Introduction reservoir engineering 3 (Gas Reservoirs)

 Gas Reservoirs

Hydrocarbon reservoir can be called gas reservoir, if the temperature of the reservoir is greater than the cricondentherm of the hydrocarbon fluid. This is only applicable to non-associated gas reservoirs which can either be wet or dry gas depending on the phase present in the reservoir and at the surface separator. 1.4.5.5 Wet-Gas Reservoirs A natural gas system which contains a significant amount of propane, butane and other liquid hydrocarbons is known as wet gas or rich gas. It contains less amount of methane (85%) and more ethane than dry gas. Figure 1.13 shows a wet gas reservoir which exists solely as a gas in the reservoir throughout the reduction in reservoir

pressure. It temperature lies above the cricondentherm of the hydrocarbon mixture similar to a dry gas reservoir. The reservoir fluid will always remain in the vapor phase region as the reservoir is depleted isothermally, along with the production path unlike retrograde condensate; no liquid is formed inside the reservoir. However, separator conditions lie within the phase envelope, causing some liquid to be formed at the surface. This surface liquid is normally called condensate. Wet-gas reservoirs are characterized by gas oil ratios between 60,000 to 100,000 scf/STB, stock-tank oil gravity above 60 API, the liquid is water-white in color and separator conditions lie within the two-phase region. 1.4.5.6 Dry Gas Reservoir The hydrocarbon mixture of a dry gas exists as a gas in the reservoir (even in the two phase region) and in the surface separator characterized with a gas-oil ratio greater than 100,000 scf/STB. It contains mainly methane with some intermediates. The pressure or production path does not enter into the phase envelope (two phase region) as shown in Fig. 1.14, this means that the surface separator conditions fall outside the phase envelope which is in contrast to wet gas reservoir; hence there is no traces of liquid formed at the surface separator. Natural gas which occurs in the absence of condensate or liquid hydrocarbons, or gas that had condensable hydrocarbons removed, is called dry gas. It is primarily methane with some intermediates. The hydrocarbon mixture is solely gas in the reservoir and there is no liquid (condensate surface liquid) formed either in the reservoir or at the surface. The pressure path (line) does not enter into the phase

Introduction reservoir engineering 2

Types of Reservoir 

The classification of a hydrocarbon reservoir is basically dependent on the composition of the hydrocarbon mixture in the reservoir, the location of the initial pressure and temperature of the reservoir and the condition at the surface (separator) production pressure and temperature. A hydrocarbon reservoir can be classified as either oil black oil or volatile oil or condensate or natural gas (associated or non-associated) reservoirs. Since the hydrocarbon system has varying fluid compositions, to appropriately classify or identify the type of reservoir system, we need to understand the hydrocarbon phase envelope (pressure-temperature diagram). 

1.4.3 Phase Envelope 

According to Wikipedia, a phase envelope is a type of chart used to show conditions of pressure, temperature, volume etc at which thermodynamically distinct phases occur and coexist at equilibrium. Figure 1.8 depicts a phase envelope or pressure temperature (PT) phase diagram of a particular fluid system. It comprises of two curves (bubble point and dew point curves) which encloses an area representing the pressure and temperature combinations for which both gas and liquid phases exist; called the two-phase region. The curves or quality lines converging at the critical

point within the two-phase envelope indicate the percentage of liquid at any given pressure and temperature of the total hydrocarbon volume of the reservoir. Furthermore, on the phase envelope, we can place the various types of reservoirs depending on the location of the initial reservoir temperature and pressure with respect to the two-phase. Above the bubble-point curve in Fig. 1.8, we have a single liquid phase called an undersaturated reservoir while at a point beyond the dew point curve; a single gas phase occurs which may be a wet or dry gas reservoir. The various terms on the phase envelope are defined below. 1.4.3.1 Bubble-Point Curve The bubble-point curve is defined as the line separating the liquid-phase region from the two-phase region and above which a single liquid phase exists as shown in Fig. 1.8. Note, if there is gas, it will be dissolved in the liquid. 1.4.3.2 Dew-Point Curve The dew-point curve is defined as the line separating the vapor-phase region from the two-phase region and above which vapor phase exists as shown in Fig. 1.8. 1.4.3.3 Cricondentherm The Cricondentherm (Tct) is defined as the temperature above which there is no existence of two-phase irrespective of the pressure or it can be defined as the maximum temperature above which a single gas phase exist and no liquid can be formed regardless of pressure (Fig. 1.8). The pressure corresponding to cricondentherm is known as the cricondentherm pressure (Pct)

1.4.3.4 Cricondenbar The cricondenbar (Pcb) is defined as the pressure above which there is no existence of two-phase irrespective of the temperature or it can be defined as the maximum pressure above which a single liquid phase exists and no gas can be formed regardless of temperature (Fig. 1.8). The temperature corresponding to cricondenbar is known as the cricondenbar temperature (Tcb). 1.4.3.5 Critical Point The critical point is the point where the bubble point curve, dew point curve and the quality lines converge (Fig. 1.8). At this point, one cannot distinguish between the liquid and gas properties. Hence it is referred to as the state of pressure and 12 1 Introduction temperature at which all intensive properties of the gas and liquid phases are equal. The corresponding pressure and temperature at the critical point are referred to as the critical pressure (Pc) and critical temperature (Tc) of the mixture. 1.4.3.6 Quality Lines These are dash lines enclosed by the bubble-point curve and the dew-point curve. They converge at the critical point. They also describe the pressure and temperature conditions for equal volumes of liquids as shown in Fig. 1.8.

1.4.3.7 Phase Envelope (Two-Phase Region) This is the area enclosed by the bubble-point curve and the dew-point curve, wherein gas and liquid coexist in equilibrium; it is the region where we have the quality lines (Fig. 1.8). That is the region of greater than zero percent (0%) liquid and less than hundred percent (100%) on the phase envelope. 1.4.4 Oil Reservoirs A reservoir can be classified as oil reservoir if the temperature of the reservoir is less than the critical temperature of the reservoir fluid. It can be further classified as a black oil or volatile oil depending on the gravity of the stock tank liquid usually the API of the crude. Also, it can be classified as undersaturated or saturated reservoir based on the location of the initial reservoir pressure. 1.4.4.1 Undersaturated and Saturated Reservoir The fluid in the reservoir is a complex mixture of hydrocarbon molecules and as pressure and temperature reduces; that is the flow of hydrocarbon fluid from the reservoir condition to the surface separator, phase changes occur. Considering an undersaturated and a saturated reservoir as shown in Fig. 1.9 it can be seen that at the initial pressure, the reservoir is represented as a single liquid phase. As the pressure drops from the initial condition to the wellbore as a result of fluids production; the fluid remains as a single phase liquid at the wellbore. Therefore, a reservoir whose temperature is greater than the bubble point pressure is referred to as an "undersaturated reservoir". As the pressure reduces further until it reaches the bubble point pressure (saturated pressure) where the first bubble of gas is evolved from the hydrocarbon mixture, the fluid still remains in a single liquid phase. Below the bubble point pressure, there is a two-phase region and with further reduction in pressure, the fluid is produced up the tubing and the amount of gas evolved increases until it reaches the separator. Thus,

1.4.5 Types of Reservoir Fluids 1.4.5.1 Black Oil Reservoir Figure 1.10 represents a black oil system which is made up of heavy hydrocarbons and non-volatile hydrocarbons. It is characterized by a dark or deep color liquid having initial gas-oil ratios of 500 scf/stb or less, oil gravity between 30 and 40 API. The pressure and temperature conditions existing in the separator indicate a high percentage of about 85% of liquid produced. The oil remains undersaturated within the region above the bubble point pressure, this means that the oil could dissolve more gas if present in the hydrocarbon mixture. At the bubble point pressure, the reservoir is said to be saturated and this implies that the oil contains the maximum amount of dissolved gas and cannot hold any more gas. Further reduction in pressure causes some shrinkage in the volume of oil as it moves from the reservoir (two-phase region) to the surface (separator). Therefore, black oil is often called low shrinkage crude oil or ordinary oil. 1.4.5.2 Volatile Oil Reservoir A volatile oil reservoir is one whose reservoir temperature is below the critical point or critical temperature of the fluid as shown in Fig. 1.11. It contains relatively low

liquid content as it approaches the critical temperature, as compared to black oil reservoir that is far away from the critical point; a volatile oil reservoir is made up of fewer heavy hydrocarbon molecules and more intermediate components (ethane through hexane) than black oils. Volatile oils are generally characterized with Temperature 100% Liquid (Twf Pwf) (Tr, Pr) Volatile oil reservoir Critical point (Tsep, Psep) Separator 0% Liquid 80% Dew point curve Bubble point curve Production path Fluid path in the reservoir Pressure Fig. 1.11 Volatile oil reservoir Temperature 100% Liquid (Twf Pwf) (Tr, Pr) Black oil reservor Critical point (Tsep, Psep) Separator 0% Liquid 80% Dew point curve Bubble point curve Production path Fluid path in the reservoir Pressure Fig. 1.10 Black oil reservoir 1.4 Reservoir Engineering 15 stock tank gravity between 40 and 50 API, with a lighter color (brown, orange, or green) than black oil. In the case of volatile oil, 65% of the reservoir fluid is liquid at the separator condition. This means that relatively large volume of gas is evolved from the hydrocarbon mixture leaving a smaller portion as liquid. It is a high shrinkage oil as compared to black oil. 1.4.5.3 Condensate (Retrograde Gas) A condensate reservoir fluid is a gas at the initial reservoir pressure. It occurs as shown in Fig. 1.12 when the temperature of the reservoir lies between the critical temperature and cricondentherm of the reservoir fluid. It contains lighter hydrocarbons and fewer heavier hydrocarbons than volatile oil, its oil gravity is above 40 API and up to 60 API (i.e. between 40 and 60 API), the gas-oil ratio increases with time due to the liquid dropout, and the loss of heavy components in the liquid whose GOR is up to 70,000 scf/stb, it has about 5–10% liquid at the surface depending on the reservoir. The reservoir fluid is water-white or slightly colored oil at the stock tank. In Fig. 1.12, at the initial condition, the reservoir is in a single gas phase and as the pressure drops, the fluid goes through the dew point which then condenses large volumes of liquid as it passes through the two phase region in the reservoir. Consequently, as the reservoir further depletes and the pressure drops, liquid condenses from the gas to form a free liquid inside the reservoir.

In the production of a gas condensate field, gas is mostly produced with some liquid dropout as the pressure drops below dew point pressure; occurring mostly in the separator and can still be produced in the wellbore which ultimately leads to a restriction in the flow of gas. The temperature and pressure may change once the reservoir fluids enter into the wellbore, thereby causing liquid dropout within the wellbore. Thus, if the gas having the larger fraction does not have enough energy to lift the dropout liquid to the surface, a fallback in the wellbore occurs or liquid loading. If this is continuous, the percentage of the liquid will increase and may eventually restrict the gas production. This challenge can be adequately handled with artificial lift technologies such as gas lift. Table 1.1 shows the comparison of blackoil, volatile and condensate reservoir fluid properties

Introduction reservoir engineering 1

 Definition of a Reservoir

A petroleum reservoir is a porous and permeable subsurface pool or formation of

hydrocarbon that is contained in fractured rocks which are trapped by overlying

impermeable or low permeability rock formation (cap rock, that prevents the vertical

movement) and an effective seal (water barrier to prevent the lateral movement of the

hydrocarbon) by a single natural pressure system. Figure 1.1 shows clearly the

essential features of a reservoir which are: source rock, cap rock (non-permeable

rock), reservoir (porous and permeable rock) rock, hydrocarbon (oil and gas) and

aquifer (water sand).

Elements Required in the Definition of a Reservoir

The definition of a reservoir is not complete without mentioning the following: the

source rock, migration pathway, reservoir rock which talks about porosity and

permeability, cap rock, trap and a seal. These are briefly explained below.

1.2.1.1 Source Rock Hydrocarbon Generation

This is a rock in which hydrocarbon is generated from or has generated moveable

quantities of hydrocarbon. It is a site where hydrocarbon liquid is formed from an

organic-rich source rock with kerogen (Fig. 1.2, a precursor of petroleum) and

bitumen to accumulate as oil or gas or a combination of both oil and gas.

To characterize a rock as source rock, the following basic features need to be in

place:

• The quantity of organic matter which is commonly assessed by a measure of the

total organic carbon (TOC) contained in a rock.

• The quality which is measured by determining the types of kerogen contained in

the organic matter and prevalence of long-chain hydrocarbons.

• The thermal maturity; usually estimated by using data from pyrolysis analysis.

Therefore, hydrocarbon generation is a critical phase in the development of a

petroleum system which depends on three main factors:

• The presence of organic matter rich enough to yield hydrocarbons,

• Adequate temperature,

• And sufficient time to bring the source rock to maturity. On the contrary, pressure

of the system, the presence of bacteria and catalysts also affect the hydrocarbon

generation.

1.2.1.2 Migration

Usually, the sites where hydrocarbons are formed are not the same sites where they

are accumulated to form a reservoir. They must travel a long distance before they are

eventually trapped. Hence, migration can be defined as the movement of hydrocar￾bons from the source rock into the reservoir rocks. Hydrocarbon migration can be

classified further as primary and secondary. When the newly generated hydrocar￾bons move out of their source rock to the reservoir rock, it is termed primary

migration, also called expulsion. While the further movement of the hydrocarbon

within the reservoir or area of accumulation is called secondary migration as shown

in Fig. 1.3.

Accumulation

It is the quantity of hydrocarbon that has gradually gathered or defined as the phase

in the development of a petroleum system during which hydrocarbons migrate into

the porous and permeable rock formation (the reservoir) and remain trapped until

wells are drilled through to produce the accumulated hydrocarbons.

1.2.1.4 Porosity

This is the storage capacity of the rock to host the migrated hydrocarbon from the

source rock. It can be defined as the fraction of the bulk volume of the rock that is

void or open for fluid to be stored.

1.2.1.5 Seal/Cap Rock

Cap rock is a harder or more resistant rock type overlying a weaker or less resistant

rock type. It is an impermeable rock that acts as a barrier to further migration of

hydrocarbon liquids. The cap rock prevents vertical migration while seal prevents

lateral migration of the hydrocarbon. A capillary seal is formed when the capillary

pressure across the pore throats is greater than or equal to the buoyancy pressure of

the migrating hydrocarbons. They do not allow fluids to migrate through them until

their integrity is disrupted, causing them to leak. Sometimes the caps are not perfect

seals and petroleum escapes to the Earth’s surface as natural seepage, which can be

spotted by oily residue on the surface soil and rocks (geologic survey). Underwater

seeps can bubble up to the surface and leave an oily sheen.

1.2.1.6 Trap

This term is defined as a subsurface rock formation sealed by a relatively imperme￾able formation through which hydrocarbons will not migrate (Fig. 1.4). It is formed

only when the capillary forces of the sealing medium cannot be overcome by the

buoyant forces responsible for the vertical/upward movement of the hydrocarbon

through the permeable rock. There are several types of traps encountered, which can

be represented as single, parallel, sealing and non-seal.

Traps can be described as structural traps, which are formed in geologic structures

such as folds and faults. structural traps are formed chiefly as a result of changes in

the structure of the subsurface rock, which may be caused by compaction, tectonic,

gravitational processes or due to processes such as uplifting, folding and faulting,

culminating to the formation of anticlines, folds and salt domes. Majority of the

world’s petroleum reserves are found in structural traps. These are shown in Fig. 1.5.

The other type of trap is the stratigraphic traps which are formed as a result of

changes in rock type or pinch-outs, unconformities, or other sedimentary features

such as reefs or build-ups. It can also be seen as traps formed as a result of lateral and

vertical variations in the thickness, texture, porosity or lithology of the

reservoir rock.

1.2.1.7 Permeability

This is defined as the ease at which the reservoir fluid flows through the porous space

of the reservoir rock to the surface when penetrated by a well.

1.2.1.8 Reservoir

For the hydrocarbons that migrated from the source rock to accumulate, there must

exist a subsurface body of rock (reservoir rock) having sufficient porosity to host or

store the migrated hydrocarbons and also permeable enough to transmit the fluids

when penetrated by a well. Therefore, a reservoir is a porous and permeable

subsurface formation containing an accumulation of producible hydrocarbons (Oil

and/or Gas), characterized by a single natural pressure system that is confined by

impermeable rock and water barriers.

The reservoir rocks are mostly sedimentary in nature because they are more

porous than most igneous and metamorphic rocks. See details in understanding the

basis of rock and fluid properties textbook written by one of the same authors.

Prior to the formation of the hydrocarbon, the reservoir was actually filled with

water. This will lead us to the concept of drainage and imbibition processes

discussed below.

1.3 Drainage and Imbibition Process

1.3.1 Drainage/Desaturation Process

It is generally agreed that the pore spaces of reservoir rocks were originally filled

with water, as hydrocarbon is being formed from the source rock, it migrates or

moves into the reservoir, where it displaces the water and leave some fraction called

connate or irreducible water undisplaced. Hence, when the reservoir is discovered,

the pore spaces are filled with connate water and oil saturation respectively. If gas is

the displacing agent, then gas moves into the reservoir, displacing the oil.

This same history must be duplicated in the laboratory to eliminate the effects of

hysteresis. The laboratory procedure is performed by, saturation of the core with

brine or water, then displace the water to a residual or connate water saturation with

oil after which the oil in the core is displaced by gas. This flow process is called the

gas drive depletion process. In the gas drive depletion process, the nonwetting phase

fluid is continuously increasing with increase in saturation, and the wetting phase

fluid is continuously decreasing. Therefore, drainage process is a fluid flow process

in which the saturation of the nonwetting phase increases and also, the mobility

increases with the saturation of the nonwetting phase.

Examples of drainage process (Onyekonwu MO, lecture note):

• Hydrocarbon (oil or gas) filling the pore space and displacing the original water of

deposition in water-wet rock

• Water flooding an oil reservoir in which the reservoir is oil wet

• Gas injection in an oil or water wet oil reservoir

• Evolution of a secondary gas cap as reservoir pressure decreases

1.3.2 Imbibition/Resaturation Process

The imbibition process is performed in the laboratory by first saturating the core with

the water (wetting phase), then displacing the water to its irreducible (connate)

saturation by injection oil. This “drainage” procedure is designed to establish the

original fluid saturations that were found when the reservoir was discovered. The

wetting phase (water) is reintroduced into the core and the water (wetting phase) is

continuously increased. This is the imbibition process and is intended to produce the

relative permeability data needed for water drive or water flooding calculations.

Therefore imbibition process is a fluid flow process in which the saturation of the

wetting phase increases and also, the mobility increases with the saturation of the

wetting phase.

Examples of imbibition process (Onyekonwu MO, lecture note):

• Accumulation of oil in an oil-wet reservoir

• Water flooding an oil reservoir in which the reservoir is water wet

• Accumulation of condensate as pressure decreases in a dew point

reservoir Figure 1.6 schematically illustrates the difference in the drainage

and imbibition processes of measuring relative permeability. It is noted that the

imbibition technique causes the nonwetting phase (oil) to lose its mobility at

higher values of water saturation than the drainage process does. The two

processes have similar effects on the wetting phase (water) curve. The drainage

method causes the wetting phase to lose its mobility at higher values of

nonwetting-phase saturation than does the imbibition method.

1.4 Reservoir Engineering

It is a branch of petroleum engineering that applies scientific principles to the

drainage problems arising during the development and production of oil and gas

reservoirs to obtain a high economic recovery. The reservoir engineer is saddled with

the responsibility like that of a medical doctor to make sure the reservoir does not go

below its expected performance (fall sick) and even if it falls sick; he/she looks for a

Role or Job Description of Reservoir Engineers

Since it is usually not possible to physically ascertain what is under the ground

because nobody goes into the reservoir, it implies that a Reservoir Engineer needs

some techniques to adequately establish what is inside the reservoir. Therefore, it is

the role of a reservoir engineer to continuously monitor the reservoir, collect relevant

data and interpret these data to be able to determine the past and present conditions of

the reservoir, estimate future conditions and control the flow of fluids through the

reservoir rock with an aim to effectively increase recovery factor and accelerate oil

recovery. It is worthy to note that the complete role/job description of a reservoir

engineer to a company differs considerably from other companies, but there are key

functions that are common to all. Some of the jobs description of a reservoir engineer

but are not limited are stated below:

• Estimation of the original hydrocarbon in place (OHCIP)

• Calculation of the hydrocarbon recovery factor, and

• Attachment of a time scale to the hydrocarbon recovery

Good experience in constructing numerical reservoir simulation models (black￾oil and compositional), model initialization, history matching, running sensitiv￾ities and predictions.

• Determination of reservoirs, field development strategy, production rates, reser￾voir monitoring plan, and economic life.

• Involvement of work with an integrated team of geologists, geophysicists,

petrophysicists, and engineers from other disciplines.

• Knowledge of PVT data analysis.

• Collecting, analyzing, validating, and managing data related to the project

• Carrying out reservoir simulation studies, either for facts finding or to optimize

hydrocarbon recoveries.

• Predicting reserves and performance from well proposals.

• Predicting and evaluating gas injection/waterflood and enhanced recovery

performance.

• Developing and applying reservoir optimization techniques.

• Developing cost-effective reservoir monitoring and surveillance programs.

• Performing reservoir characterization studies.

• Analyzing pressure transients.

• Designing and coordinating petrophysical studies.

• Analyzing the economics and risk assessments of major development programs.

• Estimating reserves for producing properties