Polyelectrolyte Agglomerates for Large Fracture Sealing
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Solution Overview
Problem
Existing methods for fluid loss control in subterranean formations are inadequate for large fractures, as traditional lost circulation materials fail to create high-strength plugs that can sustainably seal thief zones, particularly those with widths greater than 5 mm.
Innovation Solution
A method involving two treatment fluids with oppositely charged polyelectrolytes and solids, pumped separately to the thief zone, where they mix to form a low-permeability agglomerate that plugs the fluid leakage channel, offering either temporary or permanent sealing depending on the composition.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Reliability
If traditional lost circulation materials are used, then small fractures can be sealed, but large fractures (width > 5 mm) cannot be effectively plugged
Solution Approach 1:
The invention changes the physical and chemical parameters of the plugging material by using polyelectrolyte complexes that can dynamically adjust their properties. The complexes transition from soluble individual chains to insoluble aggregated networks, dramatically increasing particle size and structural strength to plug large fractures exceeding 5 mm width.
Solution Approach 2:
The invention creates composite plugging material through the interaction of oppositely charged polyelectrolytes forming complex aggregates. These composite structures combine multiple polymer chains with opposite charges to form large, strong, low-permeability plugs that can seal large-scale fractures, overcoming the limitations of single-material approaches.
2Reliability
If high-strength plugs are created to seal large fractures, then fluid loss control improves, but the complexity of the treatment system increases
Solution Approach 1:
The treatment system is segmented into two separate fluids: one containing cationic polyelectrolyte and the other containing anionic polyelectrolyte. Each fluid can be pumped separately through the wellbore, and the actual plugging material forms only when the two fluids mix in the fracture zone. This segmentation simplifies pumping operations while achieving high-strength plugging.
Solution Approach 2:
The polyelectrolyte complexes act as an intermediary mechanism between the two separately pumped fluids. The cationic and anionic polymers serve as mediators that react upon mixing to form the actual plugging structure, allowing the system to maintain simplicity during transport while achieving complexity only where needed for effective plugging.
3Duration of action of stationary object
If permanent plugging materials are used, then long-term sealing is achieved, but temporary control options are lost
Solution Approach 1:
The invention enables control over the duration of action by changing the chemical composition parameters of the polyelectrolytes. By selecting different polymer types, molecular weights, and charge densities, the plugging material can be designed to either degrade over time (temporary control) or remain stable indefinitely (permanent control), providing versatility across different application scenarios.
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
The solution effectively plugs channels up to several centimeters in width, maintaining well control during drilling, cementing, and workover operations by creating high-strength agglomerates that withstand significant pressure differences and can be either degradable or non-degradable, addressing the limitations of prior art in sealing larger fractures.
Implementation Method 1
Mixing of two treatment fluids in a downhole position produces low-permeability agglomerates that plug the fluid leakage channel
Implementation Method 2
Polyelectrolytes in two treatment fluids are oppositely charged under the downhole conditions
Data Source
AI summary
The method of fluid loss control is provided for the case of high-rate fluid loss. Two treatment fluids are provided, where a first treatment fluid comprising a carrier fluid, solids and a first polyelectrolyte, and a second treatment fluid comprising a carrier fluid and a second polyelectrolyte. Two polyelectrolytes in both treatment fluids are oppositely charged under the pumping conditions, being taken from the classes of polyanionic and polycationic polymers. Two treatment fluids are pumped separately to the zone with fluid loss. The mixing of two treatment fluids into the well creates low-permeability agglomerates that plugs the fluid leakage channel, preventing or reducing further fluid movement between the wellbore and subterranean formation. The plugging of thief zone can be temporary or permanent.