Oil & gas

OIL & GAS
EXPLORATION, PRODUCTION AND
OPTIMIZATION

Great Lakes Institute Of
Energy Management
Gurgaon
Image Sources:ABB Oil and Gas Production Handbook

AGENDA
• Geophysical data
• Rigs, Drilling,Casing & Cementing
• Wireline Logging
• Completion of well(Well head, Christmas Tree)
• Production, Well Testing
• Decision Making
• EOR
• Case Study
• Abandonment of a well

GEOPHYSICAL DATA

Riches in Rocks

Image Sources:ABB Oil and Gas Production Handbook, Schlumberger Western
Geco Public Site.

RIGS

• Land Rigs
• Jack up Rigs
• Drill Ships
Image Sources:ABB Oil and Gas Production
Handbook,Schlumberger
Videos:From You Tube

Different Types Of Rigs
• Submersible
This is a drilling structure which is used in relatively shallow
water, usually 80 feet or less. It is towed to its location where it is
submerged until it sits on the bottom. This submerging serves as its
mooring system, although anchors may also be used.

• Semi Submersible
This rig has the hull design of a catamaran and is either towed or self-
propelled. A semi-submersible can also be dynamically positioned or it
can use anchors. When the rig is on location, it is ballasted down, in
about the same way a submarine submerges, fifty feet or so to give it
stability. Semis are heavy-duty rigs and are designed for adverse
weather conditions.

Image Sources:Google Images and Schlumberger.

• Drill Ship
A drillship can be one of two types:
1) It can be a ship which was designed and built to be a drilling vessel; or
2) A drillship can be an older vessel which has been refitted with drilling equipment.
Drill ships are self-propelled, carrying a complete ship's crew while underway, as well as
a crew of drilling personnel. Drill ships are moored either by the standard anchoring
system or by dynamic positioning of the vessel. Dynamic positioning is the use of a
computer-operated inboard thruster system which keeps the vessel on location without
the use of anchors. This arrangement allows vessels to drill in ultra-deep water.

• Jack up
Jack-ups are towed to their location where rig personnel use heavy machinery to
jack the legs down into the water until they are on the ocean floor. When this is
competed, the platform containing the work area rises above the water. After the
platform his risen about 50 feet out of the water, the rig is ready to begin drilling.
Jack-up rigs are limited to a water depth of about 300 feet or less.

Image Sources: Schlumberger and Google Images

• Barge
This is used to make extremely heavy lifts (The record to-date is 4,400 tons!) or to lay
underwater pipelines. When these lifts are being made, there are usually a lot of
support personnel on board (up to 200) including welders, electricians, riggers,
operators, etc. Derrick barges can be either self-propelled or towed.

Image Sources: Google Images

PLATFORMS
• Fixed Platform
• Complaint Tower
• Sea Star
• Floating Production Systems
• Tension Leg Platforms
• Subsea Systems
• Spar Platform

Source: www.naturalgas.org

FIXED PLATFORM
Used
In shallower water, if it is possible to physically attach a platform to the sea
floor.

How
The 'legs' are constructed with concrete or steel, extending down from the
platform, and fixed to the seafloor with piles.

Weight of the legs and seafloor platform is substantial, so they do not have to
be physically attached to the seafloor, but instead simply rest on their own
mass.

Many possible designs for these fixed, permanent platforms.

Advantage
The main advantages of these types of platforms are their stability, as they are
attached to the sea floor there is limited exposure to movement due to wind
and water forces.

Limitation
These platforms cannot be used in extremely deep water, not economical to
build legs that long.

COMPLAINT TOWER
Much like fixed platforms. Each consists of a narrow tower, attached to
a foundation on the seafloor and extending up to the platform
Advantages
The tower is flexible, as opposed to the relatively rigid legs of a fixed
platform. This flexibility allows it to operate in much deeper water than
fixed platforms
Disadvantages
The stability is far lesser than the fixed platforms. They get easily
affected by rough weather and winds.


SEASTAR PLATFORMS
• Seastar Platforms are similar to tension leg platforms.
• The platform consists of a floating rig, A lower hull is
filled with water when drilling,.
• Seastar platforms also incorporate the tension leg
system employed in larger platforms. Tension legs are
long, hollow tendons that extend from the seafloor to
the floating platform.
Advantages
Seastar platforms are typically used for smaller deep-water
reservoirs, when it is not economical to build a larger
platform. They can operate in water depths of up to 3,500
feet.


TENSION LEG PLATFORM
Tension leg platform is similar to sea star platform. But unlike
in sea star, the tension legs don't go all the way to the sea
floor. The structure is held in a fixed position by tensioned
tendons, which provide for use of the TLP in a broad water
depth range up to about 2000m. The tendons are constructed
as hollow high tensile strength steel pipes that carry the spare
buoyancy of the structure and ensure limited vertical motion.
Due to this the platform experiences more horizontal motion
due to the jerks from the rough weather. This platform allows
drilling at an amazing depth of 7000 feet. A variant is Seastar.


SUBSEA SYSTEM
• This platform has features from all the platforms that we discussed earlier. are
wells located on the sea floor, as opposed to at the surface. Like in a floating
production system, the petroleum is extracted at the seafloor, and then can be
'tied-back' to an already existing production platform or even an onshore facility .
• It is used to drill at depths of 7000 and above. The drilling apparatus is fixed on the
sea bed and the drilled oil is sent up with the help of risers.


SPAR PLATFORM
The SPAR consists of a single tall floating cylinder hull, supporting a fixed deck. The cylinder
however does not extend all the way to the seafloor, but instead is tethered to the bottom by a
series of cables and lines.

SPAR is not an acronym, but refers to its likeness with a ship’s spar. Spars can support dry
completion wells, but is more often used with subsea wells. Subsea production systems are
wells located on the sea floor, as opposed to at the


References
• 8 References
• Web on line sources and references that has been used in compiling this document:
• · Schlumberger oilfield glossary:
• http://www.glossary.oilfield.slb.com/default.cfm
• · Norsk Hydro, Njord Main Process and Oil Process Description.
• http://www.hydro.com/en/our_business/oil_energy/production/oil_gas_nor
• way/njord.html
• · Wikipedia http://en.wikipedia.org/wiki/Main_Page
• · Oklahoma State, Marginal Well Commission, Pumper’s Manual
• http://www.marginalwells.com/MWC/pumper_manual.htm
• · Natural Gas Supply Association. See Natural Gas - From Wellhead to
• Burner Tip
• http://www.naturalgas.org/index.asp
• · US geological survey: http://www.usgs.gov/
• · US department of energy: http://www.doe.gov/
• · NORSOK standards, Standards Norway (SN),
• http://www.standard.no/imaker.exe?id=244
• · UK Offshore Operators Association (UKOOA)
• http://www.oilandgas.org.uk/issues/storyofoil/index.htm
• · National Biodiesel Board http://www.biodiesel.org/
• · PBS – Public Broadcasting Service - Extreme Oil
• http://www.pbs.org/wnet/extremeoil/index.html
• · http://www.priweb.org/ed/pgws/history/pennsylvania/pennsylvania.html

COST COMPARISION
FLOATING RIGS

Rig Type Rigs Working Total Rig Fleet Average Day Rate

Drillship < 4000’ WD 6 rigs 8 rigs $241000

Drillship 4000’ + WD 48 rigs 61 rigs $462000

Semisub < 1500’ WD 10 rigs 17 rigs $241000

Semisub 1500’ + WD 63 rigs 87 rigs $302000

Semisub 4000’ + WD 85 rigs 105 rigs $418000

Source: rigzone public site

JACKUP RIGS
Jackup IC < 250’ WD 32 rigs 53 rigs $68000
Jackup IC 250’ WD 37 rigs 63 rigs $80000
Jackup IC 300’ WD 94 rigs 131 rigs $89000
Jackup IC 300’ + WD 122 rigs 151 rigs $144000
Jackup IS < 250’ WD 5 rigs 53 rigs $68000
Jackup IS 250’ WD 7 rigs 53 rigs $68000
Jackup IS 300’ WD 2 rigs 53 rigs $68000
Jackup IS 300’ + WD 1 rigs 53 rigs $68000
Jackup MC < 200’ WD 2 rigs 53 rigs $68000
Jackup MC 200’ + WD 12 rigs 28 rigs $46000
Jackup MS < 200’ WD 2 rigs 2 rigs -
Jackup MS 200’ + WD 4 rigs 19 rigs $43000


OTHER OFFSHORE RIGS


Drill Barge < 150’ WD 18 rigs 39 rigs -

Drill Barge 150’ WD 6 rigs 9 rigs -

Inland Barge 27 rigs 74 rigs $47000

Platform Rg 144 rigs 250 rigs $37000

Submersible 0 rigs 5 rigs -

Tender 23 rigs 32 rigs $132000


Classes of Oil well
• Oil wells can generally be grouped into two
categories:
– Exploration or ‘Wild Cat’
• A potential ‘oil-field’ never drilled before – could be no oil

– Development
Oil field already present – simply extracting more oil

DRILLING
Horizontal Drilling
It is an enhanced oil recovery
(EOR) or gas recovery method .

Casing
Three different types
Surface
Intermediate
Production

Blow Out Preventer(BOP)

Videos Source: You Tube
Image Sources: Google Images

BOP
• Subsea Blow-out Preventor
(BOP) stacks are specially
designed to operate under
water at great depths.
• They are located on the sea
bed, rather than above water
on the rig.
• Subsea BOPs are used only
on floating rigs.
• They are a very important
safety device to prevent the
well ‘blowing’ oil

Source: ABB handbook

WIRELINE LOGGING

• Geological logs
visual inspection of samples brought to
the surface
• Geophysical logs
physical measurements made by
instruments lowered into the hole .
• Well logging is done during all phases
of a well's development;
drilling, completing, producing and
abandoning.

Image Source: Schlumberger
Video Source: You Tube

Cementing
• Two processes – Wet and Dry
• Sets through a chemical
does not need air to set
• Very complex chemistry
Contains silica, alumina and iron oxide
• Grind the resulting product to a fine powder
Dry
Cement Recipes
A ‘recipe’ – a specific combination of chemicals mixed
with neat cement and water to achieve a desired
slurry/set cement.
Many different additives in use
• accelerators, retarders, dispersants, fluid-loss,
extenders
• Schlumberger uses ‘D’ codes to designate an
additive
Wet
Source: Schlumberger

Objectives of Cement Job
• There are three main objectives:
– Provide complete isolation of zones
– Support the casing
– Protect casing string

Image Source: Schlumberger

Completion
Early wells were drilled in very shallow reservoirs which were sufficiently consolidated
to prevent caving. As deeper wells were drilled, the problems associated with surface
water prompted the use of a casing or conductor to isolate water and prevent caving
of the wellbore walls. Further development of this process led to fully cased wellbores
in which the interval of interest is perforated.
Modern completions are now commonly undertaken in deep, hot and difficult
conditions. In all cases, achieving the completion and eventual production objectives
are a result of careful planning and preparation.

Completion Types
The most common criteria for the classification of completions include the following
• Open-hole or cased hole, horizontal completion
• Producing zones, i.e., single zone or multiple zone production
• Production method, i.e., natural flowing or artificially induced production (Artificial
Lift)

• Open Hole Completion
Barefoot completions are only feasible in reservoirs
with sufficient formation strength to prevent caving or
sloughing. In such completions there are no means of
selectively producing or isolating intervals within the
reservoir or open hole section. The production casing
or liner is set and cemented in the reservoir cap
rock, leaving the wellbore through to the reservoir
open.
The use of open hole completions is now restricted
primarily to some types of
horizontal wells and to wells where formation damage
from (air drilling) drilling fluids is severe.
To prevent an unstable formation from collapsing and
plugging the wellbore, slotted screen or perforated
liners may be placed across the open


• Cased Hole Completions
Modern perforating charges and techniques are
designed to provide a clear perforation tunnel
through the damaged zone surrounding the wellbore.
This provides access to the undamaged
deformation, allowing the reservoir to be produced
to its full capability.
Cased and cemented wells generally require less
complex pressure control procedures during the early
stages of installing the completion components

• Natural Flowing
Wells completed in reservoirs which are capable of
producing without assistance are typically more
economic to produce.
In general, naturally flowing wells require less
complex downhole components and equipment. In
addition, the long-term reliability and longevity of
the downhole components is generally better than
that of pumped completions.

• Artificial Completions
All pumped, or artificially lifted, completions require the placement of specialized
downhole components. Such components are electrically or mechanically operated, or
are precision engineered devices. These features often mean the longevity or reliable
working life of an artificial lift completion is limited. In addition, the maintenance or
periodic workover requirements will generally be greater than that of a naturally
flowing completion.

• Artificial Lift Methods
• Gas lift
• Electric submersible pump
• Plunger lift
• Hydraulic or Jet Pump
• Variable Cavity Pump (VCP)
• Hydraulic or Jet pump
• Progressive cavity pump (PCP)

COMPLETION
Completion Tubing
Completion Assembly
1. Packer
2. Permanent Downhole Gauge
3. Safety Valve
4. Christmas Tree

Video Source: You Tube
Images Source: Google Images

WELL TESTING
Separator:
To separate different constituents of drawn
oil.
Flaring:
Burning the first few barrels.

Source: ABB Handbook

DECISION MAKING
• Factors affecting the decision making in E&P.
1. Reservoir Technological factors,
2. Economic factors.

Source: en.wikipedia.org

RESERVOIR TECHNOLOGICAL FACTORS
• Pressure,
• Temperature,
• Porosity,
• Permeability,
• API Gravity,
• Sulphur Content.


CRUDE OIL ANALYSIS

Source: Oil and Gas Production Handbook by ABB

PVT ANALYSIS


POROSITY & SORTING


POROSITY LEVEL IN RESERVOIRS

POROSITY
Percentage of Pores Usage
Less than 10% Poor, Productivity Doubtful.
10 - 15% Fair.
15 - 25% Good, the most common range in production reservoirs.
Over 25% Excellent, but rare.


POROSITY Vs PERMEABILITY


PERMEABILITY LEVEL IN RESERVOIRS

Permeability
Permeability Value Usage
10 mD Poor
100 mD Fair to Good
1000 mD Excellent, but rare.


RELATIVE PERMEABILITY


API GRAVITY

Ideal value of API Gravity is 10 to 70.


SULPHUR CONTENT
Standard fuel oil - Sulphur content rate should not exceed 4.5%
Low Sulphur fuel oil - Sulphur content rate should not exceed 1.5%.

Sweet crude oil has a sulphur content less than 0.5%.

Anything more than 0.5% is sour.

Heavy crude is:
• harder to handle (it is two thick to pump easily through pipelines unless
diluted with light crude)
• more expensive to refine to produce the most valuable petroleum
products such as petrol, diesel and aviation fuel.
• Sweet crude is preferable to sour because it is also (like light crude) more
suited to the production of the most valuable refined products.


ECONOMIC FACTORS

• Cost of benefit.

• Funds.

• Rate of Return.


Cost Benefit Analysis
• Cost–benefit analysis (CBA) is a systematic
process for calculating and comparing benefits
and costs of a project for two purposes:
• A) to determine if it is a sound investment to dig
a well (justification/feasibility),
• B) to see how it compares with alternate projects
(ranking/priority assignment)
• It involves comparing the total expected cost of
each option against the total expected benefits,
to see whether the benefits outweigh the costs,
and by how much.

FUNDS
• NPV (net present value)

• PVB (present value of benefits)

• PVC (present value of costs)

• BCR (benefit cost ratio) = PVB / PVC

• Net benefit = (PVB - PVC)


Rate of Return
• Rate of Return indicate cash flow from an
investment(Oil Well) to the investor over a
specified period of time, usually a year.
• ROR is a measure of investment
profitability, not a measure of investment size.
• The higher the investment risk, the greater the
potential investment return, and the greater
the potential investment loss.

PRODUCTION OPTIMIZATION
Improving Productivity is a huge problem.
Various Factors :
• Operational Costs
• Hardware Damage
• Reservoir Performance
• Environmental Requirements
• Operational Difficulties


Applications included in Production
Optimization
• Flow line Control
To stabilize the Multiphase Flow in gathering systems, risers &
Flow lines.

• Well Control
To stabilize and Optimize gas lift and naturally flowing wells.

• Slug Management
It will help mitigate variations in Inflow impact.

• Well Monitoring System
Used to estimate the flow rates of Oil, Gas & Water from all
the individual wells in an Oil Field.

ENHANCED OIL RECOVERY AND
IMPROVED OIL RECOVERY
EOR:-
•It is the process that seek to improve the recovery
of hydrocarbon from a reservoir after the primary
and secondary production phase.
•Enhanced Oil Recovery is a generic term for
techniques for increasing the amount of crude
oil that can be extracted from an oil field. Using
EOR, 30-60 %, or more, of the reservoir's original
oil can be extracted compared with 20-
40% using primary and secondary recovery.

Improved Oil Recovery:-
• Any of various methods chiefly reservoir drive
mechanism and enhanced recovery techniques,
designed to improve the flow of hydrocarbons from
the reservoir to the wellbore or to recover more oil
after the primary and secondary methods(water- and
gas floods).
Primary Oil Recovery:-
• This implies the initial production stage, resulted
from the displacement energy naturally existing in a
reservoir.
Secondary Oil Recovery:-
• A recovery improvement process such as water
flooding and gas flooding.

LIMITATIONS AND DISADVANTAGES OF
PRIMARY AND SECONDARY RECOVERY
PROCESSES
• Rapid decrease in reservoir pressure – leads to
low oil production rates and oil recovery (5 – 10
% of original oil in place).
• Secondary recovery (water / gas injection) often
does not yield a good recovery due to:
- Reservoir heterogeneity
-Unfavourable mobility ratio between oil and
water
- Water and gas coning problems
- Low sweep efficiency

WHEN TO START EOR?
A common procedure for determining the optimum
time to start EOR process after water flooding
depends on:-
• Anticipated oil recovery
• Fluid production rates
• Monetary investment
• Costs of water treatment and pumping equipment
• Costs of maintenance and operation of the water
installation facilities.
• Costs of drilling new injection wells or converting
existing production wells into injectors.

WHY EOR?
Oil and Gas market ripe for breakthrough-EOR Solution:-
• World oil consumption rate at 85 million barrel per day.
• 1/3 production increases over next 15 years to meet
projected demand.
• Oil production faster, less expensive and with less
disturbance to environment from existing wells.
• EOR can prolong life of oil field upto 30 years .
• There is significant oil in place in discovered reservoirs
that will otherwise not be recovered.
• EOR can make an important contribution to world oil
supply in the long term.
• EOR economics can be attractive.

WORLD OIL PRODUCTION FORECAST (IEA)

• 64 million b/d of capacity additions needed by
2030.
• 5 million b/d is forecast to be supplied by EOR
in 2030.
• 20 million b/d is from fields yet to be found.
• 33% recovery efficiency ->EOR target of 2.2
trillion barrels in discovered fields.

A Boom of EOR Program:-
• Proven reserves
• Hard to get oil
• Demand outstripping supply
• Cost of finding new oil reservoir
• Political problems
• Environmental concern
Example-Occidental Chemical Co. maintains a
very successful EOR program, producing
approximately 350000 barrels of oil equivalent
per day.

Business Benefits:-
• Optimize oil recovery with field proven flow
and density solutions
• Simplify operations and reduce maintenance
costs with reliable and accurate measurement
• Multi-variable output and process intelligence
enable remote surveillance and reduced
operator intervention
• Reduce chemical costs through accurate flood
material allocation and dosage

EOR POTENTIAL
Opportunities:-
• Target resource for EOR applications is 6 trillion barrels, of
the 9 trillion initially in place.
• Widespread application could far exceed the current
forecasts.
• Chemical / polymer flooding has large unrealized
potential.
• Both hydrocarbon and CO2 miscible flooding have large
potential internationally.
• A significant resource exists in the offshore, as well as
onshore .
• CO2 sequestration may provide an additional impetus and
opportunity.

WHY EOR IS NEEDED NOW?
• Design and implementation of an EOR project takes time.
• After implementation (especially as a tertiary project) production
response does not occur immediately.
EOR Project Time Line

EOR TECHNIQUES
1. Gas Injection
• Carbon Dioxide Flooding
• Miscible Solvent(LPG or Propane)
• Enriched Gas Drive
• High-Pressure Gas drive
• Inert Gas( Nitrogen)
• Flue Gas

Carbon Dioxide Flooding
• Commonly used approach.
• Aids recovery by reducing the viscosity of the
crude oil as the gas mixes with it.
• Air cannot be used to repressurize the
reservoir because the oil will quickly catch on
fire.
• Oil displacement by carbon dioxide
injection relies on the phase behaviour of the
mixtures of that gas and the crude, which are
strongly dependent on reservoir temperature,
pressure and crude oil composition.

Benefits of CO2 Flooding:-
• Injections of CO2 work with lighter gravities.
• Its production has been growing steadily, and
volumes reached 240,000 barrels a day in
2008, a tenfold increase from 28,000 barrels a
day in 1986.
• WAG is frequently used in carbon dioxide
flooding to increase sweep efficiency and
decrease the need for expensive solvents.

Cost of CO2 Flooding:-
• Adding oil recovery methods adds to the cost
of oil — in the case of CO2 typically between
0.5-8.0 US$ per tonne of CO2.
• Onshore EOR has paid in the range of a net
10-16 US$ per tonne of CO2 injected for oil
prices of 15-20 US$/barrel.
• With oil prices at around 90 US$/barrel, the
economic benefit is about 70 US$ per tonne
CO2.

Benefits of Inert gas flooding:-
• Availability and low cost.
• Prevention of oil encroachment into the gas
cap when gas cap is present.
• Higher recoveries compared to water drive in
reservoirs having low permeability.
• Residual inert gas at abandonment rather
than saleable natural gas.
• Reliability of the supply.

2. Chemical Flooding
• Alkaline Surfactant Polymer or Caustic
flooding
• Polymer-augmented water flooding
• Surfactant flooding
-Low tension water flooding
-Micellar/Polymer(micro emulsion) flooding

Alkaline Surfactant Polymer Flooding
• ASP flooding is a form of chemical enhanced oil recovery (EOR) that
can allow operators to extend reservoir pool life and extract
incremental reserves currently inaccessible by conventional EOR
techniques such as water flooding.
• Injection of diluted alkaline or caustic solutions into oil reservoir to
improve oil recovery.
• In the polymer flooding method, water-soluble polymers increase
the viscosity of the injected water, leading to a more efficient
displacement of moderately viscous oils.
• Although no large-scale surfactant-polymer floods have been
implemented, the process has considerable potential to recover oil.
• For all chemical flooding processes, inclusion of a viscosifier (usually
a water-soluble polymer) is required to provide an efficient sweep
of the expensive chemicals through the reservoir.

Benefits of ASP Flooding:-
• It is used for oils that are more viscous than those
oils recovered by gas injection methods.
• Presently have the highest application
potential, since they are low risk methods with a well
developed application technology.
• Surfactant/polymer flooding is an immature method
from an application point of view. It will need
substantial research and development to become a
technique of any importance compared to ASP.

• The potential and feasibility of ASP flooding
continues to grow and offers much potential for
increased oil recovery.
• Achievement of 20% incremental oil recovery.
Example-Husky Taber South Mannville B Pool began
ASP flooding in 2006 and is currently ongoing.
Cost Factor:-
Application of these methods is usually limited by the
cost of the chemicals and their adsorption and loss
onto the rock of the oil containing formation.

Developments in Chemical Flooding
• Advances in surfactants:-
–Thermally stable surfactants (e.g. sulphonates)
remove temperature restrictions.
–Surfactants designed to be active at 0.1%
concentrations.
–Sacrificial agents (e.g., sodium carbonate) reduce
adsorption to very low levels.
• Alkaline flooding:-
–Alkaline-polymer (AP) and alkaline-surfactant-polymer
(ASP) are new, lower-cost EOR methods.

3. Thermal Recovery
• Steam flooding or Steam-drive
• Cyclic Steam Injection
• In-situ combustion
• Thermally assisted gas-oil gravity drainage
(TAGOGD)

Steam Flooding
• It is used to heat the crude oil in the formation to
reduce its viscosity and/or vaporize part of the
oil.
• It improves the sweep efficiency and the
displacement efficiency.
• Steam injection has been used commercially
since the 1960s in California fields.
• In 2011, Solar Thermal Enhanced Oil
Recovery projects were started in California
and Oman, this method is similar to Thermal EOR
but uses a solar array to produce the steam.

Benefits of Steam Flooding:-
• It has the greatest certainty of success and
potential application is about 70% of EOR
worldwide.
• Provides highest recoveries at the lowest cost.
• Can be used for heavy oil with a viscosity less
than 10,000 centipoises.
• Power track record to produce 15-20% of the
original oil in place.

Developments in Thermal Recovery
• Controlled Combustion:-
– Removes depth, pressure restrictions of steam
– Applicable to light oils
• Steam-Assisted Gravity Drainage (SAGD):-
– Uses horizontal wells to contact formation,
reduce well costs
– Modification of steam drive

4. Microbial Injection
• Its’ aim is to improve the recovery of oil entrapped in
porous media while increasing economic profits.
• MEOR is a tertiary oil extraction technology allowing the
partial recovery of the commonly residual two-thirds of
oil, thus increasing the life of mature oil reservoirs.
• Rarely used, both because of its higher cost and because
the developments in this field are more recent than
other techniques.
• This approach has been used in oilfields near the Four
Corners and in the Beverly Hills Oil Field in Beverly Hills,
California.

Limitations of MEOR:-
1) Increasing salinity absorbs water from the microbe and negatively affects its
growth.
2) Permeability, temperature, pressure, salinity and pH affect the selection of
microbes.
3) Study of bacteria metabolism, and relation to subsurface environment, need great
effort.
4) Microbes Produce H2S and SO2 causing bio-corrosion of the equipment, and
contamination of ground water.
But on the other hand microbes produce organic chemicals less harmful than synthetic
chemicals used by EOR methods.
Economics of MEOR:-
• Microbes and nutrients are relatively cheap materials.
• Cost is independent of oil prices.
• Implementation needs minor modifications to field facilities.
• Economically attractive for marginal producing wells.
• The total cost of incremental oil production from MEOR is only 2 – 3 $/bbl.

EOR Oil Production
(Source: OGJ EOR Survey, 2010)
Worldwide EOR Oil Production US EOR Oil Production

• U.S. EOR production is ~12% of the U.S. total
Two major contributors: Thermal recovery
using steam injection and Carbon dioxide
miscible recovery.
• Thermal recovery in
Venezuela, Indonesia, China, Canada.
• Gas injection in Canada, Venezuela, and Libya.
• Chemical/polymer applications in China.
(Source: OGJ biennial surveys)

Screening criteria for EOR Methods

EOR Methods Based on Lithology

Source: SPE 130113, Manrique E., et al; April 201

COST COMPARISON FOR VARIOUS EOR METHODS

ECONOMICS CHALLENGES
• Thermal:-
– High cost
– Greenhouse gas emissions
– Combustion - perceived high risk
• Chemical – Polymer:-
– Long lead times, long payout
– Perceived high risk
• CO2 Miscible:-
– Access to CO2
However, Long term demand and price increases
present opportunities

POLITICAL ISSUES
• NOC, IOC, Governmental Relationships can harm EOR
opportunities:-
–Mutual interests are hampered by short-term
considerations.
– Access may be lost by P&A regulations.
– Economics hampered by loss of tax incentives.
• Solution: treat EOR differently
– Jointly share technical, economic risk.
– Maintain access to wells and facilities that can be used for
EOR (don’t require premature PA).
– Revise concession terms to include life-of-project for EOR.

Case Study
• The Handil Oil Field Handil is a giant oil field in
the Mahakam Province of Indonesia,
discovered in 1974 and still operated by
'TOTAL Exploration and Production Indonesia'.

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In November 1995 a lean gas injection project
was initiated in five reservoirs. The project
boosted the production of the five large
reservoirs and altered the overall decline rate of
the field.

Oil & gas

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