Classification of reservoir fluids

           The reservoir fluids are classified into five types based the pressure and temperature behavior of the reservoir and subsequent production

• Black oil
• Volatile oil
• Condensate gas
• Wet gas
• Dry gas

Black oil:

·         Black oils are made up of heavy large and non volatile hydrocarbons.

·         When the pressure lies  anywhere on the line 1-2, then it is said to be undersaturated oil  which means the oil could dissolve more gas if more gas present.

·         If the pressure lies @ point 2 then it is said to be saturated oil which means the oil contains  the maximum amount of dissolved gas and can’t hold any more gas

·         If  the pressure reduction occur below the point 2, then gas will get evolved from the oil which forms free gas phase

·         Additional gas evolved from the oil as it moves from the reservoir to the surface

·         Thus black oil is also said to be low shrinkage crude oil

                                   

Volatile oil

·        Volatile oils contain fewer heavy molecules and more intermediate components (ethane through hexane) than black oils.

·        The color is generally lighter than black oil – brown, orange, or green.

·        Gas associated with volatile oils tends to be very rich and similar to retrograde condensate gas.

·        The reservoir temperature is always lower than the critical temperature of the fluid.

·        At point 2 the gas is get evolved from oil due to pressure reduction.

·        Compared to black oil, volatile oil produce more gas phase inside the reservoir and during production.

·        Thus volatile oil is said to be high shrinkage crude oil.

   

Condesate gas(Retrograde)

·        Condensate gas is very similar to volatile oils in terms of the colour of the produced oil.

·        The reservoir temperature of a condensate gas reservoir is greater than the critical temperature of the fluid.

·        The retrograde gas exists completely in a gaseous state inside the reservoir at point 1.

·         As the pressure decreases, the condensate exhibits a dew point at point 2.

·        As the reservoir further depletes and the pressure drops, liquid condenses from the gas to form a free liquid inside the reservoir.

                                       

Wet gas

·        Natural gas that contains significant heavy hydrocarbons such as propane, butane and other liquid hydrocarbons is known as wet gas or rich gas.

·        The general rule of thumb is if the gas contains less methane (typically less than 85% methane) and more ethane it is considered as wet gas.

·        Wet gas exists as a gas in the reservoir throughout the reduction in reservoir pressure .No liquid is formed inside the reservoir.

·        However, separator conditions lie within the phase envelope, causing some liquid to be formed at the surface. This surface liquid is normally called condensate, and the reservoir gas is sometimes called condensate-gas.

·         Note that the pressure path line does not enter the phase envelope, meaning no liquid is ever formed inside the reservoir.

             

   

Dry gas

·        Natural gas that occurs in the absence of condensate or liquid hydrocarbons, is called dry gas.

·        It is primarily methane with some intermediates.

·        The gas  present in the reservoir and there is no liquid formed either in the reservoir or at surface.

·        The pressure path line does not enter into the phase envelope in the phase diagram, thus there is only dry gas in the reservoir.

·        Note, the surface separator conditions also fall outside the phase envelope hence no liquid is formed at the surface.

                  

REFERENCES:

 https://ihsmarkit.com/btp/fekete.html

By: Mohammed Zubair Ahmed M

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Horizontal wells and Multilateral Wells

INTRODUCTION:

The aim of this chapter is to introduce some of the design principles required in planning horizontal and multilateral wells. The term designer wells were introduced in this industry primarily to emphasis the complex directional profiles that can be implemented with today’s technology. It is not intended to detail all the equipment and procedures in current use as this subject is developing rapidly. Indeed, some of the equipment which were invented in the early 1990’s are now regarded as old technology. The emphasis will be placed on the more general procedures and equipment which will are in current use.

HORIZONTAL WELLS

By oilfield convention, a horizontal well is defined as a well with an inclination angle of 90^o from the vertical. A vertical well is one with zero inclination angle. In fact, the first horizontal well was drilled by Russians in 1950s.

TYPES OF HORIZONTAL WELLS:

  There are three types of horizontal wells:

1. Short radius.

2. Medium radius.

3. Long radius.

SHORT RADIUS:

The main features of this type are the very high build-up rate of 60 – 150 degrees /100 ft with a radius range of 40-100 ft. This type requires specialized articulated motors to affect the high build angles.

Advantages:

1. Enables sharp turns into thin reservoirs.

2. Both motors driven and drill pipe driven.

3. Laterals can be completed and tied back using special liners.

Disadvantages: 

1. Poor directional control.

2. Special tools and equipment required.

MEDIUM RADIUS:

The build-up rate for this type is usually 8-30^o/100ft with a radius range of 200 to 700 ft. The horizontal drain is usually Between 1000 – 3500 ft.

A typical well profile consists of build-tangent section and a build-horizontal section. Two different BHA’s will therefore be required for this type of well.

The second build-up section should ideally start at the top of the "marker zone" and should reach a maximum of 85-100^o on entry into the reservoir. An angle hold assembly should be used to drill the horizontal section.

LONG RADIUS:

This is the most common type of horizontal wells especially offshore. The build-up rate is usually from 2^o to 6⁰/100ft. The most common BHA used is a steerable system containing a single bent sub with a downhole motor.

Two profiles are in common use:

• A single build-up section terminating in the horizontal section.

• A build-tangent and then a higher build-lateral section.      

WELL PROFILE DESIGN CONSIDERATIONS:

  The following factors should be considered when designing a horizontal well:

• Target definition.

• Single curve Design.

• Double curve design.

TARGET DEFINITION:

       A horizontal well is usually a development well with well-defined geological and reservoir objectives.

The following information is required to define the horizontal target accurately:

1. target co-ordinates.

2. entry point into the reservoir.

3. length of horizontal drain.

4. azimuth range of target.

5. vertical depth range of target.

6. tolerance in vertical depth and displacement.

7. dip of target.

SINGLE CURVE DESIGN:

In this design, the hole angle is built up from zero at the KOP to 90^o at the entry point into the reservoir. If this design is used the buildup tendencies of both the formation and the rotary or steerable BHA should be known in order to avoid missing the target due to excessive or insufficient build up rates. Also, the build-up rate should be selected to land exactly on the target. If the buildup rate is too low the well path will fall below the target and if the buildup rate is too high the well path falls above the target. In both cases, expensive well correction is required.

DOUBLE CURVE DESIGN:

If the buildup rate is too high the well path will be above the reservoir and the well will require redrilling. Similarly, if the build-up rate is too low, the well path will be below the reservoir and the drilling objectives will not be met. The above problems can be solved by having a tangent section below the initial build up curve and then build up to the required angle when reaching a reservoir marker. In some cases, the final angle is actually built up inside the reservoir.

MULTILATERAL WELLS:

A multilateral well is a well that has two or more drainage holes drilled from a primary well bore. Either trunk or branches can be horizontal, vertical or deviated.

Laterals into horizontal hole: A lateral drilled from a horizontal lateral in the horizontal plane.

Laterals into vertical hole: Multiple boreholes drilled from a single wellbore. These can be horizontal or deviated.

Forked: A lateral can be a horizontal portion of a well drilled from the top of the reservoir or an entire well deviated from a given point above the top of the reservoir.

Dual-opposing laterals: A multi-lateral well with two laterals, usually the two laterals are opposed at 180^o emerging from the same wellbore.

Stacked-lateral: Two or more laterals departing from the same wellbore at different depths.

Multi-branched: Two or more laterals emanating from a single point.

ADVANTAGES OF MULTI-LATERALS:

• Increased production from a single well due to increased reservoir exposure.

• Accelerated production.

• Reduction of surface well equipment and surface facility costs.

• Multi-laterals provide flexible selectivity and easy monitoring of oil and gas wells.

• Future plug backs are laid out now avoiding expensive future re-drills.

MAIN APPLICATIONS OF MULTI-LATERAL WELLS:

• Tight reservoirs.

• EOR tools.

• Slot recovery.

• Injection/Production from same well.

• Complex drainage reservoirs.

• Structural delineation from first few wells.

• Exploration wells keepers, if main well was dry.

MULTILATERAL WELL PLANNING CONSIDERATIONS:

The following is a partial list of some of the most important considerations in planning a multilateral well:

1. Drilling methods.

2. Junction design

3. Well control issues.

4. Drilling issues.

5. Milling problems.

6. Completion requirements.

7. Multi-lateral requirements.

8. Abandonment.

REFERENCES:

     Well engineering and construction (Rabia Hussain)

by: Sameer Ahamed N

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India - Post U.S. Sanctions on Iran

           Last November, President Donald Trump, announced new sanctions on Iran limiting its exports. India being one of the largest importers from Iran had six month long waiver along with countries like China, Turkey, South Korea, Japan, Taiwan, Greece and Italy. The waiver expired during the month of May, forcing India to look for other options. India had depended on Iran for almost 10% of its oil consumption. Before the waiver, the imports skyrocketed, leading to least amounts of shipping and transport. Before the waiver expired, many shipments were ordered, some were delayed and reached only after the mid of May.

            After the waiver expired, around the mid of May, it was predicted that the Crude Oil prices would soar, depending on the fact that Iran was one of the major suppliers of  crude oil. On 17^th May, the crude oil was at 4450 INR on the contrary, Indian economy was not very much affected by the waiver. The price suddenly kept decreasing till 6^th June to a price of 3604 INR, which was that months lowest. The drop was due to shipments coming in late from Iran, fortunately aiding to the oil supply for the country. These shipments were able to hold India together and thus India remained unaffected only for this period.

            The shipments ran out after a month, and India had to import again, causing increase in the prices till 26^th of June. The increase was gradual, thanks to OPEC cuts. The OPEC decided to cut down on production, which led to slight stabilizing of Crude oil prices worldwide. This increase went on till it reached a price of 4110 INR form 3604 INR.

           Later, OPEC predicted a decrease in demand, in response reducing supply, resulting in decrease of Crude oil prices worldwide. The prices were constant till 12^th of July. After that, a tropical storm came to India’s rescue; the storm affected Gulf of Mexico dropping oil prices to the lowest of the month, 3825 INR till 18^th July.

            The tremors caused by US sanctions have not affected India fatally until now due to these reasons. The aftershocks of the event are yet to come, and is expected to be brutal for all the Asian countries. This increase will affect macro as well as micro companies as said “Rise in crude prices also impact raw material supply chain of many manufacturing companies as India imports a major portion of its crude requirements. Impact on demand and higher input costs puts pressure on the operating margins and it has to be seen if this extent of price rise will be absorbed or passed on to consumers. Indirectly, there will be additional burden of freight cost for some companies. However, the negative impacts will materialize only if oil continues to sustain at elevated levels," by Vinod Karki, Vice-president (strategy) at ICICI Securities Ltd. 

by: Bilal Hussain

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Primary Recovery Mechanism

PRIMARY RECOVERY:  

It is the recovery mechanism of hydrocarbon from the subsurface reservoir to the surface using the natural energy present in the reservoir as a drive. This natural energy present in the reservoir is mainly responsible for the primary recovery, because due to the pressure difference between the reservoir pressure and the surface pressure (atmospheric pressure) the crude oil present inside the reservoir will flow towards the oil well and reaches the surface. This drive mechanism contributes less than 15% of initial oil-in-place in the reservoir; in case a reservoir is connected to an aquifer then extra pressure support can increase the overall recovery to 40% or even more of the oil-in-place.

There are generally six driving mechanisms that provide natural energy necessary to recover the oil. They are:
·   Rock and Liquid Expansion Drive
·   Gas Cap Drive
·   Solution Gas Drive
·  Water Drive
·  Gravity Drainage Drive
·  Combination Drive

Rock and Liquid Expansion Drive:

When an oil reservoir exists at a pressure greater than its bubble point pressure, then reservoir is called as “under saturated oil reservoir”. At a pressure above the bubble point pressure, crude oil, connate water, and rocks are the only material present in the reservoir. As the reservoir pressure declines, the rocks and fluids expand due to their individual compressibilities. The reservoir rock compressibility is the resultant of two factors they are:

1)    Expansion of the individual rock grains.

2)    Formation compaction.

This driving mechanism is considered as the least efficient driving force and usually results in the recovery of small percentage of the total oil-in-place.

Gas Cap Drive:

In a Gas cap drive reservoir the main source of energy is the expansion of gas cap which is available at the top of the reservoir (i.e. Just above the oil in a reservoir). Due to the ability of the gas to expand, when the reservoir is breached while drilling because of pressure difference the gas starts to expand this provides a natural energy to produce the crude oil from the reservoir. The degree of pressure maintenance depends upon the volume of gas in the gas cap compared to oil volume. It has considerably larger recovery efficiency than depletion drive reservoir. The expected oil recovery ranges from 20% to 40%.

The ultimate oil recovery from a gas cap will vary depending largely on the following parameters:
· Size of the Original Gas Ca
· Vertical Permeability
· Oil Viscosity
· Degree of Conservation of the Gas
· Dip Angle

Solution Gas Drive:

In this drive mechanism the main source of energy is due to the liberation of gas dissolved from the crude oil and the subsequent expansion of the solution gas as the reservoir pressure is reduced. As the pressure falls below the bubble point the gas bubbles are liberated within the microscopic pore spaces. These bubbles expand and force the crude oil out of the pore space. This drive mechanism requires the reservoir rock to be completely surrounded by impermeable barriers. This drive mechanism is least effective method. Ultimate recovery from the solution gas drive reservoir may vary from less than 5% to about 30%. The low recovery from this type of reservoir suggests that a large quantity of oil remains in the reservoir so these kinds of reservoirs are best one for the secondary recovery application.

Water Drive:

In this the drive energy is provided by an aquifer that interfaces with the oil in the reservoir at oil water contact. As a production continues and the oil is extracted from the reservoir the aquifer expands into the reservoir displacing the oil. There are two types of water drive reservoir:
· Bottom Water Drive
· Edge Water Drive

In this type drive mechanism the water is encroaching into the reservoir in a uniform manner nothing can be done to restrict this encroachment, as the water will probably provide the most efficient displacement mechanism possible. The ultimate recovery from the water drive reservoir is much larger than the recovery under any other producing mechanism. Efficiency depends upon the effective flushing action of the water so that it can displace oil and the degree of activity of the water drive. Ultimate recovery normally ranges from 35% to 75% of the original oil-in-place. The 75% recovery from water drive mechanism occurs rarely in a water driven reservoir.

Gravity Drainage Drive:

The density difference between gas, oil and water results in the natural segregation in the reservoir. The reservoir fluids were subjected to the forces of gravity, as evidenced by the relative position of the fluids i.e. gas on top, oil underlying gas, and the water underlying oil. The reservoir pressure decline rate varies depending on the amount of gas conservation. If the gas conserved, and reservoir pressure is maintained, the reservoir would be operating under combined gas cap drive and gravity drainage mechanism. Therefore, for the reservoir to be operating only as a result of gravity drainage, the reservoir would show rapid pressure decline.

There are three important factors that affect ultimate recovery from gravity drainage reservoirs:
· Permeability in the direction of dip
· Reservoir Producing Rates
· Oil viscosity

Where gravity drainage is good or where producing rates are restricted to take maximum advantage of the gravitational force, recovery will be high. There are reported cases (rarely occurs) where recovery from gravity drainage reservoir has exceeded 80% of the initial oil-in-place.

Combination Drive:

     The driving mechanism most commonly encountered is one in which both water and free gas are available in some degree to displace the oil towards the producing wells. There two combinations of driving forces usually present in the combination drive reservoir:
·  Depletion drive and a weak water drive.
·  Depletion drive with a small gas cap and a weak water drive.

In addition, to this gravity segregations can also play an important role in any of these two drives. These types of reservoirs usually experience a relatively rapid pressure decline, when water encroachments and external gas expansion is insufficient to maintain reservoir pressures.

Ultimate recovery from the combination drive reservoir is generally greater than recovery from depletion drive reservoirs but less than recovery from water drive or gas cap drive reservoir. In most combination drive reservoir it will be economically feasible to institute some type of pressure maintenance operation, either gas injection or water injection or combination of both the fluid injections are performed depending upon the availability of the fluids.

REFERENCE:

1.     Standard Handbook of Petroleum & Natural Gas Engineering By William Lyons, Gary Plisga, BS Michael Lorenz.

2.     Reservoir Engineering Handbook by Tarek Ahmed.

3.     Fundamentals of Reservoir Engineering By L.P. Dake.

  https://petrowiki.org/Primary_drive_mechanisms

  https://wiki.aapg.org/Drive_mechanisms_and_recovery

  https://www.slideshare.net/kusrick29/reservoir-primary-recovery-mechanisms

by: Naveen Gokul

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