ESP Professional Design Manual

Complete Guide & Reference Documentation

Version 2.1.5 | Last Updated: November 17, 2024

Introduction 9-Step Methodology Gas Handling PVT Calculations Packer Constraint Pressure Standards Q&A Resources

Introduction

What is This System?

The ESP Professional Design & Analysis System is a comprehensive web-based engineering tool for designing, analyzing, and optimizing Electrical Submersible Pump (ESP) systems for oil and gas production wells.

             Industry-standard calculations | PVT correlations | Gas handling recommendations | Performance analysis | Professional reports
        

Who Should Use This?

👨‍🔧

Production Engineers

Design and optimize ESP systems for production wells

👨‍💻

ESP Design Engineers

Complete equipment selection and performance analysis

👨‍🎓

Engineering Students

Learn ESP design methodology with real calculations

🏢

Service Companies

Professional tool for client proposals and designs

Key Features

9-Step Design Methodology Standing's PVT Correlations PI-Based Pressure Analysis Gas Handling Recommendations GVF Analysis Pump Depth Optimization Equipment Database PDF Reports

ESP Design Methodology (9 Steps)

Industry Standard: This system implements the industry-standard 9-step ESP design methodology used by major service companies worldwide (Baker Hughes, Schlumberger, Weatherford).

Step 1: Composite Specific Gravity ✅

📌 Purpose

Calculate the weighted average density of the produced fluid mixture (oil + water). This is essential for accurate hydrostatic pressure calculations.

Oil Specific Gravity from API

SG_oil = 141.5 / (API + 131.5)

Where: API = API gravity (°API)
Range: Typical crude oil 10-50 °API
Note: Higher API = lighter oil (lower SG)

Composite Specific Gravity

SG_comp = (WC/100) × SG_water + (1 - WC/100) × SG_oil

Where:
• WC = Water Cut (%)
• SG_water = Specific gravity of water (typically 1.0-1.1)
• SG_oil = Specific gravity of oil (from API formula)
Purpose: Represents actual fluid mixture entering pump

Hydrostatic Pressure

P_hydrostatic = 0.433 × SG_comp × ΔDepth_ft

Where: ΔDepth_ft = (Datum - Pump Intake Depth) × 3.28084

Constant 0.433: psi per foot of water column (1.0 SG)
ΔDepth: Vertical distance from datum (reference depth) to pump intake
Sign Convention: Positive when pump is below datum (usual case)

Important: Datum is typically the top of perforations or mid-perforations. Ensure consistent depth reference throughout calculations.

💡 Example Calculation

// Given Data:
API = 35°
Water Cut (WC) = 30%
SG_water = 1.05
Datum = 3950 m
Pump Intake Depth = 3000 m

// Step 1: Calculate Oil SG
SG_oil = 141.5 / (35 + 131.5)
SG_oil = 141.5 / 166.5
SG_oil = 0.8498

// Step 2: Calculate Composite SG
SG_comp = (30/100) × 1.05 + (1 - 30/100) × 0.8498
SG_comp = 0.315 + 0.5949
SG_comp = 0.9099

// Step 3: Calculate Depth Difference
ΔDepth = 3950 - 3000 = 950 m
ΔDepth_ft = 950 × 3.28084 = 3116.8 ft

// Step 4: Calculate Hydrostatic Pressure
P_hydrostatic = 0.433 × 0.9099 × 3116.8
P_hydrostatic = 1228.6 psi
        

Step 2: PI-Based Pressure Analysis ✅

📌 Purpose

Calculate flowing pressures and verify pump depth optimization using Productivity Index (PI) from well test data.

             Key Concept: PI (Productivity Index) is the rate of production per unit pressure drawdown. It's measured from well tests and represents well productivity.
        

Productivity Index (PI)

PI = Q / (P_r - P_wf) [bpd/psi]

Where:
• Q = Flow rate (bpd)
• P_r = Reservoir pressure at datum (psi)
• P_wf = Flowing bottomhole pressure at datum (psi)
Source: From well test data or IPR curve
Typical Range: 0.5 - 5.0 bpd/psi (depends on reservoir)

Flowing Bottomhole Pressure (Pwf)

P_wf = P_r - Q / PI

Physical Meaning: Pressure at datum depth during production
Location: At reservoir/perforation depth, NOT at pump
Use: Calculate for both minimum and maximum flow rates

Pump Intake Pressure (PIP)

PIP = P_wf - P_hydrostatic

Physical Meaning: Actual pressure at pump suction/intake
Critical Check: PIP must be > Bubble Point Pressure
Why: If PIP < Pb, free gas forms → affects pump performance

Critical Check: PIP vs Bubble Point
If PIP < P_bubble: Free gas will be present at pump intake
→ Requires gas handling equipment (Gas Handler or Separator)
→ PVT calculations must account for two-phase flow
→ Single-phase correlations are NOT valid

📊 Drawdown Analysis

Drawdown

Drawdown = P_r - P_wf

Physical Meaning: Pressure drop causing fluid to flow from reservoir to wellbore
Maximum Allowable: Typically 400-500 psi (to avoid formation damage)
Optimization: If drawdown exceeds limit, pump must be lowered or flow rate reduced

Drawdown (psi)	Status	Recommendation	Risk Level
< 300	✅ Excellent	Current depth optimal	Low
300 - 430	✅ Good	Acceptable, monitor performance	Low
430 - 500	⚠️ Caution	Consider lowering pump depth	Medium
> 500	❌ Critical	MUST lower pump depth or reduce flow	High

💡 Example: Pump Depth Optimization

// Given Data:
P_reservoir = 5050 psi (at 3950m datum)
PI = 1.3 bpd/psi (from well test)
Q_desired = 1800 bpd (maximum flow rate)
Current pump depth = 3000 m
Datum = 3950 m
SG_comp = 0.9099 (from Step 1)

// Step 1: Calculate Pwf at desired flow
Pwf_desired = 5050 - (1800 / 1.3)
Pwf_desired = 5050 - 1384.6
Pwf_desired = 3665.4 psi

// Step 2: Calculate Hydrostatic
ΔDepth = 3950 - 3000 = 950 m = 3116.8 ft
P_hydrostatic = 0.433 × 0.9099 × 3116.8
P_hydrostatic = 1228.6 psi

// Step 3: Calculate PIP
PIP_desired = 3665.4 - 1228.6
PIP_desired = 2436.8 psi

// Step 4: Check Drawdown
Drawdown = 5050 - 3665.4
Drawdown = 1384.6 psi ⚠️ EXCEEDS LIMIT!

// Step 5: Recommendation
If Drawdown > 430 psi:
  → Lower pump depth to reduce hydrostatic
  → Or reduce maximum flow rate
  → Or accept higher drawdown with monitoring plan
        

Step 3: PVT Properties ✅

See detailed section below: PVT Calculations

Step 4: Gas & Volume Calculations ✅

See detailed section below: Gas Handling Equipment Selection

Steps 5-9: Coming Soon 🔜

Under Development: The following steps are currently being implemented and will be added to this manual soon:

Step 5: Discharge Pressure (Hazen-Williams)

Calculate pressure at pump discharge accounting for tubing friction losses using Hazen-Williams equation.

Step 6: Total Dynamic Head (TDH) Refinement

Finalize TDH calculation including net lift, friction losses, wellhead pressure, and drawdown component.

Step 7: Pump Selection & Stage Calculation

Select appropriate pump model and calculate number of stages required based on TDH and flow rate.

Step 8: Power Calculations

Calculate Hydraulic HP, Brake HP, and Motor HP with appropriate safety factors.

Step 9: BEP-Based Final Selection

Optimize pump selection based on Best Efficiency Point (BEP) and operating range.

PVT Calculations (Standing's Correlations)

Historical Note: Standing's correlations (1947) are among the most widely used PVT correlations in the petroleum industry. Developed from California crude oil data, they provide excellent accuracy for a wide range of oil properties.

Solution Gas-Oil Ratio (Rs)

📌 What is Rs?

Solution GOR (Rs) is the volume of gas dissolved in oil at specific pressure and temperature conditions. When pressure drops below bubble point, gas comes out of solution as "free gas".

             Physical Meaning: At high pressures (above bubble point), gas molecules are dissolved IN the oil like CO₂ in a closed soda bottle. When pressure drops (below bubble point), gas escapes to form bubbles - this is "free gas".
        

Standing's Correlation for Rs (1947)

Rs = 0.8 × [(P_pip × 10^{(0.0125×API)}) / (18 × 10^{(0.00091×T°F)})]^1.20482

Where:
• Rs = Solution GOR (scf/STB - standard cubic feet per stock tank barrel)
• P_pip = Pump Intake Pressure (psi gauge)
• API = API gravity of crude oil (°API)
• T°F = Temperature at pump depth (°Fahrenheit)

Temperature Conversion: T°F = T°C × 1.8 + 32
Valid Range: API 16-58°, Temperature 100-258°F, Pressure 132-5673 psi

Critical Note: Rs is calculated at PUMP INTAKE PRESSURE (PIP), not reservoir pressure. If PIP < Bubble Point, gas will separate from oil, and the actual dissolved gas will be less than total GOR.

💡 Understanding Free Gas vs Solution Gas

Parameter	Definition	Calculation	Significance
Total GOR	Total gas-oil ratio from production test	Measured from separator (scf/STB)	Includes ALL gas (dissolved + free)
Solution GOR (Rs)	Gas dissolved IN oil at pump conditions	Standing's correlation at PIP	Stays dissolved, flows WITH oil
Free Gas	Gas that separates as bubbles	Free Gas = Total GOR - Rs	Forms gas phase, affects pump performance

💡 Example Calculation: Solution GOR

// Given Data:
PIP = 2437 psi (from Step 2)
Temperature = 95°C at pump depth
API = 35°
Total GOR = 700 scf/STB (from production test)
Bubble Point = 1800 psi

// Step 1: Convert Temperature to Fahrenheit
T_F = 95 × 1.8 + 32
T_F = 171 + 32
T_F = 203°F

// Step 2: Calculate Components of Rs Formula
Numerator:
  P × 10^(0.0125×API) = 2437 × 10^(0.0125×35)
  = 2437 × 10^0.4375
  = 2437 × 2.738
  = 6673.1

Denominator:
  18 × 10^(0.00091×T_F) = 18 × 10^(0.00091×203)
  = 18 × 10^0.18473
  = 18 × 1.530
  = 27.54

// Step 3: Calculate Rs
Rs = 0.8 × (6673.1 / 27.54)^1.20482
Rs = 0.8 × (242.3)^1.20482
Rs = 0.8 × 446.7
Rs = 357.4 scf/STB

// Step 4: Calculate Free Gas
Free Gas = Total GOR - Rs
Free Gas = 700 - 357.4
Free Gas = 342.6 scf/STB ⚠️ Significant free gas present!

// Step 5: Check Pressure vs Bubble Point
PIP (2437 psi) > Bubble Point (1800 psi) ✓
Interpretation: Although PIP > Pb, free gas exists because 
pressure has dropped from reservoir conditions during production.
        

Oil Formation Volume Factor (Bo)

📌 What is Bo?

Oil Formation Volume Factor (Bo) represents how much oil expands when brought from reservoir conditions to surface (stock tank) conditions. It accounts for dissolved gas volume and thermal expansion.

             Physical Meaning: 1 barrel of oil at reservoir conditions becomes Bo barrels when gas evolves and oil expands. Bo is always ≥ 1.0. Example: Bo = 1.15 means 1 STB of oil occupies 1.15 barrels downhole.
        

Standing's Correlation for Bo (1947)

Bo = 0.972 + 0.000147 × [Rs × (SG_gas/SG_oil)^0.5 + 1.25×T°F]^1.175

Where:
• Bo = Oil formation volume factor (reservoir barrels / stock tank barrel)
• Rs = Solution GOR at pump conditions (scf/STB)
• SG_gas = Gas specific gravity (relative to air, typically 0.6-0.9)
• SG_oil = Oil specific gravity = 141.5 / (API + 131.5)
• T°F = Temperature (°Fahrenheit)

Typical Range: 1.0 - 1.8 rb/stb (most oils: 1.1 - 1.5)
Constraint: Bo must be ≥ 1.0 (oil cannot shrink at reservoir conditions)

💡 Example Calculation: Bo

// Given Data (continuing from Rs example):
Rs = 357.4 scf/STB
SG_gas = 0.75 (from gas analysis)
API = 35°
T_F = 203°F

// Step 1: Calculate SG_oil
SG_oil = 141.5 / (35 + 131.5)
SG_oil = 141.5 / 166.5
SG_oil = 0.8498

// Step 2: Calculate Inner Term
Factor = Rs × (SG_gas / SG_oil)^0.5 + 1.25 × T_F
Factor = 357.4 × (0.75 / 0.8498)^0.5 + 1.25 × 203
Factor = 357.4 × (0.8824)^0.5 + 253.75
Factor = 357.4 × 0.9394 + 253.75
Factor = 335.7 + 253.75
Factor = 589.45

// Step 3: Calculate Bo
Bo = 0.972 + 0.000147 × (589.45)^1.175
Bo = 0.972 + 0.000147 × 1183.6
Bo = 0.972 + 0.174
Bo = 1.146 rb/stb

// Physical Interpretation:
1 STB of oil = 1.146 barrels at pump conditions
Oil expansion = 14.6% due to dissolved gas and temperature
        

Gas Formation Volume Factor (Bg)

📌 What is Bg?

Gas Formation Volume Factor (Bg) converts gas volume from standard conditions (14.7 psia, 60°F) to actual downhole conditions (high pressure, high temperature).

Real Gas Equation for Bg

Bg = 5.05 × Z × (T°F + 460) / P_psia

Where:
• Bg = Gas formation volume factor (bbl/Mscf - barrels per thousand standard cubic feet)
• Z = Gas compressibility factor (dimensionless, typically 0.8-0.95 for ESP applications)
• T°F = Temperature (°Fahrenheit)
• P_psia = Absolute pressure = P_gauge + 14.7 psi

Constant 5.05: Unit conversion factor
Standard Assumption: Z = 0.85 for typical ESP gas conditions
Note: Higher pressure → smaller Bg (gas compresses)

💡 Example Calculation: Bg

// Given Data:
PIP_gauge = 2437 psi
T_F = 203°F
Z = 0.85 (standard assumption)

// Step 1: Convert to Absolute Pressure
P_psia = PIP_gauge + 14.7
P_psia = 2437 + 14.7
P_psia = 2451.7 psia

// Step 2: Convert Temperature to Rankine
T_Rankine = T_F + 460
T_Rankine = 203 + 460
T_Rankine = 663°R

// Step 3: Calculate Bg
Bg = 5.05 × 0.85 × 663 / 2451.7
Bg = 2843.36 / 2451.7
Bg = 1.160 bbl/Mscf

// Physical Interpretation:
1000 scf of gas = 1.160 barrels at pump conditions
Gas is compressed to ~8.6 times smaller volume than at surface
        

📊 Complete Volume Breakdown at Pump Conditions

// Given Production Rates (at surface/stock tank):
Total Liquid Rate = 1800 bpd
Water Cut = 30%
BOPD (oil) = 1800 × 0.70 = 1260 bpd
BWPD (water) = 1800 × 0.30 = 540 bpd
Total GOR = 700 scf/STB
Free Gas = 342.6 scf/STB (calculated above)

// PVT Factors:
Bo = 1.146 rb/stb
Bg = 1.160 bbl/Mscf

// Volume Calculations at Pump:

Oil Volume:
V_oil = Bo × BOPD
V_oil = 1.146 × 1260
V_oil = 1444 bpd (oil expands downhole)

Water Volume:
V_water = BWPD (water is incompressible)
V_water = 540 bpd

Free Gas Volume:
Total gas = 700 × 1260 / 1000 = 882 Mscf/d
Solution gas = 357.4 × 1260 / 1000 = 450.3 Mscf/d
Free gas = 882 - 450.3 = 431.7 Mscf/d

V_gas = Free Gas × Bg
V_gas = 431.7 × 1.160
V_gas = 501 bpd (free gas volume at pump)

Total Volume at Pump:
V_total = V_oil + V_water + V_gas
V_total = 1444 + 540 + 501
V_total = 2485 bpd

Gas Void Fraction (GVF):
GVF = V_gas / V_total × 100
GVF = 501 / 2485 × 100
GVF = 20.2% ⚠️ Gas handling equipment REQUIRED!
        

Phase	Surface Rate	Volume Factor	Downhole Volume	% of Total
Oil	1260 bpd	Bo = 1.146	1444 bpd	58.1%
Water	540 bpd	Bw = 1.0	540 bpd	21.7%
Free Gas	431.7 Mscf/d	Bg = 1.160	501 bpd	20.2%
TOTAL	1800 bpd	-	2485 bpd	100%

Gas Handling Equipment Selection

Why Gas Handling Matters: Free gas at pump intake drastically reduces ESP efficiency and can cause pump damage. GVF > 10% requires specialized gas handling equipment. GVF > 50% makes ESP uneconomical - consider gas lift instead.

Industry-Standard GVF Thresholds

GVF Range	Status	Without Packer	With Packer	Industry Standard
< 10%	✅ Acceptable	Standard ESP	Standard ESP	Takacs (2009): "ESP handles natural gas separation"
10% - 25%	⚠️ Moderate	Gas Separator (preferred)	Gas Handler (REQUIRED)	Schlumberger: "Gas Separator if annulus available"
25% - 50%	❌ High	Advanced Gas Separator + Handler	Tandem Gas Handlers	Baker Hughes: "Requires advanced gas handling"
> 50%	⛔ Critical	ESP NOT RECOMMENDED - Consider GAS LIFT		Industry Consensus: "ESP uneconomical"

Gas Handling Equipment Types

🌀

Rotary Gas Separator

Function: Vents free gas to ANNULUS
Efficiency: 80-90% gas removal
Requirement: Open annulus (NO PACKER below separator)
Best For: 10-30% GVF without packer

⚙️

Rotary Gas Handler

Function: Processes gas WITH liquid through pump
Types: Charge-type, Disc-type
Requirement: Works WITH packer
Best For: 10-40% GVF with packer installed

🔄

Tandem Gas Handlers

Function: Multiple handlers in series
Efficiency: Handles up to 45-50% GVF
Configuration: 2-3 handlers stacked
Best For: High GVF with packer (30-50%)

🎯

Advanced Separator + Handler

Function: Separator removes bulk, handler processes remainder
Efficiency: Up to 95% gas removal
Requirement: NO packer
Best For: 25-45% GVF without packer

⚠️ CRITICAL: Packer Constraint

FUNDAMENTAL RULE:
WITH PACKER → CANNOT USE GAS SEPARATOR → MUST USE GAS HANDLER

Why Packer Prevents Gas Separator Use?

             Physical Principle: A gas separator works by venting separated gas UP through the annulus to surface. A packer SEALS the annulus below its depth. No vent path = No gas separator functionality.
        

📊 Visual Comparison: With vs Without Packer

✅ WITHOUT PACKER - Gas Separator Works

     SURFACE
        ↑
        ║  ← GAS FLOWS UP
        ║     (to surface or gas line)
        ║
    ┌───╨───┐
    │  GAS  │ ← Separated Gas
    │  SEP  │
    └───┬───┘
        │  ← Liquid to Pump
        ↓
    ┌───────┐
    │  PUMP │
    └───────┘
        │
    ═══════════ PERFORATIONS
        │
    RESERVOIR

❌ WITH PACKER - Gas Separator CANNOT Work

     SURFACE
        X  ← ANNULUS SEALED
        ║     (no flow path!)
        ║
   ╔════════════╗
   ║  PACKER   ║ ← SEALS ANNULUS
   ╚════════════╝
        X  ← GAS TRAPPED!
        X
    ┌───╨───┐
    │  GAS  │ ← Gas has nowhere to go
    │  SEP  │    SEPARATOR FAILS!
    └───┬───┘
        │  ← Gas+Liquid to Pump
        ↓     (GAS NOT REMOVED)
    ┌───────┐
    │  PUMP │ ← Pump gets gas anyway!
    └───────┘

Decision Tree: Equipment Selection

STEP 1: Check GVF
├─ GVF < 10% → Standard ESP (no special equipment)
│
├─ GVF 10-50% → STEP 2: Check Packer
│  │
│  ├─ NO PACKER INSTALLED:
│  │  ├─ GVF 10-25% → Gas Separator (PREFERRED)
│  │  ├─ GVF 25-40% → Gas Separator + Gas Handler
│  │  └─ GVF 40-50% → Advanced Separator + Tandem Handlers
│  │
│  └─ PACKER INSTALLED:
│     ├─ GVF 10-25% → Gas Handler (REQUIRED)
│     ├─ GVF 25-40% → Tandem Gas Handlers (2 units)
│     └─ GVF 40-50% → Tandem Gas Handlers (3 units) + Consider Gas Lift
│
└─ GVF > 50% → ESP NOT RECOMMENDED - Use GAS LIFT
        

Quick Reference: Packer Impact

Scenario	Packer Status	Gas Separator	Gas Handler	Explanation
Low GVF (< 10%)	Doesn't Matter	➖	➖	Standard ESP sufficient, no special equipment needed
Moderate GVF (10-25%)	NO Packer	✅ PREFERRED	📌 Optional	Gas Separator preferred (vents to annulus)
Moderate GVF (10-25%)	Packer Installed	❌ IMPOSSIBLE	✅ REQUIRED	Annulus sealed → Gas Separator cannot vent
High GVF (25-50%)	NO Packer	✅ + Handler	✅	Combined solution for maximum gas removal
High GVF (25-50%)	Packer Installed	❌ IMPOSSIBLE	✅ TANDEM (2-3 units)	Multiple gas handlers in series required
Very High GVF (> 50%)	Any	⛔ ESP NOT RECOMMENDED		Consider Gas Lift System instead of ESP

Industry References

Takacs (2009) - "Electrical Submersible Pumps Manual"

"Gas separators require an open annulus to vent separated gas to surface. If a packer is installed below the gas separator, the separated gas has no escape path and the separator becomes ineffective. In such cases, a rotary gas handler that processes gas with the liquid must be used instead."

✓ Recommended GVF limit for standard ESP: 10%
✓ Gas Separator effective range: 10-30% GVF (without packer)

Schlumberger REDA ESP Guidelines

"When production packers are installed, the annulus below the packer is sealed from surface. This eliminates the use of conventional gas separators that rely on venting gas to the annulus. Rotary gas handlers must be specified for these applications as they handle gas-liquid mixtures through the pump."

✓ Packer installations: Always specify gas handler, never gas separator
✓ Handler efficiency: 70-85% gas volume reduction

Baker Hughes Centrilift Manual

"Production packers seal the annulus and prevent communication between the wellbore annulus above and below the packer. Since standard gas separators discharge separated gas into the annulus, they are incompatible with packer completions. Gas handlers are designed to process gas within the production stream and are the correct choice for packer applications."

✓ Tandem gas handlers for GVF > 25% with packer
✓ Maximum recommended GVF with ESP: 50%

Industry Standards & Best Practices

Recommended References

📕

Takacs (2009)

"Electrical Submersible Pumps Manual"
Comprehensive ESP design, selection, and operation. Industry bible for ESP engineers.

📗

Brown (1980)

"The Technology of Artificial Lift Methods"
Volume 3: ESP systems. Classical reference for production engineering.

📘

API Recommended Practice 11S2

"Recommended Practice for Electric Submersible Pump Testing"
Industry standard for ESP performance testing and acceptance criteria.

📙

SPE Monograph 24

"Petroleum Production Systems"
Michael Economides et al. - Complete production engineering including ESP design.

Performance Standards

Parameter	Recommended Range	Acceptable Range	Critical Limits
Pump Efficiency	60-75%	50-60%	< 40% (redesign)
Motor Load	70-90%	50-70% or 90-100%	< 50% or > 110%
Operating Frequency	55-65 Hz	45-55 Hz or 65-70 Hz	< 40 Hz or > 75 Hz
PIP vs Bubble Point	PIP > Pb + 200 psi	PIP > Pb	PIP < Pb (free gas)
GVF at Pump	< 10%	10-25% (w/ equipment)	> 50% (use gas lift)
Drawdown	< 300 psi	300-430 psi	> 500 psi (damage risk)

Design Best Practices

DO: Always use maximum flow rate for equipment sizing (conservative design)

DO: Include 10-20% safety factor in motor HP selection

DO: Check PIP vs bubble point - critical for free gas determination

DO: Verify packer status before recommending gas separator

DO: Select pump operating point near BEP (Best Efficiency Point)

DON'T: Use gas separator with packer installed - it won't work!

DON'T: Ignore high GVF (> 25%) - requires specialized equipment

DON'T: Exceed maximum drawdown limits - causes formation damage

DON'T: Operate pump far from BEP - reduces efficiency and run life

Questions & Answers

Common Questions

Q1: Why is Rs calculated at pump intake pressure and not reservoir pressure?

A: Because Rs represents the gas ACTUALLY dissolved in oil at the specific pressure and temperature where the pump operates. As fluid flows from reservoir to pump intake, pressure drops. If pressure drops below bubble point during this journey, gas comes out of solution. The Rs we calculate at PIP tells us how much gas is STILL dissolved when fluid enters the pump - the rest is "free gas" that must be handled by gas handling equipment.

Example: Reservoir pressure = 5000 psi (all gas dissolved), PIP = 2400 psi (< bubble point) → Some gas has already separated during production → Rs at 2400 psi < Total GOR

Q2: What's the physical meaning of Bo = 1.15?

A: Bo = 1.15 means that 1 barrel of oil at STOCK TANK conditions (surface, 60°F, 14.7 psia) occupies 1.15 barrels at RESERVOIR/PUMP conditions. The 15% expansion is due to:

Dissolved Gas: Gas molecules dissolved IN oil take up space (like CO₂ in soda)
Thermal Expansion: Higher temperature at reservoir → oil molecules have more kinetic energy → occupy more space
Compressibility: Lower pressure → oil is less compressed → occupies more volume

Practical Impact: Pump must handle 1.15× the surface oil rate. If surface rate = 1000 bpd, pump handles 1150 bpd of oil volume.

Q3: Can I use Gas Separator with packer if the packer is SET ABOVE the gas separator?

A: YES! This is a special case. The rule is: "Gas separator requires ANNULUS ACCESS ABOVE the separator to vent gas."

Scenario Analysis:

Packer BELOW Separator: ❌ Annulus sealed below packer → No vent path → Separator FAILS
Packer ABOVE Separator: ✅ Annulus open above separator → Gas vents through open annulus section → Separator WORKS
No Packer: ✅ Entire annulus open → Gas vents to surface → Separator WORKS (ideal)

Typical Depths: Gas Separator at 2900m, Packer at 1400m → Separator is 1500m BELOW packer → Annulus sealed → Separator CANNOT work → Use Gas Handler.

Q4: Why is GVF > 50% unacceptable for ESP?

A: ESP pumps are designed for LIQUID. At GVF > 50%, more than HALF the volume entering pump is GAS, not liquid. Problems:

Loss of Prime: Gas is compressible → pump cannot build pressure → loses prime
Cavitation: Gas bubbles collapse violently → damages impellers
Motor Overload: Gas-locked pump draws high current but moves little fluid
Efficiency Collapse: Pump efficiency drops from 60% to < 20%
Frequent Failures: Vibration, thrust bearing failure, short run life

Economic Reality: Frequent failures + poor efficiency + high maintenance → ESP becomes MORE EXPENSIVE than Gas Lift. Use Gas Lift instead.

Q5: How does Gas Handler work if it doesn't separate gas?

A: Gas Handler doesn't REMOVE gas - it PREPARES the gas-liquid mixture for the pump by:

Breaking Large Bubbles: Converts large gas bubbles into tiny bubbles (emulsion)
Homogenizing Mixture: Creates uniform gas-liquid mixture instead of slugs
Increasing Pressure: Pre-pressurizes mixture before it enters first pump stage
Reducing Shock: Eliminates gas slugging that damages impellers

Result: Pump can handle 20-40% GVF with gas handler vs only 10% without. Gas still goes through pump, but in manageable form. Final separation happens at surface (separator).

Why This Works With Packer: Gas handler processes gas WITH liquid → all fluids go up tubing → annulus not needed → compatible with packer.

Q6: What is Productivity Index (PI) and how is it measured?

A: PI = Rate of production per unit of pressure drawdown, measured in bpd/psi.

Formula: PI = Q / (Pr - Pwf)

Measurement Method (Well Test):

Produce well at known rate Q (measure at surface separator)
Measure flowing bottomhole pressure Pwf (pressure gauge at datum depth)
Know reservoir pressure Pr (from pressure buildup test or offset wells)
Calculate: PI = Q / (Pr - Pwf)

Example: Q = 1200 bpd, Pr = 5000 psi, Pwf = 4100 psi → PI = 1200 / (5000-4100) = 1200 / 900 = 1.33 bpd/psi

What PI Tells You:

High PI (> 3): Good reservoir connectivity, low skin damage, high permeability
Medium PI (1-3): Typical producing well
Low PI (< 1): Poor reservoir quality, high skin damage, may need stimulation

Q7: Why does drawdown have a maximum limit?

A: Excessive drawdown can DAMAGE THE RESERVOIR permanently:

Sand Production: High pressure gradient can mobilize sand → erodes wellbore → damages equipment
Formation Collapse: Reduced pore pressure can cause formation compaction → permanent permeability loss
Fines Migration: High velocity dislodges clay particles → plugs pore throats → reduces permeability
Water Coning: Excessive drawdown can pull water from aquifer → premature water breakthrough

Industry Guideline: Limit drawdown to 400-500 psi for most formations. Unconsolidated sands: even lower (200-300 psi).

Solution If Drawdown Exceeds Limit:

OPTION 1: Lower pump depth → reduces pressure drop from reservoir to pump
OPTION 2: Reduce flow rate → reduces drawdown (PI equation)
OPTION 3: Accept higher drawdown WITH monitoring plan for sand, water cut, pressure trends

External Resources & Links

ESP Forums & Communities

🌐

SPE PetroWiki - ESP Section

Society of Petroleum Engineers comprehensive wiki on ESP technology, design, and operation. Free access to industry knowledge.

🏢

Baker Hughes ESP Technology

Centrilift ESP product line, technical papers, case studies, and design guidelines from industry leader.

🏢

Schlumberger REDA ESP

REDA ESP systems, technical documentation, webinars, and application notes for production optimization.

🏢

Weatherford ESP Solutions

Compact series ESP, high-temperature applications, and unconventional well ESP systems.

💼

LinkedIn: ESP Professionals Group

Global community of ESP engineers, operators, and service professionals. 10,000+ members sharing knowledge and experience.

🎓

SPE (Society of Petroleum Engineers)

Access technical papers, conferences, webinars, and training courses on ESP technology and artificial lift.

Learning Resources

📺

YouTube ESP Tutorials

Video tutorials covering ESP design, installation, troubleshooting, and operation from various industry experts.

🎓

Coursera: Petroleum Engineering

Online courses from top universities covering production engineering, reservoir engineering, and well design.

📄

ResearchGate: ESP Research Papers

Academic and industry research papers on ESP technology, optimization, and case studies. Many available for free download.

Software & Tools

💻

This ESP Design System

Web-based tool implementing 9-step methodology with Standing's correlations, gas handling recommendations, and professional reports.

🔧

Vendor Design Software

Baker Hughes CENTINEL, Schlumberger PIPESIM, Weatherford LOWIS - Commercial ESP design and analysis software from manufacturers.

📊

PROSPER (Petroleum Experts)

Comprehensive well performance modeling including ESP system design, optimization, and sensitivity analysis.

Equipment Editor & Smart Comparison

Developer Note: All equipment editor features, specifications, and requirements were provided and designed by Eng. Mustafa Hamoud ALGHAITHY. This comprehensive system enables complete equipment customization with intelligent recommendations.

Equipment Editor Features

The Equipment Editor provides advanced capabilities for equipment selection and customization:

Database Selection: Dropdown showing all manufacturer equipment with key specifications
Custom Entry: Enter equipment not in database with full specifications
Smart Comparison: Automatic comparison showing differences between options
Recommendations: Intelligent scoring system with explanations
Database Persistence: Custom equipment saved permanently to application

Smart Comparison System

Comparison Display Example (Pump):

🔍 Equipment Comparison [✅ RECOMMENDED]
Current: P-250  →  Selected: P-300
BEP Flow     4500 bpd  +20%   5400 bpd
Efficiency   70.0%     +7.1%  75.0%
Head/Stage   28 ft     +7.1%  30 ft
Max Stages   300        —     350

                ⭐ Better Choice for Your Application

                Higher BEP capacity. Significantly higher efficiency. Equal or better stages capacity.
            

Recommendation System

Scoring Criteria for Pumps:

BEP Flow Match (3 points): Most critical - pump operates best near BEP
Efficiency (2 points): Higher efficiency reduces power costs
Stages Capacity (2 points): Must handle required TDH
Head/Stage Match (1 point): Affects number of stages needed

Badge	Score Range	Meaning	Action
✅ RECOMMENDED	Score ≥ 6	Better choice for application	Strongly consider selection
👍 ACCEPTABLE	Score 3-5	Acceptable alternative	Review trade-offs carefully
⚠️ CAUTION	Score < 3	Not optimal choice	Current may be better

Equipment-Specific Comparisons

What does the system compare for each equipment type?

Pumps: BEP flow, efficiency, head/stage, max stages (most detailed)
Motors: HP capacity, voltage, rated current
Seals: HP rating, number of chambers
Gas Separators: Gas handling percentage, separator type
Intakes: Type, sand handling capability

How are custom equipment entries handled?

Custom equipment is permanently saved to the application database and becomes available for future selections. All custom entries are validated and can be edited or removed as needed.

What if my manufacturer is not in the database?

The system includes a fallback mechanism - if no equipment matches your manufacturer, all available equipment is shown. You can also use "Enter Custom" option to add any manufacturer's equipment manually.

Developer Attribution: All equipment editor improvements, smart comparison algorithms, and recommendation systems were designed and specified by Eng. Mustafa Hamoud ALGHAITHY. The system implements industry-standard best practices with intelligent guidance for optimal equipment selection.

ESP Professional Design System

Complete ESP design and analysis tool implementing industry-standard methodology

Developed by: Eng. Mustafa Hamoud ALGHAITHY

Mustafa.ghaithy@gmail.com | +967 733 327 722