Acid Stimulation Treatment Fluids With Microemulsion Retardation
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Solution Overview
Problem
Existing hydrocarbon reservoir stimulation methods in carbonate formations face challenges such as brine retention, polymer-induced plugging, and surfactant incompatibilities, leading to reduced production efficiency and increased fluid volumes.
Innovation Solution
A treatment fluid comprising an aqueous acid solution with a retardation additive, including oleaginous liquids, fatty alkyl alcohol ethoxylates, and compatible surfactants, which forms stable microemulsions to enhance fluid recovery and reduce surface tension, allowing deeper matrix penetration and lower fluid volumes.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Productivity
If a polymer is used to facilitate foaming in stimulation fluid, then fluid production is improved, but polymer loading may plug porosity within the carbonate reservoir
Solution Approach 1:
The patent removes the polymer component from the stimulation fluid formulation entirely, replacing it with a surfactant-based foaming system. This extraction eliminates the porosity plugging problem while maintaining foam generation capabilities through alternative chemical mechanisms that do not require high molecular weight polymers.
Solution Approach 2:
The patent combines multiple functions into the surfactant system: foam generation, surface tension reduction, and fluid flow facilitation. By merging these functions into a single chemical class without polymer additives, the system achieves productivity improvement without the harmful porosity plugging effect.
2Stability of the object's composition
If high surface tension values are used in stimulation fluid, then fluid stability is maintained, but fluid production is limited
Solution Approach 1:
The patent changes the surface tension parameter from high to low values by incorporating surfactants in optimized concentrations. This parameter change enables improved fluid production through better wetting and flow characteristics while the surfactant system itself provides sufficient stability to maintain composition integrity under reservoir conditions.
3Reliability
If large volumes of stimulation fluid are used to account for surfactant degradation, then surfactant performance variability is addressed, but treatment fluid volume increases
Solution Approach 1:
The patent employs a composite surfactant system comprising multiple surfactant types working synergistically. This composite approach enhances overall surfactant performance and reliability under high temperature and pressure conditions, reducing the need for excessive fluid volumes to compensate for individual surfactant degradation.
4Adaptability or versatility
If conventional surfactants are used in high temperature carbonate reservoirs, then emulsification may be promoted, but surfactant incompatibility with acids and each other occurs
Solution Approach 1:
The patent selects surfactants with specific local qualities - particular hydrophilic-lipophilic balance (HLB) values and molecular structures - that are optimized for high temperature stability and acid compatibility. This localized optimization of surfactant properties ensures both emulsification capability and compatibility with the acidic reservoir environment without degradation or precipitation.
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 improves hydrocarbon production by stabilizing emulsions under carbonate reservoir conditions, reducing brine retention, and enabling efficient acid retardation, thus increasing permeability and recovery while minimizing treatment fluid volumes.
Implementation Method 1
forms stable microemulsions to enhance fluid recovery and reduce surface tension
Implementation Method 2
reduce surface tension, allowing deeper matrix penetration
Implementation Method 3
mineral acids or organic acids are used to dissolve a portion of the carbonate matrix to form passages (wormholes)
Implementation Method 4
Foaming may be utilized to facilitate production of stimulation fluids following an acidizing operation or an acid fracturing operation
Data Source
AI summary
Treatment fluids for acid stimulation operations and methods related thereto. Treatment fluids comprise: an aqueous acid solution comprising a mineral acid and an organic acid; and a retardation additive comprising: 1-15 wt % of an oleaginous liquid; 5-30 wt % of a fatty alkyl alcohol ethoxylate; 2-40 wt % of at least one of a fatty alkyl ethoxylated ammonium salt, a zwitterionic surfactant, an alkyl ether sulfate salt, or an alkyl ether sulfonate salt; 4-30 wt % of a co-solvent; and 10-85 wt % of an aqueous fluid, each wt % based on a total mass of the retardation additive. Treatment fluids or retardation additives may be oil-in-water emulsions. Treatment fluids may have 0.5-5 gallons per thousand, based on an overall volume of the treatment fluid of the retardation additive. Methods comprise providing and introducing the treatment fluid into a subterranean formation during a stimulation operation.