Horizontal Wellbore Pressure Calculation via Segmented Multi-Phase Flow Modeling
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Solution Overview
Problem
Current methods for calculating wellbore pressure in fracturing horizontal wells fail to accurately account for the heterogeneity of reservoirs and interference between fractures, leading to inaccurate predictions of fracture production and pressure distribution due to ignoring pressure loss and variable multi-phase flow characteristics.
Innovation Solution
A method using a fully implicit numerical model based on the embedded discrete fracture model (EDFM) to calculate wellbore pressure, considering gravity loss, frictional resistance, and fracture convergence, iteratively solving for bottom-hole flow pressure and pressure distribution across different sections of the well.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Device complexity
If pressure loss in the wellbore is ignored and the fracturing horizontal well is regarded as having infinite conductivity, then the calculation model is simplified, but the prediction accuracy of fracture production and pressure distribution deteriorates
Solution Approach 1:
The wellbore is segmented into multiple sections (vertical section, inclined section, horizontal section) with different flow characteristics. Each section is modeled separately with appropriate pressure drop equations, allowing the complex wellbore to be divided into manageable segments that capture the essential physics without requiring a fully complex 3D model throughout.
Solution Approach 2:
Different sections of the wellbore are assigned different flow models and parameters based on their local characteristics. The vertical section uses one-phase gas flow equations, the inclined section accounts for gravity and friction, and the horizontal section models multi-phase flow with liquid accumulation. This local differentiation improves accuracy where needed while keeping the overall model tractable.
2Device complexity
If the production of each artificial fracture is assumed to be equal, then the calculation process is simplified, but the accuracy of fracture production prediction deteriorates due to reservoir heterogeneity and fracture interference
Solution Approach 1:
The fracture production rates are treated as dynamic variables that evolve during the simulation rather than fixed equal values. The iterative coupling process allows each fracture's production to adjust dynamically based on reservoir pressure changes, wellbore pressure distribution, and interference from other fractures, capturing the heterogeneous behavior without requiring manual specification of complex production profiles.
Solution Approach 2:
An iterative feedback loop is established where fracture productions are initially assumed equal, then wellbore pressure distribution is calculated, which feeds back to update fracture productions based on local pressure gradients and reservoir properties. This feedback mechanism automatically captures heterogeneity and interference effects while starting from a simple equal-production assumption.
3Device complexity
If variable-mass multi-phase flow characteristics are not considered, then the pressure drop calculation is simplified, but the accuracy of wellbore pressure distribution deteriorates due to frictional pressure drop, gravity pressure drop, and accelerated pressure drop
Solution Approach 1:
The wellbore is divided into vertical, inclined, and horizontal sections, each with appropriate multi-phase flow models. The vertical section uses single-phase gas flow equations (simpler), while the inclined and horizontal sections use multi-phase flow equations that account for liquid accumulation, friction, and gravity. This segmentation applies complex physics only where necessary.
Solution Approach 2:
The flow regime parameters (phase distribution, liquid holdup, friction factors) are updated iteratively based on local pressure, temperature, and flow rate conditions. As pressure and temperature change along the wellbore, the fluid properties and flow characteristics are dynamically adjusted, capturing the variable-mass multi-phase flow behavior without requiring a fully complex equation of state throughout.
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
This approach provides accurate characterization of multi-medium flow laws and pressure distribution in unconventional gas reservoirs, allowing for precise prediction of wellbore pressure and wellhead casing pressure without the need for bottom-hole pressure test data, thereby reducing costs and improving predictive accuracy.
Implementation Method 1
bring the gas production volume, liquid production volume and the pressure of the grid block where the fracture initiation point is located into the pressure drop model considering the gravity loss, frictional resistance loss and fracture convergence loss
Implementation Method 2
bring the gas production volume, liquid production volume and the pressure of the grid block where the fracture initiation point is located into the pressure drop model considering the gravity loss, frictional resistance loss and fracture convergence loss
Implementation Method 3
due to the confluence of reservoir fluid, the flow in the horizontal section of the wellbore belongs to variable-mass multi-phase flow, which will generate frictional pressure drop, gravity pressure drop, and accelerated pressure drop
Data Source
AI summary
The invention discloses a full wellbore pressure calculation method, device and computer-readable storage medium for fracturing horizontal wells, includes steps: collect basic parameters, establish fully implicit numerical model of formation flow; solve the full implicit numerical model under an inner boundary condition of a constant gas production rate; calculate wellbore pressure change of each fracturing section of horizontal well; calculate the bottom-hole pressure of each fracture initiation point; repeat steps until the variables converge, the bottom-hole flow pressure and the bottom-hole pressure at each fracture initiation point are obtained at this time step; the wellbore pressure and wellhead casing pressure are calculated at this time step. The method is for predicting the variation law of full wellbore pressure and wellhead casing pressure by using production data in the absence of bottom-hole pressure test data, and has practical value for accurate prediction of production performance of gas reservoir fracturing horizontal wells.