960 results about "Formation water" patented technology

An arrangement for restricting the inflow of formation water from an underground formation to a hydrocarbon producing well, where, between the underground formation and a production tubing (38) located in the well, there is disposed at least one flow chamber (3, 33) connected to the production tubing (38), the flow chamber (3, 33), preferably via a filter (2) in one portion, being open to inflow of formation fluid and in communication with the production tubing (38) via at least one opening (7, 32), and where the flow chamber (3, 33) is provided with at least one free-floating body (4, 34) with approximately the same density as the formation water, the at least one body (4, 34) being designed by means of the closing of at least one opening (32) or choking, to reduce the inflow of formation water to the production tubing (38).

The invention relates to an oil-water displacement efficiency experimental method of longitudinal and planar nonhomogeneous slab models, which comprises an oil-water displacement efficiency experimental method of a longitudinal nonhomogeneous slab model and an oil-water displacement efficiency experimental method of a planar nonhomogeneous slab model. The experimental method mainly comprises the following steps: 1. applying confining pressure to the core holder of a multilayer slab model, then vacuumizing the multilayer slab model with three layers slab model, injecting simulated formation water to saturate cores, and then heating; 2. injecting simulate formation oil in a piston type container into the core holder of the multilayer slab model, and carrying out water-oil displacement to establish bound water saturation level; and 3. injecting simulate formation water in the piston type container into the core holder of the multilayer slab model, and carrying out water-oil displacement to obtain accumulated displacement oil output and wateryield under different water injection multiples, and thereby, the oil displacement efficiency is obtained. The invention not only can carry out displacement experiment research on the longitudinal nonhomogeneous slab model at high temperature and pressure but also can carry out displacement experiment research of different flooding well networks on the planar nonhomogeneous slab model under high temperature and pressure. The highest pressure reached by the experimental method is 25MPa, and the highest temperature reached by the experimental method is 100 DEG C.

The invention relates to a supercritical carbon dioxide drive physical analogue device, which belongs to the technical field of petroleum engineering and technology. The device adopts two paratactic simulation core devices to be connected with an injecting system, and each simulation core device is provided with an outlet measuring system; the injecting system injects formation water, crude oil and supercritical carbon dioxide to the simulation core devices, and a temperature and pressure measuring and controlling system is adopted to control the temperature set value and the pressure value of the whole system, and the outlet measuring system is adopted to measure the volumes of the carbon dioxide, the formation water and the crude oil which pass through the simulation core devices. After the CO2 gas is cooled and liquefied, the CO2 gas is pressurized and heated up to the supercriticality, and the difficulty of the accurate measurement of the injected CO2 flow; by adopting a double-tube model, the fingering and cross flow phenomenon during the driving process of the heterogeneous reservoir CO2 can be simulated; the design pressure of the device is 0 to 40 MPa, the design temperature is 0 to 180 DEG C, and the device is mainly applied to the research on supercritical CO2 miscible drive, non-miscible drive, continues gas drive or water and gas alternate drive.

A carbon dioxide drive nuclear magnetic resonance imaging detection device belongs to the technical field of petroleum engineering and technology. The detection device comprises: a simulation core device which is arranged in a nuclear magnetic resonance imaging device; an injection system which sequentially injects formation water, crude oil and supercritical carbon oxide into the simulation core device; a measurement and control system which is employed to control pressure and temperature of the whole system; the nuclear magnetic resonance imaging device which is employed to detect and perform quantitative analysis on an image to be tested to obtain voidage and permeability of a porous medium, and saturation seepage parameters of the supercritical carbon oxide, the formation water and the crude oil; and an output measuring system which is employed to measure volumes of the carbon dioxide gas, the formation water and the crude oil. The detection device has a design pressure of 0-40MPa and design temperature of 0-180 DEG C, and can simulate experimental studies of different displacement schemes of the supercritical CO2 under a complex petroleum reservoir condition; the simulation core device is made of a brass material, which produces no magnetism, satisfies requirements for high pressure and strength, has a compact structure, can be recycled, is conveniently operated, simple and applicable in an experimentation.

The invention relates to a preparation method of an emulsion deep profile/displacement control agent containing gel microspheres of a core shell structure. According to the method, materials are fed many times to carryout inverse emulsion low-temperature oxidation and reduction to initiate free radical polymerization so that water-solubility monomers (including acrylamide, ionic monomer I, the ionic monomer II and the third monomer) react with a cross-linking agent to generate the emulsion deep profile/displacement control agent containing gel microspheres of a core shell structure. The invention also relates to the emulsion deep profile/displacement control agent containing gel microspheres of a core shell structure, which is prepared by using the method. The profile/displacement control agent is a water-solubility microgel oil displacement material containing gel microspheres from nano scale to micron scale; with small initial grain size, the profile/displacement control agent can enter into the deep part of stratum; in addition, the profile/displacement control agent has high emulsion active component content and good flowability, can have volume expansion and mutual cementation under the actions of formation water and temperature according to the condition whether charges carried by the ionic monomers at a core layer and a shell layer are same or not; therefore the profile/displacement control requirements of different geological oil deposits of oil fields can be met.

Techniques for determining formation characteristics use measurements of dielectric permittivity at a number of frequencies. Determined characteristics include the vertical and horizontal formation dielectric constant and conductivity, the formation water conductivity, the water saturation, the cementation and the saturation exponents. In laminated formations these profiles can be determined for each lamina. Also, formation dielectric properties are used in determination of the rock type.

A method to stimulate the biogenic production of a metabolite with enhanced hydrogen content that includes forming an opening in a geologic formation to provide access to a consortium of microorganisms, and injecting water into the opening to disperse at least a portion of the consortium over a larger region of a hydrocarbon deposit. The method may also include measuring a change in the rate of production of the metabolite in the formation. Also, an method to stimulate biogenic production of a metabolite that includes measuring a salinity level of formation water in a geologic formation, and injecting water into the opening to reduce the salinity level of the formation water in the formation. The method may also include measuring a change in the rate of production of the metabolite in the formation.

The invention discloses a method for judging the reservoir fluid type of a difference between density porosity and neutron porosity and relates to the technical fields of oil and gas logging and geology and core test analysis. The method comprises the following steps: 1) accurately calculating the shale content, the rock composition, the density porosity and the neutron porosity of a reservoir bycore data calibrating logging and logging data environmental correction; 2) removing the influence of factors of lithology, well diameter and mud invasion on density and neutron data; and 3) establishing standards for judging the reservoir fluid type by utilizing the response difference of the density and the neutron data to gas and formation water and by comparing the values of the density porosity and the neutron porosity. When the invention judges the reservoir fluid type by utilizing the density and the neutron data, non-fluid influencing factors, such as lithology, borehole conditions, mud invasion and the like are removed, therefore, influence features of different fluids to the density and the neutron data can be truly reflected, and the coincidence rate for judging the reservoir fluid type can be enhanced to above 90 percent from the existing 70 percent.

The invention discloses a device and method for thickened oil deposit gas injection huff-puff oil extraction physical simulation experiments. The device comprises an injection system, a model system, an output control system and a data collection and control system, wherein the injection system is connected with the model system so as to inject formation water, crude oil and huff-puff gas into the model system, the outlet end of the model system is connected with the output control system, the output control system is used for controlling the output of oil-gas mixtures of the model system and calculating gas flow and oil production in the outputted oil-gas mixtures, the model system is further connected with the data collection and control system, and the data collection and control system is used for collecting pressure, temperature and huff-puff gas flow data in a model body and monitoring and processing data in real time. The device can be used for truly simulating processes of injecting gas into a stratum, soaking and extracting indoors and monitoring pressure and pressure gradient distribution rules of different positions from the well bottom of a gas injection well to the far end of the stratum in gas injection and extraction simulation processes.

The purpose of this invention is to improve on the safety and to allow more efficient production of subterranean formation during fracturing operations with a reduced down-time, minimal supervision and maintenance expense by utilizing remotely operated ground valves having metal-to-metal, gate and seat seal design operable to maintain a dual sided flow and pressure control. Use of a new 45-degree flow-T connector of a Zipper Manifold in combination with the system described is particularly useful for reducing erosion with proppant-laden fracturing fluid.

The invention discloses an experimental test method for gas reservoir reverse imbibition water blocking damage evaluation under a high-temperature and high-pressure condition. The experimental test method is completed through a water blocking effect experimental measuring device. The experimental test method comprises the steps that firstly, a core is washed and dried to be placed into a core holding unit; secondly, the core is vacuumized, displacement pressure is increased to formation pressure Pf, and formation water is injected into the core under constant pressure; thirdly, the temperature is raised to the formation temperature T0; fourthly, nitrogen is injected into the core, displacement is carried out until the liquid level of a water measuring meter at the core outlet end does not change, and gas phase permeability K1 is calculated; fifthly, formation water is injected into the core until no gas is discharged out of the core outlet end; sixthly, secondary gas driving water is carried out on the core, displacement is carried out until the liquid level of the water measuring meter at the core outlet end does not change, and gas phase permeability K2 is calculated; seventhly, the damage degree of water blocking damage to the gas phase permeability is determined. The experimental test method conforms to the actual gas reservoir developing process, a reasonable testing method is provided for reservoir water blocking damage measuring evaluation, and the experimental test method has wide market prospects.

The invention discloses a method for judging the fluid type of a reservoir through an acoustic porosity-neutron porosity differential, which relates to the technical field of oil and gas logging, geology and core test analysis. The method comprises the following steps: 1) accurately calculating shale content, rock compositions, acoustic porosity and neutron porosity of the reservoir through core data calibration logging and logging data environment correction; 2) excluding the influence of factors such as lithology, borehole diameter and mud invasion on an acoustic transit time and neutron data; and 3) establishing a standard for judging the fluid type of the reservoir by comparing the magnitude of the acoustic porosity and the neutron porosity and using the response difference of the acoustic transit time and the neutron data to the gas and formation water. In the method, non-fluid influence factors such as the lithology, borehole conditions, mud invasion and the like are excluded when the fluid type of the reservoir is judged, so the characteristics of the influence of different fluids on the acoustic transit time and the neutron data can be grasped truly, and the coincidence rate of judging the fluid type of the reservoir is improved from 70 percent currently to over 90 percent.

The invention discloses a low-tension viscosity-reducing oil displacement agent, which is used for common heavy oil reservoirs, has a good viscosity-reducing effect, has good compatibility with formation water, can form ultra-low interfacial tension with crude oil, and is prepared from the following components by weight: 30-50% of an alkyl alcohol polyoxyethylene ether sulfate salt, 15-25% of a nonionic surfactant, 15-25% of an anionic surfactant, 2-5% of an organic solvent, 0.1-3% of sodium chloride, and 5-25% of water. According to the present invention, during the use, the low-tension viscosity-reducing oil displacement agent and the polyacrylamide polymer form the composite oil displacement system, wherein the polyacrylamide polymer can provide effects of water phase viscosity increasing, water-oil mobility ratio reducing, conformance expanding and profile control expanding, and the low-tension viscosity-reducing oil displacement agent can provide effects of oil-water interface tension reducing, oil displacement efficiency improving and crude oil viscosity reducing so as to further improve the water-oil mobility ratio, such that the extraction rate of the common heavy oil reservoir can be substantially improved through the synergetic effect of the polyacrylamide polymer and the low-tension viscosity-reducing oil displacement agent.

Methods for the removal of alkaline and sulfate scales from aqueous saline streams such as seawater, oil-gas fields produced waters, formation waters, and the like. Such processing methods can also be extended for the simultaneous removal of hydrogen sulfide, and/or sulfur dioxide, and/or oxides of nitrogen, and/or carbon dioxide from gaseous streams. The same processing concept with modified methods can further be employed for the removal of gases such as radon, hydrogen sulfide, sulfur dioxide, oxides of nitrogen, and carbon dioxide from gaseous streams.

This invention relates to a process utilizing natural carbon-13 isotope for identification of early breakthrough of injection water in oil wells. All natural water sources are labeled by unique ratios of carbon isotopes (¹³C/₁₂C). Following the requirements of the invention, the carbon isotope ratio for oil bearing formation water and for local aquifer water which is to be injected in to the oil reservoir rock is determined. The carbon isotope ratio of the produced water from the selected oil wells is then monitored periodically. When the carbon isotope ratio of the produced (oil well) water shows deviation from the formation water value and tends towards injection water value, then the early breakthrough phenomenon of injection water is identified. Thus the contrast in natural carbon isotope ratios of injection water, formation water and produced water from selected oil wells serve as tracer in the identification of “Early Breakthrough” phenomenon of injection water and its movement.

The invention discloses a method for improving the oil displacement efficiency of a medium-permeability core. The method comprises the following steps: taking a core for an experiment, washing oil away and drying the core, conducting a gas survey on the permeability of the core; preparing experimental simulated formation water and simulated oil; immersing the core into the simulated formation water to enable the core to be saturated with the simulated formation water; measuring the porosity, and calculating the pore volume; preparing simulated formation water solution, and replacing the saturated simulated formation water core; using simulated crude oil to replace the core to detect a nuclear magnetic resonance spectrum, using the simulated formation water solution to replace the core to calculate the oil displacement efficiency; injecting foam liquid+carbon dioxide to calculate the oil replacement efficiency, and detecting a nuclear magnetic resonance spectrum; injecting carbon dioxide gas+simulated formation water to calculate the oil replacement efficiency; injecting the foam liquid+carbon dioxide and carbon dioxide+simulated formation water containing the to calculate the oil displacement efficiency; comparing different nuclear magnetic resonances, adding the oil replacement efficiencies under different replacement methods, and obtaining the total oil replacement efficiency. According to the method for improving the oil displacement efficiency of the medium-permeability core, on-line tests can be achieved, a sample does not need to be disassembled and assembled, and practical testing is conducted to improve the oil replacement efficiency of the medium-permeability core.

It has been discovered that certain fracturing fluid compositions can be used to fracture a subterranean formation and be permitted to stay within the formation for a relatively extended period of time, for example 28 days or more, before being flowed back or produced. At least two embodiments are envisioned, a bacteria-containing formulation and an anti-bacterial formulation. Both systems would be expected to prevent the potential of the fluid to oil wet the formulation (water block condition) by keeping the formation water wet through the use of water wetting surfactants or solvents. Additionally, both formulations would control reservoir crude souring (H₂S generation by in situ sulfate-reducing bacteria), reservoir plugging (via slime biopolymers generated by in situ microbes, inorganic scale deposition like calcium carbonate or barium sulfate, and clay fines migration).

An inline measuring apparatus (10) is operable to measure hydrate, wax, break-through of formation water and/or scale (150) on an inside surface of a wall (100) of a pipe (40) for guiding fluid. The apparatus (10) includes an electronics unit (30) coupled to a sensor arrangement (20) disposed in a spatial extensive manner into the wall (100) of the pipe (40) for sensing the growth (150). The electronics unit (30) in cooperation with the sensor arrangement (20) Is operable to perform a series of dielectric measurements at a plurality of interrogating frequencies for determining a nature and spatial extent of the growth (150). The sensor arrangement (20) includes a plurality of sensors have mutually different sensing characteristics in relation to their spatial sensing region and/or their sensitivity to different fluid components present in operation within the pipe (40). Optionally, the apparatus (10) is capable of being operated synergistically in a plurality of different operating modes which enables detection of thin film formation at an inside wall of the pipe (40) as well as a measurement of bulk properties of fluid present within the pipe (40).

The invention discloses a method for quantitatively evaluating influence of water injection on distribution of pore throats. The method comprises the following steps: taking rock core for experiment, scrubbing oil and drying, measuring porosity and gasometry permeability of the rock core and calculating pore volume; preparing formation water salinity of simulated formation water for experiment; preparing oil field crude oil viscosity of experiment simulated oil; saturating the rock core and simulating the formation water, and measuring a nuclear magnetic resonance T2 spectrum; displacing the rock core of the saturated and simulated formation water by using prepared and simulated oil and recording original oiliness saturation and recording initial oil saturation; selecting a simulated formation water displacing speed according to the rock core permeability, simulating formation temperature and pressure, displacing the rock core of the saturated oil by using the simulated formation water and enabling the rock core to achieve residual oil saturation; scrubbing oil and drying the rock core, then saturating the simulated formation water and measuring a nuclear magnetic resonance T '2 spectrum; respectively drawing a distribution curve graph of the nuclear magnetic resonance spectrums before and after driving water, quantifying to obtain the degrees of influence of different water drives on the distribution of the pore throats. The method is capable of testing online, thereby realizing the quantitative evaluation on the degree of influence of water injection on the distribution of the pore throats.

The invention provides a visual experiment device and method for simulating fracture-vug type carbonatite oil reservoir gas injection. The visual experiment device for simulating fracture-vug type carbonatite oil reservoir gas injection comprises a computer, a camera, a visual core clamping device, a planar light source, a simulation formation water piston container, a stratigraphic simulation oil piston container, a gas piston container, a constant-flux pump, a six-way valve, a pressure meter, a pressure stabilizing tank, a back-pressure valve, an oil, gas and water metering device and a pressure-resistant gas flow meter. The visual experiment device is adopted in the experiment method. By means of the device and method, fracture-vug type carbonatite oil reservoir gas injection can be simulated, production performance of the recovery efficiency is improved, and flow states and distribution conditions of a crude oil phase, a gas phase and a water phase in the gas injection huff and puff process can be observed.

The invention discloses a complex lithology natural gas reservoir interval transit time discriminating method, and belongs to the technical field of acoustic logging information application. Formation lithology mineral composition, porosity, water saturation and formation water electrical resistivity factors are utilized to calculate an interval transit time theoretical value curve, the interval transit time theoretical value curve obtained through calculation is compared with an interval transit time curve measured actually, and a natural gas reservoir is discriminated according to the different features of the interval transit time theoretical value curve obtained through the calculation and the interval transit time curve measured actually. The complex lithology natural gas reservoir interval transit time discriminating method is especially suitable for being used in discrimination of natural gas reservoirs of clastic rock, carbonate rock, igneous rock and the like, good in application prospect and capable of improving discriminating effect of the natural gas reservoirs.

Water disposal systems, apparatuses and methods that employ same, and methods for disposing water produced during power generation are provided. A separator of a fuel cell has an air supply groove formed therein for supplying air as an oxidizer gas to a cathode. The separator is also provided with water-absorbing cloths on the midway portion of the air supply groove. More specifically, the water-absorbing cloth is provided on the separator (110), as a water absorbing member for absorbing the water, so as to cover at least a part of the surface on which the air supply grooves is formed and the water-absorbing clothes is provided along the sidewall of the air supply grooves. Water generated during power generation by the power generator of the present invention is disposed in efficient and reliable manners, under a simple configuration.

The invention relates to a device and method for determining high temperature and high pressure full diameter core mud pollution evaluation. The device is mainly composed of an injection pump, a confining pressure pump, a mud intermediate container, a mud circulating device, a full diameter core holder, a nitrogen intermediate container, a formation water intermediate container, a confining pressure intermediate container, a back pressure intermediate container and a graded tube. The full diameter core holder, the nitrogen intermediate container and the formation water intermediate container are located in a high temperature and high pressure constant temperature oven, the mud circulating device comprises a low pressure circulating cylinder, a high pressure circulating mud cylinder and an automatic control device, and a supporting frame is arranged between the low pressure circulating cylinder and the high pressure circulating mud cylinder. The device and method for determining the high temperature and high pressure full diameter core mud pollution evaluation adopts a unique external circulation mode, uses a low pressure air source as power to drive high pressure mud to circulate, eliminates the problem that a conventional circulation device is easy to block and damage and short in service life, fills the blank that a conventional drilling fluid filtration apparatus cannot perform filtration experiment evaluation on a large-size full diameter core, and can comprehensively simulate and evaluate the drilling fluid pollution mechanism under real gas reservoir condition.

The invention discloses a method for testing gas-water relative permeability of a dense core. The method comprises the following steps: (1) preparing an experimental core, measuring the porosity and the klinkenberg permeability of the core, and determining the minimum return pressure of weakening a slippage effect; (2) establishing water saturation in the core by utilizing formation water or simulation formation water; (3) arranging the core in a core holding unit, applying confining pressure to the original effective stress or reservoir overburden pressure and constant displacement pressure p1, applying return pressure p2 at the core outlet, and measuring the gas flow of the core; (4) measuring the gas flow of the core under different water saturations, and calculating the gas-phase effective permeability and gas-phase relative permeability of the core; (5) establishing 100 percent of water saturation in the core, and measuring the accumulated water yield of the core in unit time; and (6) calculating the water-phase effective permeability and water-phase relative permeability of the core. The method disclosed by the invention can be used for really reflecting the gas seepage conditions under in-situ conditions and simulating the underground production state and has wide market prospects.

The invention relates to a device for measuring parallel core foam flooding gas-phase shunt volume. The device mainly comprises a foam generating device, an intermediate container for containing formation water, an intermediate container for containing crude oil, a thermostat, core barrels and a data acquiring system, wherein weighing sensors are arranged at the bottom of produced liquid collectors, and are used for monitoring the weight of separated liquid of outlets of the core barrels; and wide-mouth bottles are connected with the produced liquid collectors through gas meters. By the device, the gas-phase shunt volume of parallel cores can be independently measured in real time in a parallel core foam flooding process. Produced liquid at outlet ends of the parallel cores is subjected to gas-liquid separation, and the gas-phase shunt volume of the outlet ends of the parallel cores is measured by using a specific device. Moreover, the device can also be used for measuring the weight of separated liquid of the outlets of the parallel cores, and profile control shunt conditions of foam on high and low permeable formations in the parallel cores under different injection rates can be analyzed by combing liquid injection quantity and change of pressure at two ends of each of the parallel cores.