Fracturing fluids for delayed flow back operations

It’s been discovered that certain fracturing fluid compositions can be utilized to fracture a underground formation and be permitted to remain within the formation for a relatively extended period of time, for example 28 days or more, before being flowed back or generated. At least two embodiments are pictured, a bacteria-containing formulation and an anti-bacterial formulation. Both systems are expected to prevent the capacity of the liquid to oil moist the formulation (water block condition) by maintaining the formation water moist through the use of water wetting surfactants or solvents. Additionally, both formulas would restrain reservoir crude souring (H.sub.2S production by in situ sulfate-reducing bacteria), reservoir plugging (through slime biopolymers generated by in situ microbes, inorganic scale deposition like calcium carbonate or barium sulfate, and clay fines migration).


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Hydraulic fracturing is a procedure of utilizing pump rate and hydraulic strain to crack or fracture a underground formation. Once the cracks or crack are created, high permeability proppant, relative to the formation permeability, is pumped to thefracture to prop open the fracture. When the pump rates and pressures are reduced or removed from the formation, the fracture or fracture cannot close or heal completely because the high permeability proppant retains the crack open. The propped crackor fracture provides a high permeability route connecting the creating wellbore to a larger formation space to boost the generation of hydrocarbons.

The growth of suitable fracturing fluids is a intricate art because the fluids must simultaneously meet lots of requirements. For example, they need to be stable at high temperatures or higher pump rates and shear rates which can result in thefluids to degrade and prematurely settle from the proppant until the fracturing operation is complete. Various fluids have been developed, but many commercially employed fracturing fluids are aqueous based liquids that have either been gelled or foamed.When that the fluids are gelled, typically a polymeric gelling agent, like a solvatable polysaccharide can be used. The thickened or gelled fluid helps keep the proppants within the fluid. Gelling can be achieved or improved by the usage of crosslinkingagents or crosslinkers that promote crosslinking of the polymers with each other, thereby raising the viscosity of the fluid.

The healing of fracturing fluids may be done by lowering the viscosity of the fluid into a low value so that it may flow naturally from the formation under the influence of fluids. Crosslinked implants generally need viscositybreakers to be pumped to decrease the viscosity or”break” the gel. Enzymes, oxidizers, and acids are known polymer viscosity breakers. Enzymes are effective within a pH range, generally a 2.0 to 10.0 range, together with increasing activity because the pH islowered towards impartial from a pH of 10.0. Most traditional borate crosslinked fracturing fluids and breakers are designed from a predetermined high crosslinked fluid pH value at ambient temperature and/or reservoir fever. Optimizing the pH for a boratecrosslinked gel is important to attain proper crosslink stability and controlled enzyme breaker activity.

Fracturing fluids also include additives that will help inhibit the formation of scale including, but not always confined to carbonate scales and sulfate scales. Such climb cause blockages not just in the equipment used in hydrocarbon recovery,but can also create fines which obstruct the pores of the subterranean formation. Examples of scale inhibitors or scale removers integrated into uric acid include, but are not necessarily confined to polyaspartates; hydroxyaminocarboxylic acid(HACA) chelating agents, such as hydroxyethyliminodiacetic acid (HEIDA); ethylenediaminetetracetic acid (EDTA), diethylenetriaminepentaacetic acid (DTPA), nitrilotriacetic acid (NTA) as well as other carboxylic acids and their salt forms, phosphonates, andacrylates and mixtures thereof.

Fracturing fluids which are crosslinked with titanate, zirconate, and/or borate ions (using compounds that make these ions), sometimes contain additives which are made to postpone crosslinking. Crosslinking delay agents permit thefracturing to be pumped down hole into the underground formation until crosslinking starts to occur, thereby permitting more versatility or flexibility at the fracturing fluid. Cases of crosslink delay agents commonly integrated into fracturingfluids contain, but aren’t necessarily limited to natural polyols, such as sodium gluconate; sodium glucoheptonate, sorbitol, glyoxal, mannitol, phosphonates, aminocarboxylic acids and their salts (EDTA, DTPA, etc.) and combinations thereof. The other typeof crosslink delay mechanism for borate crosslinked fluids is type, amount, and particle size distribution of borate mineral particles. A good example is the product Fracsal Waterbase available from TBC-Brineadd (Houston, Tex.).

Other common additives employed in traditional fracturing fluids comprise crosslinked gel stabilizers that stabilize the crosslinked gel (typically a polysaccharide crosslinked with titanate, zirconate or borate) for a sufficient period of timeso the pump rate and hydraulic pressure can fracture the underground formations. Suitable crosslinked gel stabilizers formerly used include, but are not necessarily limited to, sodium thiosulfate, diethanolamine, triethanolamine, methanol,hydroxyethylglycine, tetraethylenepentamine, ethylenediamine and mixtures thereof.

Additional common additives for fracturing fluids are receptor (protein) stabilizers. These chemicals stabilize the enzymes and/or proteins utilized in the fracturing fluids to eventually break the gel after the underground formation isfractured so that they are still effective at the time it is needed to violate the gel. When the enzymes degrade too early that they will not be accessible to efficiently break the gel at the appropriate time. Examples of enzyme breaker stabilizers commonlyincorporated into fracturing fluids include, but are not necessarily confined to sorbitol, mannitol, glycerol, citrates, aminocarboxylic acids and their salts (EDTA, DTPA, NTA, etc.), phosphonates, sulphonates and combinations thereof.

It has become desired to crack a well, break the gel as in a traditional fracturing treatment, but keep the broken fracturing fluid within the formation to get a comparatively long period of time, for example a minumum of one month or up to ninemonths or longer. But, leaving the fracturing fluid composition within the creation introduces additional issues, such as oil wetting of this formation by the fluid, raising the water flow or water blocking by the fluid, bothering the clayparticles within the formation and inducing clay swelling or mist intrusion that will result in reservoir permeability harm, souring of this reservoir primitive (that is caused by H.sub.2S generation from situ sulfate-reducing bacteria), reservoirplugging (slime biopolymers generated by in situ microbes) and inorganic scale deposition (such as barium sulfate). It would be helpful if multifunctional fracturing fluid compositions may be devised that have suitable properties or characteristicsthat would permit the fracturing fluid to remain in the formation for protracted intervals.

IP reviewed by Plant-Grow agriculture technology news