Petrolyte

Drilling mud

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Fractional Distillation Of Crude Oil

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Well intersection

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Chesapeake Energy horizontal drilling method

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The Steps of Oil and Natural Gas Extraction

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Fractional Distillation Of Crude Oil

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Fractional distillation of crude oil is the first step in the production of many of the materials we have come to rely on in modern life.

All our fossil fuels, virtually all our plastics, detergents and commercial alcohols are made from products of this process. Appreciating the process of fractional distillation will further improve our understanding of the sources of fuels and plastics and the limited nature of their availability.

From the Oil Field to the Refinery

The first step is the transport of the crude oil from its natural location to the refinery. Oil drilling occurs both at sea and on land, depending on the size and profitability of the oil deposits located. Fossil fuel formation is the result of environmental conditions in the distant past and the geological processes that have occured since the laying down of the original organic matter from which the oil is formed.

Once obtained from the ground, the oil is transported by ship, truck or pipeline to the refinery.

At the Refinery

Once the oil reaches the refinery the work to separate it into useful products begins. Oil refineries are enormously complex and each part of the distilled oil goes through several stages of processing. However, the very first step is to break up the crude oil.

The crude oil is a mixture of many different chemicals. The majority of these are hydrocarbons, which are molecules made only from the element Carbon and the element Hydrogen. The mixture of hydrocarbons contains both alkane and alkene molecules and the length of the chains vary wildly, from five Carbon atoms long to 60 Carbons or more. Since fuels need to be very specific in terms of the length of the Carbon chain, the different lengths need to be separated. These different length chains are called FRACTIONS.

The boiling point of a Hydrocarbon fraction, which is the temperature at which it evaporates, is dependent on the length of the Carbon chain. Those fractions with shorter chains evaporate more easily than those with longer chains. This explains why petrol, which is mainly made of the 8-Carbon molecule octane, evaporates more easily than engine oil which has carbon chains in the range of 20 or more.

Fractional Distillation Of Crude Oil

In order to separate the different length chains in the crude mix, it is heated to a very high temperature. The temperature is set so that all those fractions with a Carbon chain length of 20 and below are evaporated from the crude mix. The temperature cannot be set higher than this as there is a risk that the lighter fractions will ignite.

The remaining liquid, which is composed of only the heavier fractions, passes to a second location where it is heated to a similar temperature, but at lower pressure. This has the effect of making the heavy Hydrocarbon fractions more likely to evaporate.

How the Distillation Tower Works

The way the Distillation Tower works is by becoming progressively cooler from the base to the top. All the Hydrocarbon fractions start off in gas form, as they have been heated to that point. The gases then rise up the tower.

The gas mixture then encounters a barrier through which there are are only openings into the bubble caps. The gas mixture is then forced to go through a liquid before continuing upwards. The liquid in the first tray is at a cool enough temperature to get the heaviest gas fractions to condense into liquid form, while the lighter fractions stay gaseous.

In this way the heaviest hydrocarbon fractions are separated out from the mixed gas. The remaining gas continues its journey up the tower until it reaches another barrier. Here the bubble cap process is repeated but at a lower temperature than before, which then filters out the next lightest set of fractions.

This process continues until only the very lightest fractions, those of 1 to 4 Carbon atoms, are left. These stay in gas form and are collected at the top of the tower.

The separation of the heavier elements in the second tower follows exactly the same process but at lower pressure.

After the Fractional Distillation Of Crude Oil

The separated fractions still contain a mixture of different hydrocarbons. After their initial separation the fractions require further processing and purification. Treatment of the initial products of the fractional distillation of crude oil also occurs in the refinery. The results of these processes are the products we use in every day life.

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Bullheading Calculation Example

Bullheading is one of the well control methods that involve pumping formation fluids back into formation into a shut-in well.

Components of Pumping Pressure

For the bullheading operation, pumping pressure on surface is equal to summation of all frictional pressure and formation pressure minus hydrostatic pressure (Figure 1). The equation below shows this relationship in a mathematical term.

Pump Pressure = Friction Pressure of Surface Lines + Friction Pressure of Tubing + Friction Pressure Across Perforations + Formation Pressure – Hydrostatic Pressure of Tubing
The pump pressure concept will be utilized for the bull heading calculation.

Figure 1 – Pump Pressure Components

The well information is given below;

Production casing was set at 12,000’MD/12,000’TVD.

Bottom of perforation is at 11,500’MD/11,500’TVD.

Bottom of perforation is at 11,000’MD/11,000’TVD.

End of production tubing is at 11,500’MD/11,500’TVD.

Production packer is at 10,300’MD/10,300’TVD.

Formation fracture gradient is 0.645 psi/ft

Formation pressure gradient is 0.445 psi/ft

Shut in tubing pressure = 2,800 psi

Production casing: 7” OD, 29 ppf, L-80, capacity factor = 0.0371 bbl/ft

Production tubing: 3.5” OD, 9.2ppf, L-80, capacity factor = 0.0087 bbl/ft

Pump output (bbl/stk) = 0.1 bbl/stk

Figure 2 describes the wellbore diagram based on the given information.

Figure 2 – Diagram of the well

Calculations

For the bull heading calculation, reference points for calculation formation pressure, fracture pressure, kill weight mud are based on top of perforation because it gives the most conservative fracture pressure value.

Formation Pressure (psi) = Pressure Gradient (psi/ft) x Top of Perforation TVD (ft)

Formation Pressure (psi) = 0.445 x 11,000 = 4,895 psi

Fracture Pressure (psi) = Fracture Gradient (psi/ft) x Top of Perforation TVD (ft)

Fracture Pressure (psi) = 0.645 x 11,000 = 7,095 psi

Initial Hydrostatic Pressure (psi) = Formation Pressure (psi) – Shut In Tubing Head Pressure (psi)

Initial Hydrostatic Pressure (psi) = 4,895 – 2,800 = 2,095 psi

Initial Average Fluid Density (ppg) = Initial Hydrostatic Pressure (psi) ÷ (0.052 x Top of Perforation TVD (ft))

Initial Average Fluid Density (ppg) = 2,095 ÷ (0.052 x 11,000) = 3.66 ppg

Kill Weight Mud (ppg) = Initial Average Fluid Density + (Shut In Tubing Pressure (psi) ÷ 0.052 ÷ Top of Perforation TVD (ft))

Kill Weight Mud (ppg) = 3.66 + (2800÷ 0.052 ÷11,000) = 8.6 ppg

Maximum Initial Surface Pressure (psi) = Formation Fracture Pressure (psi) –Initial Hydrostatic Pressure (psi)

Maximum Initial Surface Pressure (psi) = 7,095 – 2,095 = 5,000 psi

The below calculation relates to pressure while bullheading.

Maximum End of Tubing Pressure (psi) = Fracture Pressure (psi) – (Kill Weight Mud (ppg) x 0.052 x End of Tubing TVD (ft)) – Initial Average Fluid Density (ppg) x 0.052 x (Top of Perforation TVD (ft) – End of Tubing TVD (ft))

Maximum End of Tubing Pressure (psi) = 7,095 – (8.6 x 0.052 x 10,500) – (3.66 x 0.052 x (11,000 – 10,500)) = 2,304 psi

Maximum pressure when Kill Mud Weight reaches perforation

@ Top of Perforation (11,000 ft TVD)

Maximum Final Pressure (psi) = Formation Fracture Pressure @ top of perforation (psi) – (Kill Weight Mud (ppg) x 0.052 x Top of Perforation TVD (ft))

Maximum Final Pressure (psi) = 0.645 x 11,000 – (8.6 x 0.052 x 11,000)
Maximum Final Pressure (psi) = 2,176 psi

@ Bottom of Perforation (11,500 ft TVD)

Maximum Final Pressure (psi) = Formation Fracture Pressure @ bottom of perforation (psi) – (Kill Weight Mud (ppg) x 0.052 x Bottom of Perforation TVD (ft))

Maximum Final Pressure (psi) = 0.645 x 11,500 – (8.6 x 0.052 x 11,500)
Maximum Final Pressure (psi) = 2,275 psi
The most conservative figure for the maximum final pressure is 2,176 psi.
As you can see, the figure reference to the top of perforation gives the most conservative figure. This is the reason why top of perforation is selected for the calculation.

Volume Pumped in Tubing (bbl) = Tubing Capacity Factor (bbl/ft) x Length of Tubing (ft)

Volume Pumped in Tubing (bbl) = 0.0087 x 10,500 = 91.4 bbl

Stroke Pumped in Tubing (stk) = Volume Pumped in Tubing (bbl) ÷ Pump Output (bbl/strk)

Volume Pumped in Tubing (stk) = 91.4 ÷ 0.1 = 914 strokes

Volume Pumped From End of Tubing to Top of Perforation (bbl) = Casing Capacity Factor (bbl/ft) x (Top of Perforation TVD (ft) –End of Tubing TVD (ft))

Volume Pumped in Tubing (bbl) = 0.0317 x (11,000 – 10,500) = 18.6 bbl

Stroke Pumped From End of Tubing to Top of Perforation (stk) = Volume Pumped in Casing (bbl) ÷ Pump Output (bbl/strk)

Volume Pumped in Tubing (stk) = 18.6 ÷ 0.1 = 186 strokes

Volume Pumped From Top of Perforation to End of Perforation (bbl) = Casing Capacity Factor (bbl/ft) x (End of Perforation TVD (ft) – Top of Perforation TVD (ft))

Volume Pumped in Tubing (bbl) = 0.0317 x (11,500 – 11,000) = 18.6 bbl

Stroke Pumped From Top of Perforation to End of Perforation (bbl)) = Volume Pumped in Casing (bbl) ÷ Pump Output (bbl/strk)

Volume Pumped in Tubing (stk) = 18.6 ÷ 0.1 = 186 strokes

Total Volume Pumped Summary

In order to push all formation fluid back to formation, it is required that the pumping volume must be at least volume from surface to end of perforation.

Pressure Schedule While Bull Heading

This is the same concept as pressure schedule in wait and weight well control method.

Pressure Decreasing in Tubing (psi/required stks) = (Maximum Initial Surface Pressure (psi) – Maximum End of Tubing Pressure (psi)) X Required strokes (stks) ÷ Tubing volume (stk)

For this calculation, 100-strokes is selected.
Pressure Decreasing in Tubing (psi/required stks) = (5,000 – 2,304) x 100 ÷ 914 = 295 psi / 100 stks

Pressure Decreasing in Casing (psi/required stks) = (Maximum Initial End of Tubing Pressure (psi) – Maximum Final Pressure (psi)) X Required strokes (stks) ÷ Volume from End of Tubing to Top of Perforation (stk)

Pressure Decreasing in Casing (psi/required stks) = (2,304 – 2,176) X 100 ÷ 186 = 96psi / 100 stks

Draw the bullhead chart based on this data

The red line is the maximum pressure. If pressure exceeds the red line, a formation will be broken down (fracture zone). The blue line represents a shut in condition. Pressure below the blue line means that the well is in an underbalanced condition (flow zone). The area between the red line and blue line is the safe zone for bullheading operation (Figure 3).

Figure 3 – Bullheading Chart

For safe operation, pumping pressure must be within the bullheading zone (Figure 4).

Figure 4 – Safe Bullheading

The formations may be fractured if pumping pressure exceeds the fracture line (Figure 5).

Figure 5 -Bullheading Operation Exceeding Fracture Pressure

Note: this chart is constructed without accounting for friction pressure. It is the most conservative pressure to prevent fracturing formation.

Accumulator Capacity – Usable Volume Per Bottle

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To find Accumulator Capacity usable volume per bottle we will use Boyle’s Law for ideal gases, which I have listed below:

Boyle’s Law = P1 V1 = P2 V2

With that being said, there are 3 steps that must be utilized in order to complete this calculation. These steps are listed below along with some general guidelines for calculation purposes:

In general, and when addressing Accumulator Capacity usable volume per bottle, we can consider the following data as usable guidelines:

- Volume per bottle = 10 gallons

- Precharge pressure = 1000 psi

- Max pressure = 3000 psi

- Min pressure remaining post activation = 1200 psi

- Pressure gradient of hydraulic fluid = 0.445 psi/ft

NOTE – However, the above are ONLY guidelines and can change!

- Step 1 is to determine the necessary amount of hydraulic fluid necessary to increase pressure from a precharge to a MINIMUM.

Boyle’s Law = P1 V1 = P2 V2

So,

a. 1000 psi x 10 gal = 1200 psi x V2

b. 10,000 / 1200 = V2

c. V2 = 8.33 (nitrogen is compressed from 10.0 gal to 8.33 gal)

d. Then, 10.0 — 8.33 = 1.67 gallons of hydraulic fluid per bottle.

- Step 2 is to determine the necessary amount of hydraulic fluid necessary to increase pressure from a precharge to a

MAXIMUM.

Boyle’s Law = P1 V1 = P2 V2

So,

a. 1000 psi x 10 gals = 3000 psi x V2

b. 10,000 / 3000 = V2

c. V2 = 3.33 (nitrogen is compressed from 10 gal to 3.33 gal)

d. Then, 10.0 — 3.33 = 6.67 gallons of hydraulic fluid per bottle.

-Step 3 is to find the usable volume per bottle, which can be done by using the following formula:

Useable volume per bottle = Total hydraulic fluid per bottle — unused hydraulic fluid per bottle

So,

Useable volume per bottle = 6.67 — 1.67

Useable volume per bottle = 5 gallons

Slug Weight Calculation for Length of Dry Pipe

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There are 3 steps in calculating slug weight ppg for a length of dry pipe.

1. Find length of slug in drill pipe feet -

Slug length feet = slug volume bbls / drill pipe capacity bbls/ft

2. Find Hydrostatic Pressure required for slug drop in drill pipe -

Hydrostatic Pressure psi = MW ppg x .052 x dry pipe in feet

3. Find the slug weight in ppg -

Slug weight ppg = HP psi / .052 / slug length in ft + MW ppg
Now that we know how to calculate slug weight in ppg, let’s do an example

given the following data:

- Desired length dry pipe (3 stands) = 276 feet

- Mud Weight = 12.5 ppg

- Drill pipe capacity (4.5 in) = 0.01422 bbls/ft

- Slug volume = 38 bbls

1. Slug length feet = 38 bbls / 0.01422 bbls/ft

= 2672.29 bbls/ft

2. Hydrostatic Pressure psi = 12.5 ppg x .052 x 276 feet

= 179.40 psi

3. Slug weight ppg = 179.40 psi / .052 / 2672.29 ft + 12.5 ppg

= 13.8 ppg

Slug Calculation in Barrels for a Length of Dry Pipe

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There are 4 steps to take in finding the slug calculation bbls for a Length of DRY Pipe.

Step 1 -

Find the hydrostatic pressure it takes to create a specific drop inside of the drill pipe.

We can find this by using the following formula:

HP psi = Mud Weight ppg x 0.052 x length of DRY pipe in feet

Step 2 -

Find the difference in pressure gradient between the slug weight and mud weight ppg.

We can find this via the following formula:

Pressure Gradient Change psi = (slug weight ppg – mud weight ppg) x 0.052

Step 3 -

Calculate length of the slug in the drill pipe.

We can find this via the following formula:

Slug Length ft = pressure in psi / change in pressure gradient psi-ft

Step 4 -

Calculate the slug volume bbls.

We can find this via the following formula:

slug volume bbls = slug length ft x drill pipe capacity bbl-ft

Now that we know how to find the slug calculation in bbls for a Length of DRY Pipe, let’s do an example give the following data.

- Desired length of dry pipe, 3 stands = 276 ft

- Mud weight = 12.5 ppg

- Drill Pipe Capacity 4.5 in = 0.01422 bbl/ft

- Slug weight = 14.5 ppg

So,

1. HP psi = 12.5 ppg x 0.052 x 276 feet = 179.4 psi

2. Pressure Gradient Change psi = (14.5 ppg – 12.5 ppg) x 0.052 = .104

3. Slug Length ft = 179.4 psi / .104 psi-ft = 1725 ft

4. slug volume bbls = 1725 ft x .01422 bbl-ft = 24.53 bbls

Total Strokes from Kelly to Shale Shaker

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Now let’s figure out how to calculate the “total strokes” it takes for fluid to travel from the Kelly to the Shale Shaker.

The formula to calculate total strokes required to pump from the Kelly to the Shale Shaker is as follows:

Total Strokes = drill string volume bbl + annular volume bbl / pump output bbl-stk

Given the above formula, let’s do an example given the following data -

Drill String Volume bbls – 188.59

Annular Volume bbls – 1960.99

Pump Output bbl/stk – 0.148 @ 95% efficiency

So,

Total strokes = (188.59 + 1960.99) ÷ 0.148

Total strokes = 2149.58 / 0.148

Total strokes = 14524.19

Please NOTE – You will have to first calculate Drill String Volume, Annular Volume, and desired Pump Output before calculating Total Strokes from Kelly to Shale Shaker.

Bottoms Up” or Bit to Surface Strokes

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“Bottoms Up” Strokes = Annular Volume bbls / Pump Output in bbls-stk

Step 1 is to calculate Annular Volume -

The first thing we must to do in order to calculate “Bottoms Up” or Bit to Surface” strokes is to find the Annular Volume.

Annular Volume bbls = (Dh^2 – OD^2) / 1029.4 x Length in feet, where Dh is the hole diameter.

So, and given that we can now calculate Annular Volume, let’s complete a few examples given the following data -

Drill Collar Specs – 8 in OD, 3.25 in ID, 600 feet in length

Drill Pipe Specs – 6 in OD, 4.376 ID, 12225 feet in length

Open Hole Specs – 12.25 in diameter

Casing Specs – 13.625 in, ID = 12.615 in. Set depth = 4650 ft

1. Annular Volume for Drill Collar (open hole) – (12.25^2 – 8^2) / 1029.4 x 600 = 50.16 bbls

2. Annular Volume for Drill Pipe (open hole) – (12.25^2 – 6^2) / 1029.4 x 12225 = 1354.59 bbls

3. Annular Volume for Drill Pipe (cased hole) – (12.615^2 – 6^2) / 1029.4 x 4650 = 556.24 bbls

4. Total Annular Volume = 1960.99 bbls

Step 2 is to calculate “Bottoms Up” or Bit to Surface strokes-

Now that we know the Annular Volume, and given that Pump Output = 0.148 @ 95%, we have all of the information we need to solve “Bottoms Up” or Bit to Surface strokes.

So,

“Bottoms Up” strokes = 1960.99 bbls / 0.148

“Bottoms Up” strokes = 13249.93 strokes

Strokes – Surface to Bit Strokes

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Now let’s calculate Surface to Bit Strokes.

The general formula to calculate Surface to Bit Strokes is as follows:

Surface to bit strokes = drill string volume bbls / pump output in bbl/stk

Step 1 is to calculate Drill String Volume -

- Drill Pipe specs – 6 in OD, 4.356 ID, 9650 feet in lenght

- Drill Collars specs – 8 in OD, 3.5 in ID, 900 feet in lenght

A. Drill Pipe Volume in bbls = (4.356^2 / 1029.4) x 9650 = 177.88 bbls
B. Drill Collar Volume in bbls = (3.5^2 / 1029.4) x 900 = 10.71 bbls

C. To find the total drill string volume we need to add the drill pipe volume in bbls + drill collar in bbls.

Total Drill String Volume = 177.88 bbls + 10.71 = 188.59 bbls

Step 2 is to calculate Surface to Bit Strokes -

If Pump Output = 0.148 @ 95%, then we have all of the information we need to solve.

So,
Surface to Bit Strokes = 188.59 bbls / 0.148

Surface to Bit Strokes = 1274.26 strokes

Annular Volume in Barrels

2014-02-16T09:51:00.004+02:00

Now that we have a good understanding of how to calculate Drill Pipe, Drill Collar, and Drill String volume in bbls, let’s examine how to calculate Annular volume in barrels.

The general formula to calculate Annular Volume in bbls is as follows:

Annular Volume bbls = (Dh^2 – OD^2) / 1029.4 x Length in feet, where Dh is the hole diameter.

So, and given that we can now calculate Annular Volume, let’s complete a few examples given the following data -

Drill Collar Specs – 8 in OD, 3.25 in ID, 600 feet in length

Drill Pipe Specs – 6 in OD, 4.376 ID, 12225 feet in length

Open Hole Specs – 12.25 in diameter

Casing Specs – 13.625 in, ID = 12.615 in. Set depth = 4650 ft

1. Annular Volume for Drill Collar (open hole) – (12.25^2 – 8^2) / 1029.4 x 600 = 50.16 bbls

2. Annular Volume for Drill Pipe (open hole) – (12.25^2 – 6^2) / 1029.4 x 12225 = 1354.59 bbls

3. Annular Volume for Drill Pipe (cased hole) – (12.615^2 – 6^2) / 1029.4 x 4650 = 556.24 bbls

4. Total Annular Volume = 1960.99 bbls

Drill String Volume in Barrels

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Let’s find drill string volume in barrels (bbls) for drill pipe, drill collars, and total drill string volume.

The general formula to find drill string volume is as follows -

Drill string volume in Barrels = ID^2 / 1029.4 x Pipe Length

Now let’s do some examples for drill pipe, drill collar, and drill string total volume given the following data:

- Drill Pipe specs – 6 in OD, 4.356 ID, 9650 feet in lenght

- Drill Collars specs – 8 in OD, 3.5 in ID, 900 feet in lenght

Now given that we already know the formula to solve for DSV is ID^2 / 1029.4 x Pipe Length, let’s figure this out!

1. Drill Pipe Volume in bbls = (4.356^2 / 1029.4) x 9650 = 177.88 bbls

2. Drill Collar Volume in bbls = (3.5^2 / 1029.4) x 900 = 10.71 bbls

3. To find the total drill string volume we need to add the drill pipe volume in bbls + drill collar in bbls.

Total Drill String Volume = 177.88 bbls + 10.71 = 188.59 bbls

The Composition of Petroleum

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Most people presume petroleum to be similar to gasoline or petrol, simply a less pure form, which needs to be refined. In actuality the chemical composition of petroleum in its raw state can vary extremely.

This variation is the reason why petroleum composition differs so much in colour and viscosity between crude oil fields and geographical areas.

Petroleum, or crude oil as it is now usually referred too when raw, contains several chemical compounds, the most prolific being the hydrocarbons themselves which give the petroleum composition its combustible nature.

Although the composition of petroleum will contain many trace elements the key compounds are carbon (93% – 97%), hydrogen (10% - 14%), nitrogen (0.1% - 2%), oxygen (01.% - 1.5%) and sulphur (0.5% - 6%) with a few trace metals making up a very small percentage of the petroleum composition.

The actual overall properties of each different petroleum source are defined by the percentage of the four main hydrocarbons found within petroleum as part of the petroleum composition.

The percentages for these hydrocarbons can vary greatly, giving the crude oil a quite distinct compound personality depending upon geographic region. These hydrocarbons are typically present in petroleum at the following percentages: paraffins (15% - 60%), napthenes (30% - 60%), aromatics (3% to 30%), with asphaltics making up the remainder.

The composition of petroleum is defined as laid out above, and it is this composition which gives the crude oil its properties.

Raw petroleum is usually dark brown or almost black although some fields deliver a greenish or sometimes yellow petroleum. Depending upon the field and the way the petroleum composition was formed the crude oil will also differ in viscosity.

At the extreme ranges petroleum can be almost solid, and required a significant investment of resources to refine into a useable state as anything other than bitumen. At the other end of the scale the petroleum composition can be a clear fluid resembling kerosene or gasoline, needing very little refining to be useable as a fuel.

When discussing the composition of petroleum it is important to note that the compound of the raw petroleum tends to dictate the usage of the refined product. Petroleum is generally measured in volume, and for some composition of petroleum it is not cost effective to refine these into fuel.

A lighter, less dense raw petroleum composition with a compound that contains higher percentages of hydrocarbons is much more profitable as a fuel source. Whereas other, denser petroleum composition with a less flammable level of hydrocarbons and sulphur are expensive to refine into a fuel and are therefore more suitable for plastics manufacturing and other uses.

Unfortunately the worlds reserves of light petroleum (light crude oil) are severely depleted and refineries are forced to refine and process more and more heavy crude oil and bitumen.

In some cases the refining process will need to remove carbon and add hydrogen, adding an extra, costly step to the refining process. This change in compound of the world's energy producing petroleum and the associated rise in refining costs has directly affected the price of gasoline across the world.

Natural Gas - From Wellhead to Burner Tip

2012-01-09T20:19:00.000+02:00

The process of getting natural gas out of the ground, and to its final destination to be used, is a complicated one. There is a great deal of behind-the-scenes activity that goes into delivering natural gas to your home, even though it takes only the flick of a switch to turn it on. This section provides an overview of the processes that allow the natural gas industry to get their product out of the ground, and transform it into the natural gas that is used in your homes and in industry.

The Exploration section outlines how natural gas is found, and how companies decide where to drill wells for it.
The Extraction section focuses on the drilling process, and how natural gas is brought from its underground reservoirs to the surface.
The Production section discusses what happens once the well is drilled, including the processing of natural gas once it is brought out from underground.
The Transport section outlines how the natural gas is transported from the wellhead and processing plant, using the extensive network of pipelines throughout North America.
The Storage section describes the storage of natural gas, how it is accomplished, and why it is necessary.
The Distribution section focuses on the delivery of natural gas from the major pipelines to the end users, whoever they may be.
The Marketing section discusses the role that natural gas marketers play in getting the gas from the wellhead to the end user.

Acidizing Oil and Gas Reservoirs

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1. Introduction

Acid treatments have been applied to wells in oil and gas bearing rock

formations for many years. Acidizing is probably the most widely used work-

over and stimulation practice in the oil industry .

By dissolving acid soluble components within underground rock formations, or

removing material at the wellbore face, the rate of flow of oil or gas out of

production wells or the rate of flow of oil-displacing fluids into injection wells

may be increased.

2. Conventional Acid Systems

A number of different acids are used in conventional acidizing treatments, the

most common are:

• Hydrochloric, HCl

• Hydrofluoric, HF

• Acetic, CH3COOH

• Formic, HCOOH

• Sulfamic, H2NSO3H

• Chloroacetic, ClCH2COOH

These acids differ in their characteristics. Choice of the acid and any additives

for a given situation depends on the underground reservoir characteristics and

the specific intention of the treatment, for example near well bore damage

removal, dissolution of scale in fractures, etc.

The majority of acidizing treatments carried out utilize hydrochloric acid (HCl).

However, the very fast reaction rate of hydrochloric acid, and other acids

listed above, can limit their effectiveness in a number of applications.

All conventional acids including HCl, and organic acids react very rapidly on

contact with acid sensitive material in the wellbore or formation. Wormholing

is a common phenomenon. The rapid reaction means the acid does not

penetrate very far into the formation before it is spent. Conventional acid

systems are therefore of limited effectiveness in treatments where deep acid

penetration is needed. Problems in placing acid are compounded in long

horizontal or directional wells. In these wells it is difficult to achieve truly

uniform placement of acid along the well-bore, which may be several

thousand metres long, let alone achieve uniform stimulation of the

surrounding formation.

There was an early recognition that it was desirable to delay the rate of

reaction of the acid and a variety of techniques have been developed to

achieve this. Patents relating to several of these techniques have been

issued. Further information on these retarded acid systems is given below.

3. Retarded Acid Systems

Methods which have been developed to slow the acidizing process include:

· Emulsifying the aqueous acid s olutions in oil (or solvents such as kerosene

or diesel fuel) to produce an emulsion which is slower reacting .

· Dissolving the acids in a non-aqueous solvent .

· The use of non aqueous solutions of organic chemicals which release

acids only on contact with water .

· The use of solutions of methyl acetate which hydrolyses slowly at very high

temperatures to produce acetic acid .

In addition to these methods, of which emulsifying the acid is probably the

most important, some retardation of the reaction rate can be achieved by

gelling the acid or oil wetting the formation solids.

3.a. Gelled Acids

Gelled acids are used to retard acid reaction rate in treatments such as acid

fracturing. Retardation results from the increased fluid viscosity reducing the

rate of acid transfer to the fracture wall. Use of the gelling agents (normally

water soluble polymers) is limited to lower temperature formations as most

gelling agents degrade rapidly in acid solution at temperatures above 130°F

(55°C) .

Gelling agents are seldom used in matrix acidizing because the increased

acid viscosity reduces injectivity and may prolong the treatment with no net

benefit i.e. the slower injection rate counters the benefit of a reduced reaction

rate.

3.b. Chemically Retarded Acids

These acids are often prepared by adding an oil-wetting surfactant to the acid

in an effort to create a physical barrier to acid transfer to the rock surface. In

order to achieve this the additive must adsorb on the rock surface and form a

coherent film.

Use of these acids often requires continuous injection of oil during the

treatment. At high flow rates and high formation temperatures, adsorption is

diminished and most of these materials become ineffective .

3.c. Emulsified Acids

Emulsified acids may contain the acid as either the internal or the external

phase. The former, which is more common, normally contains 10 to 30

percent hydrocarbon as the external phase and 15% hydrochloric acid as the

internal phase. When acid is the external phase, the ratio of oil to acid is often

about 2:1. Both the higher viscosity created by emulsification and the

presence of the oil can retard the rate of acid transfer to the rock surface.

This reduction in mass transfer rate, and its corresponding reduction in acid

reaction rate, can increase the depth of acid penetration into the rock

formation before the acid reacts with the rock or damaging material .

Use of oil external emulsified acids may be limited by the increased frictional

resistance to flow of these fluids down well tubulars . The presence of

surfactants in the acidizing fluid, to produce the emulsion, can affect the

wetting characteristics of the rock formation i.e. change a water wet rock

surface into an oil wet surface. This can necessitate remedial post acidizing

treatments to restore the rock surface to a water wet state if successful oil

production is to be attained.

4. Types of Acidizing Processes

Acidizing is used to increase production in many situations. The most

important include damage removal, completion and stimulation of horizontal

wells, matrix acidizing, fracture acidizing and gel breaking.

4.a. Damage Removal

Damaged wells are those which suffer a restriction in flow rate. This may be

due to a number of causes, for example, drilling damage or build up of

carbonate scale. Damage may occur at the wellbore face or as a zone of

reduced permeability extending several inches or even feet into the formation

which severely restricts productivity. If the damage can be removed, very

significant increases in production rate can be achieved.

For example, if a damaged zone extends 6 inches into a formation and the

damaged permeability is only 5% of the undamaged permeability, the affected

well will only produce 30% of the production of an undamaged well. Removal

of the damage will therefore result in a 3.3-fold increase in production rate .

Conventional acidizing processes may remove damage up to several inches

into the formation but are generally not effective for treatment of deeper

damage. Success in treatment of deep formation damage requires the use of

highly retarded acids. Arcasolve™ functions as a highly retarded acid suitable

for removal of deep damage.

The importance of damage removal is highlighted by the fact that the Society

of Petroleum Engineers (SPE) now hold regular international conferences

dedicated to this subject .

4.b. Completion and Stimulation of Horizontal Wells

Horizontal drilling is a technique which has been enthusiastically adopted by

the oil industry since about 1988. Because the wellbore has a greater contact

area with the oil bearing zone, much higher rates of production are possible

compared to conventional vertical wells. Productivity at least 2-3 times that of

vertical wells can generally be achieved. Despite higher costs, return on

investment is better than for vertical wells in many circumstances.

The importance of horizontal wells is likely to increase further. The current

trend is towards very long wells which can be up to several km in length.

When bringing these wells into production, the effective clean up of drilling

fluid damage is needed. This is particularly important in low permeability

formations.

Newly drilled horizontal wells normally require acidizing to remove drilling mud

damage before being brought into production. The efficient placement of

conventional acids is critical, especially in long horizontal sections . Due

to their fast reaction rate they need to be placed using coiled tubing, which is

expensive, or using foam, gel or other diversion methods. Significant care

has to be taken over treatment design when using diversion methods and

there may be a problem with gel residues.

The difficulty of applying HCl in extremely long horizontal producing intervals

to uniformly remove drilling damage has been identified by several operators

as a very serious problem with the result being disappointing well productivity

There is a need for improved acidizing methods which are effective for the

removal of drilling fluid damage from long horizontal intervals. Arcasolve™ is

effective for this application.

4.c. Matrix Acidizing

Matrix acidizing involves the use of acid injected at below fracture pressure.

It is normally used for the removal of skin damage associated with work-over,

well killing or injection fluids, and by precipitation of scale deposits in tubulars,

the wellbore or within the formation.

As stated in (4.a.) above, removal of near well bore damage can result in

significant stimulation, by say three-fold. Treatment normally involves

injecting 15% HCl followed by a sufficient afterflush of water or hydrocarbon to

clear all acid from well tubulars. A corrosion inhibitor is added to the acid to

protect tubulars during exposure to acid. Other additives, such as anti-sludge

agents, iron chelating agents, de-emulsifiers and mutual solvents are added

as required for a specific formation.

Matrix acidizing may also be used to increase formation permeability in

undamaged wells. Where damage is thought to exist within the formation, the

aim of the treatment is to achieve more or less radial acid penetration deep

into the formation to increase the formation permeability around the wellbore.

Deep penetration can only be achieved with retarded acid systems.

In undamaged formations even significant permeability increases over a 3 to 6

meter radius around the wellbore will result in less dramatic stimulation than

achieved when removing damage. There is a practical limit of about a 50%

increase in injectivity or productivity of undamaged oil or water wells which

can be achieved using matrix stimulation.

Higher levels of stimulation would probably require the use of uneconomic

volumes of stimulation fluid (acid or acid generating solution). Increases of

less than 50% will probably be the norm. This is because the volume required

to fill an expanding circumference is a squared function. If the depth of

penetration is doubled the required volume increases 4-fold. Attempts to

stimulate extended volumes of a reservoir will show a diminishing return per

unit invested. It is important when designing jobs that a balance be struck

between the volume pumped (cost of job) and the resulting increase in

production.

Use of an acidizing system with a reaction so highly retarded that essentially

no reaction takes place during the time that the acid is being pumped into the

reservoir has been considered in mathematical terms. This hypothetical

system has been proposed as the ultimate for a matrix treatment .

Arcasolve™ (see section 5) approaches such a system.

4.d. Fracture Acidizing

Fracture acidiz ing, also known as acid fraccing is the most widely used

acidizing technique for stimulating limestone or dolomite formations . In an

acid fracturing treatment a pad fluid is injected into the formation at a rate

higher than the reservoir matrix will accept. This rapid injection produces a

Arcasolve Technical Document ATD-B1

build-up in wellbore pressure leading to cracking (fracturing) of the rock.

Continued fluid injection increases the fracture's length and width. Acid

(normally 15% HCl) is then injected into the fracture to react with the formation

and create a flow channel (by etching of the fracture surface) that extends

deep into the formation. This allows more reservoir fluid to drain into the

wellbore along the new fractures once the well is put back on production.

The key to success is penetration of reactive acid along the fracture. This is

more difficult to achieve in acid fraccing than in propped fractures (the other

main form of frac treatment). Acid penetration is particularly important in low

permeability carbonates which are frequently subject to scaling where small

fractures meet larger fractures. Acid fracturing methods which can achieve

deep acid penetration offer tremendous potential to solve scaling problems

The effective length of an acidized fracture is limited by the distance that acid

travels along the fracture before it is spent. This is controlled by the acid fluid

loss, the reaction rate and the fracture flow rate . This problem is

particularly severe when the acid reaction rate is high owing to high formation

temperature.

The acid fluid-loss mechanism is more complex than that of non-reactive

fluids. In addition to diffusive leak off into the formation, flowing acid leaks off

dynamically by dissolving the rock and producing wormholes. Wormholes are

very detrimental in fracture acidizing . They greatly increase the effective

surface area from which leak off occurs and are believed to affect acid fluid

loss adversely. Acid leaks off predominantly from wormhole tips rather than

the fracture face. As wormholing and excessive leak-off occur, the leak-off

rate exceeds the pump rate, and a positive net fracturing pressure cannot be

maintained to keep the fracture open. At this point in the treatment, which may

be as soon as 6 minutes after starting to pump acid, the fracture extension

slows or stops.

Acid fluid loss control has long been a problem in fracture acidizing. The most

common techniques involve use of viscous pads or acid solutions. The

principle behind these is to lay an impermeable filter cake on the fracture face

and minimize wormholing. In practice these filter cakes are relatively

ineffective in controlling acid fluid loss because of the quick penetration by

wormholes and the constant erosion of fracture faces during treatment.

Fluids used in the fracture acidizing process (pad fluid, acid or additives) can

be detrimental to well performance following the job. This can be due to clean

up problems or a reduction in the formation permeability adjacent to the

fracture.

Problems are particularly pronounced in the case of gas wells. A particular

problem is the removal of high viscosity fluids. The time required to achieve

cleanup increases significantly as fluid viscosity increases. For example, in a

gas well in a 0.1 mD permeability formation, a fluid such as oil or water that

has a viscosity of 0.25 cP at reservoir temperature is easily removed from the

Arcasolve Technical Document ATD-B1

formation. Maximum rate is attained after about 3 days. At 25 cP viscosity,

maximum rate is attained after about 20 days. 250 cP fluid is difficult to

remove from the formation and only 24% of the fracture fluid will have been

produced after 400 days of production. Similar increases in cleanup time are

seen as fracture length increases .

Ideally the best acid system for fracturing is one that only etches the fracture

face by dissolution and leaks off into the formation mainly by diffusion [13]. It

is also very desirable to be able to obtain deep penetration along fractures

without resorting to the use of high viscosity components.

4.e. Gel Breaking

Acids are used to break acid sensitive gels used in propped fracture

applications. The use of acid breakers in open hole horizontal well

compilations has recently been demonstrated .

5. Arcasolve™

Arcasolve™ is a patented acidizing method which uses acid precursors

(which are not themselves acidic) in combination with a catalyst. The catalyst

acts on the precursors to produce organic acid (normally acetic acid) in-situ

following placement of the Arcasolve fluid within the wellbore or rock

formation.

Arcasolve™ has a number of significant benefits:

· Deep penetration into the formation can be achieved

· Zonal coverage is excellent

· Uniform placement of acid along long wellbore intervals can be readily

achieved with no fluid loss due to wormholing

· Fluid is very low hazard - biodegradable reactants and acidizing products

ensure minimal safety and ecotoxicity issues in use and disposal

· Corrosion inhibitors are not required

· Fluid is low viscosity allowing rapid clean up post treatment

· Extent of acidizing (quantity of acid, rate of production) can be accurately

controlled in contrast with other acidizing methods

Well test data and the results of independent laboratory evaluations is

available for a number of different Arcasolve™ applications.

6. Use of Arcasolve™ in Acidizing Processes

Arcasolve™ can be used for a large number of acidizing applications including

damage removal, completion and stimulation of horizontal wells, matrix

acidizing, fracture acidizing, gel breaking and stimulation of natural fracture

networks.

Use of Arcasolve™ is a simple procedure which is similar in all applications.

An Arcasolve™ formulation is selected appropriate for the application (to

produce the required amount of acid at a particular rate). The formulation is

mixed at the wellhead and injected at the desired rate to fill the wellbore or the

formation. After placement of the fluid the well is shut in and acid is generated

in-situ. The well is then put on production.

6.a. Use of Arcasolve™ for Damage Removal

Arcasolve can evenly remove near wellbore damage along long intervals. It

can also treat damage deep in the formation including sandstone reservoirs

with deep carbonate scale, with potential for significant production

improvements.

The effectiveness of Arcasolve™ at removing damage to carbonate

formations caused by the use of water based drilling muds has been

demonstrated in an independent study carried out by Stimlab (UK) with

support from the UK DTI. Stimlab is a recognized source of expertise on

Arcasolve Technical Document ATD-B1

acidizing technologies. More recent Stimlab work has demonstrated that

Arcasolve™ is also effective for the removal of oil based drilling mud damage

from carbonate cores. Arcasolve™ may also be useful for the removal of

dolomite (carbonate) weighted drilling muds from sandstone formations.

Removal of drilling damage restores the formation to its undamaged

productivity allowing oil to be produced at its maximum rate. The potential for

the use of Arcasolve™ in remediation of mud damage resulting from drilling,

particularly in horizontal wells (see below) has been clearly demonstrated (see

Examples of Results of Arcasolve treatments). Significant gains in production

have been achieved.

6.b. Completion and Stimulation of Horizontal Wells

Horizontal wells are increasingly being used in oil and gas production and

their importance is likely to increase further. When bringing these wells into

production, the effective clean up of drilling fluid damage along the whole of

the production interval is needed. This is particularly important in low

permeability formations. This can be readily achieved with Arcasolve™.

Because the Arcasolve fluid is not reactive when being placed, the wellbore

can be filled before most of the acid is generated. Leak off into the formation

is regulated by the filter cake or other damage and there is no fluid loss due to

wormholing. Subsequent generation of acid ensures that all of the production

interval is treated, with the same amount of acid being supplied to all parts of

the wellbore. This results in effective cleanup.

The whole of the interval can be treated without a need for coiled tubing or

diverters which are required for conventional hydrochloric acid treatments.

In addition to mud damage removal, if sufficient Arcasolve™ fluid is used to fill

the wellbore and penetrate some distance into the formation an increase in

the permeability of the formation can be achieved. The matrix stimulation of

the formation can stimulate production above that which would be obtained

even with complete damage removal.

Effective damage removal and matrix stimulation reduce payback periods and

lead to increases in the net present value (NPV) of the well.

6.c. Use of Arcasolve™ in Matrix Acidizing

Matrix acidizing was the initial applic ation for Arcasolve™. The permeability

of carbonate rock formations is increased over a 10 to 20 foot radius around

the wellbore, by placing the fluid and allowing the produced acid to dissolve a

portion of the rock. Increase in the permeability allows a greater rate of

production of oil or gas (or greater rate of injection of fluids in the case of

injector wells used for pressure maintenance).

Very deep penetration of acid can be achieved if needed and the use of gels

and surfactants, which might cause cleanup or wettability reversal problems is

not needed.

6.d. Use of Arcasolve™ in Gel Breaking

Gel breaking is another application for Arcasolve™ for which additional

patents are granted or pending. Arcasolve™ can be incorporated into acid

sensitive gel systems such as borate cross linked guar so as to produce a

complete break within a specific, desired time frame.

Please contact Cleansorb if you wish to discuss this application further.

6.e. Stimulation of Natural Fracture Networks using Arcasolve™

Arcasolve™ may be used to effectively stimulate natural fracture networks.

Deep penetration along fractures can be achieved before acid is produced.

Laboratory evaluation to date has been positive. Field trials are currently

being conducted in the Austin Chalk.

7. Comparison of Arcasolve™ with Other Acid Systems

7.a. Comparison to HCl

The rapid reaction between HCl and carbonate limits the penetration of HCl

into carbonate formations. It is unlikely that HCl will remove deep formation

damage and HCl is not suitable for deep matrix acidizing. Arcasolve™ can

penetrate deeply and is suitable for both applications.

HCl is particularly corrosive to steel, aluminium or chromium plated

equipment which are components of many pumps. Expensive corrosion

inhibitors need to be used in these circumstances. This cost becomes very

significant when treating formations at higher temperatures due to the

requirement for higher doses of corrosion inhibitor. Corrosion inhibitors are

not required with Arcasolve™.

The toxicity of corrosion inhibitors presents problems when disposing of spent

HCl based acidizing fluid.. Arcasolve™ presents minimal chemical

safety/toxicity problems to well process operators and is recognized to be a

"green" product.

It is possible to use Arcasolve for drilling damage removal from horizontal

wells by introducing Arcasolve™ through the drill string following drilling

operations. Use of coiled tubing, commonly used to place HCl is not needed

with Arcasolve™.

There is no requirement for additives to be added to Arcasolve™ to retard the

rate of reaction. In particular high viscosity additives are not required, which

present problems in applications such as fracture acidizing. Clean up

following Arcasolve™ treatments is straightforward.

7.b. Comparison to Emulsified HCl

Emulsified HCl involves the use of both organic solvents and HCl. Both are

hazardous before and after mixing . The emulsion may not give a good

distribution of acid downhole.

The use of certain organic solvents in gas and water injection wells may

reduce the gas or water relative permeability and permanently reduce well

production. The use of a water based acidizing system with good penetration

would be preferred for such wells allowing much easier control over the

wetting characteristics of the formation.

Use of oil-external emulsified acids may be limited by the increased frictional

resistance to flow of these fluids down well tubulars.

Arcasolve™ is lower hazard and does not suffer from injectivity or wettability

problems.

7.c. Comparison to Acetic Acid

Although acetic acid reacts more slowly than HCl, the reaction is still

sufficiently rapid to give the problems summarized in section 2. In contrast,

generation of acetic acid in-situ using Arcasolve™ allows acid to be delivered

much deeper into the formation and better placement of acid along extended

well-bores. Arcasolve is therefore more effective, and offers a much higher

degree of control of acidizing than acid formulations based on acetic acid or

other organic acids.

How are Crude Oil and Natural Gas Produced?

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Production is the operation that brings hydrocarbons to the surface and prepares them for processing. Production begins after the well is drilled. The mixture of oil, gas and water from the well is separated on the surface. The water is disposed of and the oil and gas are treated, measured, and tested. Production operations include bringing the oil and gas to the surface, maintaining production, and purifying, measuring, and testing.

completing the well

After a well has been drilled, it must be completed before oil and gas production can begin. The first step in this process is installing casing pipe in the well.

Oil and gas wells usually require four concentric strings of pipe: conductor pipe, surface casing, intermediate casing, and production casing. The production casing or oil string is the final casing for most wells. The production casing completely seals off the producing formation from water aquifers.

The production casing runs to the bottom of the hole or stops just above the production zone. Usually, the casing runs to the bottom of the hole. In this situation the casing and cement seal off the reservoir and prevent fluids from leaving. In this case the casing must be perforated to allow liquids to flow into the well. This is a perforated completion. Most wells are completed by using a perforated completion. Perforating is the process of piercing the casing wall and the cement behind it to provide openings through which formation fluids may enter the wellbore.

Tubing and Packers

After cementing the production casing, the completion crew runs a final string of pipe called the tubing. The well fluids flow from the reservoir to the surface through the tubing. Tubing is smaller in diameter than casing-the outside diameter ranges from about 1 to 4-1/2 inches.

A packer is a ring made of metal and rubber that fits around the tubing. It provides a secure seal between everything above and below where it is set. It keeps well fluids and pressure away from the casing above it. Since the packer seals off the space between the tubing and the casing, it forces the formation fluids into and up the tubing.

Subsurface Safety Valve

A subsurface safety valve is installed in the tubing string near the surface. The valve remains open as long as fluid flow is normal. When the valve senses something amiss with the surface equipment of the well, it closes, preventing the flow of fluids.

Multiple Completions

The operator uses a multiple completion when one wellbore passes through two or more zones with oil and gas in them. Usually, a separate tubing string width packers is run in for each producing zone.

Wellhead

The wellhead includes all equipment on the surface that supports the various pipe strings, seals off the well, and controls the paths and flow rates of reservoir fluids. All wellheads have at least one casinghead and casing hanger, usually, a tubing head and tubing hanger, and a Christmas tree.

Each string of casing usually hangs from a casinghead, a heavy steel fitting at the surface. Metal and rubber seals in the casinghead prevent fluids from moving within the wellhead or escaping to the atmosphere. Each casing head also has a place for a pressure gauge to warn of leaks.

The tubing head supports the tubing string, seals off pressure between the casing and the inside of tubing and provides connections at the surface to control the flowing liquid or gas. The tubing head often stacks above the uppermost casinghead. Like the casingheads, it has outlets to allow access to the annulus for gauging pressure or connecting valves and fittings to control the flow of fluids.

Wells are equipped with a group of valves and fittings called a Christmas tree. The valves and fittings are used to regulate, measure, and direct the flow of hydrocarbons from the well.

Gauges measure pressure in the casing and in the tubing. Valves control the flow of hydrocarbons from the well. The choke controls the rate of production from the well.

Starting the Flow

Before oil production can begin the drilling mud must be removed from inside the casing. Salt water is pumped into the tubing to remove this mud. In some cases the well has too much salt water in the tubing and some must be pumped out. Production flow can also be started by forcing high-pressure gas into the tubing.

Sometimes after starting the flow the well does produce at a fast enough rate. In this situation, flow from the reservoir may be increased by stimulation. Stimulation is one of several processes that enlarge or create channels in the reservoir rock so that the oil and gas can move through it and into the well.

Gas wells are generally completed in the same way as oil wells except that natural gas usually flows without help.

Drive Mechanisms

Natural Drive

After the well has been completed, the hydrocarbons flow from the reservoir to the surface. In the first stage of a reservoir's producing life, pressure from the reservoir forces the hydrocarbons from the pores in the formation, moves them to the well, and up to the surface. This stage of production is known as primary recovery. The three principal primary recovery drive mechanisms are water drive, gas drives, and gravity drainage.

Water drive uses the pressure exerted by water below the oil and gas in the formation to force hydrocarbons out of the reservoir. The greater the depth of the reservoir the higher the pressure. Water drive is the most efficient natural drive and can be used to produce 50% or more of the oil in the reservoir.

The two types of gas drives are dissolved-gas drives and gas-cap drives. These drives use the pressure of gas in the reservoir to force oil out of the reservoir and into the well. In a dissolved-gas drive the hydrocarbons in the oil are light enough that they become gaseous when the well releases pressure from the reservoir. This is similar to dissolved carbon dioxide in a soft drink. If the can or bottle is shaken, the soda gushes out when the can is opened. When the well is opened the lighter hydrocarbons turn into gases and the oil and gas flow up to the surface. The amount of oil recovered from dissolved-gas drives varies from 5 to 30%.

In some reservoirs, gas may be present in a space on top of the oil. This gas cap provides pressure to push the oil into the well. As the level of oil in the reservoir drops, the gas cap expands and continues to push the oil into the well and up to the surface. The more space the oil leaves empty in the porous reservoir rock, the more the gas expands to take its place. The pressure of a gas-cap drive depletes more slowly than a dissolved gas drive. From 20 to 40% of the oil in the reservoir is recovered with gas-cap drives.

Artificial lift

Artificial lifting methods are used when the pressure from natural reservoir drive decreases to the point where the well stops producing. Artificial lift uses pumps and gas injection.

The most common method of pumping oil in land-based wells is beam pumping. The beam pumping unit sits on the surface and creates an up-and-down motion to a string of rods called sucker rods. The top of the sucker rod string is attached to the front of the pumping unit and hangs down inside the tubing. A sucker rod pump is located near the bottom of the well. The walking beam's reciprocating action moves the rod string up and down to operate the pump.

Gas lift describes methods in which a gas is used to increase oil well production. Gas lift-dissolved-gas drive or gas-cap drive may provide natural drive to the reservoir. Natural gas can also be injected into the well to lift the oil artificially on the same principle.

The natural gas makes oil in the wellbore column much lighter in weight. Because the liquid column is lighter, it exerts less pressure on the bottom of the well. With the pressure lower at the bottom, the pressure remaining in the reservoir becomes sufficient to push reservoir fluids to the surface through the tubing.

Gas lift is common when a supply of gas is economical and available and when the amount of petroleum it will lift justifies the expense.

Enhance Recovery Techniques

After a well has used up the reservoir's natural drives and gas lift or pumps have recovered all the hydrocarbons possible, statistics show that 25 to 95% of the original oil in the reservoir may still be there. This amount of oil can be worth recovering if prices are high enough. The major methods of improved oil recovery are waterflooding, gas injection, chemical flooding, and thermal recovery. These techniques are used when production from the well starts to decrease.

Waterflooding is a technique where water is injected into the formation using wells that have ceased production. The injected water enters the reservoir and displaces some of the remaining oil toward producing wells in the same reservoir. The producing wells then pump up the oil and water. Several injection wells surround each producing well. Water flooding is the least expensive and most widely used secondary recovery method.

Production can also be increased by injecting gas, such as natural gas or nitrogen, into the reservoir. The injected gas expands to force additional volumes of oil to the surface.

Chemical flooding uses special chemicals in water to push oil out of the formation. These chemicals act as surfactants that cause the oil and water to mix and breaks the oil into tiny droplets that can be more easily moved through the reservoir to the well.

Thermal recovery is used when the oil is so viscous, or thick, that it cannot flow through the reservoir and into a well. When the oil is heated, its viscosity is decreased and the flow increases. Recovery techniques that use heat are called thermal processes or thermal recovery.

Steam Drive or steam injection involves generating steam on the surface and forcing this steam down injection wells and into the reservoir. When the steam enters the reservoir, it heats up the oil and reduces its viscosity. The heat from the steam also causes hydrocarbons to form gases which also increases flow. The gases and steam provide additional gas drive and the hot water also moves the thinned oil to production wells.

Another way to use heat in a reservoir is fire flooding, or in situ (in-place) combustion. In fire flooding, the crew ignites a fire in place in the reservoir. They inject compressed air down an injection well and into the reservoir. A special heater in the well starts a fire. As the fire burns, it begins moving through the reservoir toward production wells. Heat from the fire thins out the oil around it, causes gas to vaporize from it, and changes water in the reservoir to steam. Steam, hot water, and gas all act to drive oil in front of the fire to production wells.

Offshore Operations

Offshore operations are fundamentally the same as onshore operations with the major difference being in the complexity of the production sites and hence their costs. Offshore production facilities are self-contained production sites. The platforms are semi-permanent structures from which many wells are drilled and completed.

Surface Mining Methods

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Strip mining (see coal mining), open-pit (or open-cut) mining, and quarrying are the most common mining methods that start from the earth's surface and maintain exposure to the surface throughout the extraction period. The excavation usually has stepped, or benched, side slopes and can reach depths as low as 1,500 ft (460 m). In strip mining, the soft overburden, or waste soil, overlying the ore or coal is easily removed. In open-pit mining the barren rock material over the ore body normally requires drilling and blasting to break it up for removal. A typical mining cycle consists of drilling holes into the rock in a pattern, loading the holes with explosives, or blasting agents, and blasting the rock in order to break it into a size suitable for loading and hauling to the mill, concentrator, or treatment plant. There the metals or other desired substances are extracted from the rocks .

Quarrying

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quarrying, open, or surface, excavation of rock used for various purposes, including construction, ornamentation, road building, and as an industrial raw material. Rock that has been quarried is commonly called stone. Quarrying methods depend chiefly on the desired size and shape of the stone and its physical characteristics. For industrial use (e.g., limestone for preparing cement), as the aggregate in concrete, or for road beds, the rock is shattered. Explosives are detonated in a series of holes drilled in the rock in a pattern designed to yield the greatest amount of fracturing. The rock fragments may be further reduced in crushing machines and sorted according to size by screening. For building stone, rocks that do not shatter are separated by blasting; for softer rocks or when explosives cannot be used (e.g., because they would disturb adjacent workings), a process known as broaching, or channeling, is used. In this process a line of holes is drilled perpendicular to the joints or cleavage planes of a formation; wedges are inserted into the holes and hammered until the stone splits off. This method was probably used in ancient times, notably by the Incas and the Egyptians. Much quarrying of ornamental stone today is done by using pneumatically operated channelers. After the vertical cuts have been made, gadding machines (working on the same principle) are used to make horizontal cuts. Wedges are then used to split off the long blocks, which are subdivided and removed. Wire saws are also used; these consist of several pulleys over which passes an endless steel wire. Holes are drilled in the rock, each hole being made large enough to accommodate a pulley and the shaft to which it is attached. The wire, extending from one pulley to another, presses down against the rock between them. As the cut is deepened by the constantly moving wire the pulleys are continuously lowered into the holes.

coal mining

2011-06-17T10:13:00.003+03:00

coal mining, physical extraction of coal resources to yield coal; also, the business of exploring for, developing, mining, and transporting coal in any form. Strip mining is the process in which the overburden (earth and rock material overlying the coal) is removed to expose a coal seam or coal bed. Excavators either dispose of the overburden or store the waste material for replacement after the coal has been extracted. Once exposed, the coal is usually removed in a separate operation. Surface soil is often stripped separately and spread back onto the reclaimed surface. The environment can also be protected by seeding or planting grass or trees on the fertilized restored surface of a strip mine. The term strip mining is most often used in reference to coal mining, although the process may also be used to extract certain metallic ores as well. Sometimes the terms open-pit, open-cast, or surface mining are used in the same sense, although they usually refer to metalliferous mining or the mining of other minerals. Underground coal mining is the extraction of coal from below the surface of the earth. The coal is worked through tunnels, passages, and openings that are connected to the surface for the purpose of the removal of the coal. Mechanical equipment breaks the coal to a size suitable for haulage. Alternatively, the coal is drilled, and the resultant holes are loaded with explosives and blasted in order to break the coal to the desired size. In order to protect the miners and equipment in an underground coal mine, much attention is paid to maintaining and supporting a safe roof or overhead ceiling for the extraction openings. Long-wall mining is a method of underground mining believed to have been developed in Shropshire, England, near the end of the 17th cent. A long face, or working section, of coal, some 600 ft (180 m) in length, is operated at one time. The miners and machinery at the working face are usually protected by hydraulic jacks or mechanical props which are advanced as the coal is extracted. The excavated, or gob, area is either allowed to cave in, or is filled in by waste material called stowing. The Anderton shearer is a widely used coal cutter and loader for long-wall mining. It shears coal from the face as it moves in one direction and loads coal onto an armored conveyor as it travels back in the opposite direction. It is ordinarily used for coal seams greater than 3.5 ft (9.1 cm) in thickness.

shaft sinking

2011-06-17T10:02:00.001+03:00

shaft sinking, excavation from the surface of an opening in the earth. Shafts, which are generally vertical, are usually distinguished from tunels, which are horizontal. Little difficulty is experienced in shaft sinking through solid rock, which contains little water. When loose, water-bearing strata have to be contended with, careful shoring and sealing of the shaft lining become necessary, and pumping facilities are needed. Shafts are usually circular or rectangular and are generally lined with wood, masonry, concrete, steel, or cast iron. Shafts sunk in loose water-bearing soils, where there is great external pressure on the shaft sides, are nearly always circular; rectangular shafts with wood lining are often used in mining work, as the shafts are frequently of a temporary nature. Shaft sinking through rock is generally accomplished by blasting. When the loose surface material has been removed, holes are drilled, and the charges are placed and are fired by electricity. The broken rock is removed and the process is repeated. In an ordinary rectangular shaft the lining consists of timbers 8 or 12 in. (20 or 30 cm) square placed horizontally around the shaft. Shafts of a more permanent nature are generally circular in form and lined with cast iron or with concrete masonry 1 to 2 ft (30–61 cm) thick, built in sections as the work advances. When excessive quantities of water are met with, cast-iron tubbing is sometimes used. This consists of heavy cast-iron rings made in segments, with flanges for connecting, and bolted together in place. Cement grout is forced into the space between the outside of the tubbing and the surrounding earth to form a seal. Shaft sinking by the freezing process in very watery soil is accomplished by sinking pipes in the area to be excavated and circulating brine at low temperature in them until the earth is frozen and hard so that it can be excavated in the same manner as rock. In the grouting method, liquid cement is forced into the water-bearing earth under very high pressure. On mixing with the water, the cement solidifies the adjacent area, and it is removed by drilling and blasting as with rock.

Mining techniques / Coal extraction methods

2011-06-17T09:07:00.000+03:00

Due to different geological formations different techniques were developed and improved to extract coal. From the earliest bell pit method to modern drift, opencast, and deep mining extraction methods.

Bell pit

The name bell pit comes from the shape of the excavation, with a narrow vertical shaft sunk into the coal or iron ore seam, which was then opened out into a small chamber. Little timber was used, so once the roof became unsafe, the pit was abandoned and another shaft sunk nearby. Coal was cut by using picks and shovels. Man and coal were transported by a basket. Candles or lamps were used for illumination. As indicated in the photograph this is the earliest system of underground mining.

Open cast

The top soil and sub soil is stripped and stored. Coal is then mined, and once operations are finished, the void is back filled with overburden, sub soil and top soil. Ground contours are graded. The Potteries coalfield occurs in a syncline (dish shaped structure). At the edges coal is near the surface, which enables open-cast methods of extraction to be used.

Drift

Inclined roadways were driven to exploit shallow coal which would be uneconomic to be worked by shafts. Due to the geology some of the North Staffordshire coal seams, the drift mine was introduced to extract the coal. The photograph shows the 1260 yard long main intake drift at Silverdale which 16ft wide, 12ft high and equipped with a 48in conveyor belt capable of discharging 750 tonnes of coal an hour.

Deep mine

At the centre of the syncline, coal occurs at much greater depths and therefore it is more economic to sink a shaft for the extraction of the coal.

Drilling mud composition

2011-03-13T21:03:00.010+02:00

Drilling mud, also known as drilling fluid, is a product which is used in the process of drilling deep boreholes. These holes may be drilled for oil and gas extraction, core sampling, and a wide variety of other reasons. The mud can be an integral part of the drilling process, serving a number of functions.

One of the most critical roles of drilling mud is as a lubricant. Drilling generates tremendous friction, which can damage the drill or the formation being drilled. Drilling mud cuts down on the friction, lowering the heat of drilling and reducing the risk of friction-related complications. The mud also acts as a carrier for the materials being drilled, with material becoming suspended in the mud and then being carried up the drill to the surface.

Using drilling mud protects the stability of a borehole by controlling variables such as friction and pressure. Different muds are needed for different circumstances, and the selection and formulation of mud is managed by a mud engineer. This engineer determines the correct viscosity level for the drilling mud, and adjusts factors such as density of the mud as well. Water, oil, and gas-based muds can all be used, with products ranging from true muds made with materials like bentonite clays to synthetic drilling fluid.

Drilling mud is recirculated throughout the drilling process. As it rises to the surface, it passes through screens which trap the materials from the borehole, before being cycled back into the system which delivers mud to the head of the drill bit. This recirculation process is designed to cut down on waste by reusing as much mud as possible. Depending on the materials being drilled, several screens may be needed to trap the materials, and sometimes the materials themselves are also coated in mud, which means that they will need to be cleaned even after filtration.

drilling fluid functions
-cuttings removal
-suspension of cuttings
-release of cuttings at surface
-transmission of hydraulic power to the drilling bit
-minimising formation damage
-reducting filtration rate
-cooling and the lubrication of the drill bit and drill string
-buoyancy support of the drill string
-corrosion prevention
-data logging

Table1

Composition of a typical bentonite gel water based mud ,density 1300kg/m3. Components added to 1 barrel of water : (bbl=barrel, pps=pounds per barrel); CMC :(carboxymethylcellulose)

component	quantity	Mass(kg)	Volume(L)	%mass	%volume
Water	1 bbl	159	1588,99	65,33	84,92
Bentonite	20 ppb	9,1	9,07	3,73	4,85
Caustic soda	0,5 ppb	0,23	0,22	0,9	0,12
Soda ash	0,5 ppb	0,23	0,10	0,9	0,5
High viscosity cmc	1,5 ppb	0,68	0,47	0,28	0,25
Low viscosity cmc	3,5 ppb	1,59	1,09	0,65	0,58
barite	160 ppb	72,58	17,28	29,82	9,23

Table 2

Composition of a typical oil based mud density 1318 kg/m3 , salinity 22.5%, oil to water ratio 65:35. components combine to give a total volume of one barrel.(bbl: barrel; ppb:pounds per barrel; gpb: gallons per barrel)

	quantity	Mass(kg)	volume(L)	%mass	%volume
Base fluid	0,5 bbl	64,63	83,31	30,37	52,40
viscosifier	5 ppb	2,26	1,40	1,08	0,88
Emulsifier 1	0,8 ppb	2,89	3,02	1,38	1,90
Emulsifier 2	0,4 ppb	1,49	1,51	0,71	0,95
Lime	5 ppb	2,26	1,00	1,08	0,63
water	0,30 ppb	47,15	47,22	22,50	29,70
Clca2	30,2 ppb	13,70	3,35	6,54	2,11
barite	167,9 ppb	76,15	18,16	36,34	11,42