Exploration and productionIntroduction

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.

Oil price

Kirkuk oil field

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

Kurdistan: Assets

Opportunity

Atrush block

Atrush-1 Jurassic oil discovery

Pulkhana oil field

Pulkhana oil field

Arbat prospect and lead

Arbat structural leads – Large surface anticlines

Block K-42

Risks

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".

P50: 50% certainty of being produced.

Possible reserves: Reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves.

P10: 10% certainty of being produced.

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.

The origins of oil and gas and how they are 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.

The origins of oil and gas and how they are 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 o shore. ff

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 e orts of the oil industry.ff

Sedimentary basins and the dynamic nature of Earth’s crust

Sedimentary basins and the dynamic nature of Earth’s crust

Basin classification schemes

Extensional basins, strike-slip basins, flexural basins, basins associated with subduction zones, mystery basins.

There are many di erent classification schemes for sedimentary basins but ffmost 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).

Sedimentary basins and the dynamic nature of 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: Reserves to production

Oil: Distribution of proved reserves

Oil production

Production and consumption by region

Crude oil prices 1861-2013

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

Grain size

Sorting

Grain shape

Packing

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 ReservoirsDescription:

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 stagesDecision process for investment projects

Project Development Process

Start Business Development/Planning studies

Start Concept Studies

Start FEED/Pre-Engineering

PDOStart Development

Start OperationOperation 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

://m

pgpetro

leum

.com

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

Exploring for oil and gasExploration technologies

Satellite imaging

Gravity and magnetic methods

Seismic

Electromagnetic surveys

Sedimentology

Geochemistry

Regional knowledge

etc.....

Exploring for oil and gasTypical prospect portfolio

Which prospect to drill?

Probability for discovery vs. volume

Market

Field development

Region

Strategic fit

Pd

isc

Volume

Gas prospect

Oil prospect

Exploring for oil and gas 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 wellData acquisition

Coring

Formation logging

Density

Resistivity

Gamma Ray radiation

Sonic velocities

Drill cuttings sampling

Biostratigraphy

Pressure points

Fluid sampling

Exploration wellData 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 wellData 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

Development stagesDecision process for investment projects

Project Development Process

Start Business Development/Planning studies

Start Concept Studies

Start FEED/Pre-Engineering

PDOStart Development

Start OperationOperation 1y

Source;The Statoil Book

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

Development stagesDecision process for investment projects

Project Development Process

Start Business Development/Planning studies

Start Concept Studies

Start FEED/Pre-Engineering

PDOStart Development

Start OperationOperation 1y

Source;The Statoil Book

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 RecoveryReservoir quality

Porosity - The percentage of void space in the rock

Permeability - The rocks ability to transmit fluids

http://mpgpetroleum.com

http://www.netl.doe.gov

Oil recoveryViscosity

Viscosity describes a fluid’s resistance to flowThe higher viscosity, the more energy is required to extract the oil from the pores

http://deshichem.en.alibaba.com/

Geitungen core samplewww.statoil.com

Oil recoveryDrive 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 recoveryArtificial 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

True V

ert

ical D

epth

Reservoir

Gas lift valve

P,T

ΔP venturi, Density

ICV

Gaslift

Surface Controlled Subsurface Safety Valve

Oil recoveryWell design

Vertical vs. Horizontal Single wellbore vs.

Multilateral Inflow Control Sand control Artificial lift Tubing size

Oil recoveryWell density

Number of wells

Rese

rves

Oil recoveryWellhead pressure

Wells

Pipeline

Riser

Near well reservoir

Topside

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.

Flow assurance

“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 assuranceSystem pressure drop

Multiphase flow simulations to recommend flowline sizes and evaluate system pressure drop

Optimize Field Architecture Evaluation of artificial lift and

processing

Flow assuranceHydrates

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 liftIPR 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)

Gas lift valve

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 lossPressure loss:

A. Acceleration

B. Gravitation

C. Friction

P/Ztotal = g/gccos + fv2/2gcd + v/gc[P/Z]

TOTALPressure diff.

Gravitation AccelerationFriction

Pressure loss

Nær overflaten

Gravitasjon

Friksjon

Akselerasjon

Nær reservoaret

Gravitasjon

Friksjon

Akselerasjon

Flow in pipes

Flow in tubing

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

GAP: Optmization

GAP: Production with gas lift

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 system

Schematic 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

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Reservoir

How A Well Is Drilled

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Template

36” Drill Bit

Reservoir

Drill pilot hole

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CementTemplate

1. Install 30” conductor with guide base2. Cement 30” conductor

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Template

26” Drill bit

Drill out for wellhead housing

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Template

Wellhead housing18 ¾” wellhead housingRunning tool

Install 18 ¾” wellhead housing

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Template

Wellhead connector

Install BOP

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Template

Mud circulation

Formation pressure

Mud hydrostatic pressure

Drill out for 13 3/8” casing

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CCC

Template

Casing Hanger

13 3/8” casing

Single Trip Tool

Seal assy.

1. Install 13 3/8” casing hanger2. Cement3. Install 18 ¾” seal assy

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Template

12” drill bit

Drill out for 10 ¾” casing

Footer 230

Template

10 ¾” casing

10 ¾” Casing hanger

1. Install 10 ¾” casing2. Cement3. Install 18 ¾” seal assy.

Footer 231

Template

Pull out of hole

Footer 232

Template

Tubing Hanger

Packer

Tubing

Down HoleSafety valve

Install Tubing Hanger with tubing

Footer 233

Template

Perforating

Perforating with wire-line tool

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Template

Well testing

Footer 235

Template

Close DHSV

Install TH plug

Business research

Other:

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

Reservoir modelling

Examples of reservoir simulation programmesCMG (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:

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

Naturally Fractured Reservoirs

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

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IMEX: Three phase black oil simulatorIMEX 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 temperatureAre 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

Naturally Fractured Reservoirs

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 IAM251

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.”

H2S market

EOR/ IOR

Global EOR potential

CO2 EOR (Alternative potential with GEM)

ConclusionChoose 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-PolymerASG: Alkali-Surfactant-GasMEOR: Microbial-Enhanced-Oil-RecoverySAGD & ES-SAGD: Steam-Assisted-Gravity-Drainage & Expaning-Solvent SAGDCombustion (LTO & HTO): High/ Low-Temperature-OxidationISC of Oil Shale: In-Situ-Conversation Process (ICP)MINC: Multiple interacting continua methodCBM: Coal-Bed-MethaneGOGD: Gas-Oil-Gravity-DrainageVAPEX (Vapor extraction) heavy oil recoveryCO2 gas injectionEOR: Enhanced Oil RecoveryECBM: Enhanced Coal Bed Methane recoveryK-Value

Strengths - Thermal

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Thermal ProcessesThermal Processes

Combustion (THAICAPRI)

Cyclic steam injection

SAGD

Electrical Heating

ES-SAGDThermal

Continuous steam injection

Leader in EOR & Unconventional Reservoir markets

Our Strengths - Chemical

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Chemical ProcessesChemical Processes

Foam Injection

Low salinity water injection

ASP

CO2 injectionwith Asphaltene

Precipitation & Plugging

Leader in EOR & Unconventional Reservoir markets

Gel Injection

Strengths - Unconventionals

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Enhanced Recovery in Unconventional ReservoirsEnhanced Recovery in Unconventional Reservoirs

CO2 Huff’n’PuffCBM / ECBM

Shale Gas/OilTight Gas

MicroseismicData Imported to simulator

Leader in EOR & Unconventional Reservoir markets