A friction reducing treatment solution that includes water, from 100 to 500,000 ppm of total dissolved solids, and from 0.5 to 3 gallons per thousand gallons of a water-in-oil emulsion containing a water soluble polymer. The total dissolved solids include at least 10 weight percent of a multivalent cation. The water-in-oil emulsion includes an oil phase and an aqueous phase, where the oil phase is a continuous phase containing an inert hydrophobic liquid and the aqueous phase is present as dispersed distinct particles in the oil phase and contains water, the water soluble polymer, and surfactants and an inverting surfactant. The water soluble polymer is made up of 30 to 60 weight percent of a non-ionic monomer, 5 to 50 weight percent of a sulfonic acid containing monomer, and 10 to 60 weight percent of a cationic monomer and makes up from 5 to 40 weight percent of the water-in-oil emulsion.

A friction reducing treatment solution that includes water, from 100 to 500,000 ppm of total dissolved solids, and from 0.5 to 3 gallons per thousand gallons of a water-in-oil emulsion containing a water soluble polymer. The total dissolved solids include at least 10 weight percent of a multivalent cation. The water-in-oil emulsion includes an oil phase and an aqueous phase, where the oil phase is a continuous phase containing an inert hydrophobic liquid and the aqueous phase is present as dispersed distinct particles in the oil phase and contains water, the water soluble polymer, and surfactants and an inverting surfactant. The water soluble polymer is made up of 30 to 60 weight percent of a non-ionic monomer, 5 to 50 weight percent of a sulfonic acid containing monomer, and 10 to 60 weight percent of a cationic monomer and makes up from 5 to 40 weight percent of the water-in-oil emulsion.

A method in one embodiment includes obtaining produced water from at least one of drilling, completion, or hydrocarbon production. The method also includes separating the produced water into desalinated water and produced salt. Further, the method includes coating the produced salt with resin to provide coated produced salt.

Systems and methods for the treatment of oil and/or gas wells are generally provided. In some embodiments, a reservoir comprising oil and/or gas may contain regions that differ in permeability to the drive fluid used to displace the oil and/or gas. The higher permeability region(s) may limit oil and/or gas recovery from lower permeability regions. A method of enhancing oil and/or gas recovery in such a reservoir may comprise injecting a fluid comprising a microemulsion into the reservoir prior to obstructing one or more region (e.g., higher permeability regions) of the reservoir. The use of a microemulsion prior to obstructing one or more region of the reservoir may enhance the barrier properties of the resulting obstruction. In some embodiments, injecting a fluid comprising a microemulsion into the reservoir may also increase the overall production of the oil and/or gas well lacking the microemulsion treatment.

Systems and methods for the treatment of oil and/or gas wells are generally provided. In some embodiments, a reservoir comprising oil and/or gas may contain regions that differ in permeability to the drive fluid used to displace the oil and/or gas. The higher permeability region(s) may limit oil and/or gas recovery from lower permeability regions. A method of enhancing oil and/or gas recovery in such a reservoir may comprise injecting a fluid comprising a microemulsion into the reservoir prior to obstructing one or more region (e.g., higher permeability regions) of the reservoir. The use of a microemulsion prior to obstructing one or more region of the reservoir may enhance the barrier properties of the resulting obstruction. In some embodiments, injecting a fluid comprising a microemulsion into the reservoir may also increase the overall production of the oil and/or gas well lacking the microemulsion treatment.

The invention concerns a tracer material for tracing fluid flows from a hydrocarbon reservoir. The tracer material comprises a plurality of separate agglomerates. The agglomerates comprise clusters of particles. The particles carry a tracer composition. A retaining material at least partially overlies the tracer composition. The retaining material retards the release of the tracer material so that the tracer is released at a more constant rate over a longer period than in the absence of the retaining material.

The invention concerns a tracer material for tracing fluid flows from a hydrocarbon reservoir. The tracer material comprises a plurality of separate agglomerates. The agglomerates comprise clusters of particles. The particles carry a tracer composition. A retaining material at least partially overlies the tracer composition. The retaining material retards the release of the tracer material so that the tracer is released at a more constant rate over a longer period than in the absence of the retaining material.

This invention is a subterranean (non-hydraulic) shock fracturing system and process for fracturing oil and gas bearing formations. The system delivers small amounts of precisely placed explosive charges into the formation. These charges produce large diameter deep penetrations and by coupling to the rock concussively fracture the formation in the vicinity increasing permeability in the rock or strata. Shock fracturing (SF) is far more efficient than hydraulic fracturing (HF), SF fractures radially across all strata and leaves no part of the volume addressed un-permeated. The objective of the system is to efficiently increase permeability of the formation by directionally controlled concussive shattering of the rock around the epicenter of the detonation of the explosive charge deposited in the formation. This invention makes possible the delivery of measured quantities of explosive deep into a subterranean oil or gas bearing formation and detonate said explosive in order to fracture the formation in the local vicinity.

The present invention discloses a double-crosslinked thermal phase transition gel temporary plugging agent and an application thereof, and relates to the technical field of oil and gas field development. The gel temporary plugging agent comprises the following components in percentage by weight: 5.8-18.3% of acrylic acid, 2.8-6.5% of 2-acrylamide-2-methylpropanesulfonic acid, 2.8-7.0% of hydroxyethyl acrylate, 0.2-1.0% of a degradable crosslinking agent, 0.4-1.2% of borax or boric acid, 0.2-0.8% of a high-temperature initiator, 2.6-4.5% of palygorskite attapulgite, 1.5-3.1% of a urea-formaldehyde resin, and the balance of water, wherein the gel temporary plugging agent is formed by underground gelation. The gel temporary plugging agent is applied to oil and gas reservoirs with a temperature of 100-150 C., can automatically be subjected to gelation and degradation, and has a low filtration loss before gelation.

The present invention provides an oil or gas wellbore polymeric cement comprising the reaction product of an aliphatic isocyanate, a trimerization catalyst, and a catalyst retarder, wherein the reaction occurs in the wellbore at a temperature of at least 250 F. (121 C.). Also provided is a method of reducing fluid loss from an oil or gas well, comprising producing a polyisocyanurate cement by combining an aliphatic isocyanate, a trimerization catalyst, and a catalyst retarder within a wellbore at a temperature of at least 250 F. (121 C.). The various embodiments of the invention meet the controllability and minimized toxicity needed for this application. Standard aliphatic polyisocyanates reduce handling concerns while providing the reactivity response that fits this temperature range.