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