63 results about "Formation fluid" patented technology

The invention discloses a high-temperature-resistant and high-pressure-resistant autonomous deep well pressure maintaining sampler, and belongs to the technical field of drilling engineering sampling. The sampler comprises an upper joint, a control outer pipe, an end cover, a valve body and a liquid storage chamber which are connected in sequence, an electromagnet is arranged on the outer side of the end cover; an electric control module is arranged in the control outer pipe; a valve element with a permanent magnet is arranged in the valve body in a sliding mode, the valve element is driven to move axially through non-contact electromagnetic force between the electromagnet and the permanent magnet, and opening and closing of the sampling flow channel are achieved. The bottom of the valve core is provided with a valve core inner channel communicated with the sampling flow channel and the liquid storage chamber and a one-way valve; a sampling inlet channel is formed in the joint of the end cover and the valve body. According to the invention, a pure mechanical sealing-based structure is adopted, so that the sealing reliability and the operation stability in a high-temperature and high-pressure environment of a deep well are remarkably improved, drilling fluid is not needed, and efficient and pressure-maintaining sampling of in-situ formation fluid is realized.

A system may include a lower completion disposed in a main bore of a multilateral well in a position downhole from a junction of the multilateral well. The system may also include a fluid separator configured to receive formation fluid, which includes oil and water, flowing from the lower completion. The fluid separator may be configured to at least partially separate the formation fluid into formation oil and formation water. The fluid separator may also be configured to output the formation oil, via a separator oil outlet, to flow uphole, and output the formation water, via a separator water outlet, to flow toward a lateral bore of the multilateral well. Further, the system may include a water cut sensor disposed uphole from the fluid separator. The water cut sensor may be configured to measure the percentage of water in the formation oil.

Methods and systems are disclosed herein. A method may include obtaining a well log of a well and obtaining a first fluid sample at a first one of the plurality of depths within the well. The method may include obtaining a second fluid sample at a second one of the plurality of depths within the well. The method may include determining a first fluid property from the first fluid sample and a second fluid property from the second fluid sample. The method may include determining a transform based on the first fluid property, the second fluid property, and the well log data. The method may include applying the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property. The method may include determining a subsurface development plan based on the first predicted fluid property.

Disclosed herein are systems and methods to obtain representative formation pore pressure and formation mobility from pressure measurements with a formation testing tool. In some embodiments, the method includes performing a first pre-test in which a pressure sensor measures a drawdown pressure and a buildup pressure, calculating a statistical value for the measured buildup pressure, determining if the statistical value is above or below a threshold, shutting down a mud pulser if the statistical value is above or below the threshold, and performing a second pre-test in which the pressure sensor measures a second drawdown pressure and a second buildup pressure. In embodiments, the second pre-test includes a formation fluid drawdown flow rate that is different than a formation fluid drawdown flow rate in the first pre-test.

The present application relates to a kind of high temperature high pressure formation fluid containing large hole fracture plugging simulation device, including nitrogen bottle, liquid storage tank, simulation wellbore, heating insulation cover, back pressure valve and hole fracture isolation plate, there is inner cylinder in upper kettle body, there is simulation leakage layer in inner cylinder, upper kettle body and lower kettle body are connected by flange, hole fracture isolation plate is set between upper kettle body and lower kettle body, back pressure valve is set at the place close to hole fracture isolation plate of lower kettle body, heating insulation cover is set on the outer wall of upper kettle body and lower kettle body.The simulation method for high temperature high pressure formation fluid containing large hole fracture plugging using the above device, including: plugging slurry is discharged or passed through formation fluid and then enters simulation leakage layer;The plugging effect of conventional drilling fluid on small hole fracture leakage layer is judged by the pressure difference of upper kettle body and lower kettle body;The breakthrough pressure of sealing zone is obtained by the pressure difference between upper kettle body and lower kettle body after sealing zone is formed by solidified cementation type plugging slurry.The present application is in line with actual downhole, easy and fast to operate, provides platform and means for the plugging research of formation fluid containing large hole fracture leakage layer.

The invention discloses a natural gas hydrate reservoir in-situ fluid sampling device and method, and relates to the technical field of natural gas exploitation. The pumping module is used as a driving device for pumping formation fluid; the double-packer module comprises an upper packer and a lower packer, a sealed test interval is formed between the upper packer and the lower packer, and a pipeline connected with the pumping module penetrates through the upper packer to reach the test interval and is connected with a probe; the probe is used for penetrating out of a test interval to extract formation fluid; a lower packer, an upper packer and a pumping module are sequentially arranged from bottom to top from the bottom of the well; the in-situ fluid identification and sampling module comprises a PVT sampling barrel and a resistivity sensor; and the PVT sampling barrel and the resistivity sensor are connected to the pipeline between the upper packer and the pumping module and penetrate through the wall of the pipeline so as to measure the formation fluid extracted from the pipeline. The in-situ fluid under the original condition can be collected.

The application discloses a formation fluid identification method, comprising the following steps: acquiring first infrared spectrum data and second infrared spectrum data of a formation section to be interpreted; performing curve fitting on the first infrared spectrum data to obtain a fitting curve, determining a first factor according to an extreme value of a first wavelength section of the fitting curve, determining a second factor according to an opening and area integral of the fitting curve, and determining a third factor according to a center of a second wavelength section of the fitting curve; calculating a standard deviation curve of a standard deviation of longitudinal absorption at all wavelengths of a same depth point according to the second infrared spectrum data, and calculating a peak tailing factor of the standard deviation curve; and determining a type of the formation section according to the first factor, the second factor, the third factor and the peak tailing factor. The application further discloses a system, a computer device and a readable storage medium.

The downhole dynamic thermal field control method and apparatus provided in this application include: acquiring initial temperature field data of the target downhole wellbore and a pre-constructed formation fluid coupling model, and calculating the first total energy supply power of each heating section of the target downhole based on these data; segmenting and heating each heating section of the target downhole according to the first total energy supply power, and acquiring the first real-time temperature data of each heating section of the target downhole; determining the corresponding first downhole thermal field uniformity based on the first real-time temperature data, and determining the thermal field control state based on the uniformity and the first real-time temperature data; if the thermal field control state is a stable and compliant state, maintaining the first total energy supply power of each heating section of the target downhole; if the thermal field control state is a state to be adjusted, adjusting the first total energy supply power to obtain the adjusted second total energy supply power; thereby improving the accuracy of downhole dynamic thermal field control and enhancing the real-time matching capability between energy supply and formation heat demand.

The utility model discloses a rock core experiment device for simulating oil reservoir environment, which comprises an oil reservoir simulation device, the oil reservoir simulation device comprises a rock core cabin body, a rock core cabin opening is arranged on the top wall of the rock core cabin body, the rock core cabin body is connected with a pressure regulating device, and a rock core base is arranged on the bottom wall in the rock core cabin body. And the core base is in the projection of the core cabin opening. The oil reservoir simulation device can provide temperature, pressure and formation fluid, simulate the real consolidation condition and performance characteristics of the artificial rock core in the formation environment, truly reflect the characteristics of the artificial rock core in the formation environment, provide more real experimental data for sand prevention design, preferably select better products, and improve the production efficiency. The sand prevention effect of chemical sand prevention is improved, and the sand prevention validity period is prolonged.

This invention discloses an oil-water-gas well reservoir expansion and sealing jet fluid production and sand removal device, relating to the field of oil production technology. The device includes a central tube and further comprises: an expansion assembly located around the central tube, with its lower end positioned on the central tube and its upper end capable of sliding on the central tube, used for radial expansion under the drive of a hydrodynamic fluid; and a jet nozzle located below the central tube and below the expansion assembly, used to spray hydrodynamic fluid, creating a negative pressure zone in the spray area to absorb formation fluid. This integrated design combines the expansion assembly and the jet nozzle, allowing for the completion of both annular sealing and jet fluid production and sand removal functions in a single well run, avoiding the cumbersome process of two well runs required by traditional technologies and shortening the operation time.

This invention provides an experimental apparatus and method for simulating the phase state of fluids in oil and gas reservoirs, belonging to the field of experimental technology for fluid phase state in oil and gas field development. It includes: a support frame with a first cavity, a second cavity, and a third cavity arranged from top to bottom; a pressure regulating mechanism for adjusting pressure is installed in the second and third cavities; the first cavity is connected to the second cavity via a first pipe and a second pipe, and the first cavity is connected to the third cavity via a third pipe; the second cavity is connected to the third cavity via a fourth pipe; an output pipe is located at the top of the first cavity, with the inlet of the output pipe located inside the first cavity and lower than the opening of the first pipe on the first cavity; valves for controlling the opening and closing of the output pipe, the first pipe, the second pipe, the third pipe, and the fourth pipe are all installed. This invention has a simple structure, is easy to use, and can accurately simulate the depletion development process of oil-bottom-water type oil and gas reservoirs in upper gas formations, clearly defining the phase change characteristics of formation fluids.

The invention discloses an underground fluid in-situ sampling system and method, and belongs to the technical field of underground fluid sampling. The device comprises a sampling valve body, an air pressure driving assembly and a sample receiving assembly, the sampling valve body comprises a valve body, a three-way cavity formed in the valve body and a first one-way valve, the first one-way valve is arranged in a first hole channel of the three-way cavity, and the first one-way valve can be opened by external pressure; the air pressure driving assembly comprises an air supply pipe used for supplying pressurized and compressed air, and the air supply pipe is communicated with the second hole channel of the three-way cavity. The sample receiving assembly comprises a sampling pipe, one end of the sampling pipe is communicated with the third hole channel of the three-way cavity, and the other end of the sampling pipe can output fresh formation fluid. The device can be suitable for long-term deployment in a limited space, and the original state of fluid is kept to the maximum extent.

This invention discloses a high-temperature, high-pressure self-contained deep well sampling device, belonging to the field of drilling engineering sampling technology. The sampling device includes an upper connector, a control outer pipe, an end cap, a valve body, and a storage chamber connected in sequence. An electromagnet is installed on the outside of the end cap, and an electrical control module is installed inside the control outer pipe. A valve core with a permanent magnet is slidably installed inside the valve body. The valve core is driven axially by the non-contact electromagnetic force between the electromagnet and the permanent magnet, realizing the opening and closing of the sampling channel. The bottom of the valve core has an internal channel connecting the sampling channel and the storage chamber, as well as a one-way valve. A sampling inlet channel is opened at the connection between the end cap and the valve body. This invention adopts a structure mainly based on pure mechanical seals, significantly improving the sealing reliability and operational stability under the high-temperature and high-pressure environment of deep wells. It does not rely on drilling fluid and achieves efficient, pressure-maintained sampling of in-situ formation fluids.

The application provides a gradient chemical sand control process method based on weakly cemented reservoir skeleton stability, which comprises the following steps: step 1, obtaining the parameters of a sanding well formation and formation fluid when sanding; step 2, selecting a reservoir middle depth as a horizontal tangent line and taking points X1-X N , calculating the reservoir formation pressure distribution of different crude oil viscosities and different shale contents; step 3, calculating the corresponding pressure gradient of X1-X N ; step 4, drawing a reservoir sanding pressure gradient curve diagram when the oil well sands; step 5, testing the strength of an anti-swelling sand stabilizer material by using a laboratory experiment; and step 6, determining the applicable limits of the near-well long-acting sand consolidation and the far-well anti-swelling sand stabilization method of a sanding well with different crude oil viscosities and different shale contents. The gradient chemical sand control process method based on weakly cemented reservoir skeleton stability utilizes the idea of "far-well anti-swelling sand stabilization + near-well long-acting sand consolidation", reduces the large use of a single sand control agent, and reduces the use cost of the sand control agent.

The invention discloses a method for calculating the maximum safe injection pressure of geological storage of carbon dioxide in a deep saline water layer, which comprises the following steps of: establishing a three-dimensional geomechanical model; the output parameters are overlying stress distribution and maximum horizontal principal stress distribution of a three-dimensional stress field under the initial formation fluid pressure field and minimum horizontal principal stress distribution under the initial formation fluid pressure field; gradually increasing the initial formation fluid pressure field to pressure fields of a plurality of simulation working conditions, and respectively obtaining minimum horizontal principal stress distribution and overburden stress distribution under the pressure fields of the plurality of simulation working conditions; determining the fracturing critical pressure of the cap layer; determining the activation pressure of a target fault at the cover layer; and determining the maximum safe injection pressure of the geological storage of the carbon dioxide in the deep saline water layer according to the critical pressure of fracture of the cover layer and the activation pressure of the target fault at the cover layer.

The application discloses a kind of oil reservoir gas drive fine delineation and gas channeling prevention and control method based on facies belt division.The method of the application can be used for the "fine" description of formation fluid migration in the process of CO2 injection development, through long core displacement, interface tension determination is combined, and well stream component is determined, the distribution of each facies zone in the ground is obtained through numerical simulation, accurate gas channeling early warning can be realized, and the starting pressure gradient at different development moments can be obtained in combination with the determined starting pressure gradient;The carbonized water is prepared by generating and breaking CO2 micro-bubbles in the application, and the enhanced CO2 micro-bubbles are generated by using the carbonized water and CO2, which can avoid the influence of water lock effect, improve the stability of micro-bubbles, better play the plugging and profile control effect, and improve the oil displacement efficiency, for the treatment of gas channeling, which is helpful to further improve the recovery efficiency and CO2 storage effect.

This invention relates to a flow pressure regulating device for drilling wellbore, comprising an isolation plate, a linkage assembly, a driven assembly, and an regulating assembly. The isolation plate has a through-cavity in its center, which seals and connects two adjacent drill pipes. The outer edge of the isolation plate, specifically the outer edge portion, seals the outer wall of the drill pipes via a sealing ring, thus preventing the formation of annulus between the drill pipes and the well wall. The isolation plate has a through-hole communicating with the annulus. During drilling, the flow of drilling fluid drives the linkage blades to rotate within the inner cavity. When the flow pressure in the annulus of a certain well section exceeds the safe range compared to the formation fluid pressure of the well section, the operator can remotely control the controller via a remote control device to rotate the linkage blades, thereby adjusting the inclination angle of the linkage blades. This device has the advantage of being able to regulate the flow pressure in the annulus of the wellbore.

The invention relates to the technical field of formation fluid exploitation, in particular to a test parameter regulation and control method of a formation test lifting device and the formation test lifting device.The test parameter regulation and control method comprises the steps that A, the pump pressure of a power liquid pump is set; s101, pressure distribution of return liquid from a return liquid outlet of the jet pump to an upper port of the first annulus is calculated, and whether the pressure of the return liquid at the upper port of the first annulus is not smaller than 0 or not is judged; s102, when the return liquid pressure of the upper port of the first annulus is smaller than 0, the pump pressure of a power liquid pump is set, and the step S101 and the step S102 are executed; and when the return liquid pressure of the upper port of the first annulus is not smaller than 0, the final pump pressure of the power liquid pump is output. The final pumping pressure Pinj is output under the condition that the return liquid pressure of the upper port of the first annulus 104 is not smaller than 0, it is ensured that the formation fluid can be stably conveyed to the ground, and the formation fluid yield testing accuracy is improved.

A method for determining a porosity log of a log type for a hydrocarbon reservoir, including: obtaining an input core image, a formation bulk log of the log type, and a formation fluid log of the log type for the reservoir; determining, using a segmentation model and the input core image, a segmented core image to delineate a distribution along the reservoir; determining, using the segmented core image, a volumetric log for the reservoir: determining, using the volumetric log and a variable rock matrix value of the log type, a rock matrix log of the log type by assigning the variable rock matrix value of the log type to a lithology or mineralogy; and determining, using the rock matrix log, the formation bulk log of the log type, and the formation fluid log of the log type, the porosity log of the log type for the reservoir.

A downhole fluid sampling system with hydraulic actuation can be used to collect one or more samples of formation fluid during a well operation. The sampling system can be within a downhole tool deployed in a wellbore of the well operation. Then sampling system then can collect a first sample from the flow of formation fluid from the wellbore using a first sampling chamber of a sampling unit in the sampling system. The sampling unit can define a set of sampling chambers including the first sampling chamber and a second sampling chamber. A piston of the sampling system that actuates on hydraulic fluid can advance the sampling unit by a predefined distance from a first position associated with the first sampling chamber to a second position associated with the second sampling chamber. Subsequently, the second sampling chamber can collect a second sample from the flow of formation fluid.

The invention belongs to the technical field of underground gas storage water invasion amount calculation, and discloses a gas cap reservoir type gas storage multi-cycle dynamic water invasion amount calculation method and a gas cap reservoir type gas storage multi-cycle dynamic water invasion amount calculation system. The method comprises the following steps: establishing a total substance amount conservation equation based on a multi-cycle fluid injection and production change rule of the gas cap reservoir type gas storage; deriving to obtain calculation equations of the amount of original formation fluid substances, the amount of extracted formation fluid substances, the amount of injected natural gas substances and the amount of residual formation fluid substances, and substituting the derived calculation equations into the total substance amount conservation equation to establish a dynamic water invasion amount calculation model; and the formation fluid high-pressure physical property, the reverse condensation liquid saturation degree and the natural gas deviation factor change rule in the multi-period injection and production process are obtained, and the multi-period dynamic water invasion amount is obtained through calculation. The calculation result is high in accuracy, the calculation process is simple, and the method can be suitable for the condensate gas cap reservoir type gas storage where a general material balance method is not suitable.

The invention relates to a tracer-based horizontal well subsection liquid production profile visual simulation experiment device and interpretation and evaluation method, and the experiment device comprises a fluid injection and control module which comprises a plurality of sets of independent fluid injection units and can independently regulate and control the oil-water phase injection flow of each horizontal well subsection; the formation fluid simulation and pretreatment module comprises a core holder and a mixing tank and is used for simulating formation liquid production and realizing uniform mixing of oil and water; the simulation shaft and tracer agent module adopts a transparent simulation shaft structure to integrate a tracer agent carrier, and supports segmented tracer release and flow process visual observation; the data acquisition and post-processing module is used for analyzing the concentration data of the tracer agent and calculating the liquid production profile and the water content of each section based on an inversion algorithm; physical simulation and quantitative interpretation of the horizontal well segmented liquid production process can be achieved, and a reliable experimental platform is provided for liquid production profile evaluation and tracer performance research.

The invention provides a maximum horizontal principal stress obtaining method based on a Mohr-Coulomb criterion, and belongs to the technical field of reservoir rock mechanics research. The maximum horizontal principal stress obtaining method comprises the steps that formation pore pressure and rock strength parameters are obtained through comprehensive logging data, and drilling fluid column pressure is calculated through drilling fluid density data; measuring the minimum horizontal principal stress; the well wall caving width is obtained through the dual-hole-diameter logging data; according to a calculation equation, factors such as tectonic stress, drilling working conditions and formation fluid are fully considered in the method, and the well wall caving width is obtained through well logging information; indoor rock core testing is not needed; the calculation precision is high, and a scientific basis is provided for oil reservoir engineering, drilling engineering and yield increase engineering.

A plurality of flow control nodes are spaced along a production conduit to control the flow of formation fluids into the conduit at various locations within the wellbore. Each flow control node defines a flow path for the formation fluids to enter the production conduit. A closure can be used to regulate the flow of formation fluids within the production conduit. A generator in each zone produces electrical power in response to a portion of the flow directed through the generator. An electrical grid interconnects the plurality of flow control nodes to collectively supply electrical power to the electrical grid. Each closure and other device components can operate using electrical power from the grid.

Disclosed herein are systems and methods to obtain representative reservoir fluid samples faster. In embodiments, a formation testing tool, which includes a probe and a fluid passageway, is conveyed in a wellbore and the probe is pressed against the wellbore to create a fluidic seal in between the formation and the fluid passageway. The reservoir fluid is then pumped from the formation to the fluid passageway. The probe comprises a rubber disposed on an outer perimeter of the probe and an inflatable barrier disposed between the rubber and a central area of the probe. After reaching a first pre-determined value of drilling fluid contamination, the inflatable barrier of the probe is inflated. Sampling of the reservoir fluid is performed after reaching a second value of drilling fluid contamination in the reservoir fluid pumped from the formation to the fluid passageway.

This invention provides a method for predicting fault connectivity based on PCA-CRITIC weights, relating to the field of oil and gas exploration technology. It includes determining the influencing factors of fault vertical connectivity, including the thickness of the displaced caprock, clay content, fault plane normal stress, formation fluid pressure, caprock brittleness index, and fault displacement. A comprehensive mathematical formula for the fault vertical connectivity coefficient is established. Based on the oil, gas, and water data from drilled wells and paleoreservoir tracing data near the displaced strata, the vertical connectivity coefficient is calculated using the comprehensive mathematical formula and by well and well depth segment. The vertical connectivity is analyzed based on the fault vertical connectivity coefficient and the oil and gas content of the near displaced strata, predicting the fault vertical connectivity in oil and gas basins. This invention accurately characterizes the oil and gas migration paths within faults, significantly improving prediction accuracy and exploration efficiency.

A system for monitoring and mapping the spatiotemporal distribution of formation fluids within a reservoir (30) comprising: at least four transceiver devices (40) arranged to be applied at predetermined equal distances along a casing pipe (12), each of the transceiver devices (40) comprising: a tubular body (41) configured to be fitted onto the casing pipe (12), the tubular body (41) having at a first end a first longitudinal section (42),at a second end a second longitudinal section (43) and a third longitudinal section (44) interposed between the first (42) and the second longitudinal section (43); a coil (45) wound on the first longitudinal section; a layer of elastomeric material (46) wound on the third longitudinal section (43); an electrode (47) wound on the layer of elastomeric material (46); a peripheral electronic control unit (48) which is connected to the tubular body (41); wherein the monitoring and mapping system comprises a central electronic control and data acquisition unit (60) configured to guide the peripheral electronic control units,

A workflow for data acquisition and processing to quantify immobile and producible fluids more accurately from log and core measurements is described. Also described are methods of reservoir characterization to distinguish producible from immovable fluids that use NMR measurements on core samples as endpoint references and calibration points for downhole logging. Endpoint signatures of pore fluids are easily identified by the NMR of core samples, thus providing more accurate results on formation fluid porosities and saturations from measured data.

The utility model relates to the technical field of in-well pressure measurement, in particular to a formation pressure measuring pipe column which comprises an oil pipe, a pressure measuring element, a packer and a liquid extractor, the packer is arranged above a formation to seal the annulus between the pressure measuring pipe column and a shaft, the liquid extractor comprises a cylinder body and a piston, the cylinder body is connected with the oil pipe, and the piston is connected with the oil pipe. The piston divides an inner cavity of the pressure measuring pipe column into an upper pipe cavity and a lower pipe cavity, the piston and the cylinder body move relatively to be used for sucking well killing fluid in the lower pipe cavity of the pressure measuring pipe column so that formation fluid can flow into a shaft from a formation, and the pressure of the lower pipe cavity of the pressure measuring pipe column and the pressure of the shaft below the packer are equal to the pressure of the formation. The liquid column pressure of the well killing fluid in the upper pipe cavity and the space above the packer is separated from the pressure of the lower pipe cavity and the space below the packer, the formation pressure can be obtained by measuring the pressure of the lower pipe cavity of the pressure measuring pipe column or the pressure of a shaft below the packer, the influence of the well killing fluid in the shaft is avoided, and the formation pressure measuring accuracy is improved.

Disclosed herein are methods and systems for identifying target analytes such as H2S and CO2 during downhole fluid analysis. The systems may include a fluid sampling tool comprising at least one probe to fluidly connect the fluid sampling tool to a formation in a wellbore, at least one passageway that passes through the at least one probe and into the fluid sampling tool, a sensor section comprising a measurement region in fluid communication with the at least one passageway, and a thin film deposited on the measurement region, wherein the thin film changes at least one of its physical properties upon exposure to the target analyte found in the at least one passageway. The methods may include disposing the fluid sampling tool into a wellbore, drawing a formation fluid from a sampling zone, and passing the fluid sample over the thin film deposited on a measurement region.