AI Optimization Logic

This section describes the optimization logic used to compare the current well operating point against the reservoir inflow, tubing outflow, and pump performance curves. The goal is to identify a practical operating point that keeps production close to the required rate while improving pump efficiency and reducing power consumption.

The workflow below covers the simple case where the produced fluid is treated as oil or water only, without mixed-flow modeling.

Workflow Summary

1. Build the reservoir inflow curve from PI, SBHP, and a swept FBHP.
2. Build the tubing outflow curve from wellhead pressure, gravity head, and friction loss.
3. Subtract inflow pressure from outflow pressure to get the system curve.
4. Overlay the system curve on the pump curve.
5. Compare the current operating point against BEP and the safe operating window.
6. Select the frequency and head requirement that preserve the accepted production target with better efficiency and lower power.

Required Data

The optimizer needs three groups of inputs:

Input group	Examples
Sensor data	Pump intake pressure, pump discharge pressure, and related downhole readings
Surface data	Wellhead pressure, operating frequency, and flow rate
Well constants	SBHP, FBHP, and PI

Variable Reference

Term	Meaning
PI	Productivity index
SBHP	Static bottomhole pressure
FBHP	Flowing bottomhole pressure
WHP / PTHP	Wellhead pressure / tubing head pressure
SG	Specific gravity of the produced fluid used for the initial fluid-gradient calculation
GAVG	Average fluid gradient used in the friction-loss estimate
HFriction	Tubing friction-loss factor from API tubing tables or equivalent calculation
Pi	Pump intake pressure
Pd	Pump discharge pressure
BEP	Best efficiency point

Inflow Curve

The inflow curve estimates the flow rate available from the reservoir.

Use:

Q = PI * (SBHP - FBHP)

Where:

Term	Meaning
Q	Flow rate
PI	Productivity index, provided by the end user
SBHP	Static bottomhole pressure, provided by the end user
FBHP	Flowing bottomhole pressure, swept from 0 to SBHP to plot the curve

Outflow Curve

The outflow curve estimates the pressure required to lift the fluid to surface.

Use:

Po = PTHP + PGravity + PFriction

Where:

Term	Meaning
PTHP	Tubing head pressure or wellhead pressure. For an initial plot, use a constant average measured value.
PGravity	Vertical depth multiplied by fluid gradient. PGravity = vertical depth * (SG * 0.433).
PFriction	Friction pressure loss. PFriction = GAVG * HFriction.
HFriction	Friction loss from API tubing tables or an equivalent tubing friction calculation.

Plot the inflow and outflow curves in the same chart. Their intersection is the natural operating point for the well when the ESP contribution is not included.

System Curve

After the inflow and outflow curves are calculated, plot the system curve.

Use:

Psys = Poutflow - Pinflow

The system curve represents the head that the pump must add at each flow rate.

Pump Curve Comparison

Plot the system curve against the pump performance curve to compare the current production point with the pump's best efficiency point.

The comparison should answer two questions:

Check	Meaning
Is the intersection at BEP?	If yes, no optimization action is required.
Is the point away from BEP?	Review alternate frequencies and the allowed operating window.

When the current point is not at BEP, the optimizer should check other pump curves at different frequencies and keep the operating point inside the safe operating window.

Selecting the Optimized Point

Select the point that gives the maximum practical efficiency, consumes less power, and stays closest to the accepted production rate.

That selected point gives the new required pump head. In this context, required head is the pressure rise across the pump:

Required Head = Pd - Pi

Where Pd is pump discharge pressure and Pi is pump intake pressure.

Flow-Rate Constraint Example

If the well has a required production rate constraint, optimize around that target.

Example:

Condition	Value
Required flow	8000 BPD
Current operating frequency	60 Hz
Current production	8000 BPD
Candidate optimized frequency	54 Hz

In this case, reducing frequency to 54 Hz can still deliver the required 8000 BPD while moving the pump closer to a better efficiency region and reducing power consumption.

Operator Guidance

Use AI optimization as a decision-support tool. Before applying a recommendation, confirm:

Check	Why it matters
The live sensor values are current	Stale intake, discharge, wellhead, or flow values move the calculated point.
The production constraint is correct	The optimizer should not reduce flow below the accepted operating target.
The point remains inside the operating window	Efficiency gains should not push the pump into downthrust, upthrust, or unstable operation.
The recommended head is physically achievable	The selected Pd - Pi must match what the pump can produce at the chosen frequency.