ELECTRICAL SUBMERSIBLE PUMPING Reference 1. ESP is an easy operation lift method applicable in any location except

In document Drilling and workover best practices (Page 175-181)


6. ELECTRICAL SUBMERSIBLE PUMPING Reference 1. ESP is an easy operation lift method applicable in any location except

where the cost of workover is high.

6.2. ESPs greatest application is in moving large volume of low GOR (<100scf/stb) fluids. They are particularly popular for high rate undersaturated oil wells, high water cut wells and water supply wells.

Their main limitation is gas production but improved downhole separators and procedures can now handle GORs up to 1,000scf/stb.

P-1-M-7100 10.2

6.3. If possible, the installation should be designed to facilitate downhole separation of free gas and vented up the annulus which is necessary when the gas volume exceeds the pump operating limit (typically +/-10% of the total fluid volume). On offshore installations, gas production up the annulus may be a significant problem. Annular safety valves or dual string with SCSSV’s shall be considered.

P-1-M-7100 10.2

6.4. Most pump installations are on the end of tubing and positioned above the perforations or open hole. The motor is situated at the bottom of the assembly so that the well flow around the motor will dissipate the heat generated. If the pump has to be positioned below the interval, a shroud is used to draw the produced fluid down past the motor. Bottom discharge pumps are used in powered dump flood wells.

P-1-M-7100 10.2

6.5. The key to an efficient ESP design is heat removal and insulation material selection for the actual operating temperatures and environment, especially when temperatures are in the region of 250oF. The clearance between the pump and the casing should be small enough that a flow velocity of a minimum of 1ft/sec is achieved.

In large casings, a shroud must be used to provide this rate.

Centralisation of the pump is also critical.

P-1-M-7100 10.2.2

6.6. Cable selection and splicing procedure shall take into account the well temperature and the well fluids characteristic including the presence of corrosion inhibitors.

6.7. Cable failure may occur and require pulling the tubing to repair. High temperature, corrosion and poor handling on splicing lead to cable failure.

6.8. The electric power supply shall be stable to avoid unwanted pump stops.

6.9. A motor electric protection device shall be installed in the main power line to avoid current drop or rise more than 20% of the actual value.

6.10. It is normal procedure to select the largest pump that will fit into the production casing (especially if this was catered for in the planning stage). Small casing or liners will obviously limit the pump size selection.

P-1-M-7100 10.2.1

6.11. Application with variable speed driver reduce starting loads and increase system life and flexibility from around 50 to 190% of nominal rate.

6.12. The ESP design is a complex process, which is normally carried out on computer. The software in use in Eni/Agip Well Area Engineering is PROSPER or AUTOGRAPH.

7. JET PUMPING Reference

7.1. The jet pump uses no moving parts and imparts momentum into the fluid using the Venturi effect with a jet, throat and diffuser. The size of these can be varied to pump volumes of 100-15,000stb/d although free pump systems are limited to 8,000stb/d with 41/2” tubing.

P-1-M-7100 10.3

7.2. The pumps can be installed and retrieved by wireline or pumping method using swab cups, hence providing lower servicing costs.

P-1-M-7100 10.3

7.3. As there is no moving parts, the pump is not as sensitive to damage and lower quality power fluids can be used and can be used in higher GOR wells up to 3,000scf/stb.

P-1-M-7100 10.3

7.4. Pump efficiency is low at 33-66% and large production rates can only be achieved in high rate installations.

P-1-M-7100 10.3

7.5. Initial capital cost is high because topside facilities must be provided to treat the mixture of power and produced fluid.

7.6. Down time in production may be caused by corrosion and abrasive fluid that will damage the nozzle as well as the maintenance of surface equipment.

7.7. Since the production must accelerate to a fairly high velocity to enter the throat, cavitation is a potential problem that shall be considered.

Reference List:

‘Completion Design Manual’ STAP P-1-M-7100


1. DEFINITIONS Reference

1.1. Completion Fluid:

It is the fluid in the well during the installation (or the removal) of the completion (300psi minimum overbalance). The hydrostatic of the completion fluid has to control the formation pressure.

M-1-M-5015 2.1

1.2. Packer Fluid:

It is the fluid in the annulus CSG/TBG above the upper packer after the packer has been set. Packer fluid can be either the same fluid used while running the completion (completion fluid) or any other fluid displaced in the annulus above the upper packer after the completion operation. In some special applications HP wells, Packer fluid could be “non kill weight fluid”.

M-1-M-5015 2.2

1.3. Safety Barrier Status Of Completion Fluid:

The completion fluid continues to be a barrier until its specific gravity remains adequate to the formation pressure.

During well testing, after packer setting, the annulus completion fluid is an indirect barrier because two operations (opening circulating valve and BOP pipe rams shut-in) are required to establish the fluid circulation to kill the well.

M-1-M-5015 2.2

1.4. Safety Barrier Status Of Packer Fluid:

The packer fluid cannot be considered a barrier. Main reasons are:

• Rheological properties and circulating capability cannot be ensured for a long term period.

In evenience of leakage from the tubing string, the tubing pressure could be higher than the hydrostatic pressure in the annulus (whichever is the density of the packer fluid). The pressure accumulated into the annulus could impair the casing integrity (especially in HP/HT wells).

M-1-M-5015 2.2

2. COMPLETION FLUID DUTY Reference 2.1. The completion fluid, usually a brine, is chosen for its compatibility

with the formation and its fluids so as not to cause any formation damage. It should be selected to provide an overbalance at the top of the reservoir. It also must be selected for its stability over long time periods and not suffer from dehydration or deterioration.

P-1-M-7100 7.3.6

2.2. Limit settling of solids if any present.

2.3. Provide carrying capacity to remove solids.

2.4. The information required to make a considered selection may be obtained from the IWIS database (which holds all the data regarding the drilling of the well), well tests carried out earlier and other sources which may be useful in the decision making process.

P-1-M-7100 7.3.6

3. PACKER FLUID Reference

3.1. Packer fluid duty

3.1.1. Limit settling of solids if any present.

3.1.2. Minimise corrosion rate.

3.1.3. Stable with temperature and time.

3.1.4. Environmental and operational safety.

3.2. Packer fluid choice

3.2.1. Water base drilling mud, should be avoided.

3.2.2. Water, Brine or OBM mud should be preferred.


4.1. Brines characteristic should minimise hydration, swelling and / or dispersion of formation clays. When the fluid weight is not a concern typical concentration of the most common brine to inhibit clay hydration are:

4.1.1. Na Cl 5-10 % 4.1.2. Ca Cl2 1-3 % 4.1.3. KCl 1-3 %

4.2. Brine parameters

4.2.1. Brine type at a relevant density shall take into account the following parameters: Freezing point. and Crystallisation temperature Corrosive properties.

4.3. Fluid density variation with temperature, it shall be taken into consideration the reduction of fluid density caused by temperature 4.4. Brine density attainable

4.4.1. Na Cl 1- 1.17 kg/l 4.4.2. Ca Cl2 1 - 1.38 kg/l

4.4.3. Na Cl and Ca Cl2 1.19 - 1.4 kg/l 4.4.4. KCl 1 - 1.16 kg/l

4.4.5. Ca Cl2 and Ca Br2 1.4 - 1.8 kg/l

4.4.6. Solution density is a function of temperature. Thus density at surface conditions may have to increased to obtain desired hydrostatic pressure downhole. Average temperature and relevant density should be adopted.


5.1. Consideration shall be given to brine/formation interactions 5.1.1. The quality of the fluid used during a completion and workover

operation cannot be over-emphasised as the productivity is governed not only by the damage caused by visible contaminants such as solids but also the damage caused by invisible contaminants such as calcium ions, sulphate ions and dissolved iron. It is, therefore, essential that all of these and other similar contaminants are controlled to as low a level as feasible and, wherever possible, completely removed.

P-1-M-7120 4.7.2

5.1.2. Incompatibility with formation fluids.

5.1.3. Entrained solids.

5.1.4. Water blocks.

5.1.5. Emulsion blocks.

5.1.6. Interference with TDT logging readings.

5.1.7. Completion fluid brines and additives may not be compatible with reservoir interstitial water. Rock permeability cam be plugged by precipitates formed when incompatible waters are intermingled. For example barium sulfate will precipitate when solutions containing barium ion and sulphate ion are intermixed. Barium is sometimes present in formation water and sulphate ion is present in seawater and in fluids containing calcium lignosulfunate fluid loss additive or as impurity in some sacked Na Cl.

5.1.8. Completion fluids that are reported solid free can contain solid particles that can cause deep bed formation plugging. Sources of these organic and/or inorganic solids include:

• The base fluid itself

• Impurities in dry salts

• Particulate matter from surface pits and well tubular

• Iron oxides precipitated from solutions containing dissolved oxygen that are circulated downhole


6.1. The prime filtration system is the Diatomaceous Earth filter press with a bag filter system for use as a downstream guard filter. Sometimes, on standby is a low pressure, Cartridge Filter unit.

Both the DE and the cartridge units are capable of filtering down to 2 microns.

P-1-M-7120 4.8

6.2. Solid content in brine shall be minimised by a good cleaning of surface equipment and well tubular and by the use of 2µm filtering unit.

6.3. Diatomaceous earth shall be used when filtering is a need. DE filtering can remove 90% of particles above 2µm. Care must be taken to prevent DE going downhole.

6.4. Absolute cartridge filters must be placed downstream of press filter to act as guard filters.

6.5. The fluids shall be treated to prevent iron oxide precipitation with scavenging oxygen or sequestering oxygen products.

7. FLUID LOSSES Reference

In document Drilling and workover best practices (Page 175-181)