Liner-Deployed Outflow Control for Injector Bottom Hole Pressure
Find Innovative SolutionsGenerate Solutions
Solution Overview
Problem
In hydrocarbon recovery operations, particularly in shallow reservoirs, the use of liner-deployed outflow control devices (LDOCDs) is hindered by the inability to accurately determine injector bottom hole pressure (IBHP), leading to underestimated steam injection and reduced hydrocarbon production, while existing tubing-deployed devices (TDOCDs) offer cost advantages but lack direct pressure measurement, necessitating a method to accurately estimate IBHP for LDOCDs.
Innovation Solution
A method involving shut-in periods and surface measurements to equilibrate wellhead pressure with reservoir pressure, using a valve, meter, and gauge to determine IBHP, and a predictive model based on polynomial relationships between pressure drop and steam flowrate to optimize steam injection.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Ease of manufacture
If liner-deployed outflow control devices (LDOCDs) are used for steam injection, then cost is reduced and device complexity is simplified, but the ability to accurately determine injector bottom hole pressure (IBHP) is lost leading to underestimated steam injection
Solution Approach 1:
The patent introduces an intermediary measurement approach by using surface pressure measurements combined with a polynomial predictive model to indirectly determine IBHP. Instead of directly measuring pressure at the bottom hole through complex downhole instrumentation, the system uses readily available surface measurements (wellhead pressure, steam flowrate) as intermediaries to calculate IBHP through the established pressure drop correlation.
Solution Approach 2:
The patent implements a feedback mechanism where surface measurements of wellhead pressure and steam flowrate are continuously monitored and fed into the predictive model. The model provides feedback on the estimated IBHP, allowing operators to adjust steam injection rates to optimize production while avoiding reservoir damage from excessive pressure.
2Measurement precision
If tubing-deployed outflow control devices (TDOCDs) are used with annular space for pressure equalization, then IBHP estimation accuracy is improved, but device complexity and cost increase
Solution Approach 1:
The patent extracts the pressure measurement function from the downhole environment where it would require complex tubing and annular space infrastructure. By taking out the pressure sensing requirement and relocating it to the surface where simple pressure gauges can be used, the system eliminates the need for complex tubing deployments while maintaining measurement capability through the predictive model.
Solution Approach 2:
The patent creates a computational copy of the downhole pressure condition by using the polynomial model to calculate IBHP from surface measurements. Instead of physically replicating the pressure environment at surface, the system uses mathematical modeling to copy the essential pressure information, avoiding the need for physical tubing infrastructure.
3Productivity
If steam injection rate is increased to enhance hydrocarbon production, then productivity increases, but reservoir pressure approaches maximum operating pressure (MOP) limiting further injection
Solution Approach 1:
The patent applies dynamics by making the steam injection rate adjustable and responsive to real-time conditions. The system continuously monitors surface pressure and flowrate, updates the IBHP estimate through the predictive model, and dynamically adjusts the injection rate to maintain optimal productivity while staying below the MOP threshold. This allows the system to adapt to changing reservoir conditions rather than operating at a fixed rate.
Solution Approach 2:
The patent changes the operational parameter of steam injection rate based on the calculated IBHP. By using the polynomial model to determine the relationship between surface measurements and bottom hole pressure, the system can adjust injection parameters (flowrate, pressure) to optimize production while preventing reservoir pressure from exceeding MOP, thereby resolving the contradiction between productivity and pressure constraints.
Applied Scientific Principles
This section explains which scientific principles are used to turn an abstract innovation direction into a practical engineering solution.
Function Achieved in This Case
Enables accurate determination and prediction of IBHP, allowing higher steam injection rates and reservoir pressures, enhancing production efficiency, reducing costs, and optimizing resource utilization.
Implementation Method 1
A method involving shut-in periods and surface measurements to equilibrate wellhead pressure with reservoir pressure
Implementation Method 2
a predictive model based on polynomial relationships between pressure drop and steam flowrate
Data Source
AI summary
Methods for determining hydrocarbon recovery injection well bottom hole pressures where a downhole liner has liner-deployed outflow control devices, for attempting to ensure operation below a maximum operating pressure. Steam flowrate is varied using a range of valve positions, including shut-in periods (0-5% flowrate) sufficient to approach equilibrium between a surface pressure and bottom hole pressure, generating a determined bottom hole pressure which can be used to calculate an average bottom hole pressure. An average steam flowrate and average surface pressure are determined for a range of valve positions. A pressure drop is calculated for each of the valve positions by subtracting the average bottom hole pressure from the measured surface pressure. Plotting the pressure drop against the average surface pressure for each of the valve positions allows generation of a best fit model defining a polynomial relationship between the pressure drop and the surface pressure. Parameters can then be derived from the best fit model, enabling prediction of the bottom hole pressure for any steam flowrate for the well. The maximum operating pressure can then be more confidently determined for various steam flowrate values. The methods may be automated using a programmable logic controller (PLC) or similar platform located at the well pad.