Casing Strength Properties: Ensuring Integrity Under Extreme Well Conditions

Artificial Lift Systems - Selection Criteria, Design Calculations, and Performance Optimization

A well produces naturally when the reservoir pressure is sufficient to lift fluids from the reservoir to the surface against the combined backpressure of the wellbore hydrostatic column and the surface gathering system pressure. As a field matures, reservoir pressure declines, the producing fluid column changes from gas-driven light oil to heavier liquid-loaded mixtures, and at some point the well stops flowing. Artificial lift restores or increases production by adding energy to the fluid column. The selection of the correct artificial lift method - and the engineering of that system - is one of the highest-impact production engineering decisions in a well's life. A gas lift system incorrectly designed for a well that needs an ESP will produce at 30% of its potential. An ESP installed in a well with high GOR and sand production will fail within 6 months. This guide gives you the engineering framework for the three dominant artificial lift methods.

1. Identifying the Need for Artificial Lift

1.1 The Minimum Flowing Bottomhole Pressure

A well requires artificial lift when the reservoir pressure can no longer maintain a flowing bottomhole pressure (Pwf) sufficient to lift fluid to surface at the wellhead. The minimum Pwf that can support flow is set by the hydrostatic gradient of the produced fluid column:

Minimum Pwf for natural flow (psi):
Pwf_min = P_wellhead + dP_tubing (at minimum economic rate)

dP_tubing = rho_fluid x 0.052 x TVD + Friction_at_min_rate

Example: TVD = 8,500 ft, 60% water cut, mixed fluid density = 0.75 (oil) + 0.25 (gas) at surface but averaging 52 ppg equivalent in tubing, wellhead = 150 psi:
Hydrostatic in tubing = 52 lb/ft3 / 144 x 8,500 = 3,069 psi + 150 psi wellhead = 3,219 psi minimum Pwf

Current reservoir pressure (Pr) = 3,500 psi → Pr - Pwf_min = 281 psi available drawdown
At PI = 0.8 bbl/day/psi: q = 0.8 x 281 = 225 bbl/day natural flow remaining

If Pr declines to 3,300 psi: available drawdown = 81 psi → q = 65 bbl/day (below economic minimum)
Artificial lift required when Pr <3,300 psi to maintain economic production

2. Gas Lift - Injecting Energy Through Gas

2.1 Gas Lift Principle and Mechanism

Gas lift injects high-pressure gas into the tubing annulus through gas lift valves at specific depths. The injected gas mixes with the produced fluid, reduces the average fluid density in the tubing, and decreases the hydrostatic backpressure on the reservoir. The well then produces at a lower Pwf for the same reservoir conditions, increasing production rate:

Gas lift production benefit:
Without gas lift: Pwf = Pwh + rho_liquid x 0.052 x TVD
With gas lift: Pwf = Pwh + rho_mixed x 0.052 x TVD + friction

rho_mixed (ppg) = (rho_oil x q_oil + rho_water x q_water + rho_gas x q_gas_injected) / (q_oil + q_water + q_gas_injected)

Example: Gas injection reduces average fluid density from 9.0 ppg (liquid-loaded) to 5.5 ppg (aerated column):
Pwf reduction = (9.0 - 5.5) x 0.052 x 8,500 = 3.5 x 442 = 1,547 psi Pwf reduction

New Pwf = 3,219 - 1,547 = 1,672 psi
Additional drawdown available = 3,500 - 1,672 = 1,828 psi (vs 281 psi without gas lift)
Production = 0.8 x 1,828 = 1,462 bbl/day with gas lift (vs 225 bbl/day natural flow)

Gas lift increased production 6.5x from the same reservoir at the same reservoir pressure.

2.2 Gas Lift Valve Design - Point of Injection Selection

The deeper the gas injection point, the longer the aerated column and the greater the Pwf reduction. The maximum injection depth is limited by the available injection pressure at surface:

Maximum injection depth from surface injection pressure:
D_max (ft) = (P_injection_surface - P_wellhead) / (rho_gas x 0.052)

Where rho_gas in the annulus ≈ 0.8-1.2 ppg (varies with pressure and temperature)

Example: P_injection = 1,500 psi available, P_wellhead = 150 psi, annulus gas gradient = 0.08 psi/ft:
D_max = (1,500 - 150) / 0.08 = 1,350 / 0.08 = 16,875 ft maximum injection depth

For our 8,500 ft TVD well: 1,500 psi injection pressure is more than adequate to reach bottom.

Optimal injection rate:
Each additional Mscf/day of injected gas reduces Pwf, increasing production - but with diminishing returns as the column becomes predominantly gas. The optimum injection rate is found by maximizing:
Revenue = (q_oil x P_oil - q_gas_injected x P_gas) per unit time

Typical optimum for shallow oil well: 0.5-2.0 Mscf/bbl injection ratio

2.3 Gas Lift Candidate Selection

Well Condition	Gas Lift Suitability	Reason
High GOR (natural gas already present)	Excellent	Gas in the tubing already reduces column density. Gas lift supplementation is efficient.
High water cut (>90%)	Moderate	Dense water column requires high gas volumes. Less efficient than in gas-cut well. ESP may be preferable at very high water cut and high rate.
Sand production	Good	No downhole moving parts. Sand does not damage gas lift valves the way it damages ESP pumps. Gas lift preferred over ESP in sandy wells.
Deviated/horizontal well	Limited	Gas injection in horizontal section has limited effect - gas migrates to high side without aerating the fluid column. Gas lift is most effective in near-vertical sections.
Deep well (>12,000 ft TVD)	Requires high injection pressure	High injection pressure compressors needed. Compressor capital cost may favor ESP for very deep wells.

3. Electric Submersible Pump (ESP) - High-Rate Liquid Lift

3.1 ESP System Design - Pump Sizing

An ESP adds head pressure to the fluid column by mechanically pumping at downhole conditions. The pump must be sized to provide sufficient total dynamic head (TDH) to lift the desired flow rate from pump intake depth to surface against all losses:

Total Dynamic Head (TDH) required (ft):
TDH = Static fluid head + Friction losses + Wellhead backpressure equivalent

TDH = Pump_intake_TVD + (P_wellhead / (rho_fluid x 0.052)) + friction head

Example: Pump at 8,200 ft, fluid density 9.2 ppg, wellhead 150 psi, friction in tubing at 1,500 bbl/day = 200 psi:
TDH = 8,200 + (150 / (9.2 x 0.052)) + (200 / (9.2 x 0.052))
= 8,200 + (150/0.4784) + (200/0.4784)
= 8,200 + 313 + 418 = 8,931 ft TDH required

Pump selection from manufacturer curves:
Find a pump that delivers 1,500 bbl/day at 8,931 ft TDH within the operating range.
Each pump stage provides a fixed head contribution. Total head = Head per stage x Number of stages

Example: Selected pump provides 35 ft/stage at 1,500 bbl/day:
Number of stages = TDH / Head_per_stage = 8,931 / 35 = 255 stages

Motor power required:
HP = q (bbl/day) x rho (ppg) x TDH (ft) / (3,960 x pump_efficiency)
= 1,500 x 9.2 x 8,931 / (3,960 x 0.55) = 123,307,800 / 2,178 = 56.6 HP motor required

3.2 ESP Failure Modes and Prevention

Failure Mode	Mean Time to Failure (typical)	Prevention Strategy
Gas interference (pump gas-locks)	Immediate to weeks	Install gas separator above pump intake. Set pump below perforations. Gas-handling impellers for wells with GOR >200 scf/bbl.
Sand abrasion (impeller wear)	Weeks to months in sandy wells	Sand-resistant hardened impellers. Reduce drawdown to stay below critical sand production rate. Consider rod pump or gas lift instead in high-sand wells.
Scale deposition on impellers	Months	Scale inhibitor injection through downhole chemical injection system. Monitor motor current for gradual increase indicating scale buildup.
Motor overheating (insufficient flow past motor)	Hours to days	Minimum flow rate through motor = 500 bbl/day in most designs. Install motor shroud to direct flow past motor if annulus flow is insufficient. Do not run ESP below minimum flow rate.

4. Rod Pump (Sucker Rod Pump) - Mechanical Lift for Low-Rate Wells

4.1 Rod Pump Design - Stroke and Speed Selection

A rod pump uses a surface pump jack (walking beam) connected to a downhole plunger via a string of steel sucker rods. Each upstroke lifts a volume of fluid equal to the plunger displacement. Pump design sets the stroke length, strokes per minute, and plunger diameter to achieve the desired production rate:

Rod pump theoretical displacement (bbl/day):
q_theoretical = 0.1166 x D^2 x S x N

Where:
D = plunger diameter (inches)
S = effective stroke length at pump (inches)
N = pumping speed (strokes per minute)

Example: 2.5" plunger, 84" stroke at surface (effective at pump ≈ 72" after rod stretch), 6 SPM:
q_theoretical = 0.1166 x 2.5^2 x 72 x 6 = 0.1166 x 6.25 x 432 = 0.1166 x 2,700 = 315 bbl/day theoretical

Actual production = q_theoretical x pump_fillage x volumetric_efficiency
Pump fillage (fraction of stroke that fills with liquid, depends on GOR and submergence): typically 0.6-0.95
Volumetric efficiency: 0.75-0.90

Actual q = 315 x 0.80 x 0.85 = 214 bbl/day actual production

4.2 Rod String Design - Tapered Rod String for Deep Wells

In deep wells, a single-diameter rod string becomes too heavy - the rods at the top must support the full weight of the rod string below plus the fluid load. Tapered rod strings use larger-diameter rods at the top (where the stress is highest) and progressively smaller rods toward the bottom:

Maximum stress in top rod (psi):
sigma_max = (W_rods + W_fluid) / A_rod

W_fluid (lbs) = 0.433 x rho (SG) x TVD x plunger_area
W_rods (lbs) = w_rod (lbs/ft) x L (ft) x buoyancy_factor

Example: 7/8" rod string (A_rod = 0.6013 in2, w = 2.224 lbs/ft), TVD = 6,000 ft, fluid SG = 1.1, 2" plunger:
W_rods = 2.224 x 6,000 x 0.855 (buoyancy in 8.5 ppg fluid) = 11,411 lbs
W_fluid = 0.433 x 1.1 x 6,000 x pi/4 x 2^2 = 0.433 x 1.1 x 6,000 x 3.14 = 8,978 lbs
sigma_max = (11,411 + 8,978) / 0.6013 = 20,389 / 0.6013 = 33,911 psi peak stress

API Grade D rod (yield 115,000 psi): SF = 115,000/33,911 = 3.4 → Adequate for this depth

At 10,000 ft: W_rods would be approximately 19,018 lbs → sigma_max ≈ 46,500 psi → SF = 2.5 → Still adequate but approaching limit. Tapered string with 1" rods at top (A = 0.7854 in2) reduces peak stress.

5. Artificial Lift Method Comparison and Selection

Selection Factor	Gas Lift	ESP	Rod Pump
Optimal flow rate range	100-30,000+ bbl/day	200-40,000+ bbl/day	5-500 bbl/day
Well depth limit	Limited by compressor pressure	15,000+ ft feasible	Practical limit ~14,000 ft (rod weight)
Sand tolerance	Excellent (no moving parts downhole)	Poor (<100 ppm recommended)	Moderate (wear accelerates)
GOR tolerance	Excellent (benefits from gas)	Poor (<100-200 scf/bbl recommended)	Moderate (<500 scf/bbl)
Offshore application	Preferred (minimal surface equipment per well, flexible)	Common in subsea wells. High-cost workover for replacement.	Not practical offshore (surface pump jack required)
Workover frequency	Low (gas lift valves last years)	Moderate (ESP MTBF 1-5 years typically)	Moderate (pump and rod failure every 2-5 years)

Conclusion

The gas lift production calculation in this article - 225 bbl/day natural flow increasing to 1,462 bbl/day with gas lift from the same reservoir - demonstrates the transformational impact of artificial lift design. The 6.5x production increase does not come from a reservoir property change or a workovers - it comes from reducing the average fluid column density in the tubing from 9.0 ppg to 5.5 ppg, which reduces Pwf by 1,547 psi and unlocks 1,547 psi of additional reservoir drawdown. The engineering is straightforward: calculate the Pwf reduction achievable with gas injection, multiply by the well's PI, and compare the result to the cost of gas compression and injection infrastructure.

The ESP sizing calculation demonstrates the same engineering discipline applied to mechanical lift: the 8,931 ft TDH requirement determines the number of pump stages (255), which determines the motor horsepower (56.6 HP), which determines the power cable and motor specifications. Each step follows from the previous - there is no independent optimization, only propagation of the production rate requirement through the hydraulic and mechanical design constraints of the downhole pump system. Selecting an ESP by catalog reference rather than by TDH calculation results in either an undersized system that cannot meet the production rate or an oversized system that wastes power and creates motor cooling problems.

Want to access our artificial lift design calculator with gas lift node analysis, ESP TDH and stage count, and rod pump displacement, or discuss lift method selection for a specific well? Join our Telegram group for production engineering discussions, or visit our YouTube channel for step-by-step tutorials on artificial lift design and optimization.