CN109826600B - Method for optimizing nitrogen injection oil extraction time of fracture-cavity oil reservoir - Google Patents
Method for optimizing nitrogen injection oil extraction time of fracture-cavity oil reservoir Download PDFInfo
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Abstract
The invention discloses a preferable method for nitrogen injection oil extraction opportunity of a fracture-cavity oil reservoir, which relates to an oil-gas field exploitation technology and comprises the following steps: (1) collecting original oil deposit data and a real rock core aiming at a target block; (2) inputting the collected oil deposit original data into a data acquisition system, and analyzing and determining the fracture-cavity type of a target block; (3) loading a rock core into a high-temperature high-pressure fracture-cavity type oil reservoir simulation device, simulating fracture-cavity type of a target block, simulating bottom water driving, setting four conditions of gas injection amount, gas-liquid ratio, gas injection speed and bottom water energy, and performing nitrogen injection oil extraction experiments under the set four conditions at different water contents; (4) and calculating the recovery ratio improvement amplitude and the input-output ratio of the nitrogen injection oil recovery to the bottom water drive oil recovery, wherein the water content corresponding to the minimum input-output ratio is the optimal nitrogen injection oil recovery time of the target block. The optimal gas injection time optimized by the method can ensure that the target block achieves the optimal economic benefit.
Description
Technical Field
The invention relates to the technical field of oil and gas field development, in particular to a method for optimizing nitrogen injection oil extraction time of a fracture-cavity oil reservoir.
Background
The reservoir heterogeneity of the Tarim basin fracture-cavity carbonate rock reservoir is extremely strong, and the reservoir spaces are various, wherein a large-scale cave is the most main reservoir space, and cracks are main communicating channels; meanwhile, the oil-water relationship and the fluid flow characteristics of the oil reservoir are complex, so that the yield is greatly reduced, the primary recovery rate is low, and the implementation difficulty and the cost of other processes are high due to the 'two-over-three-high' characteristic of the oil reservoir. Therefore, nitrogen injection technology is implemented in 2012, and is now a replacing technology after water injection of the oil field of the Tahe river in the Tarim basin. Practice shows that the gas injection parameters influence the gas injection effect, and the selection of the gas injection time directly determines the quality of the gas injection effect. Too early gas injection can cause the residual oil distribution of the oil reservoir to be disordered and increase the cost; too late gas injection causes the water drive path to press the crude oil supply path, reducing the overall economic benefit. How to accurately optimize the timing of gas injection is the key to determining the enhanced gas recovery from gas injection.
Due to the fact that the reservoir structure of the fracture-cavity oil reservoir is complex, errors are large due to the adoption of a numerical simulation mode, real results cannot be obtained, and therefore research needs to be carried out by means of indoor simulation experiments. Currently, gas injection timing is mainly determined by indoor simulation experiments, numerical simulation and other methods, for example, the types of residual oil of a fracture-cavity type oil reservoir are divided into attic oil, residual oil in a closed cavity, bypass oil, an oil film and residual oil at a filling part, and a two-dimensional visual physical model and a three-dimensional visual physical model (van den, 2016, doctor thesis, research on recovery efficiency improvement technology and related mechanism of gas injection in fracture-cavity type carbonate oil reservoir) which are designed and manufactured are adopted, or fracture-cavity type oil reservoir visual karst cave model simulation (chime and the like, petroleum science report, 2018, volume 3, phase 1, research on nitrogen foam flooding injection parameters and mechanism of a fracture-cavity type oil reservoir body) is adopted to determine injection and production parameters.
The indoor simulation experiment confirms the gas injection opportunity at present, has the following problem: firstly, the fracture-cavity structure type is separated from the actual oil reservoir type, is generally extracted from a geological model or is obtained by similarity, and has a large difference with the actual oil reservoir structure type; and secondly, the physical simulation method is relatively high in cost, and a high-temperature and high-pressure device or a visualization device is generally required to be manufactured. In addition, the existing method for determining the gas injection time through indoor numerical simulation generally adopts a permeability equivalent method, and simultaneously needs to adjust a large number of parameters, thus being troublesome and laborious and departing from the actual situation on site. Therefore, it is necessary to develop a method for optimizing the timing of gas injection which is easy and convenient to use and has a field guidance meaning.
disclosure of Invention
The invention aims to solve the problems that the error of gas injection timing determined by mathematical simulation in the prior art is large and the method has no reference significance to field construction, and provides a preferable method for nitrogen injection and oil extraction timing of a fracture-cavity oil reservoir.
The technical scheme of the invention is as follows:
A preferable method for nitrogen injection oil recovery time of a fracture-cavity oil reservoir is characterized by comprising the following steps:
(1) collecting original oil deposit data and a real rock core aiming at a target block;
(2) Inputting the collected oil deposit original data into a data acquisition system, and analyzing and determining the fracture-cavity type of the target block;
(3) Loading the rock core into a high-temperature high-pressure fracture-cavity type oil reservoir simulation device, simulating fracture-cavity type of the target block, simulating bottom water driving, setting four conditions of gas injection amount, gas-liquid ratio, gas injection speed and bottom water energy, wherein any three conditions are quantitative, one condition is variable, and performing nitrogen injection oil extraction experiments under the set four conditions at different water contents;
(4) and calculating the recovery ratio improvement amplitude and the input-output ratio of the nitrogen injection oil recovery to the bottom water drive oil recovery, wherein the water content corresponding to the minimum input-output ratio is the optimal nitrogen injection oil recovery time of the target block.
in the method, the original oil reservoir data comprises single well data, basic geological data, reserve reports and dynamic data of the target block;
The single well data comprises drilling, logging, oil extraction and water injection data; the basic geological data comprise seismic amplitude change rate phase diagrams and geologic body carving diagram data; the reserve report comprises geological reserves and dynamic reserves; the dynamic data comprises oil pressure, casing pressure, water content, accumulated oil, accumulated liquid and accumulated gas data;
the real core is an oil reservoir core of the target block or an oil reservoir core of a similar type;
The input-output ratio is calculated by the following formula:
the input-output ratio is (gas injection dosage x standard condition stratum conversion coefficient x square gas price)/(geological reserve x recovery enhancement amplitude x international oil price x exchange rate x crude oil tank ton conversion coefficient).
in the above method, the nitrogen injection oil recovery experiment was performed when the water content was 60%, 70%, 80%, 85%, 90%, 95%, and 98%, respectively.
In the method, the size of an underground storage space is calculated according to the geological reserves of the oil reservoir, and then the gas injection amount is set according to the size of the storage space; calculating the gas-liquid ratio according to the formation pressure and the rated working pressure of the gas injection and water injection equipment; setting a gas injection speed according to the rated displacement capacity of the gas injection equipment; and setting bottom water energy according to the calculation result of the oil reservoir engineering method.
In the method, the high-temperature high-pressure fracture-cave oil reservoir simulation device comprises a fracture-cave core module 16, a karst-cave core module 18 and a space structure automatic adjusting module;
The interior of the fracture-type core module 16 and the karst cave core module 18 may accommodate real cores; the fracture type core module 16 and the fracture type core module 16, the karst cave core module 18 and the karst cave core module 18, or the fracture type core module 16 and the karst cave core module 18 are connected through pipelines;
The space structure automatic adjusting module is respectively connected with the crack type core module 16 and the karst cave type core module 18 and used for accurately positioning the inclination angle and the height of the core and adjusting the relative position of the karst cave, the crack width occurrence and the communication relation of the karst cave.
in the method, the automatic spatial structure adjusting module comprises a bracket 19, and the bracket 19 is respectively connected with the fracture type core module 16 and the karst cave type core module 18; the upper part of the support 19 can rotate around a horizontal shaft or a vertical shaft, and the lower part can be lifted or translated to accurately position the inclination angle and the position of the core.
In the method, the high-temperature high-pressure fracture-cavity type oil reservoir simulation device further comprises a confining pressure system 20; the confining pressure system 20 is connected to the fracture-type core module 16 and the karst cave core module 18 by piping for simulating the pressure of the overburden.
In the method, the fracture type core module 16 comprises an actual core bin 6, one end of the actual core bin 6 is an injection end, and the other end is a production end; the width of the crack can be adjusted by the actual core bin size adjusting block 14;
preferably, the fracture width is adjusted by a set of jackscrew rods passing through the side wall of the actual core bin 6, said jackscrew rods comprising a jackscrew cap 11, a jackscrew sealing rubber ring 12 and a jackscrew distance adjusting thread 13;
Preferably, pressure monitoring points 5 are also provided on the side walls of the actual core magazine 6, passing through said side walls;
Preferably, the injection end is provided with an injection end compression plug, the injection end compression plug is composed of an injection end compression plug body 4 and an injection end compression plug connector 1, and an injection end compression plug sealing rubber ring is arranged on the injection end compression plug body 4; an injection end compression plug compression nut 2 is further arranged at the injection end, threads matched with the injection end compression plug compression nut 2 are arranged on the outer wall of the injection end, the injection end compression plug connector 1 penetrates through the central hole of the injection end compression plug compression nut 2 to extend out, and the injection end compression plug compression nut 2 is used for reinforcing the injection end compression plug; the output end disposes output end compression stopper, output end compression stopper is by output end compression stopper terminal surface 7 and output end compression stopper body 9 constitution, output end compression stopper terminal surface 7 contact the inner chamber of actual core storehouse 6 be provided with output end compression stopper sealing rubber ring 8 on the output end compression stopper body 9, still dispose output end compression stopper gland nut 10 at the output end, output end outer wall is provided with and presses stopper gland nut 10 matched with screw thread with the output end for consolidate output end compression stopper.
In the above method, the karst cave core module 18 includes a core cavity inner cylinder 32 and a core cavity outer cylinder 33 sleeved outside the core cavity inner cylinder 32; two ends of the core cavity inner cylinder 32 are respectively provided with a sealing end 27, and the sealing end 27 and the core cavity inner cylinder 32 enclose a core cavity 31; one end of the core cavity 31 is an injection end, and the other end is a production end;
Preferably, an injection channel 28 is provided in the sealed end 27 of the injection end, a production channel 30 is provided in the sealed end 27 of the production end, and the core cavity 31 is in fluid communication with the injection channel 28 and the production channel 30; a pressing screw cap 26 is sleeved outside the sealing end 27, and the pressing screw cap 26 is fixed on the outer core cavity barrel 33 through a pressing screw 34, so that the sealing end 27 and the inner core cavity barrel 32 are mutually pressed on a contact surface; a sealing rubber ring 25 is arranged between the outer wall of the sealing end 27 and the inner wall of the outer barrel 33 of the core cavity;
Preferably, on the side walls of the core cavity inner cylinder 32 and the core cavity outer cylinder 33, a temperature and pressure collecting terminal 15 is provided, which penetrates the side walls of the core cavity inner cylinder 32 and the core cavity outer cylinder 33 and extends into the core cavity 31.
in the above method, the step (3) includes:
Filling the rock core into a fracture type rock core module and a karst cave type rock core module of the high-temperature and high-pressure fracture-cave type oil reservoir simulation device, combining the fracture type rock core module and the karst cave type rock core module according to the fracture cave type determined in the step (2), and adjusting the relative position of the karst cave, the fracture width occurrence and the fracture cave communication relation to form a model;
Heating the whole device to 120 ℃;
Gradually pressurizing the saturated water and the saturated oil of the model to 60 MPa;
Simulating bottom water drive, and injecting nitrogen when simulating the water content set by the gas injection effect to be evaluated;
And closing the well for 2 hours, opening the well for evaluation, and calculating the ultimate recovery ratio.
Because numerical simulation of an oil reservoir cannot meet the requirements of a fracture-cavity oil reservoir, the invention adopts a high-temperature high-pressure fracture-cavity oil reservoir simulation device suitable for the fracture-cavity oil reservoir to carry out gas injection and improve recovery efficiency evaluation, and reflects collected oil reservoir original data of target blocks in the high-temperature high-pressure fracture-cavity oil reservoir simulation device one by one, and fully considers parameters of different fracture-cavity oil reservoirs, gas injection amount, gas-liquid ratio, gas injection speed, bottom water energy and the like, establishes the relation between final recovery efficiency and input-output ratio, and determines the optimal gas injection time. The gas injection time mainly considers the water content condition of a target block, the comprehensive water content of the oil well block is divided into n parts, and the division can be specifically carried out through experimental result statistics. The method comprises the steps of simulating different fracture-cavity oil reservoirs by using a high-temperature high-pressure fracture-cavity oil reservoir simulation device, adjusting gas injection amount, gas-liquid ratio and gas injection speed by setting different bottom water energies, determining the optimal recovery ratio of a target block under different water contents, and determining the optimal gas injection time by combining input-output ratio.
The method provided by the invention adopts a high-temperature high-pressure fracture-cavity type oil reservoir simulation device to simulate a real fracture-cavity type oil reservoir, fully researches parameter systems such as gas injection amount, gas-liquid ratio, gas injection speed and bottom water energy, can truly reflect the gas injection of the oil reservoir of the target block, optimizes the obtained optimal gas injection time, and can ensure that the target block achieves optimal economic benefit in the whole project process.
the high-temperature high-pressure fracture-cavity type oil reservoir simulation device used by the invention is suitable for placing large-scale real rock cores under stratum conditions, can realize the free combination of modularized fracture cavities, and has adjustable relative positions of the karst cavities, fracture width occurrence and fracture cavity communication relation. The high-temperature high-pressure fracture-cavity type oil reservoir simulation device can also have a certain dynamic 3D monitoring function of fluid in the fracture cavity. High-temperature and high-pressure resistant sapphire is used as a visual window, and a layered pressurization technology is combined to realize high-temperature and high-pressure and visualization.
Scientific and technical terms used in the present invention have meanings commonly understood by those skilled in the art, and some scientific and technical terms have the following meanings:
the water content of the oil field is the percentage of water production in monthly (annual) liquid production calculated by taking one oil field or production unit as a whole, and is used for expressing the whole water content condition of the oil field. Generally, the water content is 0-20% of a low water content stage, the water content is 20-70% of a medium water content stage, and the water content is 70-98% of a high water content stage.
The ultimate recovery rate is the final recovery rate of the oil field when the ultimate water content of the oil field losing the economic exploitation value is 98 percent or the ultimate water-oil ratio is 49, and the cumulative oil yield at the moment is called the ultimate yield of the oil field.
The gas-liquid ratio refers to the ratio of nitrogen and water injected simultaneously.
The bottom water energy refers to the ratio of the volume of the natural water body to the volume of the crude oil reserve. If the ratio is more than 160 times, the natural bottom water is sufficient in energy; if the ratio is 70-160 times, the natural bottom water is sufficient in energy; if the ratio is 10-70 times, the natural bottom water energy is determined; if the ratio is less than 10 times, the energy of the natural bottom water is insufficient.
the gas injection dosage can refer to the multiple of the total pore volume occupied by the gas injected underground, and the unit is PV;
The geological reserves are reserves calculated according to the data mastered by geological exploration and the rule of energy storage formation.
The input-output ratio can be calculated according to the following formula:
The standard-case formation conversion factor refers to the volume at standard-case corresponding to the gas below 1 deg.f at formation conditions.
Drawings
FIG. 1 is a flow chart of a preferable method for injecting nitrogen into a fracture-cavity oil reservoir to recover oil.
FIG. 2 is a schematic diagram of the connection of a high temperature and high pressure fracture-cavity reservoir simulation apparatus used in some embodiments of the invention.
FIG. 3 is a schematic diagram of a fractured-core module of a high-temperature high-pressure fractured-vuggy reservoir simulation apparatus used in some embodiments of the invention.
Fig. 4 is a cross-sectional view taken along line a-a of fig. 3.
FIG. 5 is a schematic diagram of a karst cave core module of a high temperature and high pressure fracture cave reservoir simulation apparatus used in some embodiments of the present invention.
Wherein 1-injection end compression plug connector, 2-injection end compression plug compression nut, 3-injection end compression plug sealing rubber ring, 4-injection end compression plug body, 5-pressure monitoring point, 6-actual core bin, 7-output end compression plug end face, 8-output end compression plug sealing rubber ring, 9-output end compression plug body, 10-output end compression plug compression nut, 11-jackscrew cap, 12-jackscrew sealing rubber ring, 13-jackscrew distance adjusting screw thread, 14-actual core bin size adjusting block, 15-temperature pressure collecting terminal, 16-crack type core module, 17-valve, 18-karst cave type core module, 19-bracket, 20-confining pressure system, 21-gas injection system, 22-liquid injection system, 23-bottom water simulation system, 24-outlet metering system, 25-sealing rubber ring, 26-pressing screw cap, 27-sealing end, 28-injection channel, 29-boosting hole, 30-output channel, 31-core cavity, 32-core cavity inner cylinder, 33-core cavity outer cylinder and 34-pressing screw.
Detailed Description
The present invention is further illustrated below with reference to examples, which are to be understood as being illustrative and illustrative only and not limiting to the scope of the invention.
In the following examples, the technical means used, unless otherwise specified, are conventional in the art; the reagents used, unless otherwise specified, are commercially available or may be prepared according to routine experimentation; the instruments and software used, unless otherwise specified, are commercially available.
Example 1 optimization of nitrogen injection and oil extraction timing of TH1# single well
Taking TH1# single well with good connectivity and poor water injection effect as an example, the optimization of nitrogen injection oil production time is carried out.
And (3) drilling a TH1# single well in 1999 at 10/5 TH, wherein the drilling completion depth is 5800m, and the drilling completion layer is the eagle mountain group of the Ordovician lower system. In 5 months of 2000, holes are filled with 5468 and 5480m, seats are sealed with 5409.77m, 12 days of 5 months and 5622 and 5631 and 564 m are subjected to acid pressure together, the highest pump pressure is 73.8MPa, the maximum discharge capacity is 4.24m3/min, the oil enters a stratum 340.3m3, wherein the thickened acid is 200.6m3, the pump stop pressure is 19.1MPa, the flowback is 240m3, oil is found after the flowback is 396.3m3, the oil enters the station at the initial stage of 9mm, the oil pressure is 4MPa, the casing pressure is 5MPa, and the daily oil production is 96-100t, and the oil is basically free of water.
TH1# single well geological reserves 20.4X 104t, recoverable reserves 14.5X 104 t.
experimental oil: the viscosity of the dehydrated and degassed crude oil in the Tahe oil field is 23.9mPa.s at 45 ℃.
Water for experiment: the mineralization degree of the formation water is 200000mg/L, the viscosity at 45 ℃ is 0.93mPa.s, and the density is 1.032 g/mL.
The experimental conditions are as follows: the experimental temperature is 120 ℃; the experimental pressure was 60 MPa.
experimental apparatus: the system consists of a high-temperature high-pressure fracture-cavity type oil reservoir simulation device, a gas injection system 21, a liquid injection system 22, a bottom water simulation system 23, an outlet metering system 24 and a data acquisition system.
high-temperature high-pressure fracture-cavity type oil reservoir simulation device: as shown in fig. 2, comprises a fracture type core module 16, a karst cave type core module 18 and a space structure automatic adjusting module.
the internal spaces of the fracture type core module 16 and the karst cave type core module 18 are actual core bins which can accommodate actual cores; the fracture type core module 16 and the fracture type core module 16, the karst cave core module 18 and the karst cave core module 18 or the fracture type core module 16 and the karst cave core module 18 are connected through a pipeline, and a valve 17 is arranged on the pipeline.
The internal specifications of the fractured core module 16 are 300mm long, 50mm wide and 50mm high; the width of the seam is adjustable from 0mm to 10 mm; the displacement pressure is 60MPa, and the ring pressure is 80 MPa; the working temperature is 0-150 ℃. As in fig. 3, the fractured core module 16 contains the actual core bin 6; an actual core bin size adjusting block 14 (shown in figure 4) is arranged in the actual core bin 6, and can clamp a cylindrical or flat core, adjust the width of a crack, realize the closing and opening functions of the core and meet the requirement that the communication relation of a crack hole is adjustable; the crack width is specifically adjusted by a group of jackscrew rods penetrating through the side wall of the actual core bin 6, and the jackscrew rods comprise jackscrew caps 11, jackscrew sealing rubber rings 12 and jackscrew distance adjusting threads 13; preferably, pressure monitoring points 5 are also provided on the side walls of the actual core magazine 6, passing through said side walls.
one end of the actual core bin 6 is an injection end, and the other end is a production end.
The injection end is provided with an injection end compression plug, the injection end compression plug consists of an injection end compression plug body 4 and an injection end compression plug connector 1, and an injection end compression plug sealing rubber ring 3 is arranged on the injection end compression plug body 4; an injection end compression plug compression nut 2 is further arranged at the injection end, threads matched with the injection end compression plug compression nut 2 are arranged on the outer wall of the injection end, the injection end compression plug connector 1 penetrates through the central hole of the injection end compression plug compression nut 2 to extend out, and the injection end compression plug compression nut 2 is used for reinforcing the injection end compression plug; the output end disposes output end compression stopper, output end compression stopper is by output end compression stopper terminal surface 7 and output end compression stopper body 9 constitution, output end compression stopper terminal surface 7 contact the inner chamber of actual core storehouse 6 be provided with output end compression stopper sealing rubber ring 8 on the output end compression stopper body 9, still dispose output end compression stopper gland nut 10 at the output end, output end outer wall is provided with and presses stopper gland nut 10 matched with screw thread with the output end for consolidate output end compression stopper.
The inner specification of the karst cave type core module is 100mm in diameter and 500mm in height; the displacement pressure is 35MPa, and the ring pressure is 50 MPa; the working temperature is 0-150 ℃. As shown in fig. 5, the karst cave core module 18 includes a core cavity inner cylinder 32 and a core cavity outer cylinder 33 sleeved outside the core cavity inner cylinder 32; the two ends of the core cavity inner barrel 32 are provided with sealing end heads 27, and the core cavity 31 is formed by the sealing end heads 27 and the core cavity inner barrel 32 in a surrounding manner; one end of the core cavity 31 is an injection end, and the other end is a production end;
Wherein an injection channel 28 is provided in the sealed end 27 of the injection end, a production channel 30 is provided in the sealed end 27 of the production end, and the core cavity 31 is in fluid communication with the injection channel 28 and the production channel 30; a pressing screw cap 26 is sleeved outside the sealing end 27, and the pressing screw cap 26 is fixed on the outer core cavity barrel 33 through a pressing screw 34, so that the sealing end 27 and the inner core cavity barrel 32 are mutually pressed on a contact surface; a sealing rubber ring 25 is arranged between the outer wall of the sealing end 27 and the inner wall of the outer barrel 33 of the core cavity;
The side walls of the core cavity inner cylinder 32 and the core cavity outer cylinder 33 are provided with a temperature and pressure acquisition terminal 15 which penetrates through the side walls of the core cavity inner cylinder 32 and the core cavity outer cylinder 33 and extends into the core cavity 31.
The space structure automatic adjusting module is respectively connected with the crack type core module 16 and the karst cave type core module 18, is connected with the computer through a data line, and is intelligently controlled by the computer according to seismic data, so that the dip angle and the position (height) of the core can be accurately positioned, and the adjustment of the relative position of the karst cave, the shape of crack width and the communication relation of the karst cave can be realized.
The space structure automatic adjusting module comprises brackets 19, each bracket 19 comprises an upper part and a lower part, the lower part is used for vertically lifting the height, the upper part can rotate freely within the range of-60 degrees to 60 degrees along a horizontal shaft, and meanwhile, the upper part can rotate 360 degrees along the vertical direction, so that the random adjustment is realized. In a preferred embodiment, the spatial structure automatic adjustment module comprises 6 brackets 19, and the height of each bracket 19 is 1200 mm.
The fracture core module 16 and the karst cave core module 18 can be used in a freely combined manner or independently. A confining pressure system 20 is connected by piping to the fracture-type core module 16 and the karst cave core module 18 for simulating the pressure of the overburden. The confining pressure system is controlled by a computer, so that the closing and opening functions of the rock core can be realized, and the requirement that the communication relation of the fracture cavity is adjustable can be met.
the high-temperature high-pressure fracture-cavity type oil reservoir simulation device can further comprise a dynamic 3D monitoring module (not shown) for fluid in the fracture cavity, and oil, gas and water distribution is displayed on a computer through a data acquisition and control system, so that a visualization function is realized.
the high-temperature high-pressure fracture-cavity type oil reservoir simulation device automatically collects and adjusts the position arrangement of each coring module in the fracture-cavity type reservoir simulation system through three-dimensional seismic data, so that the relative position of a karst cave, the fracture width occurrence and the fracture-cavity communication relation are automatically adjustable, the simulation authenticity is ensured, and meanwhile, the adopted large-scale real rock cores avoid artificial design factors.
Gas injection system 21 and liquid injection system 22: comprises a plurality of piston type intermediate containers filled with crude oil, formation water and the like, a constant-pressure constant-speed metering pump, a high-purity N2 bottle and a valve. The capacity of the piston type intermediate container is 2L, and the working pressure is 2 MPa. The working pressure of the constant-pressure constant-speed metering pump is 30MPa, and the flow rate range is 0.01-9.99 mL/min; the purity of the high-purity N2 is 99.9%. The system is connected with the injection end of the high-temperature high-pressure fracture-cavity type oil reservoir simulation device through a pipeline and a valve, and can provide saturated water and saturated oil power for the model.
bottom water simulation system 23: comprises a bottom water container, a constant-pressure constant-speed metering pump and a valve. The system is connected with a bottom well of the high-temperature high-pressure fracture-cavity type oil reservoir simulation device through a pipeline and a valve and used for providing bottom water driving force.
outlet metering system 24: comprises a back pressure valve, a back pressure pump, a back pressure container, a gas-liquid separator, a gas metering device and an electronic balance. The system is connected with the outlet end of the high-temperature high-pressure fracture-cavity type oil reservoir simulation device through an outlet pipeline and a valve, and is used for outputting liquid and gas in a metered amount.
A data acquisition system: including a computer and a differential pressure sensor. The system is respectively connected with action elements of a high-temperature high-pressure fracture-cavity type oil reservoir simulation device, gas/liquid injection systems 21 and 22, a bottom water simulation system 23 and an outlet metering system 24 through data lines and is used for model construction, simulation experiment control and data storage and processing.
The nitrogen injection oil recovery time optimization method comprises the following steps:
S1, collecting original oil reservoir data of a TH1# single well, wherein the original oil reservoir data comprise single well data, basic geological data, reserve reports and dynamic data, and a core of the TH1# single well;
The single well data comprises well drilling, well logging, oil production and water injection data, can be obtained through historical query and is used for analyzing the single well reservoir structure, liquid supply capacity, gas suction capacity and gas injection potential; the basic geological data comprise seismic amplitude change rate phase diagrams and geological body carving diagram data, and the geological data are analyzed and processed through the landmark software, so that an actual fracture-cavity structure can be restored; the reserve report comprises geological reserves and dynamic reserves, can be obtained by a common oil reservoir engineering method and is used for analyzing the gas injection potential of an oil well and calculating the input-output ratio; the dynamic data comprises oil pressure, casing pressure, water content, accumulated oil, accumulated liquid and accumulated gas data, can be obtained through historical query and is used for analyzing the current state of the oil well and the gas injection potential of the oil well; the rock core is a real rock core and is used for simulating a real fracture-cavity structure.
and S2, recording the collected data into a data acquisition system one by one. And (3) analyzing the reservoir original data of the TH1# single well by a computer to determine the fracture type of the TH1# single well. According to the fracture-cavity type determined by a computer, the core of a TH1# single well is loaded into a fracture-cavity type module and a karst-cavity type module of a high-temperature high-pressure fracture-cavity type oil reservoir simulation device.
The experimental simulation TH1# single-well fracture-hole model has the following parameter settings:
| Form of the composition | Size and breadth | Number of |
| Karst cave | 3-5cm | 3 |
| Seam | 0.1cm | 10 (for connecting 3 karst caves) |
| hole(s) | 0.2cm | 0 |
S3, setting different bottom water energy, gas injection amount, gas-liquid ratio (nitrogen and water) and gas injection speed, and performing simulated gas injection experiments by adopting a continuous gas injection mode. The displacement experiment is controlled by high-temperature and high-pressure oil displacement simulation data acquisition and processing software, and parameters such as temperature, pressure, injected gas quantity, injected water quantity, liquid production quantity, gas production quantity and the like are mainly acquired.
Bottom water energy: calculating result setting according to an oil reservoir engineering method;
Gas injection amount: calculating the size of an underground storage space according to the geological reserves of the oil reservoir, and then setting the gas injection amount according to the size of the underground storage space;
Gas-liquid ratio (nitrogen and water): calculating the gas-liquid ratio according to the formation pressure and the rated working pressure of the gas injection and water injection equipment;
gas injection speed: and setting the gas injection speed according to the rated displacement capacity of the gas injection equipment.
Bottom water flooding control group
firstly, software is opened, a system is checked and tested, whether the devices are complete or not is checked, whether connection is correct or not is checked, and the working state and reliability of each device are checked.
secondly, putting the actual core into a high-temperature high-pressure module, combining a karst cave module and a fracture module according to the determined single-well fracture-cave type, and adjusting the relative position of the karst cave, the fracture width occurrence and the fracture-cave communication relation to form a model;
The whole device is heated to 120 ℃;
Fourthly, gradually pressurizing the saturated water and the saturated oil of the model to 60 MPa;
Simulating bottom water drive until the water content is 100%, and continuously producing more than 1PV after the water content is water.
Nitrogen flooding experimental group (see experimental group 1-4)
the first step to the fourth step is the same as the bottom water flooding control group;
Simulating bottom water drive, and injecting nitrogen when simulating the water content value set for evaluating the gas injection effect.
closing the well for 2 hours, opening the well for evaluation, and calculating the ultimate recovery ratio.
When nitrogen is injected, three parameters of bottom water energy, gas injection amount, gas-liquid ratio and gas injection speed are set as quantification, and the value of the other parameter is changed to obtain the final recovery ratio of gas injection oil recovery under different water contents.
And calculating the recovery ratio improving amplitude and the input-output ratio of the experimental group compared with the control group.
And (4) counting the experimental result data, wherein the water content corresponding to the minimum input-output ratio is the optimal gas injection time.
Experimental group 1
Quantification: the gas injection dosage is 0.04PV, the gas injection speed is 140000m3/d, and the gas-liquid ratio is 400:1 (the ratio of nitrogen to water, unit m3/m 3).
variables are as follows: the bottom water energy was set to 200 times, 180 times and 160 times, respectively.
and (3) data statistics: and dividing the comprehensive water content of the oil well block into 60%, 70%, 80%, 85%, 90%, 95% and 98% according to the experimental result, and calculating the recovery efficiency improving amplitude and the input-output ratio corresponding to different water contents of a TH1# single well. The recovery factor improving range refers to that: the recovery ratio was increased as compared to the control group.
TABLE 1 Water cut of Experimental group 1 and corresponding recovery enhancement
Note: the gas injection volume is the geological reserve multiplied by the gas injection amount.
TABLE 2 input-output ratio of Experimental group 1
Note: the oil increment is equal to geological reserve multiplied by recovery factor; the oil change rate is equal to the oil increment/gas injection volume; the gas injection cost is equal to the gas injection volume multiplied by the price of nitrogen per square/10000; crude oil price is international oil price (50 dollars/barrel) x exchange rate (6.7) x 7 barrel; the oil yield is equal to the oil yield multiplied by the crude oil price/10000; the input-output ratio is gas injection cost/oil increase output. The input-output ratio is (gas injection dosage x geological reserve x nitrogen price per square)/(geological reserve x enhanced recovery amplitude x international oil price x exchange rate x crude oil barrel ton conversion coefficient).
As can be seen from Table 1, the gas injection oil recovery is performed at different water contents, and the recovery ratio is improved by different degrees. As can be seen from the data in tables 1 and 2, the yields of experiments 1-18 are the highest, the input-output ratio is 1:11.84, and the corresponding water content is 85%, so that the optimal single-well gas injection time for screening in experiment group 1 is 85% of the water content.
Experimental group 2
Quantification: the energy of bottom water is set to be 180 times, the gas injection speed is 140000m3/d, and the gas-liquid ratio is 400:1 (the ratio of nitrogen to water, unit m3/m 3).
Variables are as follows: the injection quantities were set to 0.02PV, 0.04PV and 0.06PV, respectively.
The data statistics method is the same as that of experiment group 1.
TABLE 3 Water cut of Experimental group 2 and corresponding recovery enhancement
TABLE 4 input-output ratio of Experimental group 2
As can be seen from the data in tables 3 and 4, the yields of experiments 2 to 4 are the highest, the input-output ratio is 1:13.03, and the corresponding water content is 85%, so that the optimal single-well gas injection time for screening in experiment group 2 is 85% of the water content.
Experimental group 3
Quantification: the gas injection dosage is set to be 0.04PV, the gas injection speed is set to be 140000m3/d, and the energy of bottom water is set to be 180 times.
Variables are as follows: gas-liquid ratios were set at 200:1, 400:1 and 600:1, respectively, and refer to the ratio of nitrogen to water in units of m3/m 3.
the data statistics method is the same as that of experiment group 1.
TABLE 5 Water cut of Experimental group 3 and corresponding recovery enhancement
TABLE 6 input-output ratio of Experimental group 3
as can be seen from the data in tables 5 and 6, the yields of experiments 3 to 10 are the highest, the input-output ratio is 1:11.3, and the corresponding water content is 80%, so that the optimal single-well gas injection time for screening in the experimental group 3 is 80% of the water content.
experimental group 4
Quantification: the energy of bottom water is set to be 180 times, the gas injection dosage is 0.04PV, and the gas-liquid ratio is 400:1 (the ratio of nitrogen to water, unit m3/m 3).
Variables are as follows: the gas injection velocities were set to 100000m3/d, 140000m3/d and 180000m3/d, respectively.
The data statistics method is the same as that of experiment group 1.
TABLE 7 Water cut of Experimental group 4 and corresponding recovery enhancement
TABLE 8 input-output ratio of Experimental group 4
As can be seen from the data in tables 7 and 8, the yields of experiments 4 to 18 are the highest, the input-output ratio is 1:11.6, and the corresponding water content is 85%, so that the optimal single-well gas injection time for screening in experiment group 3 is 85% of the water content.
Through repeated tests, the finally counted highest input-output ratio is 1:13.03, the corresponding water content is 85%, namely the best nitrogen injection oil extraction time of the TH1# single well is when the water content is 85%.
The experimental results are applied to the actual production of a TH1# single well, and the results show that: the water content of a TH1# single well reaches 85% in 5-21 TH-2012, the gas injection amount is designed to be 0.02PV, the converted standard conditions are 134 x 104m3, 1-11 TH 6-2012 6-21 TH, the daily gas injection amount is 15 x 104m3, the gas is injected accumulatively at 135 x 104m3, the well is opened for evaluation in 6-21 TH-2012 after 10 days of well closing, the daily oil production is 25t, the effect lasts until 100% high water content is again obtained in 10-12 TH-2013 TH, the accumulated oil production is 6214t, and the economic benefit is remarkable.
Claims (14)
1. a preferable method for nitrogen injection oil recovery time of a fracture-cavity oil reservoir is characterized by comprising the following steps:
(1) Collecting original oil deposit data and a real rock core aiming at a target block;
(2) inputting the collected oil deposit original data into a data acquisition system, and analyzing and determining the fracture-cavity type of the target block;
(3) Loading the rock core into a high-temperature high-pressure fracture-cavity type oil reservoir simulation device, simulating fracture-cavity type of the target block, simulating bottom water driving, setting four conditions of gas injection amount, gas-liquid ratio, gas injection speed and bottom water energy, wherein any three conditions are quantitative, one condition is variable, and performing nitrogen injection oil extraction experiments under the set four conditions at different water contents;
(4) Calculating the recovery ratio improvement amplitude and the input-output ratio of the nitrogen injection oil extraction to the bottom water drive oil extraction, wherein the water content corresponding to the minimum input-output ratio is the optimal nitrogen injection oil extraction time of the target block;
The high-temperature high-pressure fracture-cave type oil reservoir simulation device comprises a fracture type core module (16), a karst-cave type core module (18) and an automatic space structure adjusting module;
The inside of the fracture type core module (16) and the karst cave type core module (18) can contain real cores; the fracture type core module (16) is connected with the fracture type core module (16), the karst cave core module (18) is connected with the karst cave core module (18), or the fracture type core module (16) is connected with the karst cave core module (18) through pipelines;
the spatial structure automatic adjusting module is respectively connected with the crack type core module (16) and the karst cave type core module (18) and used for accurately positioning the inclination angle and the height of the core and adjusting the relative position of the karst cave, the crack width occurrence and the communication relation of the karst cave.
2. the method of claim 1, wherein the reservoir raw data comprises single well data, base geological data, reserve reports, and dynamic data for the target block;
The single well data comprises drilling, logging, oil extraction and water injection data; the basic geological data comprise seismic amplitude change rate phase diagrams and geologic body carving diagram data; the reserve report comprises geological reserves and dynamic reserves; the dynamic data comprises oil pressure, casing pressure, water content, accumulated oil, accumulated liquid and accumulated gas data;
the real core is an oil reservoir core of the target block or an oil reservoir core of a similar type;
The input-output ratio is calculated by the following formula:
The input-output ratio is (gas injection dosage x standard condition stratum conversion coefficient x square gas price)/(geological reserve x recovery enhancement amplitude x international oil price x exchange rate x crude oil tank ton conversion coefficient).
3. the method of claim 1, wherein the nitrogen injection oil recovery experiment is performed at a water content of 60%, 70%, 80%, 85%, 90%, 95%, 98%, respectively.
4. the method of claim 1,
calculating the size of an underground storage space according to the geological reserves of the oil reservoir, and then setting gas injection amount according to the size of the storage space;
Calculating the gas-liquid ratio according to the formation pressure and the rated working pressure of the gas injection and water injection equipment;
Setting a gas injection speed according to the rated displacement capacity of the gas injection equipment;
And setting bottom water energy according to the calculation result of the oil reservoir engineering method.
5. the method according to claim 1, characterized in that the spatial structure automatic adjustment module comprises brackets (19), said brackets (19) connecting a fracture type core module (16) and a karst cave type core module (18), respectively; the upper part of the bracket (19) can rotate around a horizontal shaft or a vertical shaft, and the lower part can be lifted or translated to accurately position the inclination angle and the position of the rock core.
6. the method of claim 5, wherein the high temperature and high pressure fracture-cavity reservoir simulation device further comprises a confining pressure system (20); the confining pressure system (20) is connected with the fracture type core module (16) and the karst cave type core module (18) through pipelines and used for simulating the pressure of an overlying stratum.
7. The method according to claim 1, characterized in that the fractured core module (16) contains an actual core bin (6), one end of the actual core bin (6) being an injection end and the other end being a production end; the fracture width can be adjusted by an actual core bin size adjustment block (14).
8. A method according to claim 7, characterized in that the crack width is adjusted by a set of jackscrew rods through the side wall of the actual core bin (6), which contains a jackscrew cap (11), a jackscrew sealing washer (12) and a jackscrew distance adjusting thread (13).
9. a method according to claim 7, characterized in that pressure monitoring points (5) are also provided on the side walls of the actual core magazine (6) through said side walls.
10. the method according to claim 7, characterized in that the injection end is provided with an injection end compression plug, which is composed of an injection end compression plug body (4) and an injection end compression plug connector (1), and an injection end compression plug sealing rubber ring is arranged on the injection end compression plug body (4); the injection end is also provided with an injection end compression plug compression nut (2), the outer wall of the injection end is provided with threads matched with the injection end compression plug compression nut (2), the injection end compression plug connector (1) penetrates through the central hole of the injection end compression plug compression nut (2) to extend out, and the injection end compression plug compression nut (2) is used for reinforcing the injection end compression plug; the output end disposes output end compression stopper, output end compression stopper is by output end compression stopper terminal surface (7) and output end compression stopper body (9) constitute, output end compression stopper terminal surface (7) contact the inner chamber of actual core storehouse (6) be provided with output end compression stopper sealing rubber ring (8) on output end compression stopper body (9), still dispose output end compression stopper gland nut (10) at the output end, the output end outer wall is provided with and presses stopper gland nut (10) matched with screw thread with the output end for consolidate output end compression stopper.
11. The method of claim 1, wherein the karst cave core module (18) comprises a core cavity inner barrel (32) and a core cavity outer barrel (33) nested outside the core cavity inner barrel (32); two ends of the core cavity inner barrel (32) are respectively provided with a sealing end (27), and the sealing end (27) and the core cavity inner barrel (32) enclose a core cavity (31); one end of the core cavity (31) is an injection end, and the other end is a production end.
12. the method of claim 11, wherein an injection channel (28) is provided in the sealing head (27) of the injection end, a production channel (30) is provided in the sealing head (27) of the production end, and the core cavity (31) is in fluid communication with the injection channel (28) and the production channel (30); a compression screw cap (26) is sleeved outside the sealing end (27), and the compression screw cap (26) is fixed on the outer barrel (33) of the core cavity through a compression screw (34), so that the sealing end (27) and the inner barrel (32) of the core cavity are mutually compressed on a contact surface; and a sealing rubber ring (25) is arranged between the outer wall of the sealing end head (27) and the inner wall of the core cavity outer barrel (33).
13. The method according to claim 11, characterized in that on the side walls of the core cavity inner barrel (32) and the core cavity outer barrel (33) there are provided temperature and pressure acquisition terminals (15) penetrating the side walls of the core cavity inner barrel (32) and the core cavity outer barrel (33) and extending into the core cavity (31).
14. the method according to any one of claims 1-13, wherein step (3) comprises:
Filling the rock core into a fracture type rock core module and a karst cave type rock core module of the high-temperature and high-pressure fracture-cave type oil reservoir simulation device, combining the fracture type rock core module and the karst cave type rock core module according to the fracture cave type determined in the step (2), and adjusting the relative position of the karst cave, the fracture width occurrence and the fracture cave communication relation to form a model;
Heating the whole device to 120 ℃;
gradually pressurizing the saturated water and the saturated oil of the model to 60 MPa;
simulating bottom water drive, and injecting nitrogen when simulating the water content set by the gas injection effect to be evaluated;
And closing the well for 2 hours, opening the well for evaluation, and calculating the ultimate recovery ratio.
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