Exploration and production, Sigve Hamilton Aspelund

Exploration and
production
Introduction

Super-gigant Kirkuk field
 The super-giant Kirkuk field lies in north Iraq, near the town of Kirkuk.
 The field is an elongated, northwest-southeast oriented structure over 100
kilometers long and up to 4 kilometers wide.
 The field comprises three domes. From the northwest these are the
Khurmala, Avanah and Baba domes.
 An additional dome, named Zab, further to the northwest, was thought to
be the fourth dome of the Kirkuk field but has been shown to be a separate
structure.
 The Baba and Avanah domes, separated by the Amshe saddle, comprise
the original and intended field development.

 Development of the Khurmala dome was planned in the 1980s but was
postponed and activity there has only recently resumed.
 Four reservoirs have been developed in the Kirkuk field.
 Extensive fracturing has caused the Jeribe and Euphrates formations to be
in communication with each other and the Kirkuk group, creating a single
reservoir of Oligocene to Miocene age known as the Main Limestone.
 The Kometan and Mauddud formations are also considered to be a single
reservoir.
 The remaining two reservoirs in the field are the Maastrichtian Shiranish and
Aptian Shu’aiba formations.

Kirkuk Production
 Middle Cretaceous Qamchuqa Limestone
 Upper Cretaceous Shiranish Limestone
 Eocene-Oligocene-Lower Miocene Asmari Limestone
 Limestones are highly fractured
 36-44 deg. API
 2% sulphur
 Miocene Lower Fars is cap rock

 Depositional Setting: Open to shallow marine carbonate shelf platform
 Discovered in 1927 - production started in 1934
 Water injection system - reservoir damaged
 Production today less than 500,000 BOPD
 Reserves: Original 25-40 BBO
 Has associated 8-9 TCFG BP has signed agreement with Iraq to develop the
field.
 Major problem with the KRG

 The Kirkuk field is still Iraq's largest oil field, estimated to hold over 12 billion
barrels of oil, and recently producing close to 600,000 b/d.
 About 500 wells have been drilled in the field so far.
 The Kirkuk oil field is a 100-km long and 12-km wide anticline consisting of
three domes and two saddles.
 It is located in the Zagros Simply Folded Zone (this term does not exclude
thrusting, salt diapirs, or strike slip faults).
 The 1927 discovery (Baba Gurgur # 1) was located on the Baba Dome and
produced from the Oligocene "Main limestone."

 Later drilling discovered two deeper payzones in the Cretaceous.
 The Paleogene shallow-marine carbonates represent a major change from
the Cretaceous deep-sea (flysch) sediments of the Tethys Ocean to the
purely continental sediments of the Neogene Fars Group.
 Majid and Veizer (AAPG Bulletin, July 1986) have described the
sedimentology of the Paleogene carbonate payzones in the Kirkuk field.
 These rocks were deposited in near-shore (mudstone, wackstone,
packstone and grainstone), fore-slope (packstone and grainstone) and
basinal (mudstone and wackstone) environments.
 Porosity is both primary (inter-granular and inter-skeletal) and secondary
(tectonic fractures and chemical dissolution).
 Porosity varies 4-36% and permeability ranges 50-1000 millidarcy.

Kirkuk field
 Kirkuk is a supergiant oil reservoir located in Iraq operated by North Oil
Company (NOC).
 Kirkuk began production in 1934, and 2 billion bbl of oil were produced
before water injection was implemented in 1961.
 From 1961 to 1971, 3.2 billion bbl of oil were produced under pressure
maintenance by water drive using river water.
 The 1971 production rate was approximately 1.1 million barrels of oil per day
(BOPD). Since then, the field has continued to produce large volumes of oil
by voidage-replacement water injection; however, few production details
for recent years appear in the technical literature.

Kirkuk reservoir geology
 The primary pay interval for the Kirkuk field is the 1,200-ft-thick Main Limestone.
 This interval consists of a series of extensively fractured limestones, some
porcelaneous and some dolomitized.
 These limestones were deposited in a variety of environments—back-
reef/lagoonal, fore-reef, and basinal—and have a wide range of porosity and
permeability properties.
 The oil is contained both in an extensive, extremely permeable but low-
capacity fracture system and in a low-permeability but high-capacity, matrix-
pore system.
 Also, the reservoir is underlain by a fieldwide aquifer.
 The oil gravity is approximately 36°API and was approximately 500 psi
undersaturated at the original reservoir pressure of 1,100 psia.

Ultimate recovery
 The interesting technical aspects of this type of reservoir are the determination
of the ultimate oil recovery from the matrix and the time scale of matrix oil
recovery.
 Laboratory experiments can be run using matrix rock samples to determine the
water/oil imbibition behavior; however, what matters is the actual reservoir’s
matrix/fracture interaction because the fracture density varies considerably.
 The early water injection showed that within the fracture network there was
rapid communication over a distance of more than 20 miles.
 Water injection initially was peripheral; however, because of low injectivity
caused by lack of downdip fracturing, injection was shifted to seven injection
wells in the saddle area between the two principal domes of this oil field, one of
which had an injection capacity of more than 400,000 barrels of water per day
(BWPD).

 A 90-day temporary production stoppage in 1967 allowed unique field
data to be acquired regarding the matrix/fracture interaction because of
the observed changes in the oil/water contact (OWC).
 It was observed that the OWCs fell in the areas where they were the
highest and rose in the areas where they were the lowest.
 These OWC changes were the result of the countercurrent imbibition
process between the fracture network and matrix pore system.
 From these data, the time-delay function could be calculated on the basis
of observed field data. Depending on the assumptions, the half-life was
estimated to be 3 to 5 years and the ultimate recovery was estimated at 30
to 45% of the original oil in place (OOIP).

Super gigant Kirkuk field
 The super-giant Kirkuk field lies in north Iraq, near the town of Kirkuk.
 The field is an elongated, northwest-southeast oriented structure over
100 kilometers long and up to 4 kilometers wide.
 The field comprises three domes.
 From the northwest these are the Khurmala, Avanah and Baba
domes.
 An additional dome, named Zab, further to the northwest, was
thought to be the fourth dome of the Kirkuk field but has been shown
to be a separate structure.

 The Baba and Avanah domes, separated by the Amshe saddle, comprise the
original and intended field development.
 Development of the Khurmala dome was planned in the 1980s but was
postponed and activity there has only recently resumed.
 Four reservoirs have been developed in the Kirkuk field.
 Extensive fracturing has caused the Jeribe and Euphrates formations to be in
communication with each other and the Kirkuk group, creating a single
reservoir of Oligocene to Miocene age known as the Main Limestone.
 The Kometan and Mauddud formations are also considered to be a single
reservoir.
 The remaining two reservoirs in the field are the Maastrichtian Shiranish and
Aptian Shu’aiba formations.

Oil Production Kirkuk Field
 The northern Kirkuk field, first discovered in 1927, forms the basis for northern
Iraqi Oil production.
 Kirkuk, with an estimated 8.7 billion barrels of remaining reserves, normally
produces 35°API, 1.97 percent sulfur crude, although the API Gravity and
sulfur content both reportedly deteriorated sharply in the months just
preceding the war.
 Kirkuk's gravity, for instance, had declined to around 32° -33° API, while
sulfur content had risen above 2 percent.

 Declining Crude Oil qualities and increased "water cut" (damaging
intrustion of water into oil reservoirs) were likely the result of overpumping.
 Production from Kirkuk reached as high as 680,000 bbl/d.
 Well above the field's estimated optimal production rate of 250,000 bbl/d,
as Iraq attempted to sell as much oil as possible in the months leading up to
the March/April 2003 war.

 Analysts believe that poor Reservoir management practices during the
Saddam Hussein years --including reinjection of excess fuel oil (as much as
1.5 billion barrels by one estimate), refinery residue, and gas-stripped oil --
may have seriously, even permanently, damaged Kirkuk.
 Among other problems, fuel oil reinjection has increased oil viscosity at
Kirkuk, making it more difficult and expensive to get the oil out of the
ground.

 To better understand the state of the Kirkuk reservoir, a contract was signed
in early 2005 for Exploration Consultants Ltd. and Shell to carry out an
integrated study on Kirkuk, with work scheduled to be completed by early
2006.
 This marked the first such study in three decades for Kirkuk, and is significant
in that it will use the latest technology.

Aims to double exports of Kirkuk crude
 Jan. 2015: Iraq will double exports within weeks from its northern Kirkuk oil
fields and continue boosting output farther south amid a global market glut
that’s pushed prices to their lowest level in more than five and a half years.
 Crude shipments will rise to 300,000 bbl/d from the Kirkuk oil hub, where
authorities are also upgrading pipelines between fields.
 “There is a need to install a new pipeline network” to increase exports from
the area.
 Kirkuk, which currently exports about 150,000 barrels a day, will boost
shipments to 250,000 bbl/d and then to 300,000 “in the coming few weeks”.

 Iraq, holder of the world’s fifth-largest crude reserves, is rebuilding its energy
industry after decades of wars and economic sanctions.
 The country exported 2.94 MMbbl/d in December, the most since the 1980s.
 The exports, pumped mostly from fields in southern Iraq, included 5.579
MMbbl from Kirkuk in that month.
 Oil tumbled almost 50% last year, the most since the 2008 financial crisis,
amid a global crude supply surplus that the United Arab Emirates and
Qatar estimate at 2 MMbbl/d.
 Brent crude was trading at $46.67/bbl at 3:07 p.m. in London after falling as
much as $1 on Jan. 14.

Kurdistan: An Emerging Region with
Giant Oil & Gas Field Potential

Exploration & development: Kurdistan

3 of the world`s largest fields are in Iraq

Kurdistan: High exploration potential

Atrush-1 Jurassic oil discovery

Arbat structural leads – Large surface
anticlines

Hydrocarbon exploration
 Hydrocarbon exploration: The search by petroleum
geologists and geophysicists for hydrocarbon deposits beneath the Earth's
surface (Oil and natural gas) .
 Oil and gas exploration: Grouped under the science of petroleum geology.

Exploration methods
 Visible surface features such as oil seeps, natural gas seeps, pockmarks
(underwater craters caused by escaping gas) provide basic evidence of
hydrocarbon generation (be it shallow or deep in the Earth).
 Most exploration depends on highly sophisticated technology to detect
and determine the extent of these deposits using exploration geophysics.
 Areas thought to contain hydrocarbons are initially subjected to a gravity
survey, magnetic survey, passive seismic or regional seismic reflection
surveys to detect large-scale features of the sub-surface geology.
 Features of interest (known as leads) are subjected to more detailed
seismic surveys which work on the principle of the time it takes for reflected
sound waves to travel through matter (rock) of varying densities and using
the process of depth conversion to create a profile of the substructure.

 When a prospect has been identified and evaluated and passes
the oil company's selection criteria, an exploration well is drilled
in an attempt to conclusively determine the presence or
absence of oil or gas.
 Oil exploration is an expensive, high-risk operation.
 Offshore and remote area exploration is generally only
undertaken by very large corporations or national governments.
 Typical shallow shelf oil wells (e.g. North Sea) cost US$10 – 30
million, while deep water wells can cost up to US$100 million plus.
 Hundreds of smaller companies search for onshore hydrocarbon
deposits worldwide, with some wells costing as little as
US$100,000.

Elements of a petroleum prospect
 A prospect is a potential trap which geologists believe may contain
hydrocarbons.
 A significant amount of geological, structural and seismic investigation must
first be completed to redefine the potential hydrocarbon drill location from
a lead to a prospect.

Five geological factors have to be present for a
prospect to work and if any of them fail neither oil nor
gas will be present.
 A source rock - When organic-rich rock such as oil shale or coal is
subjected to high pressure and temperature over an extended
period of time, hydrocarbons form.
 Reservoir - The hydrocarbons are contained in a reservoir rock.
This is commonly a porous sandstone or limestone. The oil collects
in the pores within the rock although open fractures within non-
porous rocks (e.g. fractured granite) may also store
hydrocarbons. The reservoir must also be permeable so that the
hydrocarbons will flow to surface during production.

 Migration - The hydrocarbons are expelled from source rock by
three density-related mechanisms: the newly matured hydrocarbons
are less dense than their precursors, which causes over-pressure; the
hydrocarbons are lighter medium, and so migrate upwards due to
buoyancy, and the fluids expand as further burial causes increased
heating. Most hydrocarbons migrate to the surface as oil seeps, but
some will get trapped.
 Trap - The hydrocarbons are buoyant and have to be trapped within a
structural (e.g. Anticline, fault block) or stratigraphic trap
 Seal or cap rock - The hydrocarbon trap has to be covered by an
impermeable rock known as a seal or cap-rock in order to prevent
hydrocarbons escaping to the surface

Exploration risk
 Hydrocarbon exploration is a high risk investment
and risk assessment is paramount for
successful project portfolio management.
 Exploration risk is a difficult concept and is usually
defined by assigning confidence to the presence of
five imperative geological factors.
 This confidence is based on data and/or models
and is usually mapped on Common Risk Segment
Maps (CRS Maps).
 High confidence in the presence of imperative
geological factors is usually coloured green and low
confidence coloured red.

 Therefore these maps are also called Traffic Light Maps, while the full
procedure is often referred to as Play Fairway Analysis.
 The aim of such procedures is to force the geologist to objectively assess all
different geological factors.
 Furthermore it results in simple maps that can be understood by non-
geologists and managers to base exploration decisions on.

Terms used in petroleum evaluation
 Bright spot - On a seismic section, coda that have high amplitudes due to a
formation containing hydrocarbons.
 Chance of success - An estimate of the chance of all the elements within a
prospect working, described as a probability.
 Dry hole - A boring that does not contain commercial hydrocarbons.
 Flat spot - Possibly an oil-water, gas-water or gas-oil contact on a seismic
section; flat due to gravity.
 Hydrocarbon in place - amount of hydrocarbon likely to be contained in
the prospect.
 This is calculated using the volumetric equation -
 GRV x N/G x Porosity x Sh / FVF

 GRV - Gross rock volume - amount of rock in the trap above the
hydrocarbon water contact
 N/G - net/gross ratio - proportion of the GRV formed by the reservoir rock (
range is 0 to 1)
 Porosity - percentage of the net reservoir rock occupied by pores (typically
5-35%)
 Sh - hydrocarbon saturation - some of the pore space is filled with water -
this must be discounted
 FVF - formation volume factor - oil shrinks and gas expands when brought
to the surface.
 The FVF converts volumes at reservoir conditions (high pressure and high
temperature) to storage and sale conditions

 Lead - Potential accumulation is currently poorly defined and requires more
data acquisition and/or evaluation in order to be classified as a prospect.
 Play - An area in which hydrocarbon accumulations or prospects of a given
type occur.
 Prospect - a lead which has been more fully evaluated.
 Recoverable hydrocarbons - amount of hydrocarbon likely to be
recovered during production. This is typically 10-50% in an oil field and 50-
80% in a gas field.

Licensing
 Petroleum resources are typically owned by the government of the host
country.
 In most nations the government issues licences to explore, develop and
produce its oil and gas resources, which are typically administered by the
oil ministry.
 There are several different types of license.
 Oil companies often operate in joint ventures to spread the risk; one of the
companies in the partnership is designated the operator who actually
supervises the work.

 Tax and Royalty - Companies would pay a royalty on any oil produced,
together with a profits tax (which can have expenditure offset against it).
 In some cases there are also various bonuses and ground rents (license
fees) payable to the government - for example a signature bonus payable
at the start of the licence.
 Licences are awarded in competitive bid rounds on the basis of either the
size of the work programme (number of wells, seismic etc.) or size of the
signature bonus.

 Production Sharing contract (PSA) - A PSA is more complex than a
Tax/Royalty system - The companies bid on the percentage of the
production that the host government receives (this may be variable with
the oil price).
 There is often also participation by the Government owned National Oil
Company (NOC).
 There are also various bonuses to be paid.
 Development expenditure is offset against production revenue.
 Service contract - This is when an oil company acts as a contractor for the
host government, being paid to produce the hydrocarbons.

Reserves and resources
 Resources are hydrocarbons which may or may not be produced in the
future.
 A resource number may be assigned to an undrilled prospect or an
unappraised discovery.
 Appraisal by drilling additional delineation wells or acquiring extra seismic
data will confirm the size of the field and lead to project sanction.
 At this point the relevant government body gives the oil company a
production licence which enables the field to be developed.
 This is also the point at which oil reserves and gas reserves can be formally
booked.

Oil and gas reserves
 Oil and gas reserves are defined as volumes that will be commercially
recovered in the future.
 Reserves are separated into three categories: proved, probable, and
possible.
 To be included in any reserves category, all commercial aspects must have
been addressed, which includes government consent.
 Technical issues alone separate proved from unproved categories.
 All reserve estimates involve some degree of uncertainty.

Proved reserves
 Proved reserves have a "reasonable certainty" of being recovered, which
means a high degree of confidence that the volumes will be recovered.
 P90: 90% certainty of being produced.

 Proved oil and gas reserves are those quantities of oil and gas, which, by
analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible
 from a given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations
 prior to the time at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation.
 The project to extract the hydrocarbons must have commenced or the operator
must be reasonably certain that it will commence the project within a
reasonable time.

 Probable reserves: Volumes "less likely to be recovered than proved. More
certain to be recovered than Possible Reserves".
 Possible reserves: Reserves which analysis of geological and engineering
data suggests are less likely to be recoverable than probable reserves.

 1P: Used to denote proved reserves
 2P: Sum of proved and probable reserves
 3P: Sum of proved, probable, and possible reserves.
 The best estimate of recovery from committed projects is generally
considered to be the 2P sum of proved and probable reserves.
 Note that these volumes only refer to currently justified projects or those
projects already in development.

Reserve booking
 Oil and gas reserves are the main asset of an oil company.
 Booking is the process by which they are added to the balance sheet.
 In the United States, booking is done according to a set of rules developed
by the Society of Petroleum Engineers (SPE).
 The reserves of any company listed on the New York Stock Exchange have
to be stated to the U.S. Securities and Exchange Commission.
 Reported reserves may be audited by outside geologists, although this is
not a legal requirement.
 In Russia, companies report their reserves to the State Commission on
Mineral Reserves (GKZ).

Extraction of petroleum
 The extraction of petroleum is the process by which usable petroleum is
extracted and removed from the earth.

Locating the oil field
 Geologists use seismic surveys to search for geological structures that may
form oil reservoirs.
 The "classic" method includes making an underground explosion nearby
and observing the seismic response that provides information about the
geological structures under the ground.
 “Passive" methods that extract information from naturally-occurring seismic
waves are also known.

 Other instruments such as gravimeters and magnetometers are also sometimes
used in the search for petroleum.
 Extracting crude oil normally starts with drilling wells into the underground
reservoir.
 When an oil well has been tapped, a geologist (known on the rig as the
"mudlogger") will note its presence.
 Such a "mudlogger" is known to be sitting on the rig.
 Often many wells (called multilateral wells) are drilled into the same reservoir, to
ensure that the extraction rate will be economically viable.
 Also, some wells (secondary wells) may be used to pump water, steam, acids or
various gas mixtures into the reservoir to raise or maintain the reservoir pressure,
and so maintain an economic extraction rate.

Drilling
 The oil well is created by drilling a long hole into the earth with an oil rig.
 A steel pipe (casing) is placed in the hole, to provide structural integrity to
the newly drilled well bore.
 Holes are then made in the base of the well to enable oil to pass into the
bore.
 Finally a collection of valves called a "Christmas Tree" is fitted to the top, the
valves regulate pressures and control flow.

Oil extraction and recovery
 Primary recovery
 During the primary recovery stage, reservoir drive comes from a number of natural
mechanisms.
 These include: natural water displacing oil downward into the well, expansion of the
natural gas at the top of the reservoir, expansion of gas initially dissolved in the crude oil,
and gravity drainage resulting from the movement of oil within the reservoir from the upper
to the lower parts where the wells are located.
 Recovery factor during the primary recovery stage is typically 5-15%.
 While the underground pressure in the oil reservoir is sufficient to force the oil to the surface,
all that is necessary is to place a complex arrangement of valves (the Christmas tree) on
the well head to connect the well to a pipeline network for storage and processing.
 Sometimes pumps, such as beam pumps and electrical submersible pumps (ESPs), are
used to bring the oil to the surface; these are known as artificial lift mechanisms.

Secondary recovery
 Over the lifetime of the well the pressure will fall, and at some
point there will be insufficient underground pressure to force
the oil to the surface.
 After natural reservoir drive diminishes, secondary
recovery methods are applied.
 They rely on the supply of external energy into the reservoir in
the form of injecting fluids to increase reservoir pressure, hence
replacing or increasing the natural reservoir drive with an
artificial drive.
 Secondary recovery techniques increase the reservoir's
pressure by water injection, natural gas reinjection and gas lift,
which injects air, carbon dioxide or some other gas into the
bottom of an active well, reducing the overall density of fluid
in the wellbore.

 Typical recovery factor from water-flood operations is about 30%,
depending on the properties of oil and the characteristics of the reservoir
rock.
 On average, the recovery factor after primary and secondary oil recovery
operations is between 35 and 45%.
 The injection process requires power, but installing gas turbines on offshore
platforms means shutting down the extraction process, losing valuable
income.

Enhanced recovery
 Enhanced, or Tertiary oil recovery methods increase the mobility of the oil in order to
increase extraction.
 Thermally enhanced oil recovery methods (TEOR) are tertiary recovery techniques that
heat the oil, thus reducing its viscosity and making it easier to extract.
 Steam injection is the most common form of TEOR, and is often done with
a cogeneration plant.
 In this type of cogeneration plant, a gas turbine is used to generate electricity and the
waste heat is used to produce steam, which is then injected into the reservoir.
 This form of recovery is used extensively to increase oil extraction in the San Joaquin Valley,
which has very heavy oil, yet accounts for 10% of the United States' oil extraction.
 Fire flooding (In-situ burning) is another form of TEOR, but instead of steam, some of the oil
is burned to heat the surrounding oil.

 Occasionally, surfactants (detergents) are injected to alter the surface
tension between the water and oil in the reservoir, mobilizing oil which
would otherwise remain in the reservoir as residual oil.
 Another method to reduce viscosity is carbon dioxide flooding.
 Tertiary recovery allows another 5% to 15% of the reservoir's oil to be
recovered.
 In some California heavy oil fields, steam injection has doubled or even
tripled the oil reserves and ultimate oil recovery.
 For example, see Midway-Sunset Oil Field, California's largest oilfield.

 Tertiary recovery begins when secondary oil recovery isn't enough to continue
adequate extraction, but only when the oil can still be extracted profitably.
 This depends on the cost of the extraction method and the current price of
crude oil.
 When prices are high, previously unprofitable wells are brought back into use
and when they are low, extraction is curtailed.
 Microbial treatments is another tertiary recovery method.
 Special blends of the microbes are used to treat and break down the
hydrocarbon chain in oil thus making the oil easy to recover as well as being
more economic versus other conventional methods.
 In some states, such as Texas, there are tax incentives for using these microbes
in what is called a secondary tertiary recovery.
 Very few companies supply these, however companies like Bio Tech, Inc. have
proven very successful in waterfloods across Texas.

Recovery rates and factors
 The amount of oil that is recoverable is determined by a number of factors
including the permeability of the rocks, the strength of natural drives (the
gas present, pressure from adjacent water or gravity), and the viscosity of
the oil.
 When the reservoir rocks are "tight" such as shale, oil generally cannot flow
through but when they are permeable such as in sandstone, oil flows freely.
 The flow of oil is often helped by natural pressures surrounding the reservoir
rocks including natural gas that may be dissolved in the oil (see Gas oil
ratio), natural gas present above the oil, water below the oil and the
strength of gravity.

 Oils tend to span a large range of viscosity from liquids as light as gasoline
to heavy as tar.
 The lightest forms tend to result in higher extraction rates.
 Petroleum engineering is the discipline responsible for evaluating which well
locations and recovery mechanisms are appropriate for a reservoir and for
estimating recovery rates and oil reserves prior to actual extraction.

Estimated ultimate recovery
 Although ultimate recovery of a well cannot be known with certainty until
the well ceases production, petroleum engineers will often estimate
an estimated ultimate recovery (EUR) based on decline rate projections
years into the future.
 Various models, mathematical techniques and approximations are used.
 Shale gas EUR is difficult to predict and it is possible to choose recovery
methods that tend to underestimate decline of the well beyond that which
is reasonable.

The origins of oil and gas and how they are
formed
 Kerogen is the lipid-rich part of organic matter that is insoluble in common
organic solvents (lipids are the more waxy parts of animals and some plants).
 The extractable part is known as bitumen.
 Kerogen is converted to bitumen during the maturation process.
 The amount of extractable bitumen is a measure of the maturity of a source
rock.
 Bitumen becomes petroleum during migration.
 Petroleum is the liquid organic substance recovered in wells.

formed
 Crude oil is the naturally occurring liquid form of petroleum.
 Petroleum generation takes place as the breakdown of kerogen occurs with
rising temperature.
 Temperature and time are the most important factors affecting the breakdown
of kerogen.

formed
 As formation temperature rises on progressive burial an immature stage is
succeeded by stages of oil generation, oil conversion to gas or cracking (to
make a wet gas with significant amounts of liquids) and finally dry gas (i.e.,
no associated liquids) generation.

Conventional Oil and Gas
 Conventional oil is a mixture of mainly pentanes and heavier
hydrocarbons recoverable at a well from an underground reservoir and
liquid at atmospheric pressure and temperature.
 Unlike bitumen, conventional oil flows through a well without stimulation
and through a pipeline without processing or dilution.
 Conventional oil production is now in the final stages of depletion in most
mature oil fields.
 There is a need to implement advanced methods of oil recovery to maximize
the production and to extend the economic life of the oil fields.

Unconventional oil
 Unconventional oil is petroleum produced or extracted using techniques other
than the conventional (oil well) method.
 Oil industries and governments across the globe are investing in
unconventional oil sources due to the increasing scarcity of conventional oil
reserves.
 Although the depletion of such reserves is evident, unconventional oil
production is a less efficient process and has greater environmental impacts
than that of conventional oil production.

Sources of unconventional oil
 According to the International Energy Agency's Oil Market
Report unconventional oil includes the following sources:
 Oil shales
 Oil sands-based synthetic crudes and derivative products
 Coal-based liquid supplies
 Biomass-based liquid supplies
 Liquids arising from chemical processing of natural gas

Sedimentary basins and the dynamic nature
of Earth’s crust
What are sedimentary basins?
 Sedimentary basins are regions where considerable thicknesses of sediments
have accumulated.
 Sedimentary basins are widespread both onshore and oﬀshore.
 The way in which they form was a matter of considerable debate until the last
20 years.
 The advance in our understanding during this very short period is mainly due
to the eﬀorts of the oil industry.

Sedimentary basins and the dynamic nature of
Earth’s crust

Earth’s crust
 Basin classification schemes
 Extensional basins, strike-slip basins, flexural basins, basins associated with
subduction zones, mystery basins.
 There are many different classification schemes for sedimentary basins but
most are unwieldy and use rather spurious criteria.
 The most useful scheme (presented here) is very simple and is based on basin
forming mechanisms.
 About 80% of the sedimentary basins on Earth have formed by extension of
the plates (often termed lithospheric extension).

Earth’s crust
 Most of the remaining 20% of basins were formed by ﬂexure of the plates
beneath various forms of loading (this class will be covered in the next
lecture).
 Pull-apart or strike-slip basins are relatively small and form in association
with bends in strike-slip faults, such as the San Andreas Fault or the North
Anatolian Fault.
 Only a very small number of basins still defy explanation, although we
suspect that at least some of these have a thermal origin.

Sedimentary basin
 A depression in the crust of the Earth formed by plate tectonic activity in
which sediments accumulate.
 Continued deposition can cause further depression or subsidence.
 Sedimentary basins, or simply basins, vary from bowl-shaped to elongated
troughs.
 If rich hydrocarbon source rocks occur in combination with appropriate depth
and duration of burial, hydrocarbon generation can occur within the basin.

Sedimentary
 One of the three main classes of rock (igneous, metamorphic and
sedimentary).
 Sedimentary rocks are formed at the Earth's surface through deposition of
sediments derived from weathered rocks, biogenic activity or
precipitation from solution.
 Clastic sedimentary rocks such as conglomerates, sandstones, siltstones and
shales form as older rocks weather and erode, and their particles accumulate
and lithify, or harden, as they are compacted and cemented.
 Biogenic sedimentary rocks form as a result of activity by organisms,
including coral reefs that become limestone.

Sedimentary
Precipitates, such as the evaporite minerals halite (salt) and gypsum
can form vast thicknesses of rock as seawater evaporates.
Sedimentary rocks can include a wide variety of minerals, but quartz,
feldspar, calcite, dolomite and evaporite group and clay group minerals
are most common because of their greater stability at the Earth's
surface than many minerals that comprise igneous and metamorphic
rocks.
Sedimentary rocks, unlike most igneous and metamorphic rocks, can
contain fossils because they form at temperatures and pressures that do
not obliterate fossil remnants.

Illustration of the rock cycle

Concepts of finite resources and limitations
on recovery
The Hubbert peak theory posits that for any given geographical
area, from an individual oil-producing region to the planet as a
whole, the rate of petroleum production tends to follow a bell-
shaped curve.
It is one of the primary theories on peak oil.
Choosing a particular curve determines a point of maximum
production based on discovery rates, production rates and
cumulative production.
Early in the curve (pre-peak), the production rate increases because
of the discovery rate and the addition of infrastructure.
Late in the curve (post-peak), production declines because of
resource depletion.

The Hubbert peak theory is based on the observation that
the amount of oil under the ground in any region is finite,
therefore the rate of discovery which initially increases
quickly must reach a maximum and decline.
In the US, oil extraction followed the discovery curve
after a time lag of 32 to 35 years.
The theory is named after American geophysicist M. King
Hubbert, who created a method of modeling the
production curve given an assumed ultimate recovery
volume.

M. King Hubbert's original 1956 prediction of
world petroleum production rates

Global distribution of fossil fuels and OPEC’s
resource endowment
Reserves Around the World
While most of the known oil and gas reserves are held in the
Middle East, they can be found in many places around the
world, such as Australia, Italy, Malaysia and New Zealand.
The leading petroleum producers include Saudi Arabia, Iran,
Iraq, Kuwait and the United Arab Emirates.
Oil is also produced in Russia, Canada, China, Brazil, Norway,
Mexico, Venezuela, Great Britain, Nigeria and the United
States — chiefly Texas, California, Louisiana, Oklahoma,
Kansas and Alaska.
Offshore reservoirs have been discovered in the North Sea,
Africa, South America and the Gulf of Mexico.

Components that constitute natural gas
Natural gas is a naturally occurring gas mixture
consisting primarily of methane, typically with 0–20%
higher hydrocarbons (primarily ethane).
 It is found associated with other hydrocarbon fuel,
in coal beds, as methane clathrates, and is an
important fuel source and a major feedstock
for fertilizers.
Most natural gas is created by two mechanisms:
biogenic and thermogenic.
Biogenic gas is created by
methanogenic organisms in marshes, bogs, landfills,
and shallow sediments.

• Deeper in the earth, at greater temperature
and pressure, thermogenic gas is created
from buried organic material.
• Before natural gas can be used as a fuel, it
must undergo processing to remove almost all
materials other than methane.
• The by-products of that processing include:
ethane, propane, butanes, pentanes, and
higher molecular weight hydrocarbons,
elemental sulfur, carbon dioxide, water
vapor, and sometimes helium and nitrogen.
• Natural gas is often informally referred to as
simply gas, especially when compared to
other energy sources such as oil or coal.

BP Statistical Review of World Energy
June 2014

Oil: Distribution of proved reserves

Production and consumption by
region

An introduction to petroleum geology
 Sedimentology
 The great majority of hydrocarbon reserves worldwide occur in
sedimentary rocks.
 It is therefore vitally important to understand the nature and distribution
of sediments as potential hydrocarbon source rocks and reservoirs.
 Two main groups of sedimentary rocks are of major importance as
reservoirs, namely siltstones and sandstones (‘clastic’ sediments) and
limestones and dolomites (‘carbonates’).
 Although carbonate rocks form the main reservoirs in certain parts of
the world (e.g. in the Middle East, where a high proportion of the
world’s giant oilfields are reservoired in carbonates), clastic rocks form
the most significant reservoirs throughout most of the world.

CLASSIFICATION OF SEDIMENTARY ROCKS

Texture in Granular Sediments
 The main textural components of granular rocks include:
 grain size
 grain sorting
 packing
 sediment fabric
 grain morphology
 grain surface texture

Sand and sandstone
 Sands are defined as sediments with a mean grain size between 0.0625
and 2 mm which, on compaction and cementation will become
sandstones.
 Sandstones form the bulk of clastic hydrocarbon reservoirs, as they
commonly have high porosities and permeabilities.
 Sandstones are classified on the basis of their composition
(mineralogical content) and texture (matrix content).
 The most common grains in sandstones are quartz, feldspar and
fragments of older rocks.
 These rock fragments may include fragments of igneous, metamorphic
and older sedimentary rocks.

Classification of sands and sandstones

Porosity
 Total porosity (φ) is defined as the volume of void (pore) space within a
rock, expressed as a fraction or percentage of the total rock volume.
 It is a measure of a rock’s fluid storage capacity.
 The effective porosity of a rock is defined as the ratio of the
interconnected pore volume to the bulk volume
 Microporosity (φm) consists of pores less than 0.5 microns in size,
whereas pores greater than 0.5 microns form macroporosity (φM)

Permeability
 The permeability of a rock is a measure of its capacity to transmit a
fluid under a potential gradient (pressure drop).
 The unit of permeability is the Darcy, which is defined by Darcy’s Law.
 The millidarcy (1/1000th Darcy) is generally used in core analysis.

Controls on Porosity and Permeability
 The porosity and permeability of the sedimentary rock depend on both
the original texture of a sediment and its diagenetic history.

Grain size
 In theory, porosity is independent of grain size, as it is merely a measure of
the proportion of pore space in the rock, not the size of the pores.
 Porosity tends to increase with decreasing grain size for two reasons.
 Finer grains, especially clays, tend to have less regular shapes than coarser
grains, and so are often less efficiently packed.
 Also, fine sediments are commonly better sorted than coarser sediments.
 Both of these factors result in higher porosities.
 For example, clays can have primary porosities of 50%-85% and fine sand
can have 48% porosity whereas the primary porosity of coarse sand rarely
exceeds 40%.
 Permeability decreases with decreasing grain size because the size of
pores and pore throats will also be smaller, leading to increased grain
surface drag effects.

Porosity: Function of grain size and
sorting

 Grain Shape
 The more unequidimensional the grain shape, the greater the porosity
 As permeability is a vector, rather than scalar property, grain shape will affect the
anisotropy of the permeability.
 The more unequidimensional the grains, the more anisotropic the permeability tensor.
 Packing
 The closer the packing, the lower the porosity and permeability
 Fabric
 Rock fabric will have the greatest influence on porosity and permeability when the
grains are non spherical (i.e. are either disc-like or rod-like).
 In these cases, the porosity and permeability of the sediment will decrease with
increased alignment of the grains.
 Grain Morphology and Surface Texture
 The smoother the grain surface, the higher the permeability

Diagenesis (e.g. Compaction, Cementation)
 Diagenesis is the totality of physical and chemical processes
which occur after deposition of a sediment and during burial
and which turn the sediment into a sedimentary rock.
 The majority of these processes, including compaction,
cementation and the precipitation of authigenic clays, tend to
reduce porosity and permeability, but others, such as grain or
cement dissolution, may increase porosity and permeability.
 In general, porosity reduces exponentially with burial depth, but
burial duration also an important criterion.
 Sediments that have spent a long time at great depths will tend
to have lower porosities and permeabilities than those which
have been rapidly buried.

Changes of porosity with burial depth

Reservoir Rock & Source Rock Types:
Classification
 Reservoir rock: A permeable subsurface rock that contains petroleum.
 Must be both porous and permeable.
 Source rock: A sedimentary rock in which petroleum forms.

 Reservoir rocks are dominantly sedimentary (sandstones and
carbonates); however, highly fractured igneous and metamorphic
rocks have been known to produce hydrocarbons, albeit on a much
smaller scale
 Source rocks are widely agreed to be sedimentary
 The three sedimentary rock types most frequently encountered in oil
fields are shales, sandstones and carbonates
 Each of these rock types has a characteristic composition and texture
that is a direct result of depositional environment and post-depositional
(diagenetic) processes (i.e., cementation, etc.)
 Understanding reservoir rock properties and their associated
characteristics is crucial in developing a prospect

Shales: Source rocks and seals
 Description
 Distinctively dark-brown to black in color (occasionally a deep
dark green), occasionally dark gray, with smooth lateral surfaces
(normal to depositional direction)
 Properties
 Composed of clay and silt-sized particles
 Clay particles are platy and orient themselves normal to induced
stress (overburden); this contributes to shale`s characteristic
permeability
 Behave as excellent seals
 Widely regarded to be the main source of hydrocarbons due to
original composition being rich in organics
 A weak rock highly susceptible to weathering and erosion

• History:
• Deposited on river floodplaing, deep oceans, lakes or lagoons
• Occurrence:
• The most abundant sedimentary rock (about 42%)

Sandstones and Sandstone Reservoirs
Description:
 Composed of sand-sized particles
 Recall that sandstones may contain textural features indicative of the environment in which they
were deposited: ripple marks (alluvial/fluvial), cross-bedding (alluvial/fluvial or eolian),
gradedbedding (turbidity current)
 Typically light beige to tan in color; can also be dark brown to rusty red
Classification:
Sandstones can be further classified according to the abundance of grains of a particular
chemical composition (i.e., common source rock); for example, an arkosic sanstone (usually
abbreviated: ark. s.s.) is a sandstone largely composed of feldspar (feldspathic) grains
 Sandstones composed of nearly all quartz grains are labeled quartz sandstones (usually
abbreviated: qtz. s.s.)
Properties:
 Sandstone porosity is on the range of 10-30%
 Intergranular porosity is largely determined by sorting (primary porosity)
 Poorly indurated sandstones are referred to as fissile (easily disaggregated when scratched),
whereas highly indurated sandstones can be very resistant to weathering and erosion

Sandstone and sandstone reservoirs
 Sandstones are deposited in a number of different environments. These can include
deserts (e.g., wind-blown sands, i.e., eolian), stream valleys (e.g., alluvial/fluvial), and
coastal/transitional environments (e.g., beach sands, barrier islands, deltas, turbidites)
 Because of the wide variety of depositional environments in which sandstones can be
found, care should be taken to observe textural features (i.e., grading, cross-bedding,
etc.) within the reservoir that may provide evidence of its original diagenetic environment
 Knowing the depositional environment of the s.s. reservoir is especially important in
determining reservoir geometry and in anticipating potentially underpressured (commonly
found in channel sandstones) and overpressured reservoir conditions
 Occurrence:
 Are the second most abundant (about 37%) sedimentary rock type of the three
(sanstones, shales, carbonates), the most common reservoir rock, and are the second
highest producer (about 37%)
 Geologic Symbol:
 Dots or small circles randomly distributed; to include textural features, dots or circles may
be drawn to reflect the observation (for example, cross-bedding)

Carbonate and carbonate reservoirs
 Grains (clasts) are laregly the skeletal or shell remains of shallow
marine dwelling organisms, varying in size and shape, that either
lived on the ocean bottom (benthic) or floated in water column
(nerithic)
 Many of these clasts can be identified by skilled paleontologists
and micropaleontologists and can be used for correlative
purposes or age range dating; also beneficial in establishing
index fossils for marker beds used in regional stratigraphic
correlations
 Dolomites are a product of solution recrystallization of limestones
 Usually light or dark gray, abundant fossil molds and casts, vuggy
(vugular) porositity

 Classification:
 Divided into limestones (Calsium carbonate-CaCO3) and dolomites
(Calcium magnesium carbonate – CaMg(CO3)2)
 Limestones can be divided further into mudstones, wackenstones,
packstones, grainstones and boundstones according to the limestones
depositional texture

 Properties:
 Porosity is largely a result of dissolution and fracturing (secondary porosity)
 Carbonates such as coquina are nearly 100% fossil fragments (largely primary porosity)
 Are characteristically hard rocks, especially dolomite
 Susceptible to dissolution weathering
 History:
 Limestone reservoirs owe their origin exclusively to shallow marine depositional environments (lagoons, atolls, etc)
 Limestone formations slowly accumulate when the remains of calcareous shelly marine organisms (brachiopods,
bivalves, foramaniferans) and coral and algae living in a shallow tropical environment settle to the ocean bottom
 Over large geologic time scales these accumulations can grow to hundreds of feet thick (El Capitan, a Permian reef
complex, in West Texas is over 600 ft thick)
 Occurrence:
 Are the least geologically abundant (about 21%) of the three (shales, sandstones, carbonates), but the highest
producer (about 61.5%)
 Geologic Symbol:
 Limestone – layers of uniform rectangles, each layer offset from that above it.
 Dolomite – layers of uniform rhomboids, each layer offset from that above it.

Links
 Iraq: Oil production struggles
 Iraq: Oil and Gas Part 2
 Fault Lines - On the brink: Iraq, Kurdistan and the Battle for Kirkuk
 Iriaqi news: Kirkuk
 Geology and geophysics in oil exploration
 Petroleum: Geology & Exploration
 CNN: Global oil reserves
 10 Countries With The Largest Oil Reserves
 Horizontal Drilling and Hydraulic Fracturing

Exploration
System Technology Awareness Training

Development stages
Decision process for investment projects
Project Development Process
Start Business
Development
/
Planning
studies
Start
Concept
Studies
Start
FEED/Pre-
Engineerin
g
PDO
Start Development
Start Operation
Operation 1y
Source;The Statoil Book

Reservoir
 What is a petroleum reservoir?
 A subsurface accumulation of hydrocarbons contained in porous rock
formations
 Originates from sedimentation of organic matter
 Trapped by overlying impermeable rock formation barriers
http://mpgpetroleum.c
om

Exploring for oil and gas
 Elements of a
hydrocarbon prospect
 Source rock
 Migration
 Reservoir
 Trap
 Seal
 Probability of discovery
 Product of probabilities
for all above elements
of a hydrocarbon
prospect

Exploration technologies
 Satellite imaging
 Gravity and
magnetic methods
 Seismic
 Electromagnetic
surveys
 Sedimentology
 Geochemistry
 Regional
knowledge
 etc.....

Typical prospect portfolio
Which prospect to
drill?
 Probability for
discovery vs.
volume
 Market
 Field development
 Region
 Strategic fit
Pdisc
Volume
Gas prospect
Oil prospect

Exploration drilling
Polar Pioneer
Illustration: TGS Nopec

Well architecture
30/36”
conductor
18 5/8”
casing
12 1/4”
casing
9 5/8” casing

Exploration well
Data acquisition
 Coring
 Formation logging
 Density
 Resistivity
 Gamma Ray radiation
 Sonic velocities
 Drill cuttings sampling
 Biostratigraphy
 Pressure points
 Fluid sampling

Exploration well
Data acquisition – Pressure measurements
 Reservoir pressure important
design input
 Pressure points can help
estimate fluid contacts in
the reservoir
 Pressure points can show
whether different reservoir
zones are in communication

Exploration well
Data acquisition – Downhole fluid sampling
 Oil and gas
 Gravity, Gas Oil Relationship,
composition
 Pressure Volume Temperature
(PVT) characterization
 Water
 Ion composition
 Dissolved gases
– Flow assurance
(scale potential)
– Material selection
– Estimation of
originally in place
volumes
– Flow assurance (wax,
asphaltenes,
hydrates)
– Material selection

Reservoir description and analysis
 Geophysicists interpret seismic data and provide structural framework
based on a conceptual geological understanding
 Geologists interpret well data (cores, logs, pressurepoints, PVT data) and fills
the framework with rock properties and initial fluid saturations – derived
from logs, cores, biostratigraphy etc.

Static reservoir model
167
A A‘
The static reservoir model is used to
predict Initial In-place volumes
Basis for dynamic reservoir simulator
Basis for detailed well planning, finding
the optimum well placement

Dynamic reservoir model
 Reservoir engineers build a dynamic
reservoir model based on structure and
properties in geomodel
 Dynamic behaviour of the specific
fluids implemented
 Well hydraulics
 Practical use of the dynamic model
 Evaluating reservoir drainage
strategy
 Optimising number of wells
 Optimising well location
 Establishing reserves and production
profiles = the income in a field
development project

Reservoir types
 Sandstone reservoirs
 Formed of grains of quartz which are cemented together
 Moderate to high porosity (~20%)
 Examples: Oseberg, Gullfaks, Ormen Lange
 Carbonate reservoirs
 Chemical precipitation from water saturated with calcium
carbonate
 Biochemical from marine organisms (shells, reefs, algae)
 Chalk
High porosity (40-50%)
Complex structure
Low to very low permeability
Examples: Ekofisk, Valhall

Reservoir types (2)
 Pre-salt and Sub-salt:
 Reservoir formations
located below a salt layer
 Seismic imaging
challenges
 Challenge to drill through
a thick layer of salt
 The pre-salt environment is
often corrosive with
significant amounts of
carbon dioxide (CO2) and
hydrogen sulfide (H2S)
present
 Locations
Brazil
Gulf of Mexico
Angola

Questions
 What are the main elements of a hydrocarbon prospect?
 What role can field development work play in the exploration phase?
 Why is sampling and analysis of reservoir fluids important from a field
development perspective?

Oil recovery
 Recovery factor = Recoverable volumes/Volumes in place
 The recovery factor depends on
 Reservoir quality
 Oil viscocity
 Drive mechanisms
 Well design
 Well density
 Wellhead pressure
 etc.

Oil Recovery
Reservoir quality
Porosity - The percentage of void space in the
rock
Permeability - The rocks ability to transmit
fluids
http://mpgpetroleum.com
http://www.netl.doe.g
ov

Oil recovery
Viscosity
Viscosity describes a fluid’s resistance to
flow
The higher viscosity, the more energy is
required to extract the oil from the pores
http://deshichem.en.alibaba.com/

Oil recovery
Drive mechanisms
 Primary recovery
 Natural drive (aquifer drive and/or gas expansion)
 Pure pressure depletion
 Secondary recovery
 Gas injection
 Water injection
 WAG/SWAG
 Artificial lift
 Tertiary recovery (Enhanced Oil Recovery)
 Thermal methods -> Reduce viscosity
 Microbial methods -> Reduce viscosity
 Surfactant -> Improve sweep

Natural drive
 Natural water drive and/or gas drive
 Requires large active water zones or large gas caps
 Can give high oil recovery factors
 Example from North Sea: Troll Oil

Pure pressure depletion
 Best suited for gas reservoirs, gas recovery ~ 80 %
 Oil recovery: 5 – 15%
 Examples:
 Tune, Kristin, Vega (gas-condensates)
 Oseberg Delta (oil and gas)
Gas
producer

Gas injection
 Maintains reservoir pressure
 Improves sweep
 Can reduce viscosity
 Oil recovery: 40 - 60%
 Example from North Sea: Oseberg
 Pro: Gives high recovery
 Con: Cost and availability of gas, cost of facilities (requires
high injection pressure on platform)
Oil producerGas
injector

Water injection
 Maintains reservoir pressure
 Improves sweep
 Oil recovery: 30 - 40%
 Examples from North Sea: Gullfaks, Stjerne
 Pro: Low cost, availability of water
 Con: Risk of formation damage, corrosion
Oil
producer
Water
injector

Oil recovery
Artificial lift
When reservoir pressure drops,
the wells may not flow
naturally
Wells can be completed with
 Gas lift
 Gas injected into well
via annulus between
production tubing and
casing
 Electric Submersible Pumps
Pressure
TrueVerticalDepth
Reservoir
Gas lift
valve

P,T
ΔP venturi, Density
ICV
Gaslift
Surface
Controlled
Subsurface Safety
Valve
Oil recovery
Well design
 Vertical vs. Horizontal
 Single wellbore vs.
Multilateral
 Inflow Control
 Sand control
 Artificial lift
 Tubing size

Oil recovery
Well density
Number of wells
Reserves

Oil recovery
Wellhead pressure
Wells
Pipeline
Riser
Near well reservoir
Topside

“Flow assurance” refers to ensuring
successful and economical flow of your
wellstream from reservoir to the point of
sale
Flow assurance
 System pressure drop
 Hydrate
 Wax
 Scale
 BaSO4
 CaCO3
 Sand
 Asphaltenes
 Vibrations

Flow assurance
System pressure drop
Multiphase flow simulations to
recommend flowline sizes and evaluate
system pressure drop
Optimize Field Architecture
Evaluation of artificial lift and processing

Flow assurance
Hydrates
Free water and HC
gas will under
certain pressure
and temperature
conditions form
hydrates
Model of a methane molecule
enclosed in water-molecule
“cage.”
Add hydrate
inhibitor
Example of a hydrate equilibrium
curve

Flow assurance
How to avoid hydrates?
 Keep temperature high
 Thermal insulation
 Direct Electrical
Heating
 Avoid high pressure
 Depressurization of
pipelines
 Remove hydrate
”ingredients”
 Stable oil circulation
 Use of hydrate inhibitors
(MeOH, MEG)
Deepwater field
Long tieback distance

Flow assurance
Chemical injection
 Umbilical x-section

Gas lift
IPR over Pb
Q
Q = PI (Pr - Pbh) PI = ------------- or Pr=(1/PI)Q+Pbh
Pr – Pbh (y=ax+b) linear equation
kh(Pav - Pbh)
qo = ----------------------------------- (Darcy)
141.2  oBo.[ln(re/rw) - 3/4]

IPR below Pb
Pr-Pbh=aQ^2+bQ (Jones)
eller
Pr=aQ^2+bQ+Pbh
(y=ax^2+bx+c) kvadradisk polynom

Optimizing oil production
 Q = PI (Pr - Pbh):
 PI : Scale squeeze to reduce scaling (BaSo4)
 Pr: Water and gas injection
 Lower Pbh
 Reduce density in tubing (Pbh=ρgh)
 Reduce water cut WC: Water is heavier than oil: Increasing WC -> bottom hole pressure
 Perforations
 WSO:
 Sementing, sand plugs og calsium karbonat
 ”Packer” eller ”bridge plugg”
 Resins
 Foam, emulsions or micro organisms
 Polymer threatment
 DPR
 Side track drilling
 Gas lift

Production with gas lift
INJECTION GAS
Q
(IPR)
(VLP)
(Vertical Lift Performance Relationship)
PbhPr
(Inflow Performance Relationship)

Prosper: PVT, IPR, VLP & COMPLETION

IPR: Prosper plot well A-9A
Pb=203.5barg
Pr=aQ^2+bQ+Pbh < Pb (Jones)
Pr=(1/PI)Q+Pbh > PbPr=223.5barg

Pressure loss
Pressure loss:
A. Acceleration
B. Gravitation
C. Friction
P/Ztotal = g/gccos + fv2
/2gcd + v/gc[P/Z]
TOTAL
Pressure diff.
Gravitation AccelerationFriction

Pressure loss
Nær overflaten
Gravitasjon
Friksjon
Akselerasjon
Nær reservoaret
Gravitasjon
Friksjon
Akselerasjon

VLP+IPR: Prosper plot A-9 A: WC=63%
Pbh
Qo

WHP variations +/- 10 barg >Qo -
/+~30Scm/d
.
ΔPbh
ΔPbh
ΔQo ΔQo

Gas lift variations: +/- 10 MScm/d > Qo +/-~10 Scm/d
Increase gas lift -> Increase production. Lower gas lift -> Lower production

Oil rate vs gas lift rate
Gas lift 54MScm/d ->200 Scm/d oil

Simulation: Increased gas lift in A-9 ->
more oil

GAP: Open choke i A-1
Increased oil production

Sucker-rod lift
 Beam-pumping systems
 Beam pumping, or the sucker-rod lift method, is the oldest and most widely
used type of artificial lift for most wells.
 A sucker-rod pumping system is made up of several components, some of
which operate aboveground and other parts of which operate
underground, down in the well.
 The surface-pumping unit, which drives the underground pump, consists of
a prime mover (usually an electric motor) and, normally, a beam fixed to a
pivotal post.
 The post is called a Sampson post, and the beam is normally called a
walking beam.

 Schematic of a beam-pumping systemSchematic of conventional pumping unit with major
components of the sucker-rod-lift system.

Electrical submersible pumps
 The electrical submersible pump, typically called an ESP, is an efficient and
reliable artificial-lift method for lifting moderate to high volumes of fluids
from wellbores. These volumes range from a low of 150 B/D to as much as
150,000 B/D (24 to 24,600 m3/d). Variable-speed controllers can extend this
range significantly, both on the high and low side. The ESP’s main
components include:
 Multistaged centrifugal pump
 Three-phase induction motor
 Seal-chamber section
 Power cable
 Surface controls

ESP system configuration Schematic of typical ESP system

Advantages
 ESPs provide a number of advantages.
 Adaptable to highly deviated wells; up to horizontal, but must be set in straight section.
 Adaptable to required subsurface wellheads 6 ft apart for maximum surface-location
density.
 Permit use of minimum space for subsurface controls and associated production facilities.
 Quiet, safe, and sanitary for acceptable operations in an offshore and environmentally
conscious area.
 Generally considered a high-volume pump.
 Provides for increased volumes and water cuts brought on by pressure maintenance and
secondary recovery operations.
 Permits placing wells on production even while drilling and working over wells in immediate
vicinity.
 Applicable in a range of harsh environments.

Disadvantages
 ESPs have some disadvantages that must be considered.
 Will tolerate only minimal percentages of solids (sand) production, although
special pumps with hardened surfaces and bearings exist to minimize wear
and increase run life.
 Costly pulling operations and lost production occur when correcting
downhole failures, especially in an offshore environment.
 Below approximately 400 B/D, power efficiency drops sharply; ESPs are not
particularly adaptable to rates below 150 B/D.
 Need relatively large (greater than 4½-in. outside diameter) casing size for
the moderate- to high-production-rate equipment.
 Long life of ESP equipment is required to keep production economical.

Links
 PCS Gas Lift
 Sucker Rod Pump Principles
 ESP Electric submersible pump

Footer 221
Reservoir
How A Well Is Drilled

Footer 222
Template
36” Drill Bit
Reservoir
Drill pilot hole

Footer 223
Cement
Template
1. Install 30” conductor with guide base
2. Cement 30” conductor

Footer 224
Template
26” Drill bit
Drill out for wellhead housing

Footer 225
Template
Wellhead housing
18 ¾” wellhead housing
Running tool
Install 18 ¾” wellhead housing

Footer 226
Template
Wellhead
connector
Install BOP

Footer 227
Template
Mud circulation
Formation
pressure
Mud hydrostatic
pressure
Drill out for 13 3/8” casing

Footer 228
CCC
Template
Casing Hanger
13 3/8” casing
Single Trip Tool
Seal assy.
1. Install 13 3/8” casing hanger
2. Cement
3. Install 18 ¾” seal assy

Footer 229
Template
12” drill bit
Drill out for 10 ¾” casing

Footer 230
Template
10 ¾” casing
10 ¾” Casing hanger
1. Install 10 ¾” casing
2. Cement
3. Install 18 ¾” seal assy.

Footer 231
Template
Pull out of hole

Footer 232
Template
Tubing Hanger
Packer
Tubing
Down Hole
Safety valve
Install Tubing Hanger with tubing

Footer 233
Template
Perforating
Perforating with wire-line tool

Footer 234
Template
Well testing

Footer 235
Template
Close DHSV
Install TH plug

Summary1) CMG STARS:
• H2S souring
• Injectivity & fracture modelling
• Thermal or chemical processes
• IOR/EOR
• Polymer flooding/ chemical placement
• Heavy oils and light oil
2) CMG GEM:
• CO2 EOR
• Compositional features
• Fracture modelling and
injectivity
• Gas processes
• CBM
3) CMG IMEX:
• Blackoil simulator
• Injectivity & Fracture
modelling

Examples of reservoir simulation
programmes
CMG (WinProp & Builder) Tempest More
tNavigator Tecplot

What we want for future: Reservoir
simulation software
Commercial reservoir simulation software:
CMG Suite Computer Modelling Group
IMEX: Black oil simulator
GEM: Compositional simulator
STARS: Thermal compositional simulator

STARS - Advanced Processes & Thermal
Reservoir Simulator
STARS is the undisputed industry standard in thermal reservoir simulation and
advanced recovery processes. Reservoir engineers use STARS to simulate
changes to the reservoir based upon fluid behaviour, steam or air injection,
electrical heating or chemical flooding.
Chemical Enhanced Oil Recovery (EOR) - STARS simulates the wellbore
treatment procedures required to evaluate the effectiveness of chemical
additives used in chemical EOR processes. Globally, STARS is also the most
widely used foam simulator as it is the only commercial simulator to
mechanistically model the complex physical processes involved in foam
flooding.

STARS Uses
 Chemical EOR
 Emulsions, Gels, Foams
 ASP. SP, ASG
 MEOR / Reservoir Souring
 Low salinity
 BrightWater®
 Thermal EOR
 Hot water
 Steam flood & cycling
 SAGD & ES-SAGD
 Combustion (LTO & HTO)
 ISC of Oil Shale
 Naturally Fractured Reservoirs
 Dual Porosity (DP), Dual Permeability (DK), SubDomain (SD), MINC
 Cold Heavy Oil Recovery (CHOPS)
 Natural Gas Hydrates
 Complex Thermal Wellbore Configurations
 Discretized Wells (transient, segregated flow of steam and bitumen in single tubing horizontal wells)
 FlexWells (transient, segregated flow of steam and bitumen in multiple tubing, undulating wells)
 Coupled Geomechanics
 GEOMECH

STARS: Souring modelling (3D)
Reactions:
Oxidation of sulfide with nitrate
Reduction of sulfate with acetate and precipitation of sulfide with ferrous
oxide
Model sulfide production and nitrate-dependent oxidation in an upflow,
packed bed bioreactor and to transfer the resulting model to a field wide
nitrate injection.

STARS: Souring modelling (3D)
Predicted H2S distribution in generic field model before and after nitrate injection

What STARS are used for:
• Microbial
• Surfactant
• Reactivity
• Pressure dependent properties
• Solves energy equations
• Material balance
• Reservoir performance forcasting
• Well location
• Downhole heating
• Cold production simulation
• Production and injection profiles
• Tracer transport
• Process steam injection
• Geochemistry
• Coal gasification simulation
• Cold heavy oil production
• Heat transfer
• Steam
• Heavy oil thermal recovery
• Well chemical tracer test
• Interwell tracer test
• ASP flooding
• STARS can be used for heavy and light oil

GEM - Compositional &
Unconventional Reservoir Simulator
GEM can model primary, secondary, and tertiary recovery processes, and
accurately model complex heterogeneous faulted structures, horizontal
and multilateral wells, and geomechanical deformation. GEM is used
extensively for modelling gas and liquids rich shales, coal bed methane
(CBM & E-CBM) and CO2 processes.
About: GEM is a general compositional reservoir simulator for modelling
processes such as gas condensates, volatile oils, gas cycling, WAG
processes, and many other multi-component reservoir scenarios. It can also
model gas injection processes such as miscible floods, and vaporizing or
condensing gas drives GEM accurately simulates structurally complex and
varying fluid combinations beyond conventional black oil simulators, as
well as K-value compositional simulators, including processes in which the
effects of inter-phase mass transfer (i.e. changing fluid phase composition)
are important. GEM will effectively model laboratory scale projects, pilot
areas, elements of symmetry, or full-scale field studies.

GEM Uses
 Secondary Recovery
 Miscible gas injection (CO2, N2, Sour Gas)
 Gas condensate production with cycling
 GOGD using in naturally fractured reservoirs
 VAPEX heavy oil recovery (isothermal and thermal)
 CBM & Shale Gas Production
 Multi-component desorption/adsorption, diffusion & coal swelling/shrinkage
 CO2 & Acid Gas Sequestration
 Oil reservoirs, Saline aquifers & Coal beds
 Geochemical reactions
 Asphaltene modelling during primary and secondary recovery
 Precipitation, Flocculation, Deposition & Plugging
 Dual Porosity (DP), Dual Permeability (DK), SubDomain (SD), MINC & SD-DK
 Hydraulically fractured wells with non-Darcy flow & Compaction
 Single Plane Fracs (Vertical & Horizontal Wells)
 Complex Fracture Networks (Shale Gas Wells)
 Thermal Option
 Coupled Surface Facilities
 GAP & FORGAS
 Coupled Geomechanics
 GEOMECH
249

IMEX: Three phase black oil simulator
IMEX is one of the world’s fastest conventional black oil reservoir simulators.
IMEX is used to obtain history-matches and forecasts of primary, secondary and
EOR or IOR processes where changing fluid composition and reservoir temperature
Are not important factors for accurate modelling of hydrocarbon recovery processes.

IMEX Uses
 Primary recovery
 Black Oil & Volatile Oil
 Dry & Wet Gas
 Gas Condensate
 Secondary recovery
 Waterflooding
 Polymer Flooding
 Dry Gas Injection
 GOGD in naturally fractured reservoirs
 WAG
 Pseudo-miscible Displacement
 Gas Storage
 Dual Porosity (DP), Dual Permeability (DK), SubDomain (SD), MINC & SD-DK
 Hydraulically fractured wells with non-Darcy flow & Compaction
 Single Plane Fracs (Vertical & Horizontal Wells)
 Complex Fracture Networks (Shale Gas Wells)
 Coupled Surface Facilities Modelling
 GAP, FORGAS, METTE & Avocet IAM
251

What IMEX is used for:
• Black oil simulator: 20
• Injectivity: 2
• Fracture modelling: 2
• History match: 2
• Forecast
• Conventional oil in carbonate NFR
• Polymer injection
• Water flooding
• Water injection
• Polymer flooding
• Dry gas injection
• Pseudo-miscible gas injection
• Production strategy by water
injection and drilling new wells
• Pressure dependent
• Shale gas
• Natural fractured formation
• Improved oil recovery simulation
• Non-miscible oil recovery process

What GEM is used for:
• Compositional features: 16
• CO2 EOR: 6
• CBM: 5 (Coal Bed Methane)
• Shale: 3
• Gas processes: 2
• EOS: 2
• Gas injection: 2
• Volatile oils: 2
• Fracture modelling
• History match
• Tight oil/ gas applications
• Geochemical functionality
• Gas depletion in NFR
• Shale gas modelling
• Change in composition of phases
• Miscible flooding
• Carbon capture & storage
• Fracturated reservoirs
• Non-isothermal systems
• Recovery processes

What GEM is used for:
• Geomechanical deformation
• Gas condensates
• Gas cycling
• Non-thermal
• WAG (Water Alternating GAS)
• Gas injection processes
• Simulating laboratory core
flood
• Sensitivity analysis
• Creation of field scale pattern
• Production history match
• CO2-WAG process
• Optimization
• Asphaltene deposition
• Condensate
• Complex heterogenous faulted
structures
• Light oils

Enhanced oil recovery (EOR) processes

Top comments on CMG
“The well capabilities in all of our three simulators are very similar.
Differences occur when a capability doesn’t apply to that simulator (e.g.
steam injection is not relevant for IMEX, a black-oil, isothermal simulator).
Additionally the grid capabilities are very similar. Therefore, injectivity
modeling and hydraulic fracture model can be carried out in all three
simulators.
The choice of simulator to use is determined by the reservoir fluids and the
fluids injected. E.g. water or dry gas injection can be modeled in IMEX, but
GEM would be need for volatile oil or condensate reservoirs, or CO2
injection in depleted oil or saline aquifers for sequestration. For most
thermal applications you would need to run STARS.
Production from hydraulic fractured reservoirs is usually modeled in IMEX or
GEM depending on whether or not multicomponent effects, such as
adsorption, are important.
Papers SPE 132093, SPE 122530 are a couple of references you can look at
the describe modeling of fractured shale reservoirs using CMG software.
General Manager European Region CMG”

Top comments on CMG“
1) IMEX (Black Oil simulator used for conventional reservoirs and non-
complex fluid phase behaviour)
2) GEM (Fully Compositional Equation-of-State based simulator used for
complex fluid behaviour reservoirs- also used in shale, CBM , and tight
oil/gas applications as well as CO2 EOR or sequestration. Has some
reaction and thermal capabilities)
3) STARS (Advanced- component and K-Value based simulator used for
thermal modelling and processes requiring complex reactions).”

Top comments on CMG
“IMEX: Used it for black oil model for slightly compressible oil in a sandstone
reservoir set to simulate a production history to forecast future production
and making production strategy by water injection and drilling of new wells
in leftover oil pockets. Used it for geomodeling which will be a separate
area for large discussion.
GEM: Used it simulating laboratory core flood experiment for miscible CO2
injection / sensitivity analysis / history match, creation of field scale pattern
/ production history match, Simulation of CO2 - WAG process, CO2 flood
prediction / optimization etc. / Assosiate modeled fluid phase behavior
using WINPROP prior to these work. Associate at RGIPT.”

Top comments on CMG
“IMEX is a black oil simulator and models simple oil, water, gas systems. It
derives its PVT properties from tables dependent only on pressure.
GEM is a fully compositional simulator and can model individual
hydrocarbon components. It derives its phase PVT properties from a cubic
equation of state which can be pressure, temperature and composition
dependent.
SOLVE STARS package includes access to GEM or IMEX as well as STARS.
The cost for SOLVE STARS is the same as STARS. General Manager CMG.”

Top comments on CMG STARS“We have worked with many companies such as Baker Hughes, Enerplus,
Suncor, various Universities (such as the Univ. of Calgary) and research
companies (such as Alberta Innovates Technology Futures) on souring and
microbial souring.
We recently conducted a history match to an actual bacterial souring
process with H2S production data for an operator and are currently working
on another project for a Steam-Generated sour gas application here in
Alberta. Reservoir engineer CMG.”
“CMG has worked extensively in the area of H2S bacterial souring and
STARS has the capability to model it. It’s capabilities have been validated
with real field data by some companies and have been published.
He conducted a study sponsored by DOE NETL on H2S production in
Bakken.
Tested a possibility of production of the H2S as a result of the fracturing into
overlaying formation (Lodgepole), which is notoriously sour. CMG worked
great for this task. Petroleum Engineer at Kansas Geological Survey.”

CO2 EOR (Alternative potential with
GEM)

Conclusion
Choose options in following order:
1) Chemical EOR: 3 D CMG STARS H2S study
2) Thermal EOR study with CMG STARS
3) Secondary recovery: GEM CO2 EOR study
4) 3 D Injectivity/ fracturing modelling study in CGM software depending on
reservoir fluids
5) 2D Injectivity model based on Perkins and Gonzales SPE paper
6) 2D Souring model
Injectivity modeling and hydraulic fracture model can be carried out in all
three simulators.
The choice of simulator to use is determined by the reservoir fluids and the
fluids injected

Conclusion:
CMG:
1. Cost. The CMG packages are usually cheaper than competitors. They
also offer leasing packages that are reasonable value.
2. Customer service. Because they are quite a small company, their
customer service and technical support is quite good.
3. Usability. The pre and post-processors are easy to use and easy to learn.
We find junior engineers much prefer to use the CMG packages over
anything else.

Glossary:
ASP: Alkaline-Surfactant-Polymer
SP: Surfactant-Polymer
ASG: Alkali-Surfactant-Gas
MEOR: Microbial-Enhanced-Oil-Recovery
SAGD & ES-SAGD: Steam-Assisted-Gravity-Drainage & Expaning-Solvent SAGD
Combustion (LTO & HTO): High/ Low-Temperature-Oxidation
ISC of Oil Shale: In-Situ-Conversation Process (ICP)
MINC: Multiple interacting continua method
CBM: Coal-Bed-Methane
GOGD: Gas-Oil-Gravity-Drainage
VAPEX (Vapor extraction) heavy oil recovery
CO2 gas injection
EOR: Enhanced Oil Recovery
ECBM: Enhanced Coal Bed Methane recovery
K-Value

Strengths - Thermal
268
Thermal Processes
Combustion
(THAICAPRI)
Cyclic steam
injection
SAGD
Electrical Heating
ES-SAGD
Thermal
Continuous steam injection
Leader in EOR & Unconventional Reservoir markets

Our Strengths - Chemical
269
Chemical Processes
Foam
Injection
Low salinity
water injection
ASP
CO2 injection
with Asphaltene
Precipitation & Plugging
Gel Injection

Strengths - Unconventionals
270
Enhanced Recovery in
Unconventional Reservoirs
CO2 Huff’n’PuffCBM / ECBM
Shale
Gas/Oil
Tight Gas
Microseismic
Data Imported
to simulator

Exploration and production, Sigve Hamilton Aspelund

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