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Introduction The Reservoir and its elements

Notes

© JJ Consulting 1997

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The elements of gas oil and water are not always present at the same time. Any combination is possible. To have a reservoir all the elements are needed:

The Reservoir

A reservoir rock A source rock (but it may be far away from the actual reservoir). The cap rock has to be on top. The structure must be there.

hydrocarbons migrating from the source rock

Notes

water

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Requirements of a reservoir

Organic material is needed as the source of the hydrocarbons. This material is “cooked” at high temperatures and pressures to give the liquid hydrocarbons. The process takes a very long time. The oxygen-free environment is needed otherwise the organic material cannot become hydrocarbons. The basin is a stable zone on a plate where the process has time to be completed. Unstable areas do not leave enough time for the necessary reactions.

To form a reservoir needs - source of organic material (terrestrial or marine) - a suitable combination of heat, pressure and time

Notes

- an oxygen free environment - a suitable basin

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Reservoirs are represented differently depending on who is going to use the data, geologists work with rocks, reservoir engineers with the fluids. The reservoir is pictured in two forms

Reservoir Geometry

The cross section Geological column The Cross section shows the structure and the fluids The geological column shows only the rocks making up the reservoir and the depths of each layer

The Reservoir Cap Rock

Gas Gas Cap Cap Gas-Oil Contact GOC Oil-Water Contact OWC

Notes Oil

Water

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The permeable rock is the reservoir rock. The rock must have porosity if it has permeability. The source rock is the origin of the hydrocarbons.

Reservoir elements

The impermeable rock is the cap rock and the structure makes up the trap.

The major elements of a reservoir are • permeable rock

stores the hydrocarbon

• source rock

produces hydrocarbon

• impermeable rock traps hydrocarbon • trap

captures fluids

Notes

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Basic Geology Basic Geology The Earth - Overview The Earth - Mechanisms Rock Types Deposition Clastic rocks Carbonate Rocks Reservoir Rocks Porosity Permeability

Notes

© JJ Consulting 1997

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The Earth

The earth is made up of a number of components. At the centre is the solid core which is Nickel - Iron ; around this is a liquid core of the same material. The next part is a liquid called the Mantle, composed of much lighter materials. Finally there is a solid crust, a very thin sheath.

Notes

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The crust is not one solid skin on the mantle. It is broken into a number of irregular “plates”. The plates can be large, the Pacific Plate, or relatively small, some of the Mediterranean plates. The centres of the plates are

The Earth 2

stable environments while the edges are the earthquake/volcano regions of the earth. These plates move around driven by the convection currents in the mantle.

Notes

The crust is broken into a number of plates.

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Plate Tectonics 1

The mantle is plastic. It flows in convection currents from the very hot core to the outer Mantle/crust. These currents cause the crust to move. The currents are continuous and are responsible for all the features on the earth's surface.

Notes

Convection currents flow from the very hot core up to the crust. It is these currents which produce the movements seen on the surface.

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Compressional Features

Two types of features are caused by the movement of the plates. The first set are compressional. Here two plates are pushed together. They can create a zone of mountains or one plate can go under the other creating a “trench”. Mountains are usually associated with trenching as well.

Notes

These features are caused by the mantle currents pushing plates together

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On the other side of the currents tensional effects are found. Here the plate is stretched out thin creating faults and rifts and eventually a new plate. Both compressional and tensional features play a large role in the structures of reservoirs.

Tensional Features

Notes

Tensional features are causes by the plates moving apart, for example a rift.

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This diagram shows two ocean plates colliding in a compressional event. The trench is formed on one side while mountains (volcanoes) are created on the other.

Ocean plate - Ocean Plate

Notes

Trench Mountains When an ocean plate meets another, one is forced down creating a trench. Volcanoes form at the junction.

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Ocean plate - Continental plate

This is a typical trenching effect with the ocean plate being forced Down under the continental plate. The latter is forced up into a mountain chain, while there is a trench formed at the boundary. An example of this type of feature is found on the western side of Sumatra. The island has a range of volcanic mountains while offshore is a deep trench. The ocean plate is being driven by the creation of a mid-ocean ridge. A good example of this types of feature is the Mid Atlantic Ridge which stretches from Iceland to below Argentina.

Notes

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Two continental plates colliding create a mountain between them. Compressional forces driving this effect. The entire region surrounding the mountains with be heavily affected by faulting and fracturing.

Continental - Continental

Notes

The collision of two continental plates creates a mountain range. A good example is the Himalayas, created when India collided with Asia.

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Plates

This slide shows a number of the plates and other features of the Indian Ocean. Several mid-ocean ridges are clearly visible delineating the edges of the plates. The plates contain features such as basins and plateaus. the latter are higher regions, some even forming island chains. At the edges of the plates are features such as the Java trench, created where the ocean plate moving east is going under the continental plate.

Notes

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The basins are close to continents and obtain the sediments from the interior. A basin cannot be near the edge of a plate as any sediments would be stirred making reservoir formation difficult.

Basins The basin is where hydrocarbon reservoirs are found. A shallow sea in a quiet region of a tectonic plate is required. The sediments can build up and form rocks without being disturbed.

Notes

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Current Basins

Current basins where reservoirs are forming are the Persian Gulf, the North Sea, the Gulf of Mexico, the Great Barrier Reef. All of these are stable. The Mediterranean is not a basin although there are plenty of rivers depositing sediment, it is unstable with numerous tectonic boundaries running through it. The geologist has to image the earth as it was millions of years ago to find those ancient basins where reservoirs formed.

Notes

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The rocks forming the earth’s crust are broken down into three major classes reflecting their origins. Igneous coming from molten material of the mantle, sedimentary rocks from sediments and metamorphic from the effects of heat and pressure of both of the others.

Rocks General There are three major classes of rock: Igneous: (e.g. Granite). Sedimentary:

Notes

(e.g. Sandstone). Metamorphic: (e.g. Marble).

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Volcanic rocks are those seen immediately after a volcanic eruption. They cool quickly resulting in an amorphous structure. They have no texture. Plutonic rocks cool much slower as they come up from the Mantle and stop much deeper inside the crust. They have a crystalline structure. Continuing movements of the crust may bury the volcano and bring the plutonic rock to a shallower depth or even surface.

Igneous Rocks Comprise 95% of the Earth's crust. Originated from the solidification of molten material from deep inside the Earth. There are two types: Volcanic - glassy in texture due to fast cooling. Plutonic - slow-cooling, crystalline rocks.

Notes

crystalline

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Igneous Rocks and Reservoirs

A granite has no porosity or permeability of its own, however tectonic forces may fracture the rock. Into these fractures hydrocarbons can flow to create a reservoir. The nature of volcanoes is to eject material which is mixed with the already existing formations. This is what happened in some places where the sandstone of the reservoir has volcanic debris mixed into it.

Igneous rocks can be part of reservoirs. Fractured granites form reservoirs in some parts of the world. Volcanic tuffs are mixed with sand in some reservoirs.

Notes

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The effect of heat and pressure is to transform the rock into a new form. In doing this it destroys all porosity and any hydrocarbon. Metamorphic rocks do not exist in reservoirs.

Metamorphic Rocks 2) Metamorphic rocks formed by the action of temperature and/or pressure on sedimentary or igneous rocks. Examples are Marble -

formed from limestone

Hornfels -

from shale or tuff

Gneiss -

similar to granite but formed by metamorphosis

Notes

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Sedimentary Rocks

Sedimentary rocks are formed from the material of other rocks which could be igneous, metamorphic or older sedimentary rocks. The classification splits those rocks which form from materials transported from one place to another - clastic rocks, from rocks which are created from materials in their place of formation ; no transportation - non clastic rocks.

The third category is Sedimentary rocks. These are the most important for the oil industry as it contains most of the source rocks and cap rocks and virtually all reservoirs. Sedimentary rocks come from the debris of older rocks and are split into two categories Clastic and Non-clastic.

Notes

Clastic rocks formed from the materials of older rocks by the actions of erosion, transportation and deposition. Non-clastic rocks from chemical or biological origin and then deposition.

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Depositional Environments The depositional environment can be Shallow or deep water.

The depositional environment often plays a vital part of the evaluation of a well and a field. This often defines the major lithology and points to the possibilities of minor minerals. For example the shallow fan of the delta in the slide produces a conglomerate , the deep water is showing shales ( fine sediments ). Clues to the deposition come from a lot of measurements in and around the well. Core data is invaluable for the fossils, something that can’t be seen on logs. The analysis of Dipmeter curves was always one of the first steps to choosing the depositional environment. Lately the imaging tools have made the process much easier with high resolution borehole images.

Marine (sea) and lake or continental. This environment determines many of the reservoir characteristics Notes

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Depositional Environments 2

The classical continental deposition of sand dunes produces an excellent reservoir quality reservoir rock. To create a reservoir the dune has to be buried with a source rock and cap rock providing the rest of the elements of the reservoir. The sediments carried down rivers will be deposited once the energy of the river currents drops. Heavier particles will come out first, leaving the fine sediments to go into deep water.

Continental deposits are usually dunes. A shallow marines environment has a lot of turbulence hence varied grain sizes. It can also have carbonate and evaporite formation. A deep marine environment produces fine sediments.

Notes

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Sediments deposited in deep water will form poor quality reservoir rocks as the fine grains lead to poor permeability.

Depositional Environments 3 The depositional characteristics of the rocks lead to some of their properties and that of the reservoir itself. The reservoir rock type clastic or non-clastic. The type of porosity (especially in carbonates) is determined by the environment plus subsequent events. Notes

The structure of a reservoir can also be determined by deposition; a river, a delta, a reef and so on. This can also lead to permeability and producibility. of these properties are often changed by further events.

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Diagenesis

Sedimentary rocks are subject to changes over time. If water of a different chemical composition flows through the rock, reactions can occur changing the rock type or dissolving some of it. Tectonic forces are always present. They crack the rock creating fractures.

The environment can also involve subsequent alterations of the rock such as: Chemical changes. Diagenesis is the chemical alteration of a rock after burial. An example is the replacement of some of the calcium atoms in limestone by magnesium to form dolomite. Notes

Mechanical changes - fracturing in a tectonicallyactive region.

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Rock Cycle

The start and end of all rocks is the magma in the mantle . This is cooled to create igneous rocks. these can be broken down into sediments. The sediments are turned into sedimentary rocks. These can be buried deeper with heat and pressure, turning into metamorphic rocks. If these are then heated we return to the magma. Inside this major cycle are subcycles. Igneous rocks can be heated to give metamorphic rocks. Any rocks can be broken into sediments to give sedimentary rocks.

Notes

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Clastic Rocks

Sands are a reservoir rock, while shales are a source rock and a cap rock. The shales are very fine grained and although the can contain fluids this can only leak out in geological time, very slowly. Shales and silts also contain other minerals than Quartz. The sediments are buried to create the sedimentary rock, initially filled with water.

Clastic rocks are sands, silts and shales. The difference is in the size of the grains.

Notes

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Depositional Environment - Delta

Deltas can have huge extents. There are also a large number of potential traps in this environment, channels, bars and sheets of sands further out in the deeper water. hence the delta is one of the most prolific hydrocarbon environments. They are also complex with the “ structure “ ranging from shallow , shoreline to deep water.

Sediments are transported to the basins by rivers. A common depositional environment is the delta where the river empties into the sea. A good example of this is the Mississippi.

Notes

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Ancient river beds below the current level can add up to a considerable thickness. The shape of a river/channel type deposition is often complicated, causing problems for well placement.

Rivers

Notes

Some types of deposition occur in rivers and sand bars. The river forms a channel where sands are deposited in layers. Rivers carry sediment down from the mountains which is then deposited in the river bed and on the flood plains at either side. Changes in the environment can cause these sands to be overlain with a shale, trapping the reservoir rock.

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Carbonates contain about half the worlds reserves in less than half of the reservoirs mainly due to the super giant fields of the Middle East

Carbonates Carbonates form a large proportion of all sedimentary rocks.

They consist of: Limestone. Dolomite. Notes

Carbonates usually have an irregular structure. They are formed from biological “debris”, shells, skeletons etc.

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Limestones and dolomites are usually reservoir rocks. A very dense, low porosity limestone can, occasionally, be a cap rock . Dolomitisation is a very important mechanism as it not only creates porosity but permeability paths vital to some reservoirs.

Carbonate types

Chalk reservoirs tend to have very high porosity and very low permeability.

Chalk is a special form of limestone and is formed from the skeletons of small creatures (cocoliths). Dolomite is formed by the replacement of some of the calcium by a lesser volume of magnesium in limestone by magnesium. Magnesium is smaller than calcium, hence the matrix becomes smaller and more porosity is created. Notes

Limestone

CaCO3

Dolomite

CaMg(CO3)2

Evaporites such as Salt (NaCl) and Anhydrite (CaSO4) can also form in these environments.

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A reef is the simplest carbonate deposition, the skeletons of the reef animals. Schlumberger

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Depositional Environment Carbonates

In the shallow lagoons, Calcium Carbonate is deposited. Shells and so on are added to the mixture. Changes in sea level allow the deposition of salt or anhydrite as a seal. Carbonate deposition is very complex as the rocks themselves have “ particle “ sizes ranging from whole shells to line mud. The basic deposition is in shallow seas from biological and chemical action. CaCo3 is soluble hence can be transported around as a solute and then reprecipitated elsewhere. In addition to the carbonates these environments also produce evaporites such as salt ( NaCl ) and anhydrite ( Ca So4 ) . Other rocks include pyrite ( FeS2 ) and siderite ( FeCo3 ) and chert, microcrystalline quartz, the carbonate reservoir is hence very complex.

Lagoon

Notes

Carbonates are formed in shallow seas containing features such as: Reefs. Lagoons. Shore-bars. 28 28 28

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Rock Properties

There are many other ways to describe a rock from a geological perspective. The minor constituents often determine how a rock behaves as a reservoir, hence they are included in the description. For example then shale content of a sandstone and the type of shale will be used.

Rocks are described by three properties: Porosity -

quantity of pore space

Permeability - ability of a formation to flow Matrix -

major constituent of the rock Notes

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Definition of Porosity

The amount of porosity gives the volume of the reservoir containing fluids. As it is a fraction it can be described as a number e.g. 0.25 or commonly as a percentage, 25%. Porosity can range from zero to over 50%. In normal reservoirs the range of 20% - 39%.

Notes

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Porosity Sandstones

The two packing models shown represent some of the possibilities .Cubic packing , with a porosity in excess of 47% is the theoretical maximum which is rarely reached. These pictures are valid in a lot of cases as the sand sediments deposited are often of uniform size and shape. The addition of smaller grains will reduce the porosity.

The porosity of a sandstone depends on the packing arrangement of its grains. The system can be examined using spheres.

Chalk often exhibits cubic packing.

In a Rhombohedral packing, the pore space accounts for 26% of the total volume.

With a Cubic packing arrangement, the pore space fills 47% of the total volume.

Notes

In practice, the theoretical value is rarely reached because: a) the grains are not perfectly round, and b) the grains are not of uniform size. 31 31 31

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Porosity and Grain Size A rock can be made up of small grains or large grains but have the same porosity. Porosity depends on grain packing, not the grain size.

In a clastic rock the grain size ( same size grains ) does not affect the porosity. Thus a sand, a silt and a shale can have the same porosity .The differences come in permeability where the grain size has a direct effect, large grains meaning higher permeability. This is the reason that a universal porosity - permeability transform does not work; two rocks with the same porosity but different grain sizes will not have the same permeability. The saturation can occur even in the same “ sandstone “ layer in a reservoir in a sequence where the grain size has changed during deposition eg. a firing up sequence. This implies that the silts and shales have porosity containing fluid. The fluid is water as the pore size is so small that capillary forces prevent hydrocarbon from entering.

Notes

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Sandstones can also contain fractures and vugs, however this is rarer than in the carbonates. In the case of vugs the latter are soluble while sandstone is not.

Carbonate Porosity Intergranular porosity is called "primary porosity".

Porosity created after deposition is called "secondary porosity".

Notes

The latter is in two forms: Fractures Vugs.

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Fractures are classed as either being vertical or horizontal, although they can appear at almost any angle. If they are vertical they can penetrate from an oil column down into the water, and, as they have very high permeability, can cause production problems. This set of porosities are not fabric selective, ie. they happen to the entire rock. Fractures crack through any of the types of mineral or “ shell “ in the rock.

Fractures Fractures are caused when a rigid rock is strained beyond its elastic limit - it cracks. The forces causing it to break are in a constant direction, hence all the fractures are also aligned. Fractures are an important source of permeability in low porosity carbonate reservoirs.

Notes

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Vugs

The full definition of vugs is more complicated. They are irregular holes in the rock. They have been caused by dissolution of shell (etc) fragments and also some of the matrix surrounding them. They can vary widely in size from a few microns to metres. In this context they are regarded as being a centimetres at most. In most cases the vugs are not connected to each other in any producible manner and hence do not contribute to the formations productivity. Carbonate rocks will frequently contain both vugs and fractures.

Notes

Vugs are defined as non-connected pore space. They do not contribute to the producible fluid total. Vugs are caused by the dissolution of soluble material such as shell fragments after the rock has been formed. They usually have irregular shapes.

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The major difference in the two properties porosity or permeability is that the former is a static rock property while the latter is a dynamic rock and fluid property.

Permeability Definition The rate of flow of a liquid through a formation depends on: The pressure drop. The viscosity of the fluid. The permeability. The pressure drop is a reservoir property. The viscosity is a fluid property. The permeability is a measure of the ease at which a fluid can flow through a formation.

Notes

Relationships exist between permeability and porosity for given formations, although they are not universal. A rock must have porosity to have any permeability. The unit of measurement is the Darcy. Reservoir permeability is usually quoted in millidarcies, (md). 36 36 36

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The original experiment was designed to monitor the flow of water through the sand in the town of Dijon .

Darcy Experiment

The flow of fluid of viscosity m through a porous medium was first investigated in 1856 by Henri Darcy. He related the flow of water through a unit volume of sand to the pressure gradient across it. In the experiment the flow rate can be changed by altering the parameters.

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Notes

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Darcy Experiment 2

The flow rate increases with increasing pressure drop; it decreases with increasing length ; it increases with increasing surface area; it decreases with increasing viscosity. Putting this altogether gives an equation with the unknown as the permeability, K.

Notes

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Permeability is a metric ( but not SI ) unit.

Darcy Law

Notes

K = permeability, in Darcies. L = length of the section of rock, in centimetres. Q = flow rate in centimetres3 / sec. P1, P2 = pressures in bars. A = surface area, in cm2. µ = viscosity in centipoise.

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The flow rate through the large pore spaces is high hence the permeability is high.

Permeability and Rocks In formations with large grains, the permeability is high and the flow rate larger.

Notes

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Permeability and Rocks 2

The flow rate through the small grained rocks is low hence the permeability is low. The formation contrasts with the one in the previous slide; with the same porosity the permeabilities can differ dramatically. The ultimate contrast is between a very fine grained shale with zero permeability and a coarse sandstone with a high permeability.

In a rock with small grains the permeability is less and the flow lower.

Notes

Grain size has no bearing on porosity, but has a large effect on permeability.

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Permeability and Rocks 3

low Vertical permeability

high horizontal perm

The flow through this system will be best along the horizontal direction through the large grained parts of the rock. The small grained layer will impede fluid flow in the vertical direction and hence reduce the permeability. The porosity of all 42 the layers can be exactly the same. 42 42

Due to bedding the permeability can change vertically to a clastic sequence . The vertical permeability kv is determined by the lowest permeability layer. The horizontal permeability kh does not have this problem. The anisotropy , Kv/Kh describes the difference between the two. This ratio is always less than or equal to 1.

Notes

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As noted a rock can have porosity but no permeability. If it has zero porosity it will have zero permeability. In practical terms low porosity reservoirs ( < 10% ) exist.

Reservoir Rocks Reservoir rocks need two properties to be successful: Pore spaces able to retain hydrocarbon. Permeability which allows the fluid to move.

Notes

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Clastic Reservoirs

Sandstone reservoirs account for the majority of the worlds fields. There will always be bedding variations leading to differences in the quality of the reservoirs. The porosity and permeability are relatively simple to evaluate from core samples. Fractures may be important in low porosity reservoirs.

Sandstone usually has regular grains; and is referred to as a grainstone. Porosity Determined mainly by the packing and mixing of grains. Permeability Determined mainly by grain size and packing, connectivity and shale content.

Notes

Fractures may be present.

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Carbonates reservoirs are difficult as their properties change in both the vertical and the horizontal directions, often in unpredictable ways. Fractures are nearly always present and can be essential to production.

Carbonate Reservoirs Carbonates normally have a very irregular structure. Porosity: Determined by the type of shells, etc. and by depositional and post-depositional events (fracturing, leaching, etc.). Permeability: Determined by deposition and postdeposition events, fractures.

Notes

Fractures can be very important in carbonate reservoirs.

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The majority of cap rocks are shales as it is these rocks which are normally present. Zero porosity carbonates not only form cap rocks but barriers in the reservoir itself.

Cap Rock A reservoir needs a cap rock.

Notes

Impermeable cap rock keeps the fluids trapped in the reservoir. It must have zero permeability. Some examples are: Shales. Evaporites such as salt or anhydrite. Zero-porosity carbonates. 46 46 46

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Source rocks are shale or siltstone. These sedimentary rocks form in the deep ocean and have fine grains.

Source Rocks Hydrocarbon originates from minute organisms in seas and lakes. When they die, they sink to the bottom where they form organic-rich "muds" in fine sediments. These "muds" are in a reducing environment or "kitchen", which strips oxygen from the sediments leaving hydrogen and carbon. The sediments are compacted to form organicrich rocks with very low permeability. The hydrocarbon can migrate very slowly to nearby porous rocks, displacing the original formation water.

Plankton and other dead animals fall to the bootm of the oceans

Organic rich mud

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Notes

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Temperature Window

The temperature at which the source rock has been “ cooked “ is important to the viability of the reservoir. It is closely related to the depth at which the rock was buried. As all this happened a long time in the past the geologist has to track the history of the source rock.

Temperature too low for hydrocarbon formation

Oil Formed

Gas Formed

Notes Temperature too high for hydrocarbon formation

If the temperature is too low, the organic material cannot transform into hydrocarbon. If the temperature is too high, the organic material and hydrocarbons are destroyed.

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Hydrocarbon Migration

Notes

Hydrocarbon migration takes place in two stages: Primary migration - from the source rock to a porous rock. This is a complex process and not fully understood. It is probably limited to a few hundred metres.

Secondary migration - along the porous rock to the trap. This occurs by buoyancy, capillary pressure and hydrodynamics through a continuous water-filled pore system. It can take place over large distances.

Secondary migration is simple to understand with the higher hydrocarbon floating to rest on top of the original water. The primary part of the process is much more complex. The exact mechanism is uncertain as the experiment cannot be done in the laboratory ( high temperature and pressure and a very long time ).

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Rock Classification

Clastic rocks are classified initially by their grain size. There are many more complex classifications for this type of rock but this is the simplest. In this list Conglomerates and Sandstones are reservoir rocks, Siltstones and Shales are source rocks and shales are also cap rocks. Non- Clastics can be described by their chemical composition, there are, once again many more complex descriptions. Here limestone and Dolomite are reservoir rocks and Silt and Anhydrite are cap rocks.

Clastics Rock type Conglomerate Sandstone Siltstone Shale

Non-Clastics Rock type Limestone Dolomite Salt Anhydrite Coal

Particle diameter Pebbles 2 - 64mm Sand .06 - 2mm Silt .003 - .06mm Clay <.003mm

Notes

Composition CaCO3 CaMg(CO3)2 NaCl CaSO4 Carbon

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Reservoir Structure There are many other types of structure. The criteria for a structure is that it must have: Closure, i.e. the fluids are unable to escape. Be large enough to be economical.

The exact form of the reservoir depends on the depositional environment and post depositional events such as foldings and faulting.

The rocks compromising the reservoir undergo significant changes due to tectonic movements. The most important is folding and faulting as it is these alterations to the initial horizontal strata which create the structures forming reservoir traps. The depositional environment contributes greatly to the variety of trap. Shallow lagoons can have reefs as well as layers of carbonates.

Notes

1300m

1400m 51 51 51

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In the major oil basins of the world it is often the case of series of structures. Maps of the North Sea or Middle East clearly show the reservoirs lined up as one structure has overflowed into the next.

Trap definitions

Once the hydrocarbon reaches the spill plane it goes to fill up the next structure.

Notes

Several fields can be created in a line. Closure is measured down to the spill plane.

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Traps General

The key concepts are those of Net and Gross pay. Gross pay is always > Net pay. This can also be described by the Net -to - Gross ratio which is always less than or equal to one. The spill plane is the maximum level to which this particular reservoir can filled before the next anticline starts to be filled.

Gross Pay: the total thickness of the reservoir zone from the top of the reservoir to the lowermost hydrocarbons

Closure: total reservoir size down to the spill point

Net Pay: the total thickness of producible hydrocarbons

Notes

Spill Point: connection to other systems

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Structural traps describe all the large features and includes domes, anticlines and faults. These large scale reservoirs include most of the Middle East giants.

Structural Traps The simplest form of trap is a dome. This is created by upward movement or folding of underlying sediments.

Notes

An anticline is another form of simple trap. This is formed by the folding of layers of sedimentary rock.

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Fault Traps

Faulting is an important mechanism in most reservoirs. It forms reservoirs in its own right and also breaks other reservoirs down into specific blocks. Well testing helps determine the fault parameters such as distance from a well, angle and so on. Faulting of older blocks creating grabens also makes depositional environments for new reservoir formation. Overall a very important mechanism in most reservoirs.

Faults occur when the rock shears due to stresses. Reservoirs often form in these fault zones. A porous and permeable layer may trap fluids due to its location alongside an impermeable fault or its juxtaposition alongside an impermeable bed. Faults are found in conjunction with other structures such as anticlines, domes and salt domes.

Notes

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Stratigraphic traps describe the traps associated with the depositional environment. Reefs, channels and bars are from specific environments. Unconformities exist due to tectonic movements when a formation ;an anticline in the diagram is eroded ( it is above ground level ). It is then buried and more sediments are added creating the seal and hence the reservoir.

Stratigraphic Traps

Notes

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Salt Dome Trap

Salt in creating the domes also adds faults and fractures due to the express pressures on the rocks. The traps around the dome are difficult to find as anything below the Salt is invisible on the surface seismic. ( the contrast between the salt and anything else is too large ).

Salt Dome traps are caused when "plastic" salt is forced upwards. The salt dome pierces through layers and compresses rocks above. This results in the formation of various traps: In domes created by formations pushed up by the salt. Along the flanks and below the overhang in porous rock abutting on the impermeable salt itself. Notes

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Most reservoir maps in the world use m.s.l. as the reference. Depths of the layer increases away from the crest of the structure. The reference is needed because the drilling rig can be on top of a mountain or an offshore platform. In each case the measured depth of the same layer is different as the drilling reference is different.

Reservoir Mapping

Notes

Reservoir contours are usually measured to be below Mean Sea Level (MSL). They can represent either the reservoir formation structure or fluid layers. 58 58 58

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Rock Ages

The vast majority of reservoirs fall into the middle era from about 300Myears to about 60Myears. This is because there has been enough time for all the process to happen. If too much time has passed the continuing tectonic movements will push the reservoir deep, destroying the hydrocarbon or cracked it open or raised it to the surface allowing the fluids to escape. If not enough time has passed all the elements of the reservoir will not be in place.

Notes

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Reservoir Rocks and Production Sandstones

Under high drawdown some sandstones will collapse; the well produces sand. This may cause damage to equipment.

Carbonates

Lost circulation material is produced first and can clog valves and so on. Production may be through fractures and only a few perforations producing as jets.

The mechanical strength of the sandstone formations can be predicted using wireline logs. Lost circulation material is used to stop mud losses during drilling, it can be a number of materials, ground nut shells, cotton seeds, rubber bands, mica. In all cases its major property is to block holes.

Notes

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Fluids Fluids Fluids in a reservoir Description of the Hydrocarbon Reservoir Pressure Reservoir Temperature Hydrocarbon phases Fluid Production Formation Volume factors Surface tension forces Wettability Relative permeabilities

© JJ Consulting 1997

Notes

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Definitions

Reservoir fluids need to be described in a different way from the rocks. The first definition is one of contacts, where the fluids would be in equilibrium. These are the gas-oil-contact, the oil-water-contact and the gas-water-contact. The latter is only possible in a well with gas and water (no oil). The second figure is the oil in place, the amount of hydrocarbon in the reservoir. The final figure is one of the hydrocarbon properties, the gas-oil-ratio; how much gas is in the oil. Due to the complexity of the hydrocarbons in the reservoir there are many other parameters which are needed to fully describe the fluids.

Fluid Contacts

Oil in Place

OIP

Notes

The volume of oil in the reservoir in barrels or cubic metres.

Gas/Oil Ratio

GOR

The gas content of the oil.

API Gravity

API

Oil gravity.

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Fluids in a Reservoir

Other gases can be found in wells, these include, helium, carbon dioxide and hydrogen sulphide. In most cases these occur as traces together with the hydrocarbon and water normally found. The formation water is uniquely described by its salinity. This varies from 500 ppm Chlorides to 250000ppm; a wide range. The major rock property involved in production is the permeability.

A reservoir normally contains either water or hydrocarbon or a mixture. The hydrocarbon may be in the form of oil or gas. The specific hydrocarbon produced depends on the reservoir pressure and temperature. Notes

The formation water may be fresh or salty. The amount and type of fluid produced depends on the initial reservoir pressure, rock properties and the drive mechanism.

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Hydrocarbon Structure

Another way to describe the hydrocarbons is by the mixtures of the groups of hydrocarbon structure types. The three major groups are shown. The simplest and most abundant is the paraffin series, with the more complex structures in varying proportions.

The major constituent of hydrocarbons is paraffin.

Notes

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Hydrocarbon Composition

Hydrocarbons vary widely in their properties. The first classification is by fraction of each component. This ranges from a dry gas which is mostly C1 (methane) to tar which is mostly the heavier fractions. The black oil normally found is between the two extremes, with some C1 and some heavier fractions. Every hydrocarbon extracted from a reservoir is of a different composition.

Typical hydrocarbons have the following composition in Mol Fraction Hydrocarbon C1

C2

C3

C4

C5

C6+

Dry gas

.045

.045

.01

.01

.01

Condensate .72

.08

.04

.04

.04

.08

Volatile oil .6-.65

.08

.05

.04

.03

.15-.2

Black oil

.41

.03

.05

.05

.04

.42

Heavy oil

.11

.01

.01

.04

.8

.88

Tar/bitumen

.03

Notes

1.0

The 'C' numbers indicated the number of carbon atoms in the molecular chain. 5 5 5

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Hydrocarbon Classification

The API (American Petroleum Institute)gravity is a weight.

Hydrocarbons are also defined by their weight and the Gas/Oil ratio. The table gives some typical values: GOR

Oil is more complex than gas and has to be defined in a more complete manner. The Gas-Oil Ratio, GOR (symbol Rs) is a measure of how much gas is in the oil and hence how light it is. This is measured at a specific pressure, for example the reservoir pressure.

API Gravity

Wet gas

100mcf/b

50-70

Condensate

5-100mcf/b

50-70

Volatile oil

3000cf/b

40-50

Black oil

100-2500cf/b

30-40

Heavy oil

0

10-30

Tar/bitumen

0

<10

Notes

The API gravity of an oil is defined as:

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Gas specific gravity with respect to air should not be confused with the specific gravity with respect to water.

Hydrocarbon Gas Natural gas is mostly (60-80%) methane, CH4. Some heavier gases make up the rest. Gas can contain impurities such as Hydrogen Sulphide, H2S and Carbon Dioxide, CO2. Gases are classified by their specific gravity which is defined as: Notes

"The ratio of the density of the gas to that of air at the same temperature and pressure".

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Reservoir Pressure

The pressure in the reservoir is controlled by the aquifer as it is assumed that it is, somewhere, connected to surface. This means that the pressure in the water is effectively continuous controlled by the pressure gradient. The pressure gradient depends on the salinity of the water, the temperature and the regional tectonic stresses. It is usually constant over a large area.. If the depth in the water is 10000 feet and the water gradient is 0.45psi/ft, the pressure is 10000*0.45 = 4500 psi.

Reservoir Pressures are normally controlled by the gradient in the aquifer (water table). The pressure in the water is given by

P = h*Gw Notes

where h - depth Gw - water gradient Gw, normally ranges from 0.43 - 0.5 psi/ft.

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Reservoir Pressure

The pressures in the oil and gas depend on the gradients (densities) of these fluids. The difference in gradients with the water gradient depends on the specific gravity with respect to water. Calculations could be done using the oil and gas gradients, however it is easier to use the regional gradient and the specific gravities.

Notes

The pressures in the oil and gas are controlled by the relevant gradient which is controlled by the regional water gradient. 9 9 9

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The static pressures anywhere in the reservoir can be calculated using these formula. The calculation starts at the bottom of the zone in the water, specifically at the OWC. The pressure here is simply the depth times the water gradient.

Reservoir Pressure Calculation

The pressure at the GOC is the pressure at the OWC minus the pressure du to the oil column. This is given by the thickness of the oil column times the water gradient times the specific gravity of the oil. A similar calculation can be made for the gas zone.

Powc Powc

Notes

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Find the pressures at the OWC, GOC and Top.

Reservoir Pressure Example

Notes

Water gradient

= 0.433 psi/ft

Oil Specific Gravity = 0.85 Gas Specific Gravity = 0.2

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Calculate the pressure on surface of - oil produced from the GOC - gas produced at the Top of the reservoir.

Reservoir Pressure Example 2

Notes

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Salt domes occur in the North Sea, Gulf of Mexico, Persian Gulf and several other places in the world. Pressures in the surrounding formations can greatly exceed the expected values.

Overpressured Zones Abnormal pressures can occur when the aquifer is completely sealed and the tectonic forces increase the pressure. Salt domes exert an extra pressure as they have pushed up from below. Very high pressures are common in these environments. Notes

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Reservoir Temperature Gradient

Temperature in wells depends on a regional gradient. There can be local “hot spots” where this is sharply increased. The temperature is measured during each logging run. Temperatures gradients are greatest near the edges of the plates and lowest near the centres of the old continental plates as these are the thickest points of the crust.

Notes

The chart shows three possible temperature gradients. The temperature can be determined if the depth is known. High temperatures exist in some places. Local knowledge is important. 14 14 14

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Fluid Phases

The pressure and temperature are two quantities that can be easily measured. Thus it is useful to describe the fluids behaviour during production in these terms. Experimentally it is easier to measure pressure and volume hence the classical experiment is done using these parameters at a constant temperature.

A fluid phase is a physically distinct state, e.g.: gas or oil. In a reservoir oil and gas exist together at equilibrium, depending on the pressure and temperature. The behaviour of a reservoir fluid is analyzed using the properties; Pressure, Temperature and Volume (PVT). There are two simple ways of showing this: Pressure against temperature keeping the volume constant. Pressure against volume keeping the temperature constant. 15 15 15

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PVT Experiment

The easiest experiment is to keep the temperature constant, measuring volumes and pressures. The fluid used is a pure, single component hydrocarbon. (This is not found in a reservoir fluid which consists of a number of components.) Starting in the liquid and increasing the volume, the pressure drops rapidly with small changes in volume until the first bubble of gas occurs. This is the Bubble Point. Further increase in the volume causes no change in the pressure until a point is reached where all the liquid has vaporised. This is the Dew Point. Increasing the volume beyond this point causes the pressure to drop, but much slower than with the liquid phase.

Notes

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Phase Diagram -single component

This is a plot for the single hydrocarbon component used in the experiment. The Vapour pressure curve terminates in the Critical Point. This is a unique point for any substance, pure or a mixture. The plot describes how this fluid behaves with changing pressure and temperature.

The experiment is conducted at different temperatures. The final plot of Pressure against Temperature is made. The Vapour Pressure Curve represents the Bubble Point and Dew Point. (For a single component they coincide.)

If it starts in the liquid and the pressure is reduced, keeping the temperature constant, it will cross the vapour pressure curve and become a gas. Starting as a liquid at constant pressure and increasing the temperature will also change it to a gas.

Notes Liquid

Gas

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Phase diagram Oil The Pressure/Temperature (PT) phase diagram for an oil reservoir: Point 'A' is the initial reservoir condition of pressure and temperature. If the reservoir is produced at a constant temperature until the fluid reaches the wellbore, the line to Point 'B' is drawn. This represents the flow of fluid from the reservoir to the borehole. The fluid travelling to surface now drops in both temperature and pressure arriving at he "separator conditions" (s) with a final volume of oil and gas.

Reservoirs do not have simple single-component hydrocarbons. Their Pressure/Temperature diagrams are more complex. The Bubble Point and Dew Point curves still meet at the critical point. There is now an envelope where two phases, oil and gas, exist in equilibrium. This is due to there being both heavy and light components in the fluid. This typical diagram is used to describe how the oil at reservoir conditions behaves when it is produced to surface.

Liquid

Notes

Pressure

A

Critical Point

B Bubble Point Curve

Separator Conditions Gas Dew Point Curve

Temperature

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somecondensates, Gas liquid. This as type theofname gas reservoir suggests,isstart commercially as a gas andvery condense good asout the liquid can easily be sold.

Phase Diagram Condensate/Gas Point 'C' is at the initial reservoir conditions. The reservoir is produced at a constant temperature from C to D. Fluids flowing up the well now drop in temperature and pressure, crossing the Dew point line and liquid condenses out. At separator conditions (s) the result in both liquid and gas on the surface.

Notes

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This is the final diagram for the reservoir fluids. This is a dry gas which never enters the envelope under any normal producing conditions.

Gas Reservoir In a gas reservoir the initial point is A. Producing the well to separator conditions B does not change the fluid produced. The point B is still in the "gas region" and hence dry gas is produced.

Notes

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Downhole, pressures and temperatures are high, on surface they are much lower hence the fluids will change in volume. Gas come out of the oil depending on the gas-oil ratio.

Hydrocarbon Volumes

Water will only have dissolved gas in a gas well near the gas-water contact.

Fluids at bottom hole conditions produce different fluids at surface: Oil becomes oil plus gas. Gas usually stays as gas unless it is a Condensate. Water stays as water with occasionally some dissolved gas.

Notes

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Fluid Sampling

Downhole sampling has the advantage that it is possible to measure the fluid being sampled hence avoid unwanted production, of, for example, free gas by coning. There are a number of tools to perform a bottomhole sample.

The properties of hydrocarbons are obtained in labs using samples of produced fluids. The best method of sampling is downhole as near to reservoir temperature and pressure as possible. If this is not possible, a separator sample, is taken. The oil and gas are recombined at the proper pressure and temperatures. Notes

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FVF Oil and Gas

The volume change has to be quantified. Surface volumes are measured (production rates); these need to be converted to downhole conditions in order to compute how much has been produced at reservoir conditions and hence how much is left. Bw is around 1, as water is nearly incompressible. Bo is measured in a PVT laboratory experiment, it is just over 1, a typical value would be 1.2.

There is a change in volume between downhole conditions and the surface. The volume of the fluid at reference conditions is described by the Formation Volume Factor:

Bg can be measured in the laboratory or using empirical charts. This figure depends very much on the pressure and is always very small of the order of 10-3.

Volume at downhole Conditions FVF =

Volume at reference Conditions

Notes

Bo = formation volume factor for oil. Bw = formation volume factor for water. Bg = formation volume factor for gas.

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The fluid in the reservoir will contain light fractions. The reference conditions are surface temperature and pressure.

FVF Oil, Bo

• the volume downhole conditions includes any dissolved gas • reference conditions are: Notes

60 degrees F and 14.7 psia • Bo is determined from PVT measurements on a reservoir fluid sample.

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PVT Plot, Oil

This is a typical plot obtained from a PVT laboratory measurement. The only change is an exaggeration of the increase in Bo from reservoir pressure to bubble point pressure. Note the volume of liquid “shrinks from reservoir conditions to surface.

Notes

A typical PVT plot showing the solution GOR, Rs and the FVF, oil Bo plotted against the pressure. 25 25 25

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The measurement of the gor and Bo are done at discrete points of pressure. The pressure is reduced to the required value and the gas allowed to escape. The resultant fluid is then measured.

Description On Bo/Rs Plot GOR, Rs The GOR does not change going from the reservoir pressure to the bubble point pressure. (There is no change in the amount of gas in the oil.) Below the bubble point pressure gas comes out of solution, hence there is less than before and the GOR decreases. At the reference pressure, Rs = 0. FVF, Bo The Bo increases slightly from the reservoir pressure to the bubble point pressure as the lighter components expand. Below the bubble point pressure, some of the gas has escaped hence the volume is reduced leading to a decrease in Bo. At the reference pressure Bo = 1. 26 26 26

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Gas Laws

In an ideal gas the equation links pressure and volume to the temperature, T, and two constants, n and R. Hence two different states can be compared, e.g. downhole and surface. There are no ideal gases in the reservoir as they are all compressible, hence the factor, z.

Ideal Gases PV = nRT or to compare two different states P1V1

=

T1

P2V2 T2

Notes

Non Ideal gases P1V1 z1T1

=

P2V2 z2T2

z is a compressibility factor which depends on the composition of the gas 27 27 27

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The correlation charts can be found in most textbooks, a number exist. These methods will work on “standard gases”, usually just the dry gas.

Gas Compressibility factor

The gas compressibility factor, z, is needed to compute how the gas will behave going from downhole to surface conditions. It can be measured at the PVT labs on a recovered sample of gas or estimated from empirical charts or equations.

Notes

The charts and equations are based on experimentation and correlations done on samples of a number of representative gases.

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FVF gas,Bg

The equation from the previous pages is rearranged to give the ratio of volume downhole to the volume at reference. This leads to an equation with pressure, temperature and z, all of which are easy to measure. In this equation some terms already have values, p1 = 14.7, T1 = 520 degrees R, z1 = 1. p2 and T2 are the measured downhole figures. The only factor remaining is z2 which can easily be found. Bg is a very small number controlled mainly by the pressure. This figure is often reversed to give 1/Bg.

•

the reference conditions are: Notes

60 degrees F and 14.7 psia • p1, p2 are the pressures • T1, T2 are the temperatures • z1, z2 are the compressibility correction factors Charts are used to solve the equation the units are scf/scf or cu m/cu m 29 29 29

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The pseudo reduced pressures and temperatures are essentially a mathematical method of creating a chart which will suit most situation but remain a reasonable size.

Calculating z A typical chart is that of Standing and Katz. This is entered with a value of pressure, Ppr the pseudo-reduced pressure and a value of temperature, Tpr, the pseudo-reduced temperature. These are given by the following formulae;

TPR=

T Tpc

PPR =

Notes

P Ppc

Where T and P are the relevant temperatures and pressure. Tpc and Ppc are the critical temperature and pressure. 30 30 30

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Critical Properties calculation Component

Fraction

Critical

CH4 C2H6 C3H8 i-C4H10 n-C4H10 i-C5H12 n-C5H12 C6H14

0.813 0.067 0.032 0.023 0.0086 0.022 0.0054 0.029

Pressure 343 550 666 735 765 829 845 913

The critical pressure and temperature of any (known) mixture can be approximated using this method. The critical pressures and temperatures and pressures of each component is constant. The method involves summing the contribution of each individual component.

Critical Temp 668 708 616 529 551 490 489 437

Pseudo-critical pressure =

Notes

Ppc = Σ y1Pc1 + y2Pc2 + ....... = 653 psia

Pseudo-critical temperature = Tpc =

Σ y1Tc1 + y2Tc2

+ ....... = 410 ˚R

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Example Component

Fraction

Critical

CH4 C2H6 C3H8 i-C4H10 n-C4H10 i-C5H12 n-C5H12 C6H14

0.892 0.021 0.024 0.032 0.007 0.002 0.011 0.011

Pressure 343 550 666 735 765 829 845 913

Find Bg for this gas mixture at the downhole temperature and pressures given. (Remember add 460˚ to the temperature to convert to ˚R)

Critical Temp 668 708 616 529 551 490 489 437

T2 = 234˚F p2 = 3467psia

Notes

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In most cases the figure of 1 is adequate.

FVF water, Bw

The formation volume factor for water, Bw depends on the compressibility of the water. In most cases this is very small and hence Bw = 1. If there are a lot of dissolved salts or gases the value will change. Notes

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The porosity has to be split between the fluids occupying the pore space. Saturation is the name given to the fraction of a given fluid. The normal representation is as a percentage, in equations a fraction must be used.

Saturation Formation saturation is defined as the fraction of its pore volume (porosity) occupied by a given fluid. Volume of a specific fluid Saturation = pore volume Definitions Sw = water saturation. So = oil saturation. Sg = gas saturation. Sh = hydrocarbon saturation = So + Sg

Notes

Saturations are expressed as percentages or fractions, e.g. Water saturation of 75% in a reservoir with porosity of 20% contains water equivalent to 15% of its volume. 34 34 34

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The graphical representation shows the simple porosity model split now between water and hydrocarbon. The volume of a fluid is the porosity times the saturation.

Saturation Definition

Notes

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Wettability is caused by surface tension forces between the fluid molecules. Most reservoirs are water wet, mainly because the water was there first, the rocks being deposited in water. The hydrocarbon which migrated in at a later date displaces most of the water but rarely wets the rock as the surface tension forces in the water are stronger.

Wettability

The wettability defines how a fluid adheres to the surface (or rock in the reservoir) when there are two fluids present, e.g. water and air. The angle measured through the water is the "contact angle".

Notes

If it is less than 90˚ the rock is water wet; greater than 90˚ the rock is oil wet. Most reservoir rocks are water wet.

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The capillary pressure experiment is a simple one. The controlling factor is the radius of the capillary tube. The smaller the tube the greater the capillary pressure.

Capillary Forces

Pc = capillary pressure. σ = surface tension. q = contact angle. rcap = radius of capillary tube.

Notes

In a simple water and air system the wettability gives rise to a curved interface between the two fluids. This experiment has a glass tube attached to a reservoir of water. The water "wets" the glass. This causes the pressure on the concave side (water) to exceed that on the convex side (air). This excess pressure is the capillary pressure. 37 37 37

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In a reservoir the pore spaces act as capillary tubes pulling the water up into the oil column.

Capillary Forces and Rocks In a reservoir the two fluids are oil and water which are immiscible hence they exhibit capillary pressure phenomena. This is seen by the rise in the water above the point where the capillary pressure is zero.

Notes

The height depends on the density difference and the radius of the capillaries. 38 38 38

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Irreducible Water Saturation In a formation the minimum saturation induced by displacement is where the wetting phase becomes discontinuous. In normal water-wet rocks, this is the irreducible water saturation, Swirr. Large grained rocks have a low irreducible water saturation compared to small-grained formations because the capillary pressure is smaller.

39 39 39

There is always water in the hydrocarbon zone. This water is “stuck” to the rocks by surface tension forces, it is “wetting” the rocks. The water will never be produced under normal production conditions, hence the term irreducible. The amount of irreducible water depends on the grain size and on the mixture of grains. A rock with a mixture of small grains and large grains can have water in the small grains and oil in the pore space associated with the large grains.

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Transition Zone

The transition zone is a phenomenon seen in all reservoirs. The thickness of this zone varies from less that the resolution of the standard tool to very long, hundreds of feet. The size of the pores also controls the permeability, small pores mean low permeability. Hence a long transition zone means a low permeability formation.

The phenomenon of capillary pressure gives rise to the transition zone in a reservoir between the water zone and the oil zone. The rock can be thought of as a bundle of capillary tubes. The length of the zone depends on the pore size and the density difference between the two fluids. Notes

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Permeabilities

In the reservoir the definition of permeability is no longer valid as there are usually more than one fluid present. Only in the water zone can the absolute permeability be used. Irreducible water is present is all other parts of the system, hence the other two definitions.

Absolute permeability - a rock property - measured with a fluid saturating 100% of the pore space Effective permeability - a rock/fluid property - the permeability of a fluid which does not saturate the rock to 100% Relative Permeability - a rock/fluid property - the ratio of the effective permeability to the absolute permeability

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Note that there can only be a permeability for a specific fluid if there is a flow of that fluid.

Effective Permeabilities

Notes

effective permeability is always less than the absolute permeability

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This is a simple mathematical utility to limit the range of the permeability as the relative permeability varies from 0 to 1.

Relative permeabilities

Notes

The relative permeability is the effective permeability divided by the absolute permeability.

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The four stages are 100% water, oil and water mixture, residual oil and irreducible water. The first stage represents a water zone only. The last represents an oil zone. The residual oil stage is a reservoir that has been completely produced.

Relative Permeability

The other stage is an intermediate stage, either a production stage or somewhere in the transition zone.

Take a core 100% water-saturated. (A) Force oil into the core until irreducible water saturation is attained (Swirr). (A-> C -> D) Reverse the process: force water into the core until the residual saturation is attained. (B) During the process, measure the relative permeabilities to water and oil. Notes

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Relative Permeability Experiment

Initially, the core permeability will be the absolute permeability as there is only one fluid at 100% saturation. The relative permeability of water will drop to zero when Swirr is reached because no more water will move. The relative permeability to oil will rise but never reach the absolute permeability because there is still water in the pores. When water is forced in, the relative permeability of water will rise but not reach the absolute value for the same reason.

Notes

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Drive Mechanisms

Drive Mechanisms Water Drive Gas Cap drive Solution Gas Drive Drive problems Secondary Recovery Notes

© JJ Consulting 1997

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There is also the gravity drive.

Drive Mechanisms A virgin reservoir has a pressure controlled by the local gradient. Hydrocarbons will flow if the reservoir pressure is sufficient to drive the fluids to the surface (otherwise they have to be pumped). As the fluid is produced reservoir pressure drops. The rate of pressure drop is controlled by the Reservoir Drive Mechanism. Drive Mechanism depends on the rate at which fluid expands to fill the space vacated by the produced fluid. Main Reservoir Drive Mechanism types are: Water drive. Gas cap drive. Gas solution drive

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Water Invasion 1

Water has two advantages , firstly there is water in the hydrocarbon zone in the form of irreducible water with which it can join and hence clean around the grains. Secondly capillary pressure helps the water up the small pore channels.

Water invading an oil zone, moves close to the grain surface, pushing the oil out of its way in a piston-like fashion.

Notes

The capillary pressure gradient forces water to move ahead faster in the smaller pore channels.

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There will always be some oil left in the rock, 100% recovery is impossible.

Water Invasion 2

The remaining thread of oil becomes smaller.

It finally breaks into smaller pieces. Notes

As a result, some drops of oil are left behind in the channel.

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Water Drive

The (normally) large volume of the water system gives additional assistance to this type of drive. The hydrocarbon is pushed out as its pressure drops, while the pressure in the water remains higher hence the water will move to force the oil out.

Notes

Water moves up to fill the "space" vacated by the oil as it is produced.

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Water Drive 2

The production of water will invariably increase. The amount of water finally produced depends on capabilities of the surface production facilities and the economics of the process. It can be as much as 98%. Gas production is simply that associated with the oil and depends on the gas-oil ratio.

Water Production

Notes

This type of drive usually keeps the reservoir pressure fairly constant. After the initial “dry” oil production, water may be produced. The amount of produced water increases as the volume of oil in the reservoir decreases. Dissolved gas in the oil is released to form produced gas. 6 6 6

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The very high mobility of gas (low viscosity) means that it goes down the large pore channels bypassing the smaller ones. Once past a zone the gas will continue leaving the oil trapped; it will not be produced.

Gas Invasion Gas is more mobile than oil and takes the path of least resistance along the centre of the larger channels. As a result, oil is left behind in the smaller, less permeable, channels.

Notes

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The main type of gas drive is the gas cap drive. The gas cap expansion forces the oil out. The gas cap needs to be large for this type of drive to succeed.

Gas Cap Drive

Notes

Gas from the gas cap expands to fill the space vacated by the produced oil.

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Gas Cap Drive 2

As the gas cap expands the pressure drops hence the drive efficiency goes down. In addition there is always breakthrough of the free gas and production at an apparent high GOR. The reservoir pressure will go down quickly.

As oil production declines, gas production increases. Rapid pressure drop at the start of production.

Notes

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Solution Gas Drive

This type of drive uses the energy of expansion of the gas dissolved in the oil as there is no appreciable water or gas cap drive. This is very inefficient as there on a little possible expansion. In addition the reservoir rapidly drops below bubble point in the reservoir itself. This means that gas comes out of solution in the reservoir. This will create problems for production and eventually the reservoir will die.

Notes

After some time the oil in the reservoir is below the bubble point. 10 10 10

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The slide shows the rapid decline in all the parameters in the reservoir, pressure, production. The GOR also declines as the gas is produced.

Solution Gas Drive 2 An initial high oil production is followed by a rapid decline. The Gas/Oil ratio has a peak corresponding to the higher permeability to gas. The reservoir pressure exhibits a fast decline.

Notes

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Drives General

The slide compares the total cumulative production of the various drive mechanisms against the reservoir pressure. The water drive keeps the pressure high and hence is the most efficient at production the reservoir fluids.

A water drive can recover up to 60% of the oil in place. A gas cap drive can recover only 40% with a greater reduction in pressure. A solution gas drive has a low recovery.

Notes

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Drive Problems Water Drive: Water can cone upwards and be produced through the lower perforations.

Coning is caused by producing the reservoir at a drawdown that is too high and also having perforations that are too long. The water (or gas) is drawn to the perforated interval and produced. This problem can usually be fixed.

cones upwards

Gas Cap Drive: Gas can cone downwards and be produced through the upper perforations. Pressure is rapidly lost as the gas expands.

Notes

Gas Solution Drive: Gas production can occur in the reservoir, skin damage. Very short-lived. 13 13 13

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Secondary Recovery 1 Secondary recovery covers a range of techniques used to augment the natural drive of a reservoir or boost production at a later stage in the life of a reservoir. A field often needs enhanced oil recovery (EOR) techniques to maximise its production. Common recovery methods are: Water injection. Gas injection. In difficult reservoirs, such as those containing heavy oil, more advanced recovery methods are used: Steam flood. Polymer injection. . CO2 injection. In-situ combustion. 14 14 14

Most modern reservoirs have some sort of secondary recovery built into their management from their initial production. The aim of all these schemes is to maintain the pressure in the reservoir as high as possible for as long as possible. The main problem with heavy oil is its high viscosity. Reduction of the viscosity is achieved by heating the fluid, hence the steam injection and the in-situ combustion or by adding CO2 . This substance reduces the viscosity of the oil by two orders of magnitude, for example from 500 centipoise to 5. Polymer injection adds polymers to the injection water to increase the viscosity of this fluid. Ordinary water has a much lower viscosity and hence does not sweep the heavy oil efficiently.

Notes

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Secondary Recovery 2

Water can come from the sea water, or a nearby and different aquifer. The injectors are set in patterns depending on the permeability of the reservoir. Gas often comes from produced can which can be compressed and reinjected into the gas cap.

water injection

Both types of injection can operate at the same time.

gas injection Notes

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Water Injection The simplest ( and cheapest) of the techniques Water is injected into a nearby well forcing the oil out The water can either be: sea water Recycled produced water From an aquifer different to that of the reservoir

Notes

The pattern of injectors depends on the permeability of the reservoir rock and the possibility of problems Five and nine spot are common

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Material Balance Material Balance Oil Volumes General Equation Simplified Equation Reservoir Simulation Notes

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A reservoir contains an original volume of oil, as this oil is removed the other components of the system move/expand to fill the space vacated. This is described by the drawing. It is not to scale as the gas will expand much more than the rock and water.

Oil volume gas cap expansion released gas volume Oil Volume

oil volume rock/water expansion

Notes

net water influx

The original oil volume is replaced by the expansion of the other system components - gas - water - rock

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Gas Cap Expansion When oil is produced the gas gap expands to replace part of the oil.

(G − G ) B pc

gc

G

- original gas cap in place

Gpc

- cumulative gas produced from the gas cap, scf

Bgc

- gas formation volume factor at current pressure RB/scf

Bgci

- gas formation volume factor at the original pressure

− GBgci Notes

The gas cap may shrink if the gas produced is a significant fraction of the initial amount.

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N

- original oil in place

Np

- cumulative oil produced

Gas cap expansion is always accompanied by the release of gas from the reservoir oil

Rsi

- initial solution gas oil retio

Rs

- solution gas-oil ratio at current pressure

The gas originally in solution can be placed in three categories

Gps

- cumulative gas produced

Bgs

- current solution gas formation volume factor

Released Gas Volume

still in solution produced from the reservoir released from solution but still in the reservoir Notes

The equation for the reservoir volume of released gas is:

[ NR − ( N − N ) R − G ] B si

p

s

ps

gs

This is the difference between the original gas in solution and the current gas in solution. Subtracting the gas produced gives the released gas still in the reservoir. 20 20 20

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Oil Volume

N

- original oil in place

Np

- oil produced

Bo

- oil formation volume factor

The reservoir volume of oil remaining at reservoir conditions is:

( N − N )B p

o Notes

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Rock and Connate Water Expansion Rock and connate (original formation water) expansion are combined in one term for convenience rock expansion =

connate water expansion =

cf

- formation compressibility (1/psi)

pi

- initial formation pressure

p

- current reservoir pressure

cw

- water compressibility

Swi

- initial water saturation

 NBoi  cf ( p − p)  (1 − S )  i  wi 

 NBoi  cw Swi ( p − p) ( 1 − S )  i  wi 

Notes

combining both expressions gives Rock and water expansion =

 NBoi  (c f + cw Swi ) (1 − S )( pi − p))  wi 

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Water Influx

We

- cumulative water influx

Wp

- cumulative produced water

Bw

- water formation volume factor

The volume of water influx cannot be computed from pressure and fluid properties as has been done for the other fluids. The influx can be inferred from a knowledge of the other terms in the general material balance equation

Net water influx =

We − Wp Bw

Notes

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This is the complete equation made up of the terms from the previous pages. Most of the items in the equation are measured, Bo, Rs etc. This general equation assumes everything that could happen does. In practice there are always simplifications, for example there may be no gas cap.

General Material Balance Equation Original Oil Volume = Gas cap Expansion + Released Gas volume + Oil volume + Rock and Water Expansion + Net Water Influx

Notes

NBoi = ( G − G pc ) B gc − GB gci +

[ NR − ( N − N ) R − G ] B si

s

p

( N − N ) B + (c p

o

f

ps

+ cw Swi )

gs

+

NBoi ( p − p) + 1 − Swi i

We − Wp Bw 24 24 24

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Simplified Material balance Underground withdrawal

F = N p Bo + (Rp − Rs )Bg + W p Bw Original oil and dissolved gas expansion E0 = (B0 − B0i ) + (Rsi − Rs )Bg

Gas cap expansion Eg = B0i (

Bg Bgi

N

initial oil in place

m

(initial gas cap volume)/(initial oil volume)

Np

cumulative oil production on surface

Rp

cumulative gas oil ratio

Rsi

initial gas oil ratio

Rs

gas oil ratio after pressure drop (ie production)

Boi

initial oil FVF

Bo

oil FVF after production

Bgi

initial FVF gas

Bg

gas FVF after production

Sw

original connate water saturation

cw

water compressibility

cf

total pore space compressibility

The objective here is to make a “simple” term for each specific item.

− 1)

Notes

Expansion of connate water E f , w = (1 − m)B0 i (

cw Sw + c f 1− Sw

)∆p

Material balance equation F = N( Eo + m Eg + E f ,w ) + We Bw 25 25 25

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Taking the final equation of the previous page and assuming no gas cap and no water movement results in a very simple linear equation. A plot of the observed production, F, against the oil factor, Eo should give a straight line whose slope is the original oil in place.

Simplified Equation Assuming no initial gas cap and negligible water influx

If the slope if not straight the assumptions of no other fluid interaction are wrong. One possibility is water influx leading to the equation at the bottom, where another linear equation is created, and both N and We are found.

F = NEo The observed production is a linear function of the the expansion of the oil plus the dissolved gas

If the plot is non linear it could mean water influx

Notes

F We = N+ Eo Eo

This linear equation will take this into account

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This form of the equation assumes a gas cap drive mechanism with no water. A plot of F against (Eo +mEg) will give the value for m, the size of the gas cap.

Gas cap drive

The equation can also be used to solve for both N and m if they are unknown. This type of approach is a good way of obtaining the reserves figures.

In a gas cap drive the equation reduces to

F = N( Eo + mEg ) this can be solved for m if the initial oil in place N in known. If both N and m are unknown the equation is rewritten as

Notes

Eg F = N + mN Eo Eo a ‘best fit’ solution for both N and m is then found on a linear plot 27 27 27

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A reservoir simulation is a modern way of using material balance together with a description of the reservoir to properly manage the resources. It requires a large amount of data and the work of a number of disciplines to get the best possible answer.

Objective of Reservoir Simulation The objective is to create a live description of the reservoir

The inputs are geology - lithology, units, core data, maps reservoir engineering - flow systems, fluid behaviour, and PVT analysis

Notes

petrophysics - log interpretation, reservoir parameters, zoning geophysics - areal extent, large scale features

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Model Building

One of the major steps in the simulation is the creation of the reservoir model. The process uses data from well logs and tests and seismic surveys to paint a picture of the part of the system under study. This can vary from a small part of the reservoir to an entire field. The more complex the model the more information that is required.

A model of the formation is created using all the available information. This model is divided into blocks. Each block is described by its properties, porosity, permeability, saturations, fluid properties, pressures and so on. The objective is to create a complete description of the reservoir. Notes

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The procedure outlined is a crude approximation of the work involved. Before even this flow chart there is the vital stage of data collection. Reservoir characterisation is the process of making a detailed analysis of the log and core data.

Reservoir Simulation Procedure

The model is then constructed from this and test data. The history match checks the models validity by comparing the predicted past with the actual past in terms of pressures and production. The reservoir management plan can only be made if the history match has worked.

Reservoir Characterisation

Model Construction

Model Validation

Notes

History Match

Prediction of Future Performance

Prepare Reservoir Management Plan

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History Match A match is made of the rates and pressures measured over time with those predicted by the computer model. If the match is good reservoir management plans can be made. If the match is poor the model has to be reviewed.

The example shows the match of water and gas rates over a period of a few years. In general the match is good. If there were large deviations the model has to be reviewed and the process rerun. A single pass of a history match can take over a day to run.

Notes

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Drilling

Drilling Objectives Exploration Well Types Drilling process Life of a well Perforation Production problems

© JJ Consulting 1997

Notes

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Hydrocarbon in Place

This is the formula giving the amount of oil in place, vital for the exploitation of the reservoir. Logs give porosity

The Objective of most wells is to find hydrocarbons. The volume of hydrocarbons in place is given by:

saturation height (from the depth) This means they are vital to the operator. Area comes from surface seismic and/or well testing

H=Constant

x

φ(1−Sw)hΑ

where Notes

H = initial oil in place φ = effective porosity Sw= initial water saturation h = productive interval A = drainage area

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Hydrocarbon in Place - 2

The constant in the equation is used to put the result into the required units, for example in oilfield units it is acre-ft. Logging measurements form a major part of the input to this equation, hence their importance. Errors in reading or interpreting the logs is reflected in the results of the hydrocarbon in place.

This is simple to visualise A - area of the reservoir h - the thickness of the reservoir together the product gives the total volume of rock φ - percentage of pore space in that volume of rock. i.e. the volume that contains fluids

Notes

Sw = percentage of the pore space containing water so (1-Sw) = percentage of pore space containing hydrocarbons Hence the equations for the hydrocarbons in place

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Exploration - Seismic

The seismic source was originally dynamite; this has largely been replaced by air and water implosion guns and VibroSeis trucks on land. The latter drop a heavy weight to create the noise. The modern 3D survey has lines spaced about 25 - 50m apart with the geophones spaced every 25m or so giving a detailed picture of the subsurface. The processing of the data is quite simple but takes a considerable time due to the high volume of data.

Surface seismic consists of making a “noise” and listening for the returning reflected signals. There are two types of survey 2D - with widely spaced lines of geophones 3D - with closely spaced lines The raw seismic data is processed to give a time picture of the subsurface.

Notes

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Seismic example

This picture shows a seismic section clearly showing the bedding planes. The interpreted cross section shows how the geophysicist puts the various rock types into the picture. At this time he will also make a time to depth conversion. Surface seismic is always recorded as two-way-time, which is useless for drilling. This time is converted into a depth. On this example is also shown the logs that assist the conversion.

Notes

A surface seismic with the interpreted model above. 5 5 5

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Exploration - Geology

The seismic only gives the structure of the formations, there is no information on the rock types. The geologist goes to an outcrop which may be tens of kilometers away and tries to match up the rocks there with the sub-surface picture seen on the seismic. The job of the geochemist is more difficult as he must identify, not only the source rock but also show a potential migration path. This is a difficult task even in a known basin.

In addition to seismic there are other techniques that must be applied to evaluate an exploration prospect. Geology The geologist goes to outcrops (where the formations are exposed on surface) and identifies potential cap and reservoir rocks. Notes

Geochemistry The geochemist tries to identify the source rock and also the possible migration path to the reservoir rock.

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Drilling Objectives The objective of a well is to reach a reservoir zone safely and efficiently and then produce the fluids.

The driller has to have a lot of data before he can design the drilling plan. He needs to have the rock type to chose his bits, estimate his drilling speed, and identify potential problems such as swelling shales. He needs to have the pressures to ensure his mud weight is correct to balance the reservoir. The resulting plan will be a time - depth plot showing the expected time for drilling each section, the depth of the expected casing points and any additional time for other operations. There will also be detailed specifications on casing, etc to be used.

Step 1 identify the reservoir and the beds above it which have to be drilled. Step 2 identify the reservoir fluids and pressures expected; in addition the fluids and pressures of the zones above also have to be estimated. Step 3 plan a series of casing points to minimise the risks.

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Notes

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This is a typical geological section that the driller would have to work with. It shows all the expected formations. The additional information needed is the depth of each and the pressures and fluids in each zone.

Well Prognosis Conglomerate

Shale with sandstone layers(?)

Salt with Carbonate Stringers

This is the geology of the proposed well. The drilling engineers job is to plan a well to arrive at the target reservoirs safely and efficiently. Notes

Cap Rock

Reservoir 1

Reservoir 2

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Drilling Plan The surface hole is drilled to the top of the salt zone. Potential problems in the top zone here include - caving in unconsolidated conglomerate formations. - shallow gas in the sandstone layers.

The first casing is set across the conglomerate and the shale/sandstone. The potential of caving in the surface layer is high but should pose few problems. Shallow gas can be a considerable problem in some areas. Not only is there the possibility of a blow out but gas is difficult to cement properly. This could mean that there will be gas leaking between the casings.

Conglomerate

Shale with sandstone layers(?)

Salt with Carbonate Stringers

Notes Cap Rock

Reservoir 1

Reservoir 2

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Final Well

The final well finished in two more stages. The first through the very difficult salt formation. Here is the problem of which mud to use, salt saturated or oil base, to avoid the salt dissolving. Then there is the problem of possible overpressured stringers, where heavy mud will be required to control them. The reservoir zones should give few problems. Some operators insist on an intermediate stop if there are two reservoirs such as found here. This allows them to evaluate one reservoir at least in case they lose the well.

The next stages are toConglomerate drill the well to the cap rock and then set with casing before drilling Shale sandstone layers(?) the reservoir. Potential problems here are with - salt dissolving in the Salt Carbonate drilling mud, need to Stringers use oil base mud or salt saturated mud. Cap Rock - high pressure in the carbonate stringers Reservoir 1 - a gas gap and hence high pressure in the reservoir zones. Reservoir 2

Notes

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Vertical wells are most common in exploration situations. The well is drilled to its target without the complications of deviation.

Vertical Wells Wells can be split into three categories 1) Vertical • drilled to a specific target • measured depth = true depth

Notes

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Deviated well

Deviated wells are very common in a lot of situations. The well track can be almost anything; starting vertical and then deviating, starting vertical, deviating and then vertical again, starting deviated and then going vertical. The change in direction is called a dog-leg. Severe doglegs can cause problems for logging as it makes it difficult for the tool to go down and sometimes to come out. The deviation angle is measured with respect to the vertical. The true depth has to be computed, knowing this angle and how it has changed.

possible well tracks

Notes Target formation

2) Deviated • usually from a platform or • from land to near offshore • measured depth has to be converted to true vertical depth

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Horizontal well

The ultimate deviated well is a horizontal well. Here the well is drilled in three sections, the vertical section, the curved section and finally the ramp. The curved section is typically a couple of hundred metres but can be less for specific cases. The ramp is as long as required, several kilometres is common. Guiding the well is done from surface using sensors mounted near the drill bit. These give information on direction and deviation as well as logging data such as gamma ray which helps in guiding the well paths.

Vertical section

Curvature

Notes Ramp

3) Horizontal • drilled to maximise production or minimise problems such as coning • well is precisely guided along a predetermined track 13 13 13

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Depth Overview

The depth is different depending on whether the wells are vertical or horizontal. In addition there are differences if the drilling is on land or offshore. However the reservoir is at a constant depth irrespective of the surface topography. Hence a reference is used to give a precise repeatable depth. The reference is mean sea level.

Notes

The depths and position of all wells has to be well known. This is important in mapping and evaluation. 14 14 14

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Rig Personnel

The Company Representative (company man) is the Operating companys man on site. He directs the operations on the rig. Service Company personnel report to him. The Tool Pusher is employed by the drilling company. He oversees all operations on the rig, primarily the drilling but also service company activities. The Driller and the drilling crew actually drill the well under the control of the tool pusher. He drills from the drillers console on the rig floor. The rest of the crew are Assistant driller - the number 2 on the rig floor Derrick man - works on the mast during trips handling the stacking of the drill strings Roughneck - general helper both on the rig floor and elsewhere on the rig site.

Company representative Toolpusher

Maintenance

Driller Asst Driller Derrick man

Notes

Roughneck

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The rigs hoisting system consists of two parts; the mast itself which is the supporting structure for the lifting system and the lifting system itself. The latter consists of Crown Block - a set of sheaves fixed at the top of the mast

Rig Hoist

Travelling block - a set of sheaves at the other end of the loop of the drilling line with a hook at the bottom Elevators - heavy duty clamps attached to the hook on the travelling block. During drilling the hang to the side of the swivel. they are used during tripping to lift the drill pipe and collars

crown block crown block

Drilling line - heavy steel wire Draw works - located on the rig floor near the rotary table, provide the winch system

drilling line travelling block mast

hook links draw works

drill floor

elevator

Notes

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The Swivel permits the Kelly and hence the drill string to rotate freely during drilling operations. It is attached to the travelling block via the hook. It also allows the passage of the drilling fluids down the drill string. It is a large bearing.

Swivel

gooseneck

drilling fluid in fixed bearing

Notes

free to drill string

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The rig floor contains most of the major rig components. The draw works provide the lifting power. The rotary drive gives torque to the drill string.

Rig Floor

The mouse hole is the storage for the next bit of drill pipe to be added to the string. The rat hole is a temporary store for the kelly while the drill pipe is being attached. The console is the centre for the entire operation. The driller has all the necessary controls to manage the drilling plus readouts to give him measurements of the weight on the bit, torque and so on.

draw works

The V-door and the associated ramp are the access points for any items to be brought on to the rig floor.

dog house drive mouse hole rat hole Drillers console

Notes

V-door ramp

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Rotary system

The Rotary Table provides the rotational power to the system. It transmits this via the master bushing and the kelly bushing to the drill string. The Kelly bushing has the same cross section as the kelly hence the kelly rotates. These components are removable.

Notes

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Top Drive System

The top drive system uses a dc electric motor to drive the drill string instead of the rotary table. The motor is attached to the standard swivel above it and to the drill string below. There is no need for a special kelly. This means that one stand of drill pipe can be drilled at one time, saving on the connection time and hence rig time. This system is used on about 70% of offshore and 30% of land rigs.

Notes

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The Master bushing is also used to suspend the drill string during running in or pulling out of the hole. In this case the drill string is held by the slips. These are a set of tapered grips.

Rotary table

Notes

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BOP stack

The BOP stack is the main safety system on the rig. It consists of several devices. The first are pipe rams, designed to fit snugly around the drill pipes and prevent any fluid passing up the annulus. The annular preventer is a rubber device which, within reason, can fit any shape, e.g. the kelly. The blind rams will seal if there is no drill pipe in the hole simply closing the hole. Shear rams will cut through anything in the borehole sealing it off entirely. Also in the stack is a kill line to be able to pump mud into the well at any stage to kill it. The choke line is used to regulate pressure on the annulus. BOP stacks are hydraulically operated.

Notes

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There are three basic types of tubulars used in the drilling phase of a well. The Kelly is a square (or other flat sided shape) pipe used in the rotation system to transmit torque. Drill collars are used down near the bit to provide weight to the drill string. They are very thick walled.

Tubulars

Drill pipes form the major part of a drill string. All the tubulars are hollow to allow transmission of the drilling fluids. The dimensions are given by the outer diameter and the weight. The weight (in pounds per foot) determines the inner diameter. The normal length of a drill pipe or drill collar is 30 feet (10m). In normal operations the dp is made up into stands of three. This also occurs with dcs. There are some specialised items such as stabilisers in the bottom hole assembly.

Notes

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The mud is circulated down the drill string and and back up the annulus. When it reaches surface it is first passed over the shale shakers to remove the cuttings debris. It may then be passed through a degasser, desiltter, desander or mud-gas separator to recondition it before it is returned to the mud pits for reuse.

Drilling Fluids The drilling fluid is an essential part of the drilling and well control system It can be either water or oil based Oil based is an emulsion of diesel and water water based uses anything from salt saturated to fresh water Additives to the mud give it weight. the basic additive is bentonite. Barite is added for very heavy muds Mud is used to

Notes

•Cool the bit •Remove cuttings •Lubricate the bit •Provides a pressure to overcome that of the formation •Makes a mud cake to seal permeable formations

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The mud weight is an important parameter in drilling. New mud is made for each section of the well as the pressures and formations are different.

Mud weights The mud density is kept at a level to overcome expected reservoir pressures and keep the well at a positive “overpressure”. It should not be too heavy or it will crack the formation. Mud weights are quoted in g/cc, lb/ft or lb/gal. This is essentially a density. Notes

If the formation pressure is known the mud weight for equilibrium can be computed. Example The reservoir pressure is 5400 psi. The depth is 10000’. The gradient is 0.54 psi/ft. This is equivalent to 1.25 g/cc or 78 lb/cu ft or 10.4 lb/gal 25 25 25

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Mud Weight Example

0.433psi/ft = 1g/cc 1 psi/ft = 19.27lb/gal

Compute the mud weight need to drill into the gas at the top of the reservoir.

1 psi/ft = 144 lb/cu ft

Notes

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In addition to these a surface casing, the conductor pipe is usually set. This has a normal diameter of 30”.

Casing Casing sizes depend on the purpose . They start large and gradually become smaller Casing sizes are always given as Outer Diameter. The Inner Diameter depends on the weight

Notes The drift is the maximum difference with the nominal value of the id.

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Cementing

The process of cementing is a simple one, a cleaning fluid is first pumped up behind the casing to break up the mud and mud-cake ensuring a good bond to the formation. The cement is then pumped, and a completion fluid is left in the wellbore. An essential requirement for a good cement job is centralised casing. The numbers of centralisers needed is predicted using a computer program with inputs such as well depth and deviation.

Cementing is used to fix the casing in place and provide mechanical strength to the system. The most essential use of cementing is to seal one zone from another. The cementing of a casing is performed by pumping cement slurry down the casing and forcing it up between the casing and the formation. Great care is taken to ensure a complete coverage of the cement. If the cement is found to be poor, a squeeze has to be made to repair the deficit. The cement is usually left to set for a couple of days before drilling ahead.

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Logging

The major initial use of logging is to tell the oil company where the hydrocarbon is and how much is there. In addition to this service logs provide a lot of data that could not be easily obtained by any other method.

Logging is a process of obtaining information about the formation after the well has been drilled. A sensor is lowered into the well on the end of an electrical cable. This provides power and transmits the data to the surface where it is presented in the form of a “graph” against depth. Notes

There are many types of logs; resistivity logs show where the hydrocarbon may be, high resistivity means hydrocarbon porosity logs show porous reservoir zones sonic and density logs give information about the rock types.

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Testing and Logging

There are many log services that are used in testing. One important one is depth measurement. This is made at the initial logging of the well and is then used as the depth reference for the rest of that wells life. Cement Bond Logs, Corrosion logs and Production Logs give detailed information on the well which helps explain test results.

Some logs that are useful in Testing operations. Gamma Ray - shows shale and clean zones, gives net and gross pay. Cement bond logs - show how good the cement is and if there may be channels and problems. Corrosion logs - show possible problems inside and outside the casing. Production logs - show flow in the well. CCL - shows the casing collars

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Life of a well-1

The information requirements in a wells life depend on the stage. The first stage of the well is short, a few months. Once the well is drilled the question is “where is the hydrocarbon?” The logs are run for this purpose. Once the well is cased and cemented, the question is “how good is the cement”. Then the zone(s) are perforated. Once cased it is difficult to make measurements, especially of the important resistivity.

Notes

Drilled well

Cased Well

Perforated Well

Need to find: Saturation

casing integrity

Porosity

cement quality

Zones

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Life of a well-2

In the second “half” of a wells life the questions are different. Here the emphasis is on production , fluids and pressures. Different techniques are employed. Well testing and reservoir monitoring tools are used to answer most of the questions. Some specialist devices such as corrosion monitoring tools may be required. The phase of the wells life lasts for a much longer time, often years; hence there will be a number of surveys during this time.

Notes Well Produced

Workover activity

Recompleted

Production

Perforation efficiency

Flow rates

fluid mix

new zones

Zone Production

Pressures

Flow rates

Pressures

Need to know:

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Completing a well

The choice of a completion is a essential part of the well construction. Numerous computer programs help the engineer decide on the type he will employ. For example the choice between single and dual tubing depends on the zones to be completed their individual pressures, the reservoir performance in each zone. If a dual is selected this means a smaller tubing in the same casing or a larger hole and the same tubing's. In either case there is an expense involved.

When a well is drilled it needs to be completed The objective of a completion is to produce the well’s fluids safely and efficiently Completions can take a lot of different forms •single string tubing •dual string tubing •annulus

Notes

there is also a choice in how the reservoir zone is handled: •perforated casing •open hole •gravel pack The choice of the correct type of completion is vital to the future of the well

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Tubing completion is made up of a tubing set in a fixed packer, the annulus is sealed. The tubing itself has a number of nipples and seats at the bottom to accommodate valves and so on.

Tubing Completions

Notes

The most common type of completion. The fluid is directed to surface in a tubing set in a packer. There can be a lot of zones using either one single tubing or flowing through a tubing per zone. (the normal maximum is two tubings in a well). 34 34 34

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The tubing is by far the most common type as it is easy to control the behaviour of the well. It is also relatively simple to change with a workover.

Tubing completions

This common type of completion has several advantages over the others: •Flow is sent up a narrow tubing, hence easily controlled •the tubing can be removed or replaced easily during workover Notes

•the well is easily controlled •zones can be selectively produced without mixing The disadvantage is that there is extra material in the well thus extra cost.

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This type of completion is used for wells at the opposite end of the flow rate spectrum. In ultra high flow rate wells the well is allowed to flow up through the annulus itself, there is no flow up the tubing. This is done as a tubing would be too small to accommodate the flow rate of the well.. The tubing here is for well control, is the well needs a workover it can be killed.

Annulus Completion

At the opposite end wells which will not produce to surface have to be pumped. A pump is placed in the tubing and the well flowed through the tubing.

A variation on the tubing completion. Fluid is allowed to flow up both the tubing and the annulus

Notes

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annulus This pumped but not completion to surface.shows The pump the well pulls flowing the fluid up up to athe level tubing. in theThis can either be, as shown, a sucker rod pump (nodding donkey) or a submersible pump run by electricity from surface.

Pumped Completion

Notes

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This sort of completion works in very consolidated formations. It is flowed up through a tubing as with a standard completion.

Open Hole Completion

Notes

The simplest form of completing a reservoir zone is the open hole completion. The casing is set in the overlying cap rock. The reservoir is penetrated for a few metres 38 38 38

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Open Hole Completions

Flowing a well from the maximum possible area gives a very good performance with little or no damage. However the problem with an open hole completion is formation collapse, only the very consolidated rocks, carbonates, will stand such a system.

Advantages •Full bore diameter for flow •no perforating is needed, cost saving •can be easily recompleted or deepened later •formation damage in the reservoir is minimised Disadvantages Notes

•no control of fluid entry •no selective treatment of the formation is possible •well is difficult to kill •rock may collapse This type of completion is usually employed in high flowrate wells and consolidated formations

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Gravel Pack Completion

The placing of a gravel pack can be difficult, there are a number of methods. The gravel is put in first and the screen lowered on drill pipe and forced into the gravel or the screen fixed first and the gravel placed in a similar manner to the cement.

Notes

The gravel pack completion is used where there is a need to control sand production. It retains the high flow area of the open hole completion The major elements are a wire screen and the gravel pumped behind it.

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Gravel packs are common, retaining the advantages of the large flow area of the open hole completion while containing the formation collapse. The disadvantages are that in placing the gravel pack the reservoir may be damaged.

Gravel Pack Completions

Gravel packs are commonly used in unconsolidated sands. Advantages are: •keeps sand production down •provides a large flow area Notes

Disadvantages are: •Expensive and complex to install •difficult to perform any workover operation •can introduce a skin effect in the reservoir

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Gravel Pack Example

This is a complex completion with three sand formations, each with a gravel pack. The three intervals can be flowed simultaneously by opening the sliding side doors (SSD) or each can be flowed separately by closing the unwanted zones. The expense of such a system is offset by its expected long lifetime allowing the separate layers to produce without interference.

Notes

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Gas Lift Completion

A gas lift completion is a very common device to assist the reservoir production. A typical reservoir will produce to surface for a number of years; as time goes on the reservoir pressure declines and the reservoir is no longer able to push the oil all the way to surface. The solution is to lighten the oil column in the tubing. This is achieved by injecting gas into the tubing via valves from the annulus. This gas is usually produced gas making this a very efficient system.

Notes

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Perforated reservoir

Perforation in casing is by far the most common method. This is done in both a normal completion and a gravel pack although the requirements are different. The gravel pack needs a lots of shots and an entry hole as big as possible. The standard completion needs deep penetration. Both are possible using varied charges

The commonest method of handling the reservoir zone. A casing is set across the entire reservoir. The zone to be produced can then be selectively perforated. Advantages - The reservoir is produced in only the best intervals Notes

- Stimulation and repair are simple - unwanted fluids are excluded - production logging/monitoring of the reservoir performance is easily performed Disadvantages - the area for flow is small - the perforations may not all produce

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Explosives are used in perforating and other well operations such as sample taking.

Explosives Explosive Categories An Explosion Sudden release of chemical, mechanical or atomic energy - Expanding gas, High Pressure Chemical Explosives Two main types: Notes

1. Low Explosives or deflagrating. 2. High Explosives or detonating

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Low Explosives

Others - 83% Ammonium perchlorate (Cl NH4) + 17% Carbazol. White powder, looks like flour. Less powerful than Western Ball Powder. Flash point 550 degF. Rated at 450 degF for 1 hour. - Uses: brass cst cartridges high temp.

Low Explosives

- 86% Ammonium Perchlorate + 14% Carbozol. White powder. Flash point 550 degF. Rated at 450 degF for 1 hour.

- Initiated by heat or flame.

- Uses: aluminium cst cartridges high temp.french high temp. (lb-51) .american high temp.

- Pressure reaches 50 Kpsi. - Used in CST guns. Black Powder - 75% Saltpetre KNO3 + 10% Sulfur + 15% Charcoal. - Fine, black powder.

Notes

-- Uses: primer "needle" igniters (cst) & squibs Western Ball - Nitrocellulose - Small black ball. - Very hydroscopic (takes water from its surrounding). - Uses: sealed plastic cst cartridges.

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High Explosives

Primary - Lead Azide Sulfone- Pb N6 - Very sensitive to friction. Will self detonate when heated sufficiently at atmospheric pressure. Flash point 625 degF. Uses: Blasting Caps, Boosters. Secondary - RDX - White crystalline solid (dyed pink) with a melting point of 388 degF , crystal density 1.82 gr/cc, with detona tion velocity of 8,400 m/sec. RDX "outgasses" or decomposes harmlessly when heated or burned at atmospheric pressure, however, will detonate if heated in confinement above 180 degC Rated at 340 degF for 1 hour, when not exposed to well pressure or 320 degF when exposed. This rating corresponds to an average rate of descent of 20,000 ft/hr without appreciable lowering of charge performance. Insoluble in water and alcohol.

High Explosives Detonate rather than burn. - Pressure reaches 50 K to 4Mpsi.

- Uses: Detonating Cord, & Shaped Charges of All Types SN6 O14 (Picryl-Sulfone) Yellow powder. Flash point 584 degF. Rated at 470 degF for 1 hour.

Two categories:

- Uses: Shaped Charges & Detonating Cord High Temp.Secondary High Explosives

1. Primary High Explosive - Initiated by hot wire / flame. Notes

- Burn first, then undergo transition from deflagrating to detonating - Sensitive to shock / friction. - Use in blasting caps. 2. Secondary High Explosive - High energy shock wave will initiate the detonation. - Can explode if heated in confinement. - Use in primacords and shaped charges.

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Perforation Gun systems use three components:

Perforation is the most popular method of reservoir completion. The objective is to create a path for flow from the formation to the well through the casing and cement. The requirement is thus for a hole to be made in the casing, cement and into the formation for a short distance. Standard perforations have an entrance hole of about 0.4” and a penetration of around 20”. The perforation “gun” contains these three components. The detonator to start the reaction, the prime cord to propagate it and the shaped charge to make the holes.

- detonator - primary high explosive ignited by heat or shock

- primacord - secondary high explosive ignited by the detonator, burns at 8400 m/ sec

- shaped charges - create the perforations, detonated by the primacord.

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Shaped Charges were developed shortly after World War II from the military bazooka weapon. Three basic elements of a shaped charge

Shaped charge

1. Case (Steel or Aluminium). 2. Cylinder of High Explosive & a Primer. 3. Conical Metallic Liner. It was found that the conical shape produced a depression / hole in a metal target. The addition of the liner increased the efficiency of the system. Modern liners are made of powdered metal and leave a powder residue at the end of the perforation. A Typical charge has only about 20 grams of explosive material. The pressure causes the material in the path of the jet of metal to move out of the way creating the perforation. If the liner opening is widened the entrance hole size increases but the penetration decreases. These type of charges are used for applications such as gravel pack. Notes

The dimensions of the perforation, length of the tunnel, and diameter of the entrance hole are linked and depend on the geometry of the shaped charge. A wide mouth gives a large entry hole and shallow penetration. A narrow mouth gives deep penetration but a smaller hole. 49 49 49

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Jet Formation

The liner is forced inside out to create the liner. The liner tip is at several million psi hence the penetration. The depth of penetration is at maximum about 35 inches as the objective of perforation is to create a pathway for flow between the formation and the wellbore. The liner is made of powdered metal which ends up as dust which is washed away by the flow.

Detonator Cord

The explosion starts at the base of the liner.

Case Liner Primer Charge Explosive

Detonation Front

The detonation front forces the liner to flow forming a characteristic jet shape.

Tips (7000m/s)

Tail (500m/s)

Notes

Jet Tip (15 x 106 psi)

The jet tip is moving at high speed but the main reason for the penetration is the pressure.

Tail Particles

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A Perforation A picture of a glass being perforated. It happens so quickly that the glass remains intact after the jet has passed through. It will shatter a very short time later when the shock wave arrives.

Notes

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Types of Perforation Three Types of perforated completion a) Wireline - Carried on an electric line 1) Casing Gun Completion Well Pressure > Formation Pressure

The advantage of a casing gun completion is that all perforation material is carried inside the carrier hence it is protected from the well fluids. The resulting debris is also brought out of the well in the same carrier. The carrier can be either re-usable or not depending on the type of operation being performed. The more complex gun types are all “ throw-away” type carriers. The disadvantage of overbalanced perforation is that the mud in the well bore will enter the well as it is at a higher pressure. Through tubing perforation eliminates the invasion problem and gives the formation the chance to flow immediately. The disadvantage is that smaller guns have to be used, which means either smaller charges in a small carrier, or larger charges exposed to well fluids and debris left in the well. The choice depends on the type of well being perforated.

Overbalanced perforating Large diameter carrier gun 2) Through Tubing Perforation

Notes

Well Pressure < Formation Pressure. Completion and final surface production equipment, or a temporary completion and testing facilities are in place Underbalanced perforating, with pressure control equipment Through tubing gun (small guns) Gauges can be run with the string 52 52 52

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Tubing Conveyed Perforating

Tubing conveyed perforation ( TCP ) connects a carrier gun to the end of the drill pipe or tubing. The gun can be fired by a number different types of detonators such as drop bar, pressure firing heads or inductive coupling. The choice depends on the conditions and type of well. The advantages of this method are mainly the long interval (s) possible and the possibility of a simultaneous well test using downhole gauges.

b)Carried on Drill Pipe or Tubing 3) Tubing Conveyed Perforating Perforation gun is carried on either the drill pipe or on tubing. Well Pressure < or > Formation Pressure Large interval of perforation in one run - in - hole Notes

High explosive content, perforation spacing Gauges can be run at the same time

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Perforation Characteristics

The number of shots per foot depends on the application and the reservoir parameters. The objective is to obtain the best flow efficiency most economically. Computer program exists which allow the reservoir engineer to select the best combination of shots per foot and phasing. The most common number of shots per foot is four or six.

Guns are classified by the number of shots per foot, spf. The current maximum is 21 spf.

Notes

Guns are also described by their Phasing- the directions of the perforations. This ranges from 0 degrees to 30/60 degrees The example shows 90 degrees. 54 54 54

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Carrier guns have in common, an outer casing into which is put an expendable tube loaded with the charges. They vary from the reusable casing guns to hsd carriers and the through tubing scallop guns.

Carrier Guns These guns consist of pressure tight tubular steel carrier into which explosive shaped charges are mounted. They are: Casing Guns - 3 3/8" , 4" and 5" O.D. Guns. - for overbalanced perforating. - reusable carrier Scallop Guns

Notes

- small size. - for underbalanced through-tubing perforating. - disposable carrier. High Shot Density (Hsd) Guns - Large size - HSD Guns can be run with Wireline or TCP. -- disposable carrier.

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Casing Guns Casing Guns Features - Retrievable gun. - 4 shots per foot , 90 deg. phasing (22.5 deg. for squeeze guns). - Common lengths: 10ft and 15ft per gun.

Notes

- Re-usable guns (15 to 20 times), mechanically rugged. - Limited to 45ft in one run-in-hole. - Mainly for overbalanced through casing perforating .

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Casing Guns 2 Advantages - High reliability ,charges protected. - High temperature (up to 400F) - High pressure rating (25 000 psi). - Gas tight. - Resistant to chemicals. - Selective firing system. - No debris left in well.

Notes

- Little casing damage. - Re-usable carrier. - Large charge gives deep penetration. Disadvantages - Perforating holes not surged - Drilling mud invades formation - Limited length up to 45ft.

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HSD High Shot Density Guns Features - Retrievable gun with wireline operation. - Retrievable or non-retrievable with TCP. - Up to 21 shots per foot. - 60, 120, 135/45, and 140/20 deg. phasing between shots.

Notes

- Common lengths: 5 ft , 10 ft and 20 ft. - High explosive density and very good phasing. - Big range of sizes ( 2 7/8" to 7 O.D.).

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HSD Guns Advantages - High reliability, charges protected. - High temp & pressure rating. - Gas tight. - Resistant to chemicals. - 21 shots per foot (high density) - Large charge gives deep penetration. - No debris left in well. Notes

- Selectivity for small gun sizes. Disadvantages - Carrier not reusable. - Very heavy guns. - Big guns with maximum 20 ft in one run - in hole. - Overbalanced perforating has holes not surged clean and drilling mud invades formation

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Through Tubing Guns Enerjet Guns Features -Semi-expendable for 0 deg. phasing (strips are retrievable, but not reusable). -Expendable for ± 45 deg. phasing (strips are not retrieved). - 6 shots per foot , 0 or 180 degree phasing between shots.

Notes

- Shaped charges are attached to steel or aluminium carrier strip. - Shaped charges are exposed to well condition. - Mainly for underbalanced through tubing perforating

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Enerjet Guns Advantages - Excellent charge performance for its size. - Stiff , but flexible. - 40 to 50 ft in one run-in-hole -Temperature limitation. - Easy assembly. - Deeper penetration than scallop. Notes

- Perforating holes surge clean. Disadvantages - Can only fire 2 guns selectively in one run-inhole. - Non H2S resistance. - A lot of debris left in well after perforation. 61 61 61

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TCP Tubing Conveyed Perforating Features - HSD Guns used. - Run with Drill Pipe or Tubing (Permanent or Temporary). - Normally underbalanced perforating, but long interval may be with overbalanced.

Notes

- Very long gun string is possible. - Gun string is retrievable ( but can also be dropped in the well ).

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TCP 2 Advantages - Same as HSD. - Top down firing. - Very long gun string is possible - Very safe underbalanced perforating. - Overbalanced is also possible. - Different types of firing methods. - Pressure gauges to monitor well pressure. Notes

Disadvantages - Needs correlation of string with GR + pip tags. - Much hardware required. - Unreliable indication of whole string firing. - A misfire will have a long lost time. - Temp. rating of explosive needs to be high (long exposure). 63 63 63

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A typical problem. This is the result of poor cementation. It can happen in either a water or a gas. The only solution is to pull the completion , squeeze cement to block the channel and reperforate.

Channelling Unwanted fluids are produced because of channels in the cement. The only solution is to pull the completion and squeeze. Notes

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Crossflow is usually impossible to tell from surface measurements, a tool such as a downhole flowmeter is required. The flow can go in either direction and can be substantial. If the lower zone is producing water it is possible to block it off, however if it is producing oil this will waste that production. A dual completion may be necessary.

Crossflow When more than one zone is producing commingled the pressure in each zone will change in a different manner. Eventually one zone will be a a higher pressure and flow into the other.

Notes

The solution is to block off the problem zone or install a dual completion.

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Coning

A typical problem in a producing well. Gas can cone down from the gas cap and be produced through the upper perforations. Water can cone up. The reasons for such problems are perforations too close to the contacts or too high a pressure drawdown.

Notes

Excess drawdown and a perforation interval that is too long could lead to coning problems. Here there is unwanted production of both gas and water.

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Fingering

This is caused by having a number of different permeabilities in the same completed interval. The high permeabilities will be produced first caused the water level to rise there. A the point shown there will probably be only water produced as this is the high permeability layers.

Notes

Higher permeability layers produce first bypassing some oil. A solution is selective zone completion. 67 67 67

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The near wellbore is often damaged by the drilling or completion process. The objective of stimulation is to create a permanent zone near the wellbore with a higher permeability.

Stimulation Stimulation is used to improve the permeability of the near well bore environment There are two major methods Fracturing Acidising Notes

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Fracturing creates artificial fractures to enhance production. They are made by increasing the wellbore pressure and breaking the rock. A proppant is used to keep the cracks open.

Fracturing

Only hard rocks such as carbonates, or tight sandstones are fractured.

Notes

A Fracture is made by pumping water at a high enough pressure to crack the formation. Proppant is used to keep the fracture open. 69 69 69

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Acid Wash

This technique is normally carried out in carbonates, where a simple HCl (hydrochloric acid) solution can be used. The normal strength of the acid is 15%, i.e. 15% acid, the rest water. The acid cleans up any perforation damage and adds some small pathways for flow.

Notes

Acid is pumped into the formation. It cleans up any near wellbore damage improving the permeability.

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This is a combination of both techniques. The fracture thus created is etched by the acid; there is no need for proppant. The wing length, as with a normal fracture, is of the order of 10m.

Acid Fracturing

Notes

Acid is pumped under high pressure, a fracture is created and the rock is etched creating a fracture. 71 71 71

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Well Testing Well Testing Flow Regimes Basic Equation Well Testing Drawdown Test Build up Test IPR Test Summary

Notes

© JJ Consulting 1997

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Well Testing Theory

The pressure wave is likened to a wave in a pool after a stone has been dropped into it. At the earliest time the wellbore and zones close to it are influencing the response, at later time it is the reservoir boundaries. The idea is very simple but gives a lot of information about the reservoir in spite of the simple measurement of pressure and time.

A well test is conducted by making a sudden change in flowrate and then measuring the changes in the pressure with respect to time. The pressure wave travels out into the reservoir “seeing” deeper as time goes on.

rate Q

Producing

Shut in

Notes

0

Time, t

Bottom hole Pressure P

0

Time, t 0

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Flow In the well

Slug and Plug flow are not very efficient as they lose energy as they tumble.

FLOW REGIMES

LIQUID VELOCITY

102

10

The flow in the wellbore/casing/tubing of oil will take a number of forms. The flow starts as single phase, as gas comes out of solution the flow regime changes first to bubble flow, small gas bubbles in the oil. The other states may or may not happen in the tubing depending on the pressures and gas oil ratio.

REGION I

REGION III

TR

AN

SIT

IO

N

REGION II

1 BUBBLE FLOW

Notes

10-1

PLUG FLOW 1

MIST FLOW

SLUG FLOW 10

102

103

GAS VELOCITY

The actual flow regime depends on a number of factors, such as gas-oil-ratio and pressures.

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The idea of radial flow seems obvious as the fluid is coming from all directions in the reservoir.

Flow in the formation Flow form a reservoir into a borehole is normally radial

Well bore

Notes

It flows from the surrounding reservoir into the borehole, equally on all sides This model is used to compute flow rates and pressure distributions

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Types of flow

fracture Other forms will of cause flowthe areflow possible to be near linear, thenot wellbore. radial. However An induced as the or natural pressure/flow moves further out into the reservoir the flow is moving radially to reach the fracture.

Radial Flow

Notes Linear Flow

Bi-Linear Flow 5 5 5

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Assuming radial flow and knowing some parameters, Pwf, Pi, rw, h, re. the pressure at any point in the reservoir, P, can be described in terms of known or measured quantities.

FTC

Radial Flow Model

h

PWF

P

Pi i

rw r

Notes re

This is the model for flow in the ideal case Constant pressure at the boundary, Pi Reservoir thickness, h Reservoir radius re Wellbore radius is rw Pwf, is the flowing pressure 6 6 6

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Flow States

The pressure time graph is roughly split into three regions. The final region is when the reservoir reaches its steady state. As this is unknown, it could have arrived at the reservoir limits, or a fault or the pressure disturbance created by a nearby well, this region cannot be easily described. The transition is equally ill defined. However in the transient period radial flow can be assumed and hence the problem analysed.

Transient period Transition

Pressure

Pseudo-Steady State

Notes Time

The transient period is also known as infinite acting radial flow All tests have some time in this region hence this is the zone normally analysed. 7 7 7

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Basic Equation

Note the units used determine the constant. The solution to the proposed model, assuming radial flow gives this equation. It is simply the pressure versus the log of time. If a plot is made of these two the radial flow period should, from this equation, appear as a straight line with a slope of 162.6qBµ/kh. In this everything else but the permeability k, are known, hence this can be determined. The solution assumes some “starting” and “boundary” conditions, which work well for liquids. Gas is different, it has a high compressibility, and the equation has to be modified.

This equation in “oilfield units” is

 162. 6qBµ   kt   − 3. 23 ∆p = pi − pwf = log 2 kh   φ µC tr w   Notes

Note this is only valid if: •The pressure gradients are small •Viscosity is constant •Fluid flow is single phase •Darcy (non turbulent) flow exists •Constant flow rate •Small compressibility 8 8 8

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The measurements in the well test are simply pressure and time, with a constant, known, flowrate. The build up test is the one normally used because the flowrate (in the reservoir) is constant. In a drawdown test it is often difficult to keep a constant rate. Mathematical analysis produces the required answers.

Well Testing Requirements The objective of a well test is to obtain detailed information about the reservoir the parameters sought are Permeability Formation pressure Skin factor productivity ratio reservoir geometry There are two possibilities • Drawdown test

Notes

the well goes from shut in to flowing The pressure drops from the shut in to flowing • Build-up test The well goes from flowing to shut in. pressure increases towards the reservoir pressure 9 9 9

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A drawdown test, as the name suggests, starts shut - in and is the opened to flow. The pressure drops with time. The production rate is controlled on surface with a choke.

Drawdown test

rate Q

Producing

Shut in 0

Time, t 0

Bottom hole Pressure P

Notes

Time, t 0

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The equation is the one seen previously, Pwf is the well flowing pressure which is measured. Pi is the initial pressure of the reservoir just prior to flow.

Drawdown Test equations

The Transient equation becomes the following equation with the flowing pressure a function of the time during the flow period.

162.6qµB p wf = p i − [ log(t ) + c] kh

Notes

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The pressure v log time plot should give a straight line when the well is at radial flow. The slope is computed and hence the permeability calculated. Note the slope is negative as the pressure is decreasing.

Drawdown Test Plot

Pressure, Pwf

recorded data

straight line, slope = m

1

.1

Notes

10

Time, t

The standard method of analysing a drawdown test is to plot the pressure on a linear scale against the time on a logarithmic scale. A straight is drawn through the later time points when the flow is assumed to be radial, the slope is

- m=

162.6qµB kh

The reservoir parameters can then be obtained.

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Damaged Zone

The zone around the wellbore is susceptible to damage from a number of sources. The net result is a zone of poor permeability close to the borehole. Perforating guns are made to fire deep in an effort to bypass this region.

The zone immediately surrounding the wellbore can be damaged for several reasons • clay materials in the formation swollen by the drilling fluids • emulsions between the drilling fluid and the reservoir oil Notes

• drilling mud particles clogging pore channels • precipates forming from incompatible drilling and formation waters • crushing of the rock by the drilling process This causes a zone of pressure loss called the "skin".

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The Skin Factor is an important number in reservoir planning. A high positive skin will mean that some form of stimulation is required to improve the situation.

Skin Factor

The skin factor, S is given a positive sign for a damaged formation and a negative sign for an improved one. The positive sign reflects the additional resistance to fluid flow, the negative the improvement in flow. The amount of skin can be calculated from well tests

Notes

Improvements can be made by techniques such as fracturing or acidising or both.

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The damaged zone has the effect of creating a pressure drop around the wellbore. The Skin is thus added to the basic equation as an additional pressure term.

Pressure -Damaged Zone Pressure Distribution with Skin

Pressure distribution without skin Pressure

∆p skin

Pwf Damaged zone

Notes

Kres > Kdamaged zone

Kres

Kdamaged zone

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The build up test is the opposite of a drawdown test, here the well is closed in and the pressure increases. In order to analyse this type of test the production time has to be known.

Pressure Pw

Build up test

constant rate

Pwf, ∆t = 0 Flow period

time, t

tp

Notes

∆t

A common form of the pressure versus time curve for a build up test. The well is flowed for a (known) period of time, t at a constant rate and the shut in. The pressure starts to rise. 16 16 16

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Build up test equations

The reservoir is still “flowing” as it builds up to its static pressure. The equation used is called the Horner equation and uses the production time is the time part of the equation. In all other respects it is the same as the equation for the drawdown test.

This test is slightly more complex than the drawdown test to analyse mathematically. It is assumed there are two periods of “flow” one with a flowrate of q and the other of -q. The equation becomes: Notes

162.6qµB  t p + ∆t  p ws = pi + log  ∆t  kh

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This plot is analysed in exactly the same manner as that for a drawdown. The slope in the radial flow section is taken and the permeability computed.

Horner plot

Pressure

time, t

extrapolated to Pr

Slope = m

skin and wellbore storage effect

Notes 10 4

10 2 10 3 Horner Time function

10

1

The Horner time function is

t p + ∆t ∆t

where tp is the production time ∆t the time of the test, ie since shut in. 18 18 18

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Downhole shut-in, for example using a DST tool limits the effect. If there is tubing in the well a special tool has to be used.

Wellbore Storage Wellbore storage happens because when the well is shut in on surface it continues to flow downhole as the fluid in the column is compressible. The effect is greatest when the well contains released gas. Conventional well tests are run for a long time to overcome this effect. A better solution is to shut in downhole limiting the problem to a small volume.

A major problem in build up tests is wellbore storage. If it is large it may mask the radial flow portion of the plot and hence make the test unusable.

Gas coming out of Solution

Notes

Single Phase Flow

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The wellbore storage is simple to compute. The plot of ∆p v ∆t gives a straight line which will deviate at the end of wellbore storage.

Wellbore Storage Equations The wellbore storage is given by C=

∆V ∆p

In a well with a single phase fluid ∆V =

qB 0 ∆t 24

therefore qB 0 ∆t C= 24 ∆p

Notes

If ∆p is plotted against ∆t on a linear scale the wellbore storage will show up at early time as a straight line with the slope that is a function of C.

qB 0 m= 24C 20 20 20

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The drawdown pressure is fixed by the operator and depends on the tubing and the fluid flowing. The Productivity Index is a measure of how good a well is. It is measured in barrels/psi.

Definitions-production Drawdown Pressure for fluid flow a pressure difference must exist between the reservoir and the well bore Drawdown = Pi - Pwf Productivity Index The productivity index, J, is the ratio between the production rate, q, and the pressure drawdown J = q / ( Pi - Pwf)

Notes

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This plot is used to compute the productivity index. The flow rate does not increase continuously with reducing pressure, it will reach a maximum value. The PI is computed in the straight portion of the graph.

Inflow Performance Relation This shows the relationship between the production rate, q, and the flowing pressure. It is determined by flowing the well at a number of rates and measuring the pressures.

Pwf = Pi

Notes

Pwf

0

Flow rate

This is an idealised curve for a liquid only. The slope of this curve is the Productivity Index

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The test used to compute the PI is often part of a standard well test. The well is flowed at a number of different rates and the steady pressures measured. These values are used to make the plot .

IPR test procedure Wellhead Flowrate

QT4 QT3 QT2

QT1

Time

Notes

Bottom Hole Pressure

Schlumberger

P1 P2 P3 P4 Time

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Derivative Plots

The derivative plot is a very useful construction as it will give valuable information unseen on other plots. This is usually the first plot made in a modern well test to ensure all the objectives have been met, radial flow and flow barriers or other information have been acquired. In some complex cases a theoretical plot of the expected reservoir is made first. It is then compared to the actual results to better analyse the test.

A method of identifying the straight line is to use not only the pressure and time but the derivative of the pressure as well The straight line portion of radial flow appears as a horizontal straight line on a log-log derivative plot In addition to identifying radial flow the derivative identifies reservoir geometry and some parameters. The derivative for each situation is unique although the pressure profile may look identical. The analysis of this these curves is called Type curve analysis

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Derivative Plot Uses The plots show the different shapes of the pressure derivative curve with changing reservoir properties or geometry. Using model libraries a more precise picture of the reservoir is obtained.

There a very large number of possible geometry's and hence shapes for these plots. Some, although showing widely different properties are similar and have to be dealt with carefully. There is always enough difference for a full interpretation.

Notes

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Well test summary Analysis of well tests for reservoir properties is done when the test has reached radial flow Radial flow is occurring when there is a straight line on the plot of pressure versus a logarithmic time function The straight line portion of the curve may be masked by early time effect - skin and wellbore storage late time effects - the pressure wave reaches a heterogeneity in the reservoir. This could be a fault, the reservoir boundary Specialised analysis using MDH and Horner plots gives the required properties of the well and reservoir.

Notes

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