What is Cement Bond Log (CBL)?

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The Cement Bond Logging tools have become the standard method of evaluating cement jobs. They indicate how good the cement bond is. A cement bond log (CBL) documents an evaluation of the integrity of cement job performed on an oil well. It is basically a sonic tool which is run on wireline. Similar to a ringing bell, when no cement is bonded to the casing, pipe  is free to vibrate (loud sound). When the casing is bonded to hard cement, casing vibrations are attenuated proportionally to bonded surface.

CBL Measurement Principle:

The basic tool configuration of CBL-VDL log is composed by One Transmitter and Two Receivers: the first Receiver is located 3 ft. from the Transmitter and is used for CBL Measurement. The second Receiver is located 5 ft. from the Transmitter and is used for Variable Density Log (VDL).

NB: CBL-VDL logging tools MUST be centralized.

The following video explains the basics of Cement Bond Log:

NB: API 10TR-1 is an API standard for Cement Sheath Evaluation.

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Pressure Gradient

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Pressure and depth:

“Pressure and Depth” is the FUNDAMENTAL relationship in the oil industry. Your understanding of the concept is crucial. The easiest way to calculate pressure from depth is to use the pressure gradient of the given fluid.

Pressure gradients for incompressible fluids have units of pressure/depth. For example, psi/ft, bar/m.

Pressure gradient seems difficult, but it is simply using the density of the fluid and converting units:

The density of pure water is 1000 kg/m3. To convert to gradient:

  • 1 kg = 2.2 pounds
  • 1 m = 39.37 inches
  • 1 m = 3.28 feet

0.433 is the gradient for pure water (SG = 1) in Imperial units, remember it.

NB: Specific Gravity is always relative to pure water.

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Advantages and Disadvantages of ESP Systems

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Advantages & Disadvantages of Electrical Submersible Pumping Systems

From Tables 10-5(a) – 10-5(j), 10-6(a) – 10-6(i), 10-7(a) – 10-7(l)

Artificial Lift Selection, SPE Handbook

Artificial Lift – Design Considerations and Overall Comparisons (Clegg, et al., 12/1993)

Category

Consideration for ESP’s
Capital cost ·    Relatively low capital cost if electric power available. 

·    Costs increase as horsepower increases.
Downhole equipment ·    Requires proper cable in addition to motor, pumps, seals, etc. 

·    Good design plus good operating practices are essential.
 

Operating efficiency

(Hydraulic HP/Input HP)

 ·     Good for high rate wells but decreases significantly for < 1000 BFPD. 

·     Typically total system efficiency is about 50% for high rate wells but for < 1000 BPD, efficiency typically <40%. 

·     Can be as high as 60% for large ID equipment.
Flexibility ·     Poor for fixed speed. 

·     Requires careful design. 

·     VSD provides better flexibility.
Miscellaneous problems ·     Requires a highly reliable electric power system. 

·     System very sensitive to changes downhole or in fluid properties.
Operating costs ·     Varies. 

·     If high HP, high energy costs. 

·     High pulling costs result from short run life especially in offshore operation. 

·     Repair costs often high.
System reliability ·     Varies. 

·     Excellent for ideal lift cases.

·     Poor for problem areas (very sensitive to operating temperatures and electrical malfunctions).
Salvage value ·     Fair. 

·     Some trade in value. 

·     Poor open market values.
System (Total) ·     Fairly simple to design but requires good rate data. 

·     System not forgiving. 

·     Requires excellent operating practices. 

·     Follow API RP’s in design, testing, and operation. 

·     Each well is an individual producer using a common electric system.
Usage/outlook ·     An excellent high rate artificial lift system. 

·     Best suited for <200 0F and >1000 BFPD rates. 

·     Most often used on high water cut wells. 

·     Used on about 5% of US lifted wells.
Casing size limits

(Restricts tubing size)

 ·     Casing size will limit use of large motors and pumps. 

·     Avoid 4.5” casing and smaller. 

·     Reduced performance inside 5.5” casing depending on depth and rate.
Depth limits ·     Usually limited to motor HP or temperature. 

·     Practical depth about 10,000 feet.

·     1000’ – 10000’ TVD is typical, Max is 15,000 ‘ TVD.
Intake capabilities

(Ability to pump with low pressures at pump intake)

 ·     Fair if little free gas (i.e. >250 PSI pump intake pressure). 

·     Poor if F = 666*(Qg/Ql)/Pip > 1.0

Where: Pip: intake psi; Qg: gas vol; Ql: liquid vol @ intake conditions.

·     5% gas at low pressures can cause problems.
Noise level ·     Excellent. 

·     Very low noise. 

·     Often preferred in urban areas if production rate high.
Obtrusiveness ·     Good. 

·     Low profile but requires transformer bank.
Prime mover flexibility ·     Fair. 

·     Requires a good power source without spikes or interruptions. 

·     Higher voltages can reduce losses.
Surveillance ·     Fair. 

·     Electrical checks but special equipment needed otherwise.
Relative ease of well testing ·     Good. 

·     Simple with few problems. 

·     High water cut and high rate wells may require a free water knock out (three-phase separator).
Time cycle and pump off controllers application ·     Poor. 

·     Soft start and improved seal/ protectors recommended.
Corrosion/scale handling ability ·     Fair. 

·     Batch treating inhibitor only to intake unless shroud is used.
Crooked/deviated holes ·     Good.

·     Few problems.

·     Limited experience in horizontal wells.

·     Requires long radius wellbore bends to get through.

10° typical,

0 – 90° < 10° / 100 build angle maximum.

·     However must set in section 0 – 2° max deviation.
Duals application ·     No known installations.

·     Larger casing required.

·     Possible run & pull problems.
Gas handling ability ·     Poor for free gas (i.e. >5% through pump).

·     Poor if F = 666 * (Qg/Ql)/Pip > 1.0

Where: Pip: intake psi; Qg: gas vol; Ql: liquid vol, @ intake conditions.

·     Rotary gas separators helpful if solids not produced.
Offshore application ·     Good.

·     Must provide electrical power and service pulling unit.
Paraffin handling capability ·     Fair.

·     Hot water/oil treatments, mechanical cutting, batch inhibition possible.
Slim hole completions

(2 7/8″ tubing, casing)

 ·     No known installations.
Solids/sand handling ability ·     Poor.

·     Requires <100 – 200 PPM solids for standard construction.

·     200 – 2000 ppm possible with special bushings, stage materials, coatings, and thrust supporting bearings or fixed pumps employed.

·     A maximum of about 5000 ppm might be possible depending on pump and sharpness and angularity of sand.
Temperature limitation ·     Limited to <2500F for standard & <4000F for special motors & cable.

·     100 – 275°F typical.
High viscosity fluid handling capability ·     Fair.

·     Limited to as high as 1000 cp.

·     Depends on economics.   (~>7-9°API)

·     Increases HP and reduces head.

·     Potential solution is to use “core flow” with 20% water.
High volume lift capabilities ·     Excellent.

·     Limited by needed HP and can be restricted by casing size.

·     In 5.5” casing can produce 4000 BFPD from 4000 feet W/240 HP.

·     Tandem motors increase HP & operating costs.

200 – 20,000 bpd typical, ~30,000 bpd max.

52,000 bpd, shallow, 10.25” equip has been done.
Low volume lift capabilities ·      Generally poor.

·      Lower efficiencies and high operating costs <400 BFPD.

 

Step 9 – Variable Speed Submersible Pumping System

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Compared to conventional ESP installations with constant motor speeds, installations running at variable frequencies have several advantages. The most important benefit of a Variable Speed Submersible Pumping System is the wide flexibility of the variable frequency ESP system that permits perfect matching of the lift capacity of the ESP system and the well’s productivity. Therefore, it operates over a much broader range of capacity, head, and efficiency.

NB: Variable Frequency Drive basics (also, named: Variable Speed Drive) are presented and discussed in the article “Variable Frequency Drive Basics”.

Since a submersible pump motor is an induction motor, its speed is proportional to the frequency of the electrical power supply. This relationship between variables involved in pump performance (such as head, flow rate, shaft speed) and power is known as “Affinity Laws” (also called “Pump Laws”).

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Step 8 – Downhole and Surface Accessory Equipment

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This article “Downhole and Surface Accessory Equipment” is the step 8 of the nine-step procedure to design an ESP with an efficient and cost-effective performance. The required downhole and surface accessory equipment are discussed and recommended practices are highlighted.

Downhole Accessory Equipment:

  • Motor Lead Extension (MLE):

API RP 11S4 defines the Motor Lead Extension as a “special power cable extending from the pothead on the motor to above the end of the pump where it connects with the power cable. A low-profile cable (flat configuration) is usually needed in this area due to limited clearance between the pump housing and the well casing”. It is recommended to select a length at least 6 ft. (1.8 m) longer than the upper end of the pump. The length of MLE has to be select in a way to avoid a splice over a tubing collar. Doing so could allow the cable to catch on the wellbore casing and damage the equipment.

  • Banding Cable Protectors:

Cable protectors are used to protect the Motor Lead Cables from damage during installation, operation and pulling. The figures below show an example of cable protectors.

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