Chapter 3.1_Immiscible Gas Injection1.pdf

Enhanced Oil
Recovery
PCB4113
By Ms Nur Asyraf Md Akhir
IMMISCIBLE GAS
INJECTION
PART 1

At the end of this lesson, you should be able to:
 Describe the processes in immiscible gas flooding.
 Determine the gas flood design and screening
process.
 Explain the considerations taken for the gas
flooding.
Lesson Outcomes

Types of Gas
Injection
Immiscible Gas
Injection
Miscible Gas
Injection
How to determine the
miscibility of gas??

Gas Miscibility
Slim-Tube Test
 To define the minimum pressure for miscibility using
crude oil obtained from the field.
 The pressure that corresponds to
a break or sharp change in the
oil recovery at:
 1.2 pore volumes of injection,
when plotted against the
injection pressure.
 At the lowest pressure: the
recovery is about 90-95%.
immiscible gas
injection
miscible gas
injection

 MMP is typically smaller for low viscosity oils.
 Rough “rules of thumb” for oils with bubble-point viscosities less
than about 10 cp and an API oil gravity of 25 or greater:
 CO2 or enriched gases become miscible with the oil when
the reservoir pressure is above 1000 psia,
 methane can become miscible with light oils at pressures
greater than about 3000 psia,
 nitrogen at pressures greater than about 5000 psia.
NOTE: reservoir temperature and oil composition play an
important role in this assessment as well.
Gas Miscibility

 Gas injection aids oil recovery by 3 mechanisms:
 Vaporizing gas drive (oil vaporizes into gas).
 Condensing gas drive (injected gas condenses into oil).
 Increasing oil relative permeability and decreasing
residual oil saturation.
Gas Injection
Source: Practical Aspects of CO2 Flooding (2002)

Gas Injection
 Gas flooding is the injection of hydrocarbon or nonhydrocarbon
components into oil reservoirs.
 Injected components are usually:
 vapors (gas phase) at atmospheric temperature and
pressure.
 mixtures of hydrocarbons (methane to propane)
 nonhydrocarbon components such as carbon dioxide,
nitrogen, and hydrogen sulfide or other exotic gases such as
SO2.
 Gas injection today often means CO2 or rich hydrocarbon gas
injection to recovery residual oil, and in some cases to also store
or sequester CO2 from the atmosphere.

Gas Injection
 The primary mechanism for oil recovery by high pressure gas flooding
is through mass transfer of components in the oil between the
flowing gas and oil phases.
 Secondary recovery mechanisms include swelling and viscosity
reduction of oil as intermediate components in the gas condense
into the oil.
 The key to gas flooding:
 to contact as much of the reservoir with the gas as possible.
 to recover most of the oil once contacted.
 Injection gases are designed to be miscible with the oil so that oil
previously trapped by capillary forces mixes with the injected gas.
 The injected gas or hydrocarbon phase then drives the oil
components to the production well.

Gas Injection
 Ideally, miscible flow is piston-like in that whatever gas volume is
injected displaces an approximately equal volume of reservoir
hydrocarbon fluid.
 Unfortunately, in real field applications such piston-like behavior
does not occur because reservoir heterogeneities and gravity
override cause gas to cycle through one or more high-permeability
layers, bypassing some oil and leading to poor sweep efficiency.
 Mixing of oil and gas components within a single phase will also
lead to non piston-like behavior.

 Gas injection in an oil reservoir takes place either
into:
 A gas-cap
 Directly into the oil zone
Gas Injection

1- Gas Injection Into A Gas-Cap
 Gas-cap originally exists.
 Formed by segregation during
primary production.
 Maintain the reservoir pressure
while forcing gas into the oil
zone and driving the oil
towards the producers.
 Resulting to the rise of OWC
when water is injected into an
underlying aquifer.
In gas cap drive, the velocities
are very low giving stable
interface.

2- Gas Injection Into An Oil Zone
 When there is no gas-cap.
 Gas flows radially from the injection wells.
 The oil will drive towards the production wells.
 Unfavorable mobility plus large gravity impact.
 Tendency for gas override.

 A proper gas flood design will consider both:
 microscopic displacement efficiency
 sweep efficiency
 The profitability of that process is a function of the overall
recovery:
𝐸𝑣 = the volumetric sweep efficiency, which is the fraction of the
reservoir that is contacted by the gas,
𝐸𝐷 = the displacement efficiency is the fraction of contacted oil
that is displaced.
Gas Flood Design
𝐸𝑅 = 𝐸𝑣𝐸𝐷

Gas Flood Design
 Gas flooding designs are limited by both economics and
physics of displacement so that there is often a trade-off
between the sweep and displacement efficiencies.
 Because it is not possible to give exact values for these
efficiencies in the field, they are useful only to qualitatively
explain how key parameters such as:
 injection fluid viscosity
 phase behavior
 heterogeneities
 other fluid and rock properties affect recovery and the
design of gas flooding processes.

Calculation of Required Gas
– for complete pressure maintenance
1. Consider an oil reservoir producing at a GOR of (R).
Where:
R: GOR
Rs: solution GOR
Rc: excess GOR due to the circulation of free gas
𝑅 = 𝑅𝑠 + 𝑅𝐶

2. The production of unit volume of stock tank oil corresponds
to a withdrawal of a reservoir fluid volume of:
3. While the surface gas production is:
𝐵𝑜 + 𝑅𝑐𝐵𝑔
𝑅𝑆 + 𝑅𝐶

 If I percent of the produced gas is re-injected, its volume at
reservoir conditions will be:
 Complete pressure maintenance is assured when the
reservoir volumes produced and injected are equal:
𝐼 (𝑅𝑆+𝑅𝐶)𝐵𝑔
  g
c
s
g
c
o
B
R
R
B
R
B
I




 When no free gas is produced:
 For normal oils, I > 1
 the calculation indicates the need for a source of make-up
gas.
g
s
o
B
R
B
I 

Gas Flood Design
 The engineering steps in gas flood design depend on
whether a flood is a small or large project.
 For a large project there is more risk involved so that the
process involves three basic steps:
 Screening
 Design
 Implementation
 Small projects require fewer steps as detailed reservoir
studies, simulations, and associated predictions and
economics may not be done to reduce costs.
 Screening process is typically used to provide required
predictions and economics.

Gas Flood Design
 The basic design steps for a large flood are the following:
1. Technical and economic screening to eliminate reservoirs
under consideration before a more detailed study is done.
2. Reservoir/geologic study, including 2-D and 3-D reservoir
simulation to make performance predictions.
3. Wells and surface facility design based on forecasted fluid
volumes, compositions and reservoir continuity.
4. Economic studies where key input variables are varied to
understand associated risks.
5. Management approval (or disapproval) of the gas flood
based on uncertainties and economic considerations.
6. Implementation of the gas flood design by making wellbore
modifications, installing field facilities and any required
recycle plant, and injecting initial gas.

 These steps often require iteration as more is learned about
the field when:
 new wells are drilled
 laboratory data is obtained.
 Iterations in the design may also be required to maximum
present value profit, for example, by changing the volume
of gas injected.
Gas Flood Design

Technical and Economic
Screening Process
 The primary objectives of the screening process are to:
1. Rank potential candidate reservoirs for gas flooding.
2. Identify potential injection fluids.
3. Identify analogue fields.
4. Make some preliminary production rate estimates and
scoping economic calculations.
5. Identify which reservoirs should be examined in a later
more detailed analysis, especially if the gas flood is a large
project.

 Most fields undergo waterflooding prior to gas injection:
 to increase reservoir pressure
 to reduce risks associated with potential gas flood
projects.
 Risk is reduced if a secondary waterflood is done first:
 much is learned about well connections within the
reservoir during water injection
 facility costs associated with water injection are already
built.
Screening Process

 Important technical factors in screening process:
 residual oil saturation to waterflooding (initial). If residual oil
saturation is small (say less than 0.15), then there is little oil
left to recover by gas flooding.
 average reservoir pressure
 minimum pressure for miscibility
 oil viscosity
NOTE: The reservoir pressure must usually be near or above the
minimum pressure for miscibility to achieve good displacement
efficiency.
Screening Process

 A good screening process will consider several key technical
factors in addition to investment and operating costs. Typical
reservoir screening considerations include:
1. Residual oil saturation to waterflooding.
2. Average reservoir pressure (and temperature).
3. Oil viscosity and minimum pressure for miscibility.
4. Available miscible gas source and cost.
5. Reservoir heterogeneity and conformance issues at injection
well and well pattern scale.
6. Reservoir permeability and ability to inject and produce fluids
at economic rates.
7. Reservoir geometry and flow: gravity effects and vertical
permeability.
Screening Process

 Reservoir heterogeneity and conformance play important
role in screening:
 Conformance is defined as injecting fluids where you
want them to go, usually into the pay zone.
o If a waterflood had poor conformance (either at
injection wells or at the pattern scale), the sweep from
a gas flood is likely to be worse.
 A reservoir with:
o Greatly varies permeability is not likely a good
candidate for gas flooding.
o Many high-permeability fractures is also typically a poor
candidate, especially when these fractures are aligned
from injectors to producers.
Screening Process

 Injection well completions can also be faulty so that fluids
do not go into the pay zones.
 Fluids can travel behind the casing if the cementing
job is not good.
 Wells with poor conformance issues typically require
significant upfront costs to redo their completion,
which should be considered in the gas flood
economics.
Screening Process

 Water and gas must also be able to be injected in sufficient
quantities that oil can be produced at economic levels.
 the ability of fluids to be injected or produced can be poor
if the formation permeability is low or the fluid viscosities are
large.
 In most cases, if water was able to be injected at economic
rates then gas can be injected at the same or higher rates.
 Well injectivity tests should be done in the field if the gas
flood is to be done as a secondary recovery method,
instead of as a tertiary flood following a waterflood.
Screening Process

 Gravity effects:
 Injection fluids with a higher density than the oil (such as water)
can move downward through the reservoir bypassing oil.
 Injection fluids with a smaller density (such as gas) can move
upward through the reservoir.
o May require new perforations at the bottom of the pay zone to
lessen the effect of gravity (in fields with low vertical
permeability, e.g. CO2 floods in West Texas).
Screening Process

 Gravity effects:
 Advantage for the reservoir with a significant dip (Gulf-Coast
reservoirs):
o Gas can be injected up-dip and oil produced down-dip
in a gravity stable process.
o As oil is produced the injected gas can move down-dip
contacting more oil.
o Such a gravity stable process can overcome large
heterogeneities within the reservoir and yield high oil
recoveries.
Screening Process

 Economics. Both investment (capital) and operating costs should be
considered at an early stage. Both are depend on:
 Rates and volumes predicted from a scoping model or detailed
simulation.
 Such rates are typically calculated from simplified simulations or by
analogue gas floods that are similar to the current reservoir under
consideration.
 The cumulative injection and production rates must be scaled up
by considering the relative size of the proposed gas flood
compared to the analogue flood.
Screening Process

Considerations…..
 The principal factor involved in the decision to commence
gas injection is the availability of a nearby source of
cheap gas in sufficient quantities.
 The recycling of produced gas is a major source, but
can only slow down the reservoir pressure decline.
 Secondary gas must obtained either from adjacent
reservoir or from a nearby gas pipeline.

The relative advantages of gas and water injection:
 The capital investment required for gas injection is usually
higher than water injection.
 The microscopic displacement efficiency of gas is much less
than that of water.
 If dry gas is injected into an oil reservoir, the produced oil is
made up of:
 oil displaced from the porous medium.
 oil fractions vapourised by injected gas.
 Very light oil has extremely high mass of vapourised oil lead
to high oil recovery.
Considerations…..

There are certain conditions under which water injection should
not be considered:
 A very extensive gas-cap may form a preferential path for
injected water which will thus by-pass the oil zone. By
comparison gas injection into the gas cap may result in
additional oil recovery for the price of a few gas injection
wells.
 A reservoir with a high initial water saturation may not be
suitable for water injection. There is a risk that no front will be
formed and that oil and water will flow in parallel, giving a
low recovery efficiency.
 oil recovery by gas recycling may be possible, as long as
the free gas saturation in the reservoir is not too high.
Considerations…..

 If the reservoir has sufficiently high vertical permeability, gas-cap
injection will result in higher recovery than injection into the oil zone.
 It is advantageous to start gas injection into the gas-cap as soon as
possible. It is to avoid:
 the formation of a high free gas saturation in the oil zone
 an increase in oil viscosity
o allowing a high oil relative permeability
o maintain the productivity
 Every gas injection project should be preceded by laboratory
experiments (displacement studies on cores, physical models, etc.).
 Considering the underground gas storage and may render a project
economically attractive in certain circumstances.
Considerations…..

Enhanced Oil
Recovery
PCB4113
IMMISCIBLE GAS
INJECTION
PART 2

 Determine the injection well location
 Describe the sweep efficiency.
 Explain the effects of the recovery mechanisms
on the ultimate recovery for immiscible gas
injection.
Lesson Outcomes

Injection Well Location
 In general, the increase in recovery which gas injection
can provide does not warrant the drilling of a large
number of new wells, thus most of the injection wells are
obtained by the conversion of existing producers.

 All the injection wells are concentrated around the
top of the structure.
 The converted production wells may need to have
their existing perforations cemented off.
 New perforations made in the gas cap.
 The adequate number of injection wells depends
on the total injection rate required.
1- Gas Injection Into A Gas-Cap

 The well density varies widely, but there is always less
than one injector per producer (common in water
injection).
 Earlier there was no attempt to keep a regular pattern.
 Nowadays, seven spots (1 injector, 6 producers) is
often selected.
 However, such a pattern is often difficult to achieve,
due to location of the wells drilled during the primary
production phase.
2- Gas Injection Into An Oil Zone

Sweep Efficiency
 A measure of the effectiveness of an enhanced oil
recovery process that depends on the volume of
the reservoir contacted by the injected fluid.
(Oilfield Glossary)
or
 The percentage of original oil in place displaced
from a formation by a flooding fluid.
(Oil Gas Glossary)

 Both gas and water injection results in the formation of a
displacement font.
 The injected gas does not wet the rock surfaces, but sweeps
through the oil and tends to form a continuous gas phase
throughout the reservoir.
 It happens very rapidly, due to low critical gas saturation.
 During injection into the gas-cap there is more chance that a
distinct front will be maintained, since gravity will assist in the
segregation of the gas and liquid phases.
 The cumulative oil production is directly proportional to the log of
cumulative injected gas.
 For a given volume of injected gas, the greater pressure
gradient the greater produced oil.
 The greater the oil viscosity the lower the volume of produced
oil.
Sweep Efficiency

Recovery Factor
 The ratio of recoverable oil reserves to the oil in place in
a reservoir.
oi
o
oi
S
S
S
RF



Calculate the recovery factor when 1000
pore volumes of gas have been injected:
a. For core initially oil-saturated:
Soi = 1.00, (So)1000 = 0.53
b. For core with an initial water saturation:
Soi= 0.5, Swi=0.4, Sgi=0.1, (So)1000=0.17
Exercise

a. For core initially oil-saturated:
Soi = 1.00, (So)1000 = 0.53
b. For core with an initial water saturation:
Soi= 0.5, Swi=0.4, Sgi=0.1, (So)1000=0.17
Solution
47
.
0
1
53
.
0
1 


RF
66
.
0
5
.
0
17
.
0
5
.
0



RF

Enhanced Oil
Recovery
PCB4113
IMMISCIBLE GAS
INJECTION
PART 3

 Describe the preliminary studies and field
evaluation of injection efficiency.
Lesson Outcomes

Preliminary Studies and Field Evaluation
of Injection Efficiency
 In order to evaluate the efficiency of gas injection:
 A radioactive tracer can be used to physically
monitor the progress of the injected gas.
 At the same time, calculations based on frontal
displacement theory and material balance can be
performed.
The first estimation of the recovery
efficiency

 Using different radioactive gases it is possible to
“tag” the gas injected into each well in a limited
area of a field.
1 - Monitoring of Sweep Efficiency
using Radioactive Tracers
 At the production wells, the
produced gas can be
analysed and the tracers
identified.

 Using of radioactive tracer:
 Enables a picture of the heterogeneity and anisotropy
of the reservoir to be built up.
 The shape of the gas fronts to be estimated at given
times.
 Example: Hassi-Messoud, Algeria
 Hydrocarbons irradiated to Tritium have been used
with success.
 The first four alcanes were used and tracers were
injected for about 80 days at each well.
 Gases were separated & passed through detector to
measure the weak β radiation.
1 - Monitoring of Sweep Efficiency
using Radioactive Tracers

 The Buckley-Leverett theory is equally applicable to both gas
and water injection.
 However, for the vertical flow of gas and oil it is not possible
to neglect the effects of gravity.
 Thus, different equations must be used for the fractional flow
of gas (fg) depending on whether the injection takes place
in:
 the oil zone (horizontal flow assumed)
 the gas cap (vertical flow assumed).
2 - Calculation based on Frontal
Displacement Theory and material balance

Chapter 3.1_Immiscible Gas Injection1.pdf

Chapter 3.1_Immiscible Gas Injection1.pdf

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