168 results about "Sweep efficiency" patented technology

The present invention provides a microbial consortium containing three hyperthermophilic, barophilic, acidogenic, anaerobic bacterial strains for enhanced oil recovery from oil reservoirs where temperatures range from 70° C. to 90√ C. The said microbial consortium is unique in producing a variety of metabolic products mainly CO2, methane, biosurfactant, volatile fatty acids and alcohols in the presence of specially designed nutrient medium. These metabolic products increase sweep efficiency of crude oil from oil bearing poles of rock formation. The present invention also provides a process for enhancing the oil recovery by in situ application of the said microbial consortium.

A system and method for optimizing sweep efficiency of an enhanced oil recovery process in a subterranean reservoir is disclosed. The system and method include computing a displacement coefficient representative of heterogeneity of an unswept region in the subterranean. A functional relationship between operating conditions of one or more well control devices and the displacement coefficient is determined The sweep efficiency of the enhanced oil recovery process can be optimized by adjusting the well control devices such that the displacement coefficient is minimized. Streamline simulation can be utilized to compute the displacement coefficient from the flow capacity and storage capacity of the unswept region in the subterranean reservoir.

The present invention is directed to a method of hydrocarbon production from a hydrocarbon reservoir. The method includes providing a substantially horizontal wellbore having at least one productive interval within a hydrocarbon reservoir and forming at least one non-conductive transverse fracture in the reservoir along the substantially horizontal wellbore. An injection well is also provided. A fluid is injected into the reservoir through the injection well to displace hydrocarbons within the reservoir toward a production portion of the substantially horizontal wellbore. Hydrocarbons are drained from the reservoir into at least one production interval of the substantially horizontal wellbore. Fluid production from the at least one production interval into the substantially horizontal wellbore flows through an inflow control device that can restrict the fluid flow. A non-conductive transverse fracture can form a barrier within the reservoir to divert injected fluids to increase sweep efficiency and reduce the influx of injected fluids into the production interval.

The invention provides a cross-linked polymer microsphere-polymer composite deep water control agent and a using method thereof. The control and drive agent includes water-soluble cross-linked polymer microspheres, water-soluble polymers and water; in the composite deep-seated control and drive agent, the mass percentage of the water-soluble cross-linked polymer microspheres is 0.01% to 0.3%, The mass percent content of the water-soluble polymer is 0.05%-0.5%, and the balance is water. The cross-linked polymer microsphere-polymer composite deep control and flooding agent provided by the present invention has a higher liquid flow redirection ability than conventional polymer flooding, can delay the one-way breakthrough of the polymer solution in the application process, and improve the efficiency of polymer flooding. The sweep coefficient has a higher ability to improve the oil-water phase mobility ratio than the conventional cross-linked polymer solution, and improves the displacement ability of the cross-linked polymer solution, which is more suitable for water injection development reservoirs with heterogeneous porous media.

Method for estimating fluid heterogeneity in a subsurface region from seismic wave attenuation or velocity dispersion that is either measured or extracted from geophysical data (210). A rock physics model in the form of a mathematical relationship is selected that relates attenuation or velocity to frequency and to physical properties that are related to fluid heterogeneity (220). The model, or asymptotes (230) representing the model's behavior at frequency extremes, is inverted (240) and that relationship is used to obtain (250) one or more of the physical properties related to fluid heterogeneity, such as characteristic length scale for fluid saturation heterogeneities (270) and relative volume fractions of the fluids saturating the pore space (280).

The present invention provides a method for recovering oil from a subterranean reservoir using waterflooding, wherein the flooding fluid used in the waterflooding process comprises water and one or more ionic polyvinyl alcohol copolymers. The use of one or more ionic polyvinyl alcohol copolymers is expected to increase the recovery of oil by improving both the oil / water mobility ratio and the sweep efficiency in reservoirs with a high degree of heterogeneity.

The invention belongs to the field of oilfield chemistry, and particularly relates to a reinforced gel dispersion deep profile control and flooding agent for low-permeability high-temperature high-salt oil reservoirs. The reinforced gel dispersion deep profile control and flooding agent for low-permeability high-temperature high-salt oil reservoirs is composed of the following components in percentage by mass: 0.4-0.6% of functional polymer, 0.4-0.8% of crosslinking agent, 0.2-0.3% of inorganic reinforcer and the balance of water. The average particle size distribution of the reinforced gel dispersion deep profile control and flooding agent is nano or micron size; and the reinforced gel dispersion deep profile control and flooding agent can be used for deep profile control and flooding for low-permeability oil reservoirs, and has favorable deep migration capacity, favorable profile improvement effect and obvious recovery efficiency enhancement effect. The deep profile control and flooding agent can be used for deep profile control and flooding operation of high-temperature high-salt oil reservoirs. The reinforced gel dispersion deep profile control and flooding agent effectively improves the stratigraphic profile, obviously enhances the subsequent water flooding sweep efficiency and further enhances the recovery efficiency.

The present invention provides a microbial consortium containing three hyperthermophilic, barophilic, acidogenic, anaerobic bacterial strains for enhanced oil recovery from oil reservoirs where temperatures range from 70° C. to 90√ C. The said microbial consortium is unique in producing a variety of metabolic products mainly CO2, methane, biosurfactant, volatile fatty acids and alcohols in the presence of specially designed nutrient medium. These metabolic products increase sweep efficiency of crude oil from oil bearing poles of rock formation. The present invention also provides a process for enhancing the oil recovery by in situ application of the said microbial consortium.

The present invention relates compositions and methods for enhanced oil recovery. The method is directed to employing a water-soluble The present invention relates compositions and methods for enhanced oil recovery (EOR). The method is directed to employing a water-soluble functional polymeric surfactant (FPS), with a medium IFT value, preferably ranged from about 0.1 to about 15 dyne / cm between water phase containing polymeric surfactant and hydrocarbon phase, for recovery of hydrocarbons from subterranean formations. The FPS solution demonstrates a strong interaction with oil and the great potential to increase both volumetric sweep efficiency and microscopic displacement efficiency in EOR.

In a WAG flood oil is displaced from a subterranean formation by injecting water alternately with gas into a single injection completion per pattern. The ratio of water to gas injected is the WAG ratio. In this invention, two separate injection completions are used in each pattern, with one placed directly above the other. A very low WAG ratio is used for injection into the bottom extremity of the formation. A very high WAG ratio is injected into the upper interval, at as high a rate as can safely be used without fracturing the formation. In the preferred embodiment, two horizontal well bores serve as the two completion intervals. Proper design of this method gives a vertical sweep efficiency of the gas that is several-fold greater than the best of previous WAG flood designs, especially in thin formations.

The invention provides a CO2 drive oil-gas-water separate well injecting oil reservoir mixing drive development method, and belongs to the field for improving recovery ratio of an oil reservoir. The method comprises the following steps of: firstly, determining a development well pattern, well spacing and a development layer system of the oil reservoir; then, utilizing an overall process numerical simulation technique to determine advantage seepage direction and sweep efficiency of injection gas, designing an injection well in the advantage seepage direction of the injection gas as a water injection well, designing other injection wells as a gas injection well, forming water-gas mixed drive of partial water injected to well and partial gas injected into well; and finally determining the injection parameter of an injection production well and the development index forecast of a whole region. The method can form a water barrier in a gas channeling direction, thereby effectively controlling gas channeling, enlarging swept volume of the injected gas, and improving recovery efficiency; and the method provided by the invention has excellent guiding function on the gas injection drive oil well pattern, well type and injection and production parameter of a developed block and an undeveloped block, and the application prospect is wide.

The invention provides a similar limit water cut period take-turn water drive method for a multi-layer sandstone reservoir. The method includes the steps that a geological model based on single-cause sand bodies is established; on the basis that the geological model based on the single-cause sand bodies is established, a remaining oil distribution model based on the single-cause sand bodies is established; the single-cause sand bodies similar in property are combined into cause sand body sets; according to the reservoir characteristics of different single-cause sand body sets in a layer system and the remaining oil distribution conditions, the corresponding vectorization water drive adjustment scheme is determined; take-turn water drive based on the single-cause sand body sets is performed. With the similar limit water cut period take-turn water drive method for the multi-layer sandstone reservoir, influences of the heterogeneity of reservoir stratums of the multi-layer sandstone reservoir on water drive development can be reduced to the maximum, comprehensive displacement and balance displacement in a plane in the longitudinal direction of the single-cause sand bodies are achieved, and therefore a high-strength and high-efficiency water driving flow field can be established, and water drive sweep efficiency and water drive recovery efficiency can be improved substantially.

A process for recovering oil from a carbonate reservoir of high salinity, wherein supercritical CO2 floodings are combined with a fluorosurfactant in the tertiary recovery. Embodiments include alternating injection and co-injection schemes of the supercritical CO2 and the fluorosurfactant. A stable fluorosurfactant-CO2 foam that is not susceptible to the harsh conditions of the reservoir (temperature, pressure and salinity) can be successfully generated, leading to a reduction in the mobility of CO2, an increase in the mobility of the reservoir oil, higher contact between the injected fluid with the oil and a better sweep efficiency of the oil.

The present invention relates to compositions and methods for enhanced oil recovery. The method is directed to employing a water-soluble fThe present invention relates compositions and methods for enhanced oil recovery (EOR). The method is directed to employing a water-soluble functional polymeric surfactant (FPS), with a medium IFT value, preferably ranged from about 0.1 to about15 dyne / cm between water phase containing polymeric surfactant and hydrocarbon phase, for recovery of hydrocarbons from subterranean formations. The FPS solution demonstrates a strong interaction with oil and the great potential to increase both volumetric sweep efficiency and microscopic displacement efficiency in EOR.

The invention provides a determining method for a distance of well-drain and the length of a pressure break of low penetration oil reservoir artificial fracture. The determining method comprises the following steps of first, establishing a well yield formula under a non-darcy flow condition, second, establishing water drive sweeping efficiency calculating formula of different well patterns under the non-darcy flow condition, third, drawing matching plates of different well distances, well-drain distances and pressure-break lengths of a target oil reservoir based on the water drive sweeping efficiency calculating formula, and fourth, evaluating a reservoir stratum use condition of the reservoir stratum, optimizing the well-drain distance and optimizing the matching pressure-break length according to the matching plates of the different well distances, well-drain distances and pressure-break lengths in the third step. Optimized combination between pressure-break half length and the well-drain distance can be achieved when water drive sweeping efficiency and economic and rational well-drain distance of the target oil reservoir are determined; and the method requires less parameters, quick calculation and strong application.

The present invention provides methods and apparatuses for the enhanced recovery of hydrocarbon fluids from subterranean reservoirs using cryogenic fluids. Using the Earth's geothermal energy to warm cryogenic flood fluids injected into subterranean reservoirs, the pressure within the subterranean reservoir is increased. Consequently, the reservoir conductivity is enhanced due to thermal cracking, and improved sweep efficiency of the reservoir by the flood fluids is provided. This rise in pressure due to the injection of the cryogenic fluid increases the reservoir conductivity enhancement and improves sweep efficiency of the flood fluids, which leads to the production of more fluids from to the subterranean reservoirs.

The invention discloses a method and a well pattern structure for mining an oil deposit with nano magnetofluid displacement. The method comprises the steps that an injection well, four edge wells and four corner wells form a square inverted nine-spot displacement well group; electromagnets are put into shafts of the edge wells and the corner wells; a nano magnetofluid dispersion solution is injected into the injection well; the electromagnets under the edge wells are started; a magnetic flux is adjusted; the electromagnets under the edge wells are closed; oil flow production is started; the electromagnets under the corner wells are started; a magnetic flux is adjusted; the electromagnets under the corner wells are closed; the oil flow production is started; the electromagnets under the edge wells are started; the magnetic flux is adjusted; and the edge wells and the corner wells alternately apply an electromagnetic field and alternately conduct the oil flow production for a certain period according to the sequence. The method for mining the oil deposit with the nano magnetofluid displacement changes an oil displacement direction and a speed of a nano magnetofluid in an oil layer by adopting the alternate magnetic field and an alternate production mode of the corner wells and the edge wells, so that crude oil between injection and production wells is used effectively, the sweep efficiency of an injection medium is improved, and a recovery ratio of the crude oil in the oil deposit is increased.

The invention discloses a method for increasing condensate oil recovery ratios of condensate gas reservoirs by means of gas injection vertical displacement, and belongs to the technical field of condensate gas field development. The method includes selecting proper injected gas according to a principle that a gravitational differentiation phenomenon is obvious when a density ratio of the preferable injected gas to fluid of the gas reservoirs is lower than 0.75 under a formation condition in gas injection physical model experiments and actual production; determining injection and production well locations, perforation intervals, well patterns and well spacing by the aid of a kinetic mechanical analysis process for micro-elements of the injected gas so as to effectively form artificial gas caps in gas injection procedures; determining critical gas production rates according to a critical production rate correction formula. The critical gas production rates are used for preventing increase of gas-oil ratios due to coning of the injected gas. The method has the advantages that the artificial gas caps can be formed at high structural positions by the injected gas, condensate gas can be subjected to vertical downward displacement by the aid of the injected gas, accordingly, the sweep efficiency of the injected gas is close to 100%, and the injected gas utilization rate and the final condensate oil recovery ratios can be obviously increased.

A method for enhancing oil recovery by combining miscible or near miscible gas flooding with Alkaline-Surfactant-Polymer (ASP) flooding to produce an enhanced Water-Alternating-Gas (WAG) flooding method is described. The ASP flooding may include individual and combination injections of alkaline, surfactant and polymer. Carbon dioxide may be used as a flood gas. Numerical simulations show that the present method may provide better oil recovery when compared with separate ASP or CO2 WAG flooding for different depositional environments, as a result of high micro and macro sweep efficiencies plus miscible gas flooding. A significant acceleration and improvement in recovery may be achieved with as small as a 10% pore volume ASP slug size.

In a WAG flood oil is displaced from a subterranean formation by injecting water alternately with gas into a single injection completion per pattern. The ratio of water to gas injected is the WAG ratio. In this invention, two separate injection completions are used in each pattern, with one placed directly above the other. A very low WAG ratio is used for injection into the bottom extremity of the formation. A very high WAG ratio is injected into the upper interval, at as high a rate can safely be used without fracturing the formation. In the preferred embodiment, two horizontal well bores serve as the two completion intervals. Proper design of this method gives a vertical sweep efficiency of the gas that is several-fold greater than the best of previous WAG flood designs, especially in thin formations.

Systems and methods for creating a hydraulic barrier at an interface between high and low permeability regions that may exist in high permeability-contrast subterranean formations. These systems and methods may include providing injection and / or production wells that are completed within the high and / or low permeability regions, supplying a pore throat blocking agent to an interface between the high and low permeability regions, and forming the hydraulic barrier at the interface. The pore throat blocking agent may be sized to substantially flow through the high permeability region while being substantially blocked, or occluded, from the low permeability region. In some embodiments, the hydraulic barrier may be greater than one acre (0.4 hectare) in area. In some embodiments, the subterranean formation may include an oil reservoir. In some embodiments, the high and / or low permeability formations may be swept concurrently and / or independently to remove oil from the oil reservoir.

The invention discloses a high-temperature resistant secondary cross-linked gel profile control agent and a preparation method thereof, and belongs to the technical field of oilfield chemistry. The profile control agent has good gelling property and high plugging strength and can resist high temperature of 150 DEG C, and the gelling strength and the gelling time can be adjusted. The high-temperature resistant secondary cross-linked gel profile control agent is mainly characterized by the secondary composite crosslinking process, that is, a plugging agent reacts with a first crosslinking agent under the ground condition to form flowable gel similar to weak gel so as to reduce filter loss of the plugging agent in oil deposit during the construction process and reduce the risk of blocking a low-permeability oil flow channel by the plugging agent; and a second crosslinking agent has a second crosslinking reaction under the high-temperature condition of an oil layer to form high-strength gel so as to effectively plug a high-permeability steam flowing channel, and accordingly, steam suction is controlled, and the sweep efficiency is improved. Gelling of the high-temperature resistant secondary cross-linked gel profile control agent is characterized in that micromolecules are inserted into organic macromolecular materials HPAM, and micromolecules and macromolecules mutually permeate, so that a gel system easily performs sizing; and meanwhile, temperature resistance, salt resistance, shear resistance and ageing resistance are enhanced, and the system performance can be well played.

The invention discloses fracturing fluid and a preparation method thereof. The fracturing fluid is formed by mixing base fluid and crosslinked fluid according to the crosslinking ratio of 100 to 5; the base fluid consists of the following compositions according to mass percentage: 03 to 0.5 percent of hydroxypropyl guanidine gum HPG-1, 0.4 to 0.5 percent of a temperature stabilizer for the fracturing fluid, 0.05 to 0.15 percent of a low temperature evocating agent for the fracturing fluid, 0.2 to 0.3 percent of a cleanup additive and the balance being sewage water from a crude oil layer; and the crosslinked fluid consists of the following compositions according to mass percentage: 0.5 to 1.5 percent of borax, 0.5 to 1.5 percent of ammonium persulfate and the balance being clear water. The method for preparing the fracturing fluid comprises the following steps: the prepared base fluid and the prepared fracturing fluid are respectively placed for 100 to 120 minutes and are mixed according to the crosslinking rate of 100 to 5 to form the fracturing fluid. The method adopts the sewage water for matching the fracturing fluid, saves cost, has small pollution to the environment and improves the wave and volume of a water-driven reservoir and the oil-sweeping efficiency.

The invention relates to a surfactant micelle oil displacement agent which is used for increasing recovery rate of crude oil chemical flooding. The micelle oil displacement agent includes, by weight, 0.3-0.6% of lauramide propyl betaine, 0.1-0.2% of lauryl sodium sulfate, 0.3-1.0% of nano silicon dioxide sol, 2-4% of sodium chloride, and the balanced being water, wherein all the components are mixed together to prepare the micelle oil displacement agent. The particle size of the nano silicon dioxide sol is 7 nm, the sum of the weight percentage ratios of the components is 100%. By adding the nano silicon dioxide, the micelle oil displacement agent is improved in oil resistance and viscoelasticity and is improved in the capability of reducing oil-water interface tension, so that not only is displacement efficiency increased but also sweep efficiency is increased. As an oil displacement agent for tertiary oil recovery, the micelle oil displacement agent can increase the recovery rate by more than 7% on the basis of water flooding.

The invention relates to the field of oil displacement of an oil reservoir and discloses an oil displacement method of an oil reservoir. The oil displacement method comprises the steps of injecting apreposed slug A into an oil layer from an injection well, then injecting gas, sequentially and alternately injecting a viscosity reduction oil displacement system B and the gas, injecting a protectionslug C, and injecting water at last, wherein the preposed slug A is an aqueous solution containing a surfactant and / or a polymer; the viscosity reduction oil displacement system B comprises a surfactant, alcohol, a polymer and water; and the protection slug C is an aqueous solution containing a polymer. According to the method, a shearing effect of an emolsifier and high-viscosity oil in a deep stratum is enhanced by a periodically changed 'liquid-gas' alternating injection method; emulsification of the high-viscosity oil in the deep stratum is promoted; an emulsification and displacement effect of an oil displacement system in the deep stratum is strengthened; and displacement efficiency and sweep efficiency in an oil displacement process are significantly improved.

The present invention discloses an oilfield profile and drive control blocking system which comprises a sludge pool, a clean water pool and a stirring pool. The sludge pool and the clean water pool are connected through a pipeline which is provided with a flow meter. The clean water pool is connected to the stirring pool through a clean water pipeline which is provided with a valve. The stirring pool is internally provided with a drug injection port and an output tube. The output tube is provided with the flow meter and a pressure meter. The output tube is connected to a water injection well and is provided with three output valves. The water injection well is communicated with a ground layer with the need of filling. The invention also relates to a method for using the oilfield profile and drive control blocking system to carry out oilfield profile and drive control blocking and a composition for each slug system in the oilfield profile and drive control blocking method. Oil-contained sludge can be transformed to make a profile control sealing agent and carry out deep drive control, the oilfield sealing is carried out, and the problems of oil injection well single direction onrushing, low sweep efficiency and uneven oilwell benefit are solved.

A process for recovering oil from a carbonate reservoir of high salinity, wherein supercritical CO2 floodings are combined with a fluorosurfactant in the tertiary recovery. Embodiments include alternating injection and co-injection schemes of the supercritical CO2 and the fluorosurfactant. A stable fluorosurfactant-CO2 foam that is not susceptible to the harsh conditions of the reservoir (temperature, pressure and salinity) can be successfully generated, leading to a reduction in the mobility of CO2, an increase in the mobility of the reservoir oil, higher contact between the injected fluid with the oil and a better sweep efficiency of the oil.

The invention relates to an oil and gas reservoir development unit and well group numerical simulation dynamic analysis method. The method includes the steps of analyzing the injection and production relation and the production state in a development unit, putting forward a reasonable adjustment potential tapping measure, obtaining a sweep triangle followed by an oil reservoir production degree and volume sweep efficiency relation curve from a matter balance equation, making the oil reservoir production degree and volume sweep efficiency relation curve fall into the sweep triangle when matter balance of an oil reservoir is kept, and judging the oil reservoir dynamic state from the form and tendency change of the curve. Meanwhile, in order to further learn the detailed dynamic situation between wells in the oil reservoir, the oil reservoir needs to be subdivided into subunits; a virtual boundary is drawn for a well group unit, and the problem that a non-flow boundary is troublesome to process is ingeniously solved by adjusting parameters in the dynamic analysis process. A numerical result can be given by conducting dynamic monitoring and dynamic analysis and prediction on the oil field production, and the oil reservoir dynamic situation can be simply and clearly reflected.

Re-crosslinkable preformed particle gels and compositions containing, e.g., those further comprising at least one re-crosslinking agent are provided, as well as the use thereof, e.g., in methods, processes, and techniques related to enhanced oil recovery, e.g., conformance control, wherein the use of said re-crosslinkable preformed particle gels when re-crosslinked may improve hydrocarbon recovery, e.g., by improving sweep efficiency. These re-crosslinkable preformed particle gels and compositions containing are also useful in water and gas shutoff, fluid loss control, zone abandonment, water and gas coning, squeeze and recompletion, chemical liner completions and lost circulation during drilling operations and plugging during drilling and drilling completion.