The later test above can help in the selection of the right well completion procedure for production.

Introduction Recovery Mechanisms:
Fluid withdrawal from wells lowers the pressure of the remaining fluids in a reservoir. The relative permeability that breaks down flow capacities between fluids (oil/gas/water) as a function of saturation helps generalize a simple one phase flow condition compared to complex multiphase flow conditions. The knowledge of fluids in a reservoir and it’s heterogeneities helps to determine the mechanism that causes fluid displacement towards wells by natural drive (primary recovery).

Introduction Recovery rates from wells depends on the type of reservoir and fluids. Recovery rate can be from as average of 25% oil or as high as 75% or more for gas of the reservoir volume in place. Reserves means the recoverable volumes that appears to be producible. Reserves = Volumes in place x recovery rate

Introduction Secondary or artificial recovery methods are used if a reservoir’s primary recovery (natural drive) does not allow for good oil production or to accelerate production. This methods can consist of water injection or use of associated gas (gas injection or gas lift). Improved or enhanced oil recovery can be used, if profitable, to further produce the oil left in the reservoir. This can be after the application of secondary recovery, since the recovery is rarely above 40%. This methods include CO2 injection or addition of chemicals to water, and thermal methods (i.e. steam injection or in-situ injection) for heavy oils.

Introduction See the Dig. On the Mechanism of primary recovery. (Fig. 2)

Introduction A reservoir image. (The Volume in place)
Reservoir studies characterizes: A reservoir image. (The Volume in place) A well potential. (The Productivity) The recovery mechanisms. (Recoverable from reserves) - Based on the information above a schematic reservoir model is obtained that represents the synthesis of data and knowledge of each reservoir.

Introduction Uncertainties: - Involves the concept of using new approaches in the analysis and use of small data from large data set, which represents an infinitesimal portion of an actual reservoir space. - Possible margins in errors in oil and gas volume in place (N and G); and oil and gas production forecasts (Np and Gp) consequences must be established to account in the uncertainties.

Introduction Simulation of Reservoir Production:
Involves the use of computer that allows a much more accurate reservoir simulation by discretization of a reservoir in space and time. This simulation model integrates specific reservoir data and laws governing flow in porous medium to form a complex reservoir numerical model for production forecasting.

Introduction Development of a Project, Optimization:
Development plans such as: number of wells, location, injection, e.tc on simulation models are compared. Initial choices takes account of related techniques, such as well and surface production and economic data. The forecast helps assess probable future production, which leads to anticipated income and it is compared to capital investments i.e. drilling, completion etc.., and operating cost. At the end the configuration with the best rate of return is chosen. Reservoir studies involve three phases in this order: Analytical; synthesis and forecasting. Each phase can be repeated as a new well is drilled, during development phase and throughout the reservoir life.

Introduction A Reservoir studies sample. (Fig. 3)

Introduction The Place of Reservoir Engineering in Production: After a well is discovered operations go from exploration function to production function. See the diagram in the next slide that shows reservoir engineering applications from exploration to development phases : (Fig:4)

Introduction Fig.4

Reservoir Geology and Geophysics
Goals: Reservoir Image (Geological Model) A Reservoir Image is developed when the forms, boundaries, internal architecture (heterogeneities), distribution and volumes of fluids contained in a reservoir are known or to start with, approximated. The basic parameters used to draw up a reservoir image is shown in Fig 5. The techniques to get the information in Fig. 5 are mainly: 1. Direct Method: Core analysis and PVT analysis of fluids. 2. Indirect Method: Well logging (information such as Lithology, porosity and fluid saturation are obtained)

Fig. 5

Other methods used to describe a reservoir image are: Seismic surveys: Gives the reservoir form, faults and occasional variations in facies and fluid boundaries. Sedimentology: Defines the nature of depositions from the analysis of cores, cuttings and logs. Chemical measurements: used for mineralogical composition, percentage of organic matter, and the hydrocarbon family. Tectonics or microtectonics: used in detailed description of fractures from core analyses, overall surface studies, and aerial and satellite photographs. Production data: Used to determine flowrates, Interference between wells, pressure buildup, temperatures, type and specific gravities of fluids in bottom hole conditions, e.tc.

The Reservoir Image (Geologic model) is used to: Calculate the volumes in place of a discovery. (Enhance the reservoir value) 2. Identify probable well locations for development. 3. Provide static details that are introduced into the simulation models. (Used for production forecast and determine the ideal development method) The results from the geological model are illustrated by: Vertical profiles i.e. composite well logs. Correlation cross-sections and facies cross-sections. (See Fig Correlation between wells) 3. Isobaths, isopach (same thickness), isofacies and isopercentage map, especially “h x Φ and “h x K”, which helps to characterize the reservoir value.

Fig. 6

NOTE: Geological models are not fixed. They are updated continually based on data gathered throughout the lifetime of the field.

Hydrocarbon Generation and Migration: Generation: Hydrocarbons originate in the organic matter contained in sediments. Some deposited sediments are broken by oxidation and the remaining part contains Kerogen. The Kerogens in the buried sediments are transformed into hydrocarbons by thermal cracking. Kerogen is converted to oil at above 50 to 70 deg. C At 120 to 150 deg. C Oil goes from wet to dry gas. Oil window is between the temperatures above and can correspond to burial depths between 1000 and 3500 meter. See Fig 7.

Fig. 7

Sources rocks are mainly shale and sometimes carbonates. Oil potential of source rocks are analyzed by pyrolysis at increasing temperature of a sample of ground rock. (Rock Eval Method) Allows for source rock identification during drilling. Migration: Hydrocarbons in source rocks are generally expelled. (Towards low pressure zones) The source rock (with respect to shale) are permeable at the time of migration. The two types of hydrocarbon migration are: Primary migration: - Hydrocarbon movement is from a source rock to a more porous adjacent environment. The hydrocarbon migration that is caused by forces associated with burial and compaction.

2. Secondary Migration: Hydrocarbon movement is within the reservoir from a nearby source rock. Hydrocarbon movement is normally upwards within one or two reservoirs through faults, fracture zones etc.. Hydrocarbon movement can be due to gravity or/and capillarity effect between Oil, Gas and Water. See Fig 8( different hydrocarbon upward movement types)

Fig:8

Reservoirs Definitions: A reservoir is a porous and permeable subsoil formation that contains hydrocarbons (Oil and/or gas). It is surrounded by impermeable rocks and often by aquifer barrier. Has only one natural pressure system. Reservoirs have lithology layers. They consist of one or more superimposed or lateral nearby porous pools, which may contain oil, gas or both fluids superimposed.

Reservoir Rocks: Mainly sedimentary rocks (sandstone and/or carbonates). (99% of total sedimentary rocks) Sandstone Reservoirs: The most type of reservoir that accounts for about 80% of reservoirs and 60% of oil reserves. Examples sandstone, shaly sandstone, carbonate sandstone, e.tc. Carbonate Reservoirs: Carbonate rocks are formed by: Detrital: Debris from grains of limestone, shells, e.tc. Constructed: of reef type Chemicals: precipitation of bicarbonate and originating in marine muds. Examples are limestone, dolomite, shaly carbonates. Others are Chalk (High porosity and low permeability) and Karst (Very porous and permeable)

Traps: An area bounded by a barrier lying upwards from flow that prevents the flow of hydrocarbon from a reservoir. Reservoir upward seal has a layer of impermeable rock called a cap rock. (i.e. shale, salt or anhydrite). Classification of Traps: The three types of traps are structural, stratigraphic or combination: Structural traps: Due to rock deformation (i.e. anticlines or faults, domes , folds) stratigraphic traps: Due to variation in facies that causes rocks to be laterally impermeable. (i.e. sandstone lenses in shale/sandstone whole, depositional or erosional pinch-outs and carbonates reefs. Combination traps: eroded anticlines, traps associated with salt domes.

Characteristics: Reservoir traps size are determine by: Closed area Closure Impregnated zone closure Filling ratio See Fig. 9 for the different types of reservoir traps.

Fig. 9

Reservoir Seismic Survey Principles: The objective of seismic techniques and interpretation for reservoirs is to able to apply larger basin area seismic exploration by convectional seismic surveying with reservoir surveying of relatively small reservoir size and thickness. The primary aim of seismic reflection shooting in seismic surveying is to obtain structural image of geological layers (markers). See Fig. 10

Fig. 10

The picked up seismic reflections are seismic profiles in vertical time sections. The seismic profiles are used to plot “isochrone” (equal time) curves, which are converted to isobaths (equal depth) with offset wells acoustic logs. Exploration seismic can be inappropriate for structural analysis of reservoirs due to the following: A smaller/tighter grid spacing is needed in reservoir surveying due to reservoir size compared seismic exploration surveying. (Density of grid pattern in exploration seismic rarely exceeds one profile per kilometer unlike in reservoir surveying where profiles are required at 500, 250 or even 100 m intervals) The source and recording array for exploration seismic must be adapted to reservoir depths. Accurate determination of different bed markers in reservoirs can be a problem using seismic exploration surveying. (Vertical Seismic Profiles (VSP), Offset Vertical Seismic profiles (OSP), Sonic logs and Synthetic Seismic films are tools used to obtain and refine depth/time calibration of seismic sections).

2D seismic surveying is a drawback in representing all the activities underneath a profile. (Due to subsoil/substructure time image distortion) 3-D Seismic Survey: 3D Seismic surveying is a better technique for interpretation of subsoil/substructure images. Profiles are very close (at 50 m interval) and interpreted with 3-dimensional migration, which helps to re-position sloping events/structures to their true position) 3D can be very costly (grid pattern and interpretation) for onshore surveys. Used mostly offshore.

Vertical Seismic Profile (VSP) and Offset Vertical Seismic Profile (OSP): Their profile information/recording from wells are used in depth/time calibration for accurate image of reservoirs close to those wells. (Well records are normally, 10 to 20 meter apart) Detection of Fluids: Seismic surveying image can be used in fluid detection based on acoustic impedance contrast between gas zones, cap rocks, or between gas (or oil) zone and the aquifer to create different marked reflections called bright spots, flat spots and pull-downs as per each specific case. Acoustic impendence is based on decreases in the apparent density of the reservoir and in acoustic propagation velocities due to the presence of gas (and, to a lesser degreed oil) in a reservoir. This is not often obtained, except in favorable and limited conditions. See Fig. 11

Fig. 11

Characterization of Reservoir Rocks
For a rock to form a reservoir: It must have the following: Porosity - storage capacity. Permeability - Fluid flow through the rock. Saturations – contains sufficient quantity and concentration of hydrocarbons. Core analysis and well logging are methods used to characterize reservoir rocks.

Porosity Definition: For a rock sample- Apparent volume/total volume (VT) is equal to solid volume (Vs) plus pore volume (Vp). Porosity= 𝑃𝑜𝑟𝑒 𝑉𝑜𝑙𝑢𝑚𝑒 (𝑉𝑝) 𝑇𝑜𝑡𝑎𝑙 𝑉𝑜𝑙𝑢𝑚𝑒 (𝑉𝑇) (expressed in %) Effective porosity (фu): Well connected pores or interconnected pores to each other and to other formations that allows fluid to circulate. Total porosity (фt): Accounts for all pores interconnected or not. Residual porosity(фr): Accounts for only isolated pores Total porosity = Effective porosity + Residual porosity If the effective porosity is 30 % and residual porosity is 10 %, what is the total porosity?

Effective porosity varies from less than 1% and over 40%. Effective porosity ranges can be classifies as: - Low porosity if value is less than 5% - Mediocre porosity if value is >5% and <10% - Average porosity if value is >10% and <20% - Good porosity if value is >20% and <30% Excellent porosity if value is >30% Values for Intergranular porosity, dissolution porosity (i.e. limestone) and fracture porosity (<1%) are different.

Porosity tends to decrease with depth. Determination of Porosity: Porosity can be determined by core analysis or well logging: Core Analysis: - Based on the equation: ф = Vp/VT= 𝑉𝑇 −𝑉𝑆 𝑉𝑇 = 1- 𝑉𝑆 𝑉𝑇 - Two of the three values Vp, Vs and VT are determined. A. The following methods are used to measure (VT): Mercury buoyancy measurement when a sample is immersed in it. (IFP apparatus) Use of a mercury positive displacement pump. Note: Mercury should not penetrate the sample for VT to be accurate using the methods above.

3. Direct measurement. - Involves the use of sliding caliper for core measurements. - For example for a piece of cylindrical core, VT= 𝜋 𝑑 2 ℎ 4 (Core diameter “d” and height “h” are determined with the sliding caliper) - Best method to use for rocks that have fissures or macro pores. if you have a piece of cube core, will (VT) be the same as the measurement for a cylindrical core?

B. The following methods are used to measure (VS): Measurement of the buoyancy exerted on a sample by a solvent with which it is saturated. - Vs is obtained based on the weight difference of sample in air and in the immersed solvent. VS= 𝝆𝑎𝑖𝑟 −𝝆𝑖𝑚𝑚𝑒𝑟𝑠𝑒𝑑 𝝆𝑠𝑜𝑙𝑣𝑒𝑛𝑡 2. Use of a compression chamber and Marriote-Boyle’s law. - Based on the relationship between Pressure and Volume that is applied in a chamber to determine Vs.

C. The following methods are used to measure (Vp): (Effective pore volumes) Measurement of the volume of air in the pores. - Based on relationship between pressure and volume (Boyle’s law) Measurement by weighing a liquid filled pore. (Brine is mostly used) Measurement by mercury injection. (Vp value is usually less, due to less invasion of mercury in the interconnected pores)

D. A special method: Fluid saturation - Based on measuring a fresh sample filled with water, oil and gas. (Not the same fluid distribution as downhole). why? - Sum of the of volume of the three fluid is equal to the rock total volume. (A mercury positive displacement pump is used to determine VT) Effect of Pressure: - Rock porosity is reduced due to rock compression for example due to production in the reservoir. - Porosity obtained from the above methods do not correct for difference’s between reservoir and laboratory conditions because the porosity variation is low and a core does not represent as entire reservoir.

Permeability The Specific or absolute permeability of a rock is ability of the rock to allow a fluid with which it is saturated to flow through it’s pores. An experimental law, Darcy’s law is used to determine permeability. Permeability can vary from 0.1 mD: to more than 10 D. The following are permeability ranges: <1mD: Very low 1 to 10mD: Low 10 to 50mD: Mediocre 50 to 200mD: Average 200 to 500mD: Good > 500 mD: Excellent

Laws of Horizontal Flow in Steady-state condition: Note: Oil, water: Darcy’s law Gas at low velocity: Darcy’s law Gas: Elementary pressure drop law Oil, water at high velocity: Elementary pressure drop law Liquids: Parallel flow: Q=KA/Ɲ 𝑃1 −𝑃2 1 Cylindrical steady state flow: For a well drilled from the boundaries of a layer: Q= 2𝝅𝐻𝑘 Ɲ ∗𝑃𝑖 −𝑃𝑤𝑓/ ln ( 𝑅 𝑟𝑤 ) R=drainage radius rw= Borehole radius ( at pressure Pwf) Pi= initial reservoir pressure - Flow rate is the same at any annulus centered in the well.

Gases: If Darcy’s law applies: Parallel flow: Q=KA/Ɲ 𝑃1^2 −𝑃2^2 21𝑃 Cylindrical flow= Q= 2𝝅𝐻𝑘 Ɲ ∗𝑃1^2 −𝑃2^2/2𝑃 ln ( 𝑟1 𝑟2 )

Absolute Permeability, Effective Permeability and Relative Permeability: Absolute rock permeability depends on the direction considered. (kv and Kh) Due to stratification (problems of fluids with different densities), kv is much lower than Kh. Relative permeability (oil) = Effective permeability (oil) Permeability of rock Will relative permeability for oil be the same as that of gas in a oil and gas reservoir? Explain - Relative permeability depends on the rock sample and the fluid proportions.

Absolute permeability is determined by air circulation (constant or variable head air permeameters) See page 44 and 45 on how absolute rock permeability can be determined, using the above methods Note: Porosity/Permeability exercise will be illustrated in class.

Saturations For a pore volume (Vp) that contains (Vw) volume of water, (Vo) volume of oil, and Vg (Volume of gas). The oil, water and gas saturations are: Sw= Vw/Vp, So = Vo/Vp and Sg=Vg/Vp Sw + So + Sg = 100% To know the oil and gas volume in place requires knowing this saturations.

The distribution and displacement of different fluids in a reservoir depends on capillarity properties of rocks such as Wettability, Interfacial pressure and Capillary pressure in the pores. Note: For a rock sample saturated with a fluid and surrounded by another fluid: 1. if the saturation fluid s wetting, it is displaced by the surrounding fluid only if the excess pressure applied to the surrounding fluid is at least equal to the capillary pressure for the largest pores. 2. If the surrounding fluid is non-wetting, it is displaced spontaneously by the surrounding fluid. Note: Water/oil- Water is the wetting zone Water/gas- Water is always the wetting zone Oil/gas- Oil is the wetting zone

Characterization of Reservoir Rock
Equilibrium of an initial-state reservoir: For a homogenous reservoir (contains single-phase oil (or gas) and water, and is water wet. Hydrodynamism is absent. Hydrodynamism is present in inclined zones with water at the base and along the flow direction with hydrocarbon accumulation. The change in saturation with depth is not uniform for a non-homogeneous reservoir. Discuss example in class. See fig on page 55 in class. Capillary migration: considers the effect of oil drop movement from source rock to reservoir rocks. Relationship between pore constriction and fluid (oil) movement in hydrocarbon migration.

See the methods used to obtain capillary pressure curves. (Discuss) Determination of in-situ saturation: 1. Direct method (Core analysis): Not possible (Pressure and temperature falls when cores are at the surface, that results to the fluids expansion and re-distribution). -In some cases, with the right drilling mud, the saturations with irreducible water can be determined on samples taking from the core center. 2. Indirect method by analysis of capillary mechanism.

Well log Method: Basic method used to determine saturation. Reservoir saturation cross-sections: Saturations from a reservoir cross-section can be made as a function of depth. See Fig 2.21 Surveys with a scanner: - Used to obtain cross-sections images that aid to visualize porous medium, morphology of the pores, heterogeneities and fractures. Used to aid in saturation calculation and saturation variations and porosity calculations.

Well logs Downhole recording of formations in a drilled borehole with depth. Example is an electric well log: Used for reservoir assessment. The purpose of a well logs are: Identification of reservoirs. (Lithology, porosity, saturations( water/oil/gas) as a function of depth. The dip of beds. Well survey. (Diameter, inclination, casing cementing, perforations) Well correlations.

Main characteristic recorded: Resistivity and Spontaneous potential Natural radioactivity (gamma rays) and induced radioactivity (neutron/gamma-gamma) Speed of sound, attenuation of acoustic waves. Borehole diameter and deviation, Dip of beds

Electric Logs: Spontaneous Potential (SP) - The log is based on natural currents (no transmitters) - Variation in electric potential are measured directly between a surface electrode and the sonde. Characteristics obtained are: Boundary of the reservoir beds and resistivity of pore water Rw. 2. Resistivity log: - Involves the use of transmitters to send electric current into the formation. - It measures the apparent formation/reservoir resistivity. (Hydrocarbons have high resistivity and water with increasing salinity (salt-water) has decreasing resistivity; rock matrices is insulating. - Characteristics obtained are a function of the porosity and saturation (water/hydrocarbon)

Resistivity logs can differentiate water from hydrocarbons. Archie equation: 𝑆𝑤= 1 ф ∗ n√(Rw/Rt) n = 2 (for Formations with fractures) Rt = True formation resistivity (can be obtained from logs) Rw = Water resistivity ф = Rock porosity Sw = Water saturation NOTE: The above equation is satisfied for clean reservoirs (with very little shale). 3. Microresistivity Log: - Used for measuring invaded zone resistivity that helps to provide information on porosity and water saturation of the reservoir.

Radioactivity Logs: 1. Gamma ray log (GR): - Measures the natural radioactivity of formations. - Shales and marls (Higher gamma reading) more radioactive than Sandstone and limestone (Lower gamma reading). - Used to identify formation/ reservoir beds. 2. Neutron log (N): - Measures the level of hydrogen content in the formation from the number of detected slow neutrons. - Formation porosity is determined because it can be referred to amount of hydrogen components in the formation pores. 3. Density (D): - Measures the density of the formation. (Gamma ray radiation) - Formation porosity can be calculated from a relationship with density measurements.

4. Neutron Relaxation (TDT): The log helps to locate hydrocarbons behind casing and monitor interface changes during production. Sonic (or Acoustic) Log: Involves sound waves transmission and reception. Delta time is transmitter/receiver interval that varies with fluid types and formation types. See page 69. Can be used to determine lithologies and porosity (compressional travel time) Auxillary Logs: 1. Caliper logs: - Measures borehole diameter. (identifies cavings, constrictions, cement quantities e.tc)

2. Dipmeter: - Logs provide dip bed values and it’s direction. 3. Cement Bond Log: - Measures the amplitude of acoustic signal received through cement. (Signal is weak, if cement is present (attenuation) and signal is strong, if cement is absent). - The log analysis helps to identify cement bonding to the casing and to the formation. Determination of Lithology, Porosity and Saturations: The following are used: Lithology: Gamma and/or SP + cuttings (and cores) and, if necessary with: b. “Neutron + Density + or (Sonic)” combinations

Porosity: Resistivity, neutron, density, sonic Saturations: a. Resistivity (+SP), for Rw,as needed) 𝑆𝑤= 1 ф ∗ n√(Rw/Rt) water and oil (or gas). b. “neutron + density” combination for gas (lower density and higher neutron, where “D” indicates too strong apparent porosity and “N” too weak apparent porosity) Hence you can use: Resistivity (+SP) + N + D -> water, oil and gas Fig 2.25 (A composite log) – Discuss in next class…See Fig 12. Repeat Formation Tester (RFT): - Used for spot microtest at desired depths to get information such as : Static pressure of the reservoir fluids; fluid types and possibly an order of permeability magnitude and other vertical thickness reservoir parameter values.

Production Logs: - The logs analysis the production and characteristics of fluids level by level to determine: Production(injection) intervals; fluid types produced and at each level; completion quality (i.e. well treatment (acidizing) or cementing job seal etc.) - Ran during well production(examples of instruments are: flow-meters, gradiometer or combined (Production logging tool)) - Information such as: Flow-rate, water cut, GOR, density e.tc are obtained for each interval; and also the production well results at the surface for each interval.

Fluids and PVT Studies General Fluid Behavior:
Fluids can be a mixture (i.e. Oil and gas or liquid mixtures) with different molecules or pure substances with identical molecules. (i.e. natural gas or liquid). Both fluid types behavior are different due to their One-phase fluid: The behavior depends on the volume occupied by the fluid, which depends on Pressure and Temperature. Two-phase fluid: The behavior depends on the pressure as a function of temperature and not the volume of the two phase. Three phase fluid: Only a single temperature/pressure is possible. (Volume=zero)

Fluids and PVT Studies Pure Substances:
The following illustrates the fluid behavior of pure substances on pressure/specific volume and pressure/temperature diagrams: Pressure/Specific Volume Diagram/(Clapeyon Diagram):

Fluids and PVT Studies Pressure/Specific Volume diagram illustration: The following is observed in an experiment: Pure substance is Liquid state at pt. A Increase in Volume (at constant temperature), results in the following: 1. Steep drop in pressure. (Substance in liquid phase only) 2. Vapor phase. (At bubble pt.) 3. Increase in vapor phase/decrease in liquid phase. (At constant pressure) 4. No more liquid phase, at point R (Dew pt.) 5. Vapor phase only as pressure slowly decreases.

Fluids and PVT Studies Temperature can be varied from below the starting temperature (T) up to the maximum critical temperature (TC). Above (TC), pure substance is one phase gas (Supercritical state) regardless of pressure. Combination of the bubble point curve (with bubble points) and the dew-point curve (with dew points) is called the saturation curve. Any point within the two-phase zone is equal to pure substance distribution within the liquid and vapor phase BM/BR=Mass of vapor/Mass of pure substance

Fluids and PVT Studies Pressure/Temperature Diagram:

Fluids and PVT Studies Pressure/Temperature diagram illustration:
Bubble point and dew point pressures are the same (Points merge at the same temperature) Two phase stage ends at critical pt. (Pc and Tc) Vapor pressure curve is referred as liquid/vapor equilibrium pressure. (Depends on temperature and not volume)

Fluids and PVT Studies Mixtures:
Pressure/Specific Volume: The following is observed: Mixture is liquid at Pt. A (Press. and Temp. T1)’ Increasing the volume results in: Steep decrease in pressure in liquid state. Vapor phase. (Bubble pt.) Increase in vapor phase/decrease in liquid phase. (Pressure decrease but not as in 1 above) No more liquid phase at Pt. R1 (Dew-point) Vapor phase only as pressure slowly decreases.

Fluids and PVT Studies Pressure/Specific Volume Diag.

Fluids and PVT Studies Between the critical temperature Tc and critical condensation temperature Tcc, the fluid behavior described above holds. At a constant temp. and increasing volume: The following is happens: Gas phase (Supercritical phase) as pressure falls. Liquid phase reappears. (Retrograde dew pt. R2) Increase and a decrease in liquid state. No liquid state present. (Dew pt. R2) Only gas phase. (Pressure falls) Above Critical condensation temperature Tcc, mixture is always gas.

Fluids and PVT Studies Pressure/Temperature diagram illustration:
At a given temperature (Bubble pt. and dew pt. pressures are not the same) Has equal composition curves in the liquid phase (0% for dew pt., 100% for Bubble pt. curve)

Fluids and PVT Studies

Fluids and PVT Studies Different types of Reservoirs: Oil Reservoirs:
- Reservoir temperature is lower than mixture critical temperature. a. Initial reservoir fluid is under-saturated oil. (One phase hydrocarbon) - Gas phase appears at bubble pt. or saturation pressure) - Results in decrease in oil pore volume and increase in oil viscosity. - Oil is thereafter replaced by flowing trapped gas. - Results in decrease in reservoir pressure and low oil production b. Initial reservoir fluid is oil with gas cap. (Two phase liquid and vapor hydrocarbon) - Released produced gas adds to a non-produced gas cap

Fluids and PVT Studies for reservoir pressure maintenance and better oil production. - Oil is saturated at this state. (Reservoir pressure is below the bubble pt. pressure) - For a given reservoir, bubble point pressure of oil decreases with increase in depth. 2. Retrograde condensate gas reservoir: - Reservoir temperature is between the critical and critical condensate temperatures of the reservoir mixture. Initial reservoir pressure is the retrograde dew point pressure. - Results in a rapid condensation of hydrocarbons in the reservoir. - Gas produced is depleted with heavy condensate production.

Fluids and PVT Studies 3. Gas reservoirs one-phase in reservoir conditions: - Reservoir temperature is higher than the critical condensation temperature of the reservoir mixtures. - The gas are mostly wet gas at the surface. (Condensate) Some are dry gas at the surface. (Methane and ethane) See Fig. below on classification of hydrocarbon reservoirs based on thermodynamic criteria. P/T diagram.

Fluids and PVT Studies Behavior of Oil and Gas between the Reservoir and Surface: Hydrocarbon fluids differ in the volume and quality of the fluids in the reservoir and the surface. Light oils produce more gas at the surface. Heavy oil produce very little gas or likely ( dead oil) at the surface. Dry gas yields only gas at the surface. Condensate gas yields mostly condensate. See Fig on the behavior of oil and gas between the reservoir and surface.

Fluids and PVT Studies Natural gases:
See the ideal gas equation in text Z factor (compressibility factor, depends on the gas composition, pressure and temperature) - As pressure approaches zero, molecular interaction decreases and the gas approaches ideal gas and Z approaches 1.

Fluids and PVT Studies Volume factor of Gas Bg:
- Used to convert volume occupied by gas at P and T from the reservoir to standard volume. Determination of Z: Experimental By chart: Z as a function of Pseudoreduced pressure and Pseudoreduced temperature(illustrate in class)

Fluids and PVT Studies Condensate Content of Gas:
Mainly (propane and higher), (butane and higher) and pentanes and higher content of gas. Viscosity of Gas: Gas viscosity rises with temperature at low pressure (close to atmos. Pressure) At other pressures, it rises as the pressure increases and temperature decreases.

Fluids and PVT Studies Oils:
Well Effluent composition of Gas Reservoirs. See table and discuss. Oils: The specific gravity (SG) is between 0.75 and 1. (Also in API gravity) See equation in Text. Behavior in the one-phase liquid state and the two phase state: Discuss in class

Fluids and PVT Studies Formation Volume Factor and Gas/Oil Ratio:
Quantities of oil-in-place, reserves, flowrates and cumulative production are expressed in volumes (or masses) of stock tank oil. Gas in place (dissolved and free) is measured in standard volumes. Gas oil ratio: volume of produced gas/volume of stock tank oil. Variation between Reservoir Oil and Stock tank Oil at a Given Reservoir Pressure: Due to the drop in pressure and temperature when oil falls to the surface from the oil reservoir to become a stock tank oil, a dissolved gas comes out of oil solution. This results a smaller stock tank liquid volume recovery than the volume leaving the reservoir.

Fluids and PVT Studies The following is used:
Formation Volume Factor (FVF) Bo:(Bbls/bbl) Volume of reservoir liquid phase that yields a unit volume of oil in stock tank conditions. (Unit can be in: Bbls/bbl) 2. Solution Gas Oil Ratio (GOR) Rs: Standard volume of gas recovered with a unit volume of stock tank oil. (Unit can be in: Ft3/bbl)

Fluids and PVT Studies Variation in FVF Bo and Solution GOR Rs with Reservoir Pressure, Production GOR: Discuss in Class (Include Diagrams) Viscosity: Viscosity varies with pressure, temperature and quantity of dissolved gas The order of magnitude in the reservoir is: 0.2 cp to 1 P (Light crude and Heavy crude is above 1 P).

Fluids and PVT Studies Viscosity can be determined in: Laboratory
- Fall of ball in a calibrated tube filled with oil at a given temperature. - Capillary tube viscometer. 2) Chart (see text)

Fluids and PVT Studies Viscosity:
Well Effluent composition of Oil Reservoirs: See table and discuss. Formation water: The presence of two or more compositions may indicate several aquifers, and for water flooding, the compatibility with injected water that must be investigated. Compressibility: It is property that enables the water from an aquifer to drain a reservoir by expansion. Viscosity: Viscosity is determined in the laboratory or from a chart.

Fluids and PVT Studies Water and Hydrocarbons:
Problems associated with formation water during production: With Oil: Emulsion problems With gases: - Production of gases causes condensation of the water that forms gas hydrates with methane, ethane, propane, butanes, CO2 and H2S in certain temperature and pressure. The hydrates can clog the lines at the surface.

Fluids and PVT Studies Liquid/Vapor Equilibrium, Equation of State: Discuss in class with other charts.

Volumetric Evaluation of Oil and Gas in Place
Knowing the Volume of hydrocarbon in place in a reservoir is a fundamental importance. Oil and gas in place: Original Oil in Place (OOIP), Oil initial in Place (OIIP), Original gas in place (OGIP), Gas Initial in Place (GIIP). Or called Accumulations

The Different Categories of Oil and Gas in Place: Volumes in place are classified and varies with time as the reservoir is better understood. Information from drilled wells (such as: logs, petrophysical measurements, PVT analysis, e.t.c) along with geophysical and geological surveys are used in the estimation. When a reservoir is discovered, a rapid preliminary calculation is used to estimate Hydrocarbon Initial in place (HCIIP) volume. - Few data is available to be used and all results form the discovery are analyzed. - Rough estimation results.

First/second (HCIIP) estimate leads to a decision to drill one or more extension wells. - Used for reservoir image clarification and if, possible for production forecast. Improved estimation results. Reservoir development starts thereafter. - More drilled well provides more information - Information is added to further clarify reservoir image. - Reservoir estimation is finally clarified at the end of the field development phase.

The different categories of quantities in place are represented roughly by: “Proven”, “Probable” and “Possible” for a level or reservoir. Proven oil in place: Considered as certain.(Zones penetrated by wells) Probable oil in place: structural data, log interpretations and pressure indicate impregnated zones, but without absolute certainty. Possible oil in place: Insufficient data on fluid interfaces and extension of facies in certain zones leads to uncertainties, but the presence of hydrocarbon-saturated rocks is not discarded. Proven oil < Actual (Start of the life of a field) Proven + Probable+ Possible oil > Actual (more wells drilled to enhance reservoir image leads to closer to actual oil) See Figure below: Different categories of oil in place

Volumetric Calculation of Oil and Gas in Place: Two methods are used to assess the volume in place. Volumetric methods (will illustrate here) Dynamic method (later chapter) Dynamic method is used if the reservoir has produced for sometime (one or two years) and to confirm the values from the volumetric method.

Principle of Volumetric method: It can be difficult to access (HCIIP) because: Complexity of porous medium Uncertainty to the exact reservoir shape Insufficient data such as porosity, Saturation, e.t.c. (Few drilled wells in a large area) Difficulty is in the parameters determination that is used in (HCIIP) estimation and not the volume calculation.

The calculation can be simplified as: Volume (reservoir conditions) = Volume of impregnated rock VR x Useful thickness/Total thickness or net pay /gross pay x porosity x saturation with hydrocarbons 2. Volume (Surface conditions)= Volume in reservoir conditions/Formation volume factor Combine 1 and 2: for example, for oil 𝑁=𝑉R * ℎ𝑢 ℎ𝑡 *∅∗ 1−𝑆𝑤 ∗ 1 𝐵𝑜 The volume in place are adjusted to surface conditions fro easy of comparison with cumulative hydrocarbon production.

Calculation of Volume of Impregnated Rock VR: Can be made considering the whole reservoir, or Can be made composed of several sectors or compartments (faults, different levels, facies variations) by subdividing the reservoir vertically and Horizontally. Horizontal Subdivision: First made automatically when the structure saddles two or more permits or leases. Used to make individualized sectors when there are faults, structural saddles, facies variations and data that shows the existence of independent sectors. (Different oil/water, interfaces, distinct initial pressures) The identification of the distribution of the volume- in- place in the individualized sectors allows production rates to be defined by sectors. This helps to identify required number and location of development wells based on the sectors.

Vertical Subdivision: This subdivision depends mainly on the geological model adapted. Can be made from the identification of large units from logs and/or sedimentological analysis. The volume in place for each unit and the best production scheme can be determined for wells in the unit. The subdivision is made by units that can be identified on the entire sector. The reservoir must be considered as a whole, without a need for subdivision if the distribution of sedimentary bodies is anarchic. It is best to subdivide the reservoir to a reasonable degree (not more) to minimize errors that would lead to vast calculations. An example is a subdivision that is based on log analysis and laboratory measurements (cuttings and cores) that will help determine if the reservoirs are independent or not. This can help in analyzing changes in pressure and production in each level after production starts in the reservoir.

FIG: Same as page 121

Fluid Interfaces: Exact position of any O/W, G/W and G/O interfaces in each level (unit) must be clarified. The interfaces can be identified by logs, core analyses, and production tests. The two methods below can be used to calculate the volume of impregnated rock (VR) or Reservoir rock. 1. Reservoir rock volume calculation from Isobaths cubic content or Area depth method: - Can be used in the calculation of each unit volume. - Geological and geophysical surveys are used to furnish isobaths maps for the top and the base of the reservoir. - A planimeter is used on the two maps to calculate the rock volume. - The maps are plotted on a depth/area diagram and together with the OWC contact gives the volume of impregnated rock. With a Gas cap (GOC), rock volume for gas and that of oil is determined separately.

2. Rapid Calculation Method: - Used for rapid estimation of the rock volume to obtain an order of magnitude from a poorly known structure at the time of discovery. (Area depth method is not employed) - Structure is treated as spherical dome or trapezoidal shape. See examples in the fig. below that demonstrates the determination of VR based on the structures.

Calculation of the volume of Oil from Isopach Maps: This calculation is made later when a minimum number of wells has been drilled. Involves the combination of two isobaths maps (Top and Bottom of the reservoir) to get an isopach map of the reservoir. An “iso-h/porosity” map is obtained from the porosities of wells to chart a map of porosities. Pore volume calculation is made from a Planimeter tracing the area S between curves for the two maps. Vp = S x hu x porosity. (See figure in text)

More accurate if lateral variations in thickness and porosity are substantial. Volume in place (N) are calculated with the determination of the average value of Bo and Swi (or Sw in the transition zone) with the aid of “iso-oil” (or “iso-gas) maps. Choice of Average Characteristics, Uncertainties: Choice of Average Characteristics: Involve the use of average reservoir characteristics such as: hu/ht, porosity, water saturation and Oil formation volume factor in the calculation of oil thickness or oil equivalent. (Illustrate in class) Used for newly discovered reservoirs where characteristics from one well is extrapolated to the entire reservoir.

Uncertainties and Probabilistic Methods: Lack of information about a reservoir can lead to major numerical errors. Probabilistic method is applied to parameters characterizing reservoirs to minimize errors. Examples of the probabilistic methods used are: “Monte Carlo” and “Krigeing Methods”. The results gives an average value and a probabilized “range of volumes” in place. The following type of uncertainties origin can be distinguished: Systematic: Due to related technique applied. (i.e. Uncertainties related to seismic picking, acoustic velocity, e.t.c) Occasional: Related to the reservoir itself. (i.e. water levels, correlations (function of the type of sedimentation), e.t.c.

The uncertainties can be quantified by: Subjective uncertainties: Use of “light statistical approach” and recommendation of experienced personal in determination of the uncertainties to derive the probabilities. Objective uncertainties: Uncertainties made at end of the field development with large data set that provides more valid statistics. NOTE: Decisions are mainly taken at the start of development and the uncertainties are essentially subjective.

One-Phase Fluid Mechanics and Well Test Interpretation
The two conditions below can be expected to occur in a reservoir: Fluid flow alone in a layer or in the presence of an immobile fluid. (One-phase flow) Simultaneous flow of two or three fluids. (Multi-phase flow) One phase flow mechanics relates flow rate with pressure as a function of time and others fluid and rock properties.

Well testing: Involves wellbore reservoir pressure measurements at the start and during production. Well testing can identify: A wells production capacity Reservoir static pressure (or well drainage area) Product of “hk” (hydrocarbon producing thickness multiplied by permeability) Any change in production zone properties due to Skin effect. (Affects meanly reservoir permeability when the area around the wellbore is damaged or improved by stimulation) Well drainage radius R. Existence of rock heterogeneities or structural discontinuities such as faults.

7. Types and changes of produced fluids. 8. Oil and gas in place and drive mechanism, if applicable. PVT sample studies and analysis are carried out during testing at the onset of a reservoir life to determine how effluents will be processed. Also, from the test, initial or changes in well completion requirements can be established.

Oil flow around wells: Diffusivity equation for a simple homogeneous isotropic reservoir is derived under the following conditions: Porosity with constant permeability (no direction considered) Fluid volume is equal to pore volume. (single phase) Constant reservoir temperature Assume an incompressible rock Liquid compressibility is constant in pressure interval corresponding to the area drained by the well. (Viscosity is also used)

The diffusivity equation for this reservoir type is derived from the relationship in (5), Darcy’s law, Law of conversation of mass and equation of state. (Illustrate in class) We are considered with circular radial flow that occurs around wells. See Fig below: Use to characterize different equations for different flow boundary conditions in time and space.

Standard Solution to the Diffusivity Equation: Production or changes in flow-rate of a well creates a disturbance that is felt in a wide area. Pressure between reservoir boundary and well drainage area before the disturbance reaches both point is a function of location both points and time. At this time the fluid is in transient.

The flow regime changes from Transient flow until the disturbance is felt at the reservoir boundary (or well drainage zone) , and at this point it is in Transition, then to a steady-state flow (constant pressure outer boundary reservoir) and semi-steady state flow ( bounded reservoir). Typically reservoirs can exhibit flow regime changes from transient to semi-steady state. Constant Pressure outer boundary reservoir: Not common Steady-state flow with constant pressure. Examples: 1. Aquifer drive reservoir. (Volume of hydrocarbon produced from the reservoir is replaced by an equal volume of water)

2. Production from water flooding and pressure maintenance. (Volume injected equal volumes produced). (More common) Bounded Reservoirs: Semi-steady state flow with constant pressure drop. Pressure difference between any two points is the same. Examples sandstone lenses in shale or reservoir drained by many wells. See the figs. below for the two examples described above.

Pressure Drawdown Equations: (Flow-rate) 1. At constant flow rate: The flow conditions that occur are from transient flow (valid as long as the reservoir behaves like a “infinite reservoir”) then to either semi-steady state flow (bounded cylindrical reservoir ) or steady state flow (constant pressure outer boundary reservoir) both at when the disturbance reaches the reservoir boundaries or well drainage zone. NOTE: Discuss relationship.

2. At Variable Flow Rate: During well testing variation of flow-rates is done to confirm the reservoir parameter results. This is done by using the principle of superimposition to obtain equations that relates the changes in flow-rate with time. NOTE: Discuss in relationship.

Equation of Pressure Build-up after Shut-in: Discuss relationship. Note: In an “Infinite reservoir”. The pressure build-up (well shut-in) interpretation helps to obtain reservoir pressure Pi (extrapolated) and a mean permeability of the drainage area.

Important Remark: Discuss in class. Skin Effect or Damage: Decrease in permeability due to the partial plugging of invaded zones by cakes and filtrates from drilling mud. S = Skin effect coefficient S > 0 = If the layer near the wellbore is damaged. (Additional pressure loss) S<0 = If the layer near the wellbore is improved. (Reduced pressure loss) Discuss the relationship between pressure drawdown with skin effect. Discuss the relationship between the pressure build-up with skin effect.

Total skin effect St: Skin effect due to perforations (Sp), if applicable + Skin effect due to partial penetration effect (Se). Sp and Se can be obtained by chart or formulae. See figure on text (page 146) St = Sc + Sp + Se, Sc (due to plugging) can be found. Sc can be used for well improvement by stimulation.

Productivity Index: Defines the production capacity of a well. It is calculated in order to determine the completion of a well for a given flow-rate (pumping or gas-lift) or the pressure loss that must be at the wellhead. (Naturally flowing)

Multi-Phase Flow Flow in reservoirs are not generally one phase flow.
An oil reservoir, with oil above the bubble point or dry/wet gas reservoir without an aquifer is an example of a one phase flow Multi-phase flow can result from two or three phase flow among oil ,gas and water in a reservoir

Multi-Phase Flow Cases of Multi-phase flow Oil Reservoir:
Original G/O and O/W interfaces location change (2- phase) Dissolved gas liberation from oil (PR<Pb); 2-phase or if near an O/W interface (3-phase) Gas injection in an oil reservoir or water injection in an under-saturated oil (2-phase) and if water in injected in saturated oil (3-phase)

Multi-Phase Flow Gas Reservoir:
Original G/W or G/O interfaces location change (2- phase) When gas condensate is under retrograde dew-point pressure (2-phase) or if near a near an aquifer (3-phase) Forces acting on multi-phase flow (2-phase flow) are Viscosity forces, gravity forces and capillarity forces

Multi-Phase Flow Relationship between capillary doublelet, development of drops and Jamin effect in 2-phase flow in two porous medium One porous medium with two smaller pore spaces and the other with a smaller and wider pore space Movement of displaced oil in the pore space of a reservoir whether injected with water or due to an aquifer is easier in the first porous medium compared to the second porous medium (doublelet) This is due to additional capillary forces in a smaller pore spaces of the first porous medium with the external forces

Multi-Phase Flow The oil/water interface advances quicker in narrower part of the second porous medium Oil droplet is formed in the wider part of the second porous medium and either block the pore (trapped) or pass through (referred as “Jamin effect”) Whether the oil is trapped or passes through the pore spaces depends on the pressure gradient (pressure drop) across the flow. It is common in reservoirs to have trapped or immobilized oil in pores (referred as “residual oil”) This is due to low pressure gradient (pressure drop) in across pore fluids during hydrocarbon production A reservoir residual oil corresponds to a reservoir residual oil saturation Reservoir residual oil saturation (Sor) average values are typically in this range (20% <Sor>40%) NOTE: In conclusion, unless, there are two fluids that miscible, only part of oil or gas is displaced.

Multi-Phase Flow Concept of Relative Permeability
The simultaneous flow of two fluids tends to reduce permeability for each fluid. This is referred as the effective permeabilities of both fluids. Effective permeability of fluids depend on specific permeability of the medium (reservoir nature) and the fluids saturations. (i.e. Effective permeability of gas in a gas-water reservoir) If the volume of one fluid is increased either by flow or injection it will affect both fluids effective permeability and saturations. The term relative permeability is now introduced and depends only on saturations Relative permeability is ratio of effective permeability of one fluid at a particular saturation to the absolute permeability of that fluid at total saturation.

Multi-Phase Flow Relative permeability kri = Ki/K
Ki = Effective permeability (2-phase) K = Absolute permeability (1-phase) The relative permeabilities for water, oil and gas, when any two of the fluids exist in a given medium is given as: Water: Krw = Kw/k Oil: Kro = Ko/k Gas: Krg = Kg/k Relative permeability range is between 0 and 1 When a single fluid is present in a rock, relative permeability is 1.

Multi-Phase Flow Relative permeability calculation is used for comparison of the ability of different fluids to flow in the presence of each other

Multi-Phase Flow Variation in Relative Permeability as a Function of Saturation Oil/Water (or Gas/Water)Pair: If a rock sample has oil and contains pore water. Initially (Sw = Sw) and when a water (wetting fluid) is slowly injected, (Referred as “Displacement by imbibition”), the following can be observed. The relative oil permeability decreases and the relative water permeability increases up to a maximum water saturation Swm = 1- Sor; as the water saturation increases (Oil is slowly pushed out from the pores and replaced by water) Oil stops circulating at the residual oil saturation (minimum saturation) Water starts circulating above the connate water or initial water saturation in the pores (Swi)

Multi-Phase Flow When Kro + Krw < 1 (indicates that both fluids hinder each other during simultaneous movement) When (Swm =1 – Sor), oil no longer flows out and at this point an oil reservoir has being swept by water The same phenomenon happens in a oil reservoir with a aquifer drive energy source See the diagram that shows the relative permeability relationship with saturation for Oil/Water mixture

Multi-Phase Flow

Multi-Phase Flow Oil/Gas Pair:
Similar observation as above, but with the gas phase The critical gas saturation is the minimum gas saturation required for gas to flow See the diagram below that shows the relative permeability relationship with saturation for Oil/Gas mixture

Multi-Phase Flow

Multi-Phase Flow Relative permeabilities comments: Practical applications NOTE: The inhibition curve must be if oil is displaced by water (O/W interface and/or water injection) at least for water-wet medium. This also applies to a gas reservoir with an active aquifer The drainage curve must be used if oil is displaced by gas (G/O interface and/or gas injection) because the gas is non-wetting compared to oil

Multi-Phase Flow Determination of Relative Permeabilities
This can be done by taking measurements in reservoir condition (P,T) on large core samples or use of empirical equations in the absence of cores Two methods that used are: Displacement of one fluid by another, “Unsteady-state”, WJBN method “Static” method for measuring relative permeability, “steady-state” method Empirical equations: See text on the equations for gas/oil pair and oil/water pair as specified.

Multi-Phase Flow Capillary Imbibition
It is the spontaneous displacement of non-wetting fluid by a wetting fluid A typical example is oil displacement by water and is a favorable mechanism for oil recovery Theory of Frontal Displacement Front Concept: Involves the flow of two immiscible fluids in a large medium in one direction with variations in pressure, saturations, fluid speeds e.tc in a single space direction that corresponds to the movement direction Typical examples are: A displacement that corresponds to the movement of G/O or O/W interface during natural depletion or it may occur between two lines of production and injection wells See the diagram below that shows the saturation profile for water at a given time, as a function of the displacement direction x (Increasing x), when it displaces Oil (Four zones are noted)

Multi-Phase Flow

Multi-Phase Flow See the relationship (equation) for water-cut (fw) at the front with regards to flow-rate, relative permeabilities, Viscosity for oil and water as specified Water cut is a function of saturation and flow-rate of oil Encroachment, Instability Mechanism, Definition of Mobility Ratio Encroachment: Involves the distortion of the interfaces (i.e. O/W, G/O or G/W) and “fronts” in a porous medium

Multi-Phase Flow Encroachment that occurs in a larger scale in the front is called Tongue Encroachment that occurs in a smaller scale is called Fingering Encroachment that occurs near a producing well is called coning Encroachments are governed by conditions of stability or instability A stable movement is where a small change in the movement initial conditions (initial coordinates, initial speed) causes variations in the movement that remains small over time and of the same order as the initial disturbance The opposite to above is called unstable movement

Multi-Phase Flow Mobility Ratio:
See the relationship (equation) for mobility ratio as specified Mobility ratio of displaced oil or gas depends on relative permeability of oil/oil viscosity and that of the displacing fluids on relative permeability of the displacing fluid/fluid viscosity The lower the mobility ratio, the better the displacement stability Instabilities such as (tongues, fingering) are most likely to occur if Mobility ratio is higher than 1 Mobility ratio (M > 1) is unfavorable (i.e. for gas displacement, since gas is gas viscosity is very low0 Mobility ratio (M< 1) is favorable (only for gas or light oil displaced by water)

Multi-Phase Flow Tongue:
Two conditions that results to the instability mechanism in the formation of tongue are: M>1 and Qo>Qc (Production flowrate > critical flowrate) Tongue formation affects production Fingering: Occurs due to rock heterogeneity (variation in permeabilities) and grows to a metric or decametric scale if (M>1) If (M<1), incipient fingering is resorbed Higher the mobility ratio and more rock heterogeneity, the more likely for fingering to occur Fingering is superimposed on tongue occurrence

Multi-Phase Flow Coning:
An example of interface encroachment that results from the local interface deformation (G/O or O/W) near a producing well Draw-off is related to the pressure difference between the well and interface, which results in the distortion of the interface to approach the well Two types of coning are: Bottom coning and Edge coning See the diagram below that describes tongue, fingering and coning (Bottom and Edge coning)

Multi-Phase Flow Bottom coning Tongue Edge Coning Fingering

Multi-Phase Flow Production Aspect: Coning Parameters
Drilling a well subject to coning and required production rate : A cautious solution consists of perforating over a short stretch of pay zone and the adoption of a low flowrate to delay undesirable fluid arrival at the well for as long as possible (still used, if Qo < Qc) Note: Better to avoid drilling a well close to (O/W, G/O or G/W) interface with a large thickness of undesirable fluid A “full pot” solution involves wide perforations and withdrawing at maximum flowrate (Results to more production of the undesirable fluid i.e. water) The use of injected polymers to prevent water influxes is another method that can be used in wells

Primary Recovery, Estimation of Reserves
Primary recovery or natural depletion of a reservoir involves the production of hydrocarbons with a reservoir natural energy. Reservoir pressure and flow-rate will eventually decrease over a period of time Secondary recovery method can be applied to recover more hydrocarbons Hydrocarbon in place x recovery factor (R%) = reserves

Means estimated recoverable hydrocarbon volumes in place (to be produced) Also referred as “Initial reserves” Reserves that is obtainable from primary recovery depends on: Initial oil and gas volume in place and their distribution Reservoir rock and fluids characteristic The present drive mechanism and production rate Economics factor

A reservoir drive mechanism influences recovery factor and hence production rates Reserve classification is both technical and economical Typical recoverable reserves classifications are: Proven Probable Possible Ultimate

Drive and Recovery Mechanism types: One phase expansion - Possible in gas or under-saturated oil reservoir - More gas production from a gas reservoir than oil production from an oil reservoir Why? 2. Expansion of gases coming out of solution - Possible when reservoir pressure is less than bubble point pressure in under-saturated oil reservoir - Also called dissolved gas drive or solution gas drive - Increased produced GOR - Affects oil production

3. Expansion of the water of an aquifer - In oil reservoir, oil is readily recovered by this drive - In a gas reservoir, high pressure gas can be trapped behind the water (G/W interface). (Not ideal and can be harmful) 4. Expansion of gas cap - Involves gas expansion from a gas cap on top of a saturated oil reservoir - Also called gas-cap drive See the diagram below that shows the mechanisms that allow production for under-saturated and saturated oil reservoirs

5. Imbibition: - Slow mechanism - ideal for heterogeneous reservoir 6. Gravitational Forces - Separation of hydrocarbons due to gravity 7. Rock compressibility -ideal for one phase flow

Influence of production rate: Oil Reservoir without Aquifer - If it has a gas cap or not, recovery can be faster - Production rate can be rapid (recovery independent of flow-rate) - No aquifer influence 2. Oil Reservoir that has a mediocre petro physical characteristics with an aquifer: Two cases I) - Production rate can be rapid (i.e. one-phase expansion and Solution gas drive reservoirs) - aquifer has less time to influence oil production - Recovery rate is about (20 to 30%) ii) - Production rate can be slowed - aquifer has time to influence oil production -Recovery rate is about 40%

3. Fractured oil that has good characteristics reservoir with a large aquifer: Two Cases i) -Production rate can be rapid - aquifers acts mainly in the large connected fractures - Oil in matrix can move into these water flooded fractures and become trapped ii) – Production rate can be slowed - Aquifer has time to simultaneously drain all fractures and matrix - Recovery rate is higher than in case 1.

Note: The decision on production rates lies between economic factors and reservoir conservation policy. Secondary recovery method should be considered, if production rate is increased

Compressibility Coefficients, Fluid Expansion Compressibility The different compressibilities of reservoir fluids influence their recovery rate Gas is more compressible than Liquid (Oil or water) Fluid Expansion Also gas expands more easily than other fluids (Oil or water) as reservoir pressure decreases NOTE: This explains why Gas recovery from a gas reservoir and oil recovery with a gas cap is higher than oil recovery in an under-saturated oil reservoir (Pr >Pb) (one-phase oil)

Multi-phase Flow, Reservoir Heterogeneities Multi-phase Flow Presence of two or three fluids in a reservoir can hinder the flow of one fluid over another due to the effective and relative permeabilities of the fluids (i.e. saturated oil reservoir with a gas cap, under-saturated reservoir with reservoir pressure below bubble point pressure , retrograde gas condensate phase) all with underlying aquifer support. For an oil reservoir as the main recovery fluid, other fluids (water or gas) can come into the well that will eventually slow oil production.

Reservoir heterogeneities Heterogeneous reservoirs with decreased permeability have reduced recovery rate compared to permeable and continuous homogeneous reservoirs

Three types of calculation methods are used to calculate recovery factor (ratio) and reservoir size Material Balance Numerical method Decline laws 1) used at the start and 2) at the end of production

Recovery Statistics Hydrocarbon recovery rate in different reservoirs varies due to: The fluids properties Thermodynamic conditions Petro-physical properties Variation on reservoir architecture and heterogeneities Production rate The figure below shows different reservoir types (drive mechanisms and recovery rates)

World Reserves: Take note

Material Balance Based on making the volume of fluids contained in the reservoir the same as the reservoir pore volume at any given time. The simplest reservoir simulation model Used for: Production forecast: Np, Gp, Wp, at various pressure and also produced GOR and WOR Volume in place calculations: N,G, W Material balance calculations can be compared with Volumetric calculations

Recovery = Cumulative production/Volume in place (oil or gas) See Table below with notations.

Under-saturated Oil Reservoir: See text on specified the relationship (equation) between cumulative oil production (Np) and Initial oil Volume (N) Dissolved gas drive reservoir: See text on the specified relationship (equation) between cumulative oil production (Np) and Initial oil Volume (N)

Oil reservoir associated with an aquifer A very extensive, very continuous and highly permeable aquifer guarantees perfect reservoir pressure maintenance that increase oil recovery. (Perfect “water drive”) A relatively small, non-continuous or mediocre permeability aquifer can guarantee only limited pressure maintenance that decreases oil recovery. (Partial “water drive”) When water flows vertically from an aquifer that is in contact with a reservoir over its entire length, it is called a “bottom-water drive” or bottom aquifer.

When water flows lateraly from an aquifer that surrounds a reservoir length, it is called a ‘edge-water drive” or edge aquifer. Water flow involves vertical permeabilities with bottom aquifer Water flow involves horizontal permeabilities with edge aquifer Edge aquifer is more common See figs. below that shows a description of both bottom-water drive and edge-water drive mechanism

Bottom-water aquifer drive Edge-water aquifer drive

Calculation of water inflow: See text on the specified relationship (material balance equation) that can be used to calculate water influx from an aquifer Segregation: Mechanism that occurs due to gravitational forces allows released gas to rise above oil and be produced or trapped in an existing gas cap or forms a secondary gas cap in under-saturated oil reservoir. This depends on the reservoir pressure and on the anisotropy ratio of the permeabilities Kv/Kh When oil replaces the gas it is called concurrent segregation

Dry (or wet) gas reservoir without water influx: See text on specified the relationship (material balance equation) that can be used to calculate Gas- in -place Dry (or wet) gas reservoir with water: See text on specified the relationship (material balance equation) that can be used to calculate Gas- in- place

Condensate reservoirs: Contains complex hydrocarbon mixture At lower pressure, a liquid part (condensate) is deposited in the reservoir Gas and Condensate is produced Normally from deep reservoirs The mobility of condensate in reservoir and in a well depends on it’s saturation (critical vs in-situ saturation) Higher critical condensate saturations compared to in-situ saturations results in simultaneous mobility of gas and condensate phases Most common is where in-situ saturation is higher than critical saturation and the condensate is not mobile Condensate generally immobile in a reservoir and mobile in a well Relative permeability of gas and well productivity can be affected, although by limited volume

NOTE: Material balance calculation method is the simplest simulation tool It does not necessarily account for the geometry, internal architecture and heterogeneities of the reservoir Reservoirs used with material balance are considered as large bubble containing oil, gas, and water (with a single pressure This method is ideal for relatively homogenous reservoirs with a simple structure (not common) and reservoirs at the outset of production (lack of data) Reservoir drive mechanism must be determined as early as possible (i.e. for oil reservoir with gas cap, comparing initial reservoir pressure and bubble point pressure gives indicate if a well has crossed the gas/oil interface and the resultant drive mechanism. (Use with caution – most reservoirs have variable bubble point pressure) An aquifer characteristics must be optimized based on Re/Ri (expected/Initial recovery) and k (permeability) as soon as possible with the production history). (i.e. estimates maximize recovery)

Decline Laws: Used to extrapolate well parameters at the end of production of the field. (i.e. mainly flow-rate) Mainly used for small reservoirs or complex reservoirs The two basic laws are: Exponential decline of flow rate (water cut and flowrate can be extrapolated with time).See relationship in text. Hyperbolic (and Harmonic) decline (water cut and flowrate can be extrapolated with time). See relationship in text.

Production in Fractured Formations: Fractured formations can be good/very good producers in fractured zones and mediocre elsewhere Typically fractured reservoirs can have permeable or porous medium with additional fractured networks within the reservoir Can have additional network of fractures with or without deposits of chemical in the porous medium of the fractured reservoir The nature of fractured formations based on open fractures/channels, network fractures and chemicals deposits results to either a “porous fractured reservoir” or “non-porous fractured reservoir”. Non-porous fractured reservoirs contain less hydrocarbon volume in place and can have little or no hydrocarbon flow depending on the network of open/closed fractures when compared to porous fractured reservoir See the diagram of a typical fractured reservoir below

Sw (Initial water saturation) and Pc (capillary pressure) in fractured reservoirs are negligible. (Capillary mechanism does not normally exist in fracture) Some magnitude of order concerning fractures: Block dimension: a few centimeters to a few meters Useful fracture openings: normally a few dozen microns, sometimes a few millimeters Fracture permeability: a few dozen milli-darcys to a dozen darcy Matrix permeability: a dozen millidarcys to a dozen darcys Fracture porosity: about 0.01 to 1% (related to the total volume) Vug porosity: about 1% Matrix porosity: variable, sometimes nil

Geological Aspect of Fractures Methods used for geological information: Visual observation and description of cores - characterizes fractures by Opening, filing, length, dip and azimuth of the fracture plane and distance between two consecutive fractures 2. Observation of outcrops from observed core data during well correlation - main measurement is fracture density per unit length or area 3. Rock mechanics model - Information such as fracture stress (geostatic pressure, fluid pressure, tectonic forces associated with distortion of the fracture unit) 4. Reservoir seismic shooting - Identification of areas of intense fracturing Data Obtained from logs and Production Test Are mainly Permeability (Kf) and Porosity of a fracture system

Logs: Two types of instruments can provide essential data: Production instruments (Flow metering + temperature measurement 2. Acoustic (Analysis of wave attenuation) Seismic instruments in particular can locate fracture zones and help supplement core analysis

Production Test: Initial test that shows very high production indexes (PI) materialize the presence of fractured zones Drive Mechanisms: The supervision of a fracture network on a porous matrix represents the specificity of the system. The analysis of drive mechanism is based on the supply of one-phase or multi-phase flow from the blocks to the fractures Two key mechanism are: Expansion and Exudation One-Phase flow: 1. Expansion The expansion is due to the total compressibility of the block + fracture system (Not different from that same formation without fractures)

Two-phase flow: 1. Expansion Oil/water: similar to expansion mechanism, except it involves water rising very fast through the fractures (Affects production) Gas/oil: Not much difference from a non-fractured formation because the main compressibility is due to gas except for the rapid formation of a secondary gas cap due to the fractures 2. Exudation Involves the expulsion of hydrocarbons from the block into the fractures due to a combined action of capillarity forces (static imbibition) and gravitational forces Oil/water and water-wet rock: Involves the spontaneous penetration of water into the block by imbibition and also by gravity from the top. (Both processes are cumulative)

Oil water and oil-wet rock: Capillary forces oppose water entry into the block. Exudation is possible only if the gravitational forces prevail and if the blocks are large in size Gas/oil: Gas is the non-wetting fluid which results to opposition between gravity and capillary forces. Exudation can only occur with very large blocks NOTE: Exudation is significant in the oil/water case with a water-wet rock. It is significant for large blocks in other cases See the diagram below that summarizes the drive mechanism in fractured reservoirs (oil with gas cap and water level here)

Specific production technique (Horizontal drain hole) Well productivity is proportional to h.K (Reservoir thickness and Permeability) Well productivity is reduced for a thin reservoir and rises with the penetration distance into the reservoir Productivity over a vertical well is (3 to 5) times Drilling and Completion cost, can be variable, lies between (1.5 to 2) times that of a vertical well Fractured reservoirs with sub-vertical fracture network are ideal for horizontal drain holes because they intersect a large number of fractures and can achieve high productivity gain

Horizontal drain holes have a better chance of intersecting high productivity zones in extremely non-porous fractured reservoir The productivity index in this reservoirs can be (4 to 10) times that of a vertical well Benefits of a Horizontal drain hole (Horizontal well): They can be placed at the reservoir top to obtain a sufficient water blanket (away from the O/W or G/W interface) The horizontal length stresses the aquifer less Vertical sweep is more effective and recovery is high They can be placed away from a gas cap in the lower part of he oil zone to prevent against gas influxes (No aquifer present)

Secondary and Enhanced Oil Recovery
Hydrocarbon recovery by natural drive is the range of 30 % to 40% and is lower for oil Secondary recovery (injection of water or gas) is used to achieve better recovery after depletion of the natural drive energy Enhanced oil recovery involves the use of improved or tertiary methods for higher recovery

Typical applications for secondary recovery and EOR Reservoirs with low natural energy; under-saturated oil, very small or low-permeability aquifer Low permeability or large oil reservoirs (wide pressure differences between producing wells and aquifer or gas cap) Heterogonous reservoir (local permeability barriers) Condensate gas reservoirs Mediocre conventional secondary recovery (need to improve recovery by EOR process; injection of water with chemical additives, miscible fluids, steam, air, e.tc.

Secondary and EOR do not concern dry or wet gas reservoirs If used in condensate gas reservoir, the goal is to recover more natural gasoline by cycling gas Secondary and EOR methods are mainly for additional liquid hydrocarbon recovery

Secondary recovery or convectional artificial recovery methods: Water-flood (Water injection) Flooding by (immiscible) hydrocarbon gases (Gas injection) i.e. in condensate gas reservoirs: cycling of gas Enhanced oil recovery or improved or tertiary recovery methods: Miscible methods (CO2, CH4, e.tc.) Chemical methods Thermal methods: (i.e. steam, in situ combustion) for heavy oils

Factors that Influence Recovery This factors affects fluid flow between the producing wells and injection wells. A. Reservoir and Fluid Characteristics 1. Reservoir Geology: - Presence of impermeable barrier between injection and production wells that affects sweep (fluid flow)with regards to the injected fluid and oil. i.e. shale/sandstone or carbonate formation with sedimented permeable materials and close packed materials 2. Permeability: - Good permeability results in large swept of oil volume for the same volume of injected displacement fluid - Also provides high fluid flow-rate (allows for increased well spacing and decrease in required flooding pressure)

- Heterogeneous reservoirs with different permeabilities affects fluid flow (Displacement fluid) compared to permeable formations. This condition is unfavorable for fluid injection between injection wells and production wells for oil recovery. 2. Viscosity of Fluids and Mobility Ratio - Amount of oil not recovered (Trapped) is higher for a more viscous oil compared to a less viscous fluid

NOTE: Recovery is higher with regards to the reservoir and fluid characteristics, if: Few or no barriers Good or high K Narrow range of heterogeneities High angle dip Low viscosity: light oil High viscosity of injected fluid (advantage of injected water over injected gas)

B. Injection Characteristics: Injected fluid Volume: -if volume is higher, the injection volume will depend on the sources (aquifer level, associated gas or gas bearing zones), and is not possible to maintain pressure - If injection volume, in reservoir condition is equivalent to oil, gas and water produced volume, the pressure is maintained - Better injection volume for displacement results to maximum oil sweep.

2. Type of Fluid - Injection is more effective, if injected fluid is more viscous - Water injection good for light oil, not effective for more viscous oil - Gas injection not good for oil (Gas viscosity is very low) 3. Injection Patterns - Layout of injection and production wells depends on: reservoir geology, fluid content, volume of impregnated rock that must be swept. - Two types of injection patterns are: 1. Grouped flood (injection wells are grouped together) - Ideal for fairly high-dip reservoirs where injection wells can be placed to allow for regular displacement due to gravitational forces - Also, suitable for reservoirs with gas cap and/or an aquifer (Gas injection into a gas cap or water injection into an aquifer (peripheral flood) to allow for a slow and uniform breakthrough (more oil recovery) 2. Dispersed flood (injection and production wells are in alternate arrangement) - Ideal for a reservoir that is virtually horizontal and extensive where gravitational

forces can be used and a limited zone is effectively flooded, particularly in low permeability reservoir or heterogeneous reservoirs. - In the case, production and injection wells are laid out in a fairly regular pattern (Dispersed flood in oil zone) - Number of patterns used are laid out: In a line or alternate arrangement (five spot, seven spot or nine spot, i.e. 5 wells, 7 wells or 9 wells) which involves the ratio of number of injection to production wells (1/1, 1/2 and 1/3 respectively, i.e. how production wells will be covered by an injection well in the patterns)

NOTE: Injection Well Pattern: A. Grouped or Local Flood: - Referred as Peripheral flood (Water) or Central flood (Gas) - Ideal in reservoirs with gravitational forces and low pressure gradients (high K) - Well site choice depends on fluid type injected Advantages: 1.Good for front with wide areas (allows slow movement with respect to injected volume) 2. Countercurrent gravity vector 3. No relative permeability (allows maximum injectivity) B. Dispersed Flood in oil: - Valid in mediocre permeability - Used Offshore (shorter interwell distance) Geometric Patterns: 1. In line: Straight or staggered 2. Five spot, Nine spot, Seven spot patterns allows for i.e. number of injection wells : 1, 1/3, 1/2 respectively number of production wells Recommendation: Five spot or staggered lines for water injection Nine spot or staggered lines for gas injection

Analysis of Efficiencies: -Involves the efficiency of flooding as it relates to the recovery Injection efficiency: - Total efficiency is the recovery factor (zone subjected to flooding) in reservoir conditions Total Efficiency E = 𝑁𝑝 𝑋 𝐵𝑜 𝑉𝑝 𝑋 𝑆𝑜𝑖 (Soi is at the start of flooding) Also, Total efficiency can be defined as the product of the flowing three efficiencies E = EA X EV X ED (Represents oil recovery fro zones subjected to flooding) 2. Areal Sweep Efficiency: Involves area covered from injection that maximizes recovery. EA = 𝐴𝑟𝑒𝑎 𝑠𝑤𝑒𝑝𝑡 𝑏𝑦 𝑡ℎ𝑒 𝑓𝑟𝑜𝑛𝑡 𝑇𝑜𝑡𝑎𝑙 𝑎𝑟𝑒𝑎 - Depends on time (volume injected), well pattern and mobility ratio. - Increases with time (volume injected), different for 5 spot compared to 7 or 9 spot; or in line and decreases with increase in mobility ratiJ

3. Vertical Efficiency (or Invasion) Ev: Involves flooding in a vertical direction that maximizes recovery - Ratio of the area swept to the total area for a vertical cross-section Ev = 𝐴𝑟𝑒𝑎 𝑠𝑤𝑒𝑝𝑡 𝑏𝑦 𝑡ℎ𝑒 𝑓𝑟𝑜𝑛𝑡 𝑇𝑜𝑡𝑎𝑙 𝑎𝑟𝑒𝑎 ( 𝐴 ′ 𝐵 ′ 𝐶 ′ 𝐷 ′ ) - Increases as a function of time (volume injected) and decreases with increase mobility ratio (M) - Product of EA and EV (referred as sweep(volumetric) efficiency) See diagram below:

4. Displacement Efficiency ED: Involves the effective sweeping of oil volume compared to the initial oil ED = 𝑆𝑜𝑖 𝑋 𝑆𝑜𝑚 𝑆𝑜𝑖 Soi = 1 –Swi Som = 1 – SDM (SDM is the mean saturation of displacing fluid behind the front) Depends on time (volume injected), irreducible water saturation and oil (or gas) saturations Increases with time (volume injected)

In conclusion: - Water-flooding (water injection) is used for reservoir pressure maintenance May be dispersed type in oil zone or peripheral type in aquifer The technical and economic aspects: Technical aspect: Selection: - Based on oil viscosity (Good oil recovery efficiency with water flooding for light oil compared to heavy oil) - Based on water source, which is usually aquifer levels in shallow water, sea-water in offshore drilling or surface water onshore (lakes, rivers) -Based on reservoir heterogenueousity (Water-flooding is good for water-wet heterogeneous reservoir rocks) Economic aspect: Higher investment for water-flooding compared to gas flooding (require more water-flooded wells compared to gas flooded wells since water mobility and injectivity is lower), however the injected fluid flow-rate depends on the injection pressure.

Time and Start of Flooding: See text on comments as discussed. Implementation: See text on comments as discussed.

Gas Injection (Non-miscible): - Only attractive for light oil (low viscosity oil) Sweep efficiency is much lower than that of water Injection is performed in either the gas cap (local) or directly into the oil (dispersed) Injection gas consist mostly of hydrocarbons: reservoir production gas Reservoir pressure can be slowed down, when no outside gas source is available. Not efficient compared to the use of injection gas Gas injection can be advantageous compared to water injection: 1. If a gas cap is present 2. If oil is light (solution GOR is high and oil viscosity is low) 3. Reservoir permeability is high -Good recovery vertical sweep of oil by gas cap and injected gas in an oil reservoir can be produced after breakthrough (Produced GOR)

Economic Aspect: Few new wells are drilled for gas injection and it allows production wells to be converted as gas injection wells when gas is trapped in a gas cap Gas injection in oil zone (requires nine spot pattern) and uses fewer injection wells compared to water-flooding (water injection). However gas recompression cost for gas injection can be higher compared to using water.

Implementation: See text on comments as discussed. See table below on Comparison of water-flooding and Gas Injection

Gas Cycling in Retrograde Condensate Gas Reservoirs - Involves the used of dry gas for condensate recovery (Highly valuable product) - Injection wells are far from production wells (to avoid any premature breakthrough of gas)

Used due to further increase oil recovery (i.e. secondary recovery of oil in oil reservoir is about 25 to 50%) because of incomplete sweep of the reservoir and trapping of residual oil. Three enhanced oil recovery methods are: Miscible Method (i.e. CO2, CH4 e.tc) -Involves the use of an injected fluid (gas) miscible with oil 2. Chemical Methods - Involves the use of chemicals injected in water or more rarely to gas (produces foam) The two types used are: 1. Microemulsions: aims at improving displacement efficiency 2. Polymers: aims at improving sweep efficiency by raising the water viscosity

3) Thermal Methods: - Involves the use of A) Steam injection or B) in-situ combustion for mainly heavy oil recovery. - Helps reduce heavy oil viscosity for improved oil flow recovery by increasing the reservoir temperature - Also improves the reservoir fluidity (cracks heavy components) - See the table below on characteristics of heavy oil Steam Injection: - Can be done by 1)Well stimulation and 2) Injection with drainage between injection and production wells.

Well Stimulation methods: Heating of the well by steam injection 2) Alternate injection (heating) and production cycles - PI is often improved by 200 to 500% B. Steam Injection (Injection with drainage between injection and production wells) Involves alternation of production/injection wells Most widely used compared to other EOR methods See the information below about Steam injection:

B. In situ Combustion: - Involves the use of fire with injected air downhole to increase downhole temperature in reservoirs - Helps reduce the high viscosity of heavy oil - Two methods are a) Forward Combustion: fire is started downhole at the point where air is injected and b) Reserve Combustion: Air is injected until it reaches the production wells and the fire is started with an electrical system downhole See the information below on Forward combustion method Note: Reserve method very little used because it is difficult to apply

Principles of Reservoir Engineering

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