CN113356842A - Method for measuring shaft oil reservoir parameter distribution based on packing particle accumulation - Google Patents
Method for measuring shaft oil reservoir parameter distribution based on packing particle accumulation Download PDFInfo
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- 238000012856 packing Methods 0.000 title claims abstract description 128
- 239000002245 particle Substances 0.000 title claims abstract description 111
- 238000000034 method Methods 0.000 title claims abstract description 95
- 238000009826 distribution Methods 0.000 title claims abstract description 46
- 238000009825 accumulation Methods 0.000 title claims abstract description 16
- 239000007788 liquid Substances 0.000 claims abstract description 95
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 55
- 238000012360 testing method Methods 0.000 claims abstract description 54
- 238000010521 absorption reaction Methods 0.000 claims abstract description 47
- 230000035699 permeability Effects 0.000 claims abstract description 38
- 238000005213 imbibition Methods 0.000 claims abstract description 34
- 230000008569 process Effects 0.000 claims abstract description 31
- 238000005259 measurement Methods 0.000 claims abstract description 26
- 239000003129 oil well Substances 0.000 claims abstract description 6
- 239000012530 fluid Substances 0.000 claims description 27
- 238000004519 manufacturing process Methods 0.000 claims description 12
- 238000002347 injection Methods 0.000 claims description 7
- 239000007924 injection Substances 0.000 claims description 7
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- 238000005065 mining Methods 0.000 abstract description 2
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- 238000005086 pumping Methods 0.000 description 9
- 238000010992 reflux Methods 0.000 description 8
- 238000005516 engineering process Methods 0.000 description 6
- 238000005429 filling process Methods 0.000 description 5
- 238000011010 flushing procedure Methods 0.000 description 5
- 239000004576 sand Substances 0.000 description 4
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- 238000000691 measurement method Methods 0.000 description 3
- 238000005406 washing Methods 0.000 description 3
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- 239000004927 clay Substances 0.000 description 1
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- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
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Abstract
A method for measuring wellbore oil reservoir parameter distribution based on packing particle accumulation comprises the following steps: filling liquid or flowback liquid is injected into the shaft, and the length of the submerged section of the packed particles in the shaft is changed; measuring and calculating the bottom hole pressure difference and the stratum liquid absorption of the unsubmerged section in the shaft; and calculating the distribution of the imbibition index per meter and the formation permeability in the shaft along the shaft. By continuously changing the length of the submerged section of the packing particles in the shaft, the invention can directly and continuously measure the formation parameters such as imbibition index per meter and formation permeability of the imbibition formation, and has the following advantages: firstly, the flow of produced liquid in the stratum in the actual underground mining process is directly simulated, so that the stratum parameters can be directly and continuously measured, and the resolution, accuracy, precision and other aspects of the measurement result are greatly improved; secondly, the testing process is simple, the time consumption is less, and the cost is low; the adaptability is strong, and the measurement requirements of the formation parameters of various oil wells such as an open hole well, a cased well and the like can be met.
Description
Technical Field
The invention belongs to the technical field of oil and gas exploitation, relates to a shaft, in particular to a method for measuring oil deposit parameter distribution, and particularly relates to a method for measuring oil deposit parameter distribution of a shaft based on packing particle accumulation.
Background
In the development of oil fields, physical parameters of oil reservoirs along a shaft are required to be known, the development and well repair design of the oil fields are facilitated, wherein the physical parameters comprise permeability, porosity, well diameter, fracture volume and the like.
However, the existing well logging technology usually adopts an indirect measurement method to measure, for example, the parameters of downhole electric, magnetic and neutron radiation are measured through a cable and a measuring instrument, and the parameters of downhole formations are indirectly measured by changing the running length of the cable. For the formation parameter measurement of the horizontal well, a logging tool is difficult to drop into a horizontal section by gravity, the measurement accuracy is low while drilling, and the cost is high; the measurement of the clay content by natural gamma, the water saturation by resistivity, the porosity by neutron density radioactivity curve, and the measurement of the permeability is inaccurate. The natural gamma log measurements are static data, while permeability is a dynamic parameter. The error of calculating the permeability by using the static parameters is large, and sometimes the error reaches about 10 times. For a fractured reservoir, GVR imaging logging can measure the width of a fracture, but the precision is not high, and meanwhile, logging cost is high, and the volume and the flow conductivity of the fracture cannot be measured. The logging technology does not meet the development requirements.
In order to make up for the deficiency of the logging technology, the oil field adopts the oil testing technology to measure the formation parameters, the oil testing is to clamp the production end through two packers to measure the liquid production amount, and gradually clamp and test the formation parameters of other production sections, the test result of the method is usually the permeability of multi-section formations, so the resolution of the measurement result is lower. Because the difference of the formation permeability is large, the measured result cannot be distinguished into each small layer; even if the measuring area is the same large layer, the distribution of the permeability in the layer has large difference, and the measuring result still cannot accurately reflect the actual formation state.
Disclosure of Invention
The invention aims to overcome the defects of the prior art and provide the method for measuring the oil deposit parameter distribution of the shaft based on the packing particle accumulation, which can directly and continuously measure the stratum parameters, has simple measuring process, time and labor saving and accurate result.
In order to achieve the purpose, the invention adopts the following technical scheme:
a method for measuring wellbore oil reservoir parameter distribution based on packing particle accumulation comprises the following steps: filling liquid or flowback liquid is injected into the shaft, and the length of the submerged section of the packed particles in the shaft is changed; measuring and calculating the bottom hole pressure difference and the stratum liquid absorption of the unsubmerged section in the shaft; and calculating the distribution of the imbibition index per meter and the formation permeability in the shaft along the shaft.
Further, the method for changing the length of the submerged section for packing particle accumulation in the well bore comprises the following steps: and injecting a filling liquid containing packing particles into the well bore, wherein the packing particles are accumulated in the well bore from the far end to the near end, and the length of the submerged section is increased.
Further, the wellbore is an open hole well; in the process of filling the filling liquid, the accumulated volume (accumulation volume) of the packing particles injected into the shaft is divided by the sectional area of the shaft, so that the length of the submerged section of the packing particles accumulated in the shaft at any time is obtained.
Further, a seepage test pipe column is arranged in the shaft; filling liquid containing packing particles is injected into an annulus between the seepage testing pipe column and a well wall, and the packing particles are accumulated in the annulus from inside to outside; and the length of the submerged section accumulated by the packing particles in the shaft at any moment can be obtained through the backflow amount of the well mouth filling liquid and the pressure difference between the inner side and the outer side of the seepage test pipe column.
Further, for a wellbore filled with packing particles, the method for changing the length of the submerged section of packing particle accumulation in the wellbore is as follows: and (4) the packing particles fully accumulated in the shaft are discharged back to the wellhead, and the length of the submerged section is reduced.
Further, the wellbore is an open hole well; by lowering the coiled tubing into the wellbore, packer particles fully accumulated in the wellbore are discharged back to the wellhead, thereby reducing the length of the submerged section.
Further, the length of the submerged section of the packed particles in the shaft at any time is obtained by calculating the length of the coiled tubing.
Further, a seepage test pipe column is arranged in the shaft; the outer ring space between the seepage test pipe column and the well wall is filled with packing particles; by injecting the backflow liquid into the annulus between the seepage testing pipe column and the well wall, the backflow liquid flows into the annulus through the seepage holes, and then the packed particles fully accumulated in the annulus are discharged back to the well head, so that the length of the submerged section is reduced.
Further, the length of the submerged section accumulated by the packing particles in the shaft at any moment is obtained through the backflow amount of the wellhead flowback fluid and the pressure drop inside and outside the seepage test pipe column.
Further, the packing particles have a density of 0.95 to 1.05g/cm3(true density rather than bulk density) particle size of 40-70 mesh; the packing particles form a submerged section in the shaft stack, and the seepage of the wall of the submerged section is prevented.
Further, the method for measuring the bottom hole pressure difference comprises the following steps: subtracting the on-way friction resistance from the injection pressure of the wellhead filling liquid/flowback liquid; alternatively, the measurements are made directly by a downhole pressure gauge mounted on the seepage test string.
Further, the method for measuring the stratum fluid absorption amount comprises the following steps: and subtracting the backflow amount of the wellhead filling liquid or the flow-back liquid from the injection amount of the wellhead filling liquid or the flow-back liquid.
Further, the method for calculating the distribution of the imbibition index and the formation permeability per meter in the wellbore along the wellbore comprises the following steps: calculating to obtain a stratum liquid absorption index according to the ratio of the stratum liquid absorption amount to the bottom hole pressure difference; calculating the ratio of the accumulated liquid absorption amount of the stratum in a period of time to the length change value of the submerged section in the period of time and the bottom hole pressure difference to obtain a liquid absorption index per meter; calculating and obtaining the permeability of the imbibition layer section through a steady-state yield formula of the vertical well or the horizontal well; and (5) drawing a distribution curve of the imbibition index per meter and the formation permeability in the shaft along the shaft.
Further, the method for calculating and obtaining the permeability of the liquid-absorbing interval through the steady-state production formula of the vertical well or the horizontal well comprises the following steps: assuming that the stratum participating in imbibition is uniform and has the same thickness, providing plane radial flow of a boundary for a circle, and participating in seepage by the length of the submerged section in a period of time; and (3) through a steady-state yield formula of the vertical well or the horizontal well, the stratum liquid absorption amount is the oil well yield in the period of time, and the permeability of the liquid absorption layer section in the period of time is reversely calculated.
The invention relates to a method for measuring the oil deposit parameter distribution of a shaft based on packing particle accumulation, which can directly and continuously measure the formation parameters such as imbibition index per meter and formation permeability of the imbibition formation by continuously changing the length of the packing particle submerged section in the shaft under different well conditions. Compared with the traditional indirect measurement method (the measurement method which indirectly reflects the formation parameters through electromagnetism and the like), the method directly simulates the flow (reverse flow) of the produced liquid in the formation in the actual underground mining process, so that the formation parameters can be directly and continuously measured, and the measurement result is greatly improved in the aspects of resolution, accuracy, precision and the like; secondly, the testing process is simple, the time consumption is less, and the cost is low; the adaptability is strong, and the measurement requirements of the formation parameters of various oil wells such as an open hole well, a cased well and the like can be met.
Drawings
FIG. 1 is a schematic diagram of a wellbore configuration for a method of measuring wellbore reservoir parameter distribution based on packing particle packing in examples 1 and 3;
FIG. 2 is a schematic diagram of a wellbore configuration for a method of measuring wellbore reservoir parameter distribution based on packing particle packing in examples 2 and 4;
FIG. 3 is a schematic diagram of a wellbore configuration of a method for measuring wellbore reservoir parameter distribution based on packing particle packing in example 5;
FIG. 4 is a graph of the results of the index per meter in example 5;
FIG. 5 is a graph of the formation permeability results of example 5.
Detailed Description
The following further describes an embodiment of the method for measuring the wellbore oil deposit parameter distribution based on packing particle accumulation according to the present invention with reference to fig. 1 to 5. The method for measuring the distribution of the oil deposit parameters of the shaft based on the packing particle accumulation is not limited to the description of the following embodiment.
The definitions of the words used herein are as follows:
packing particles: a round or other irregularly shaped particulate material, having a density close to that of water, which can be injected into the wellbore by a packing fluid or drained from the wellbore by a return fluid; the concrete structure and the filling and flowback method refer to international patent application (application number: PCT/CN2010/002014) of anti-channeling packing particles at the production section of an oil-gas well, a well completion method and an oil extraction method using the particles, and related technologies for carrying out oil-gas auxiliary exploitation by using the packing particles provided by Andongbulin Petroleum science and technology (Beijing) Limited company.
Seepage test pipe column: the whole body is of a pipe cavity-shaped structure, seepage holes are circumferentially arranged, and the diameters of the seepage holes are smaller than the diameters of the packing particles; the imbibition index of the seepage test column is constant under the unit pressure difference (namely, the flow rate of liquid flowing out of the tube cavity or flowing into the tube cavity from the outside is constant under the condition that the unit pressure difference exists between the inside and the outside for the seepage test column with the unit length). Specifically, the seepage flow test tubular column can comprise a plurality of tubular columns that have the flow control device, and the tubular column outer wall is attached with the sand control filter screen, has functions such as accuse water, sand control.
The meanings of the symbols used herein are as follows:
q is ΔtThe amount of formation fluid imbibed over time, K is the permeability, μ is the fill fluid viscosity, B0Is the volume coefficient of the filling liquid, delta P is the bottom hole pressure difference, a is the ellipse major axis half length, L is deltatLength of flood in time, h reservoir thickness, rwIs the radius of the well bore, rehTo drive the radius, L1Is t1Length of flood section of time, L2Is t2Length of submerged section at time, R is stratum imbibition index, P is wellhead pressure, P is1For friction along the way, P0Is the formation pressure, Q1For well head pumping volume, Q2Q is Δ for the amount of refluxtThe amount of packing particles is accumulated in time, S is the cross section area of the shaft, l1Is t1The running depth of the flushing pipe of the continuous oil pipe at any moment2Is t1The running depth of the flushing pipe of the continuous oil pipe at any momentThe degree of the magnetic field is measured,
is t1The length of the seepage test pipe column participating in the flow at any moment,
is t2And testing the length of the pipe column by seepage which participates in the flow at any time.
Is t1The pressure drop inside and outside the flow control device at the moment,
is t2And the pressure drop inside and outside the flow control device at the moment.
Example 1:
this example presents a specific method for measuring wellbore reservoir parameter distribution based on packing particle packing.
As shown in fig. 1, the wellbore 1 is composed of a vertical well section 6 and a horizontal well section 3, and a packer 4 is arranged inside the wellbore. The horizontal wellbore section 3 is an open-hole wellbore without running casing or other production tubing.
The packing fluid containing the packing particles 5 is injected into the open hole wellbore by running a washpipe through surface equipment, a portion of the packing fluid returns to the surface along the wellbore, and a portion of the packing fluid penetrates the formation. Preferably, as much of the fill fluid as possible is lost through the formation by controlling the injection flow rate and injection pressure. With the leakage of the filling liquid, the packing particles are continuously settled and accumulated from the far end to the near end in the open hole shaft, and a submerged section is gradually formed. In the accumulated packing particle flooding section, the packing particles can effectively prevent formation fluid and injection fluid from flowing axially along the shaft in the shaft space or being absorbed by the shaft wall. As the filling is carried out, the distance of the submerged sections is increased continuously, the distance of the non-submerged sections is reduced continuously, and the stratum liquid absorption amount shows a gradually reduced characteristic under the same bottom hole pressure difference. In the filling process, the pumping amount and the backflow amount of the filling liquid are recorded in real time through a wellhead flowmeter, so that the stratum liquid absorption amount can be calculated; recording the pressure through a wellhead pressure gauge or a bottom hole pressure gauge so as to obtain the bottom hole pressure difference; the hole diameter (i.e., wellbore diameter) distribution is obtained by pre-logging.
The specific calculation process and principle are as follows:
in the filling process, the wellhead pressure, the pumping amount and the backflow amount at different moments are recorded, and the bottom hole pressure difference and the stratum liquid absorption amount of the unsubmerged section are calculated. The differential pressure at the bottom of the well can be obtained by subtracting the friction resistance along the way from the pressure at the top of the well.
ΔP＝P-P1-P0
Similarly, the bottom hole pressure difference can be obtained by measuring in real time through a downhole pressure gauge.
ΔP＝P2-P0
In the formula: p is the wellhead pressure, P1For friction along the way, P0Is the formation pressure, P2Is the downhole gauge pressure.
Q＝Q01-Q02
In the formula: q01For well head pumping volume, Q02Q is the formation fluid uptake.
By atAnd calculating the accumulated filling amount of the packing particles by using the concentration of the packing particles of the filling liquid. The cumulative packing volume of packing particles is divided by the cross-sectional area of the wellbore to obtain DeltatThe length of the inundated segment increases by an amount.
Assuming a constant radius of the wellbore r, ΔtThe accumulated filling packing particle amount in time is q, the length of the shaft is L0Then, then
Cross-sectional area of wellbore being S ═ r2
Length L of particle-engulfing zone q/pi r2
Assuming wellbore radius r (L), ΔtThe accumulated filling packing particle amount in time is q, then
Shaft cross-sectional area S ═ r (L)2
Length of particle submerged section L ═ q/pi r (L)2
Dividing the stratum liquid absorption quantity by the stratum liquid absorption index participating in seepage at different moments by the bottom hole pressure difference, and utilizing deltatCumulative fluid uptake of the formation over time divided by ΔtThe length increment of the submerged segment and the bottom hole pressure difference are obtained within the time, and the imbibition index per meter is obtained.
Using the calculated stratum liquid absorption amount and bottom hole pressure difference at different time, the liquid absorption index of stratum seepage section is equal to liquid absorption amount/bottom hole pressure difference, namely
In the formula: r is stratum imbibition index
Absorption index per meter equal to deltatCumulative fluid uptake of the formation over time divided by ΔtThe length increase of the submerged section and the bottom hole pressure difference are submerged in the time.
For open hole wells with constant wellbore radius
Open hole for wellbore radius variation
In the formula:
is the liquid absorption index per meter.
Calculating delta by using a steady-state yield formula of the vertical well and the horizontal welltThe time is related to the formation permeability of the imbibition.
The steady state production formula of the vertical well can be used for obtaining:
the steady-state yield formula of the horizontal well can be used for obtaining:
wherein the content of the first and second substances,
in the formula: Δ Q is ΔtThe amount of formation fluid imbibed over time, K is the permeability, μ is the fill fluid viscosity, B0Is the volume coefficient of the filling liquid, delta P is the bottom hole pressure difference, a is the ellipse major axis half length, L is deltatLength of flood in time, h reservoir thickness, rwIs the radius of the well bore, rehIs the drive radius.
And drawing a relation curve of the liquid absorption index and the permeability per meter and the distribution of the shaft by taking the length of the shaft as an abscissa and taking the liquid absorption index and the permeability per meter as an ordinate respectively.
The embodiment adopts the technical scheme of directly filling packing particles for a bare well, has simple testing process and low construction cost, and can realize continuous measurement of the liquid absorption index per meter and the formation permeability of the formation in a full well section. By measuring the stratum liquid absorption amount, the liquid production capacity of the stratum after the oil well is put into operation can be accurately reflected.
Example 2:
this example presents another specific method for measuring wellbore reservoir parameter distribution based on packing particle packing.
As shown in fig. 2, the shaft 1 is composed of a vertical well section 6 and a horizontal well section 3, and a seepage testing pipe column 2 and a hanging packer 4 are arranged in the shaft 1. Firstly, a seepage test pipe column is put into a downhole production section, and a shaft is divided into two parts, namely an inner space of the pipe column and an outer annular space formed between the pipe column and a well wall, by the seepage test pipe column. Filling liquid containing packing particles 5 is injected into the annular space through ground equipment, and a part of the filling liquid enters the inner space of the pipe column through a seepage hole of the seepage test pipe column and returns to the ground; a portion of the packing fluid then penetrates directly into the formation. Because the particle diameter of packing granule is greater than the diameter of seepage hole, so packing liquid itself can pass through the seepage test tubular column smoothly, but the packing granule of its carrying then can not get into seepage test tubular column, and then constantly subsides from the distal end to near-end and piles up in the annular space between tubular column and the wall of a well, forms the inundation section. In the packed-formed packing particle flooded section, the packing particles can impede the axial flow of formation fluids and injected packing fluid along the wellbore or be absorbed by the formation. In the filling process, the pumping amount and the backflow amount are recorded in real time through a wellhead flowmeter, and then the stratum liquid absorption amount is calculated; and recording the pressure through a wellhead pressure gauge or a bottom hole pressure gauge so as to obtain the bottom hole pressure difference.
The specific calculation process and principle are as follows:
the method and process for recording the wellhead pressure, the pumping amount and the backflow amount at different moments in the filling process, measuring and calculating the bottom hole pressure difference and the liquid absorption amount of the seepage section are the same as those in the embodiment 1.
The length of the test pipe column participating in imbibition can be calculated through the reflux amount of the seepage test pipe column to obtain deltatLength of submerged section in time
Testing the reflux quantity Q of the pipe column by seepage02Calculating the length of the seepage test tube column participating in imbibition
In the formula: l0For a single flow control device length, a is the flow control device coefficient.
In the formula:
is t1The length of the seepage test pipe column participating in the flow at any moment,
is t2And testing the length of the pipe column by seepage which participates in the flow at any time.
Stratum participating in seepage at different moments by dividing stratum liquid absorption amount by bottom hole pressure differenceThe method and procedure for calculating the imbibition index, formation imbibition index, were the same as in example 1. Absorption index per meter equal to deltatCumulative fluid uptake of the formation over time divided by ΔtLength increase of submerged section and bottom hole pressure difference
In the formula: q021Is t1Amount of reflux at time, Q022Is t2The amount of reflux at the moment of time,
is t1The pressure drop inside and outside the flow control device at the moment,
is t2And the pressure drop inside and outside the flow control device at the moment.
Calculating delta by using a steady-state yield formula of the vertical well and the horizontal welltThe specific calculation method and procedure for the time-dependent imbibition of the formation was the same as in example 1.
The specific drawing method and process of the liquid absorption index and permeability per meter and the distribution of the wellhole are the same as in the example 1.
In this embodiment, by setting the seepage testing string and using the seepage testing string as a scale for calculating the submerged section, the length of the submerged section can be calculated more accurately, and thus the formation parameters obtained by calculation have higher accuracy. Meanwhile, packing particles filled into the shaft are easier to discharge through the seepage test pipe column, and the shaft cannot be damaged.
Example 3:
this example presents another specific method for measuring wellbore reservoir parameter distribution based on packing particle packing.
The structure of the well bore in this example is the same as that in example 1. The entire flooded section is formed in the wellbore by surface equipment after the wellbore is filled with packing particles. And (3) putting a coiled tubing flushing pipe, injecting return liquid, gradually stripping the packed packing particles in the shaft from outside to inside gradually and returning the packing particles out of the well mouth, and further changing the length of the submerged section of the packing particles.
The specific calculation process and principle are as follows:
the specific calculation method and process for recording the wellhead pressure, the pumping amount and the backflow amount at different moments in the flowback process, calculating the bottom hole pressure difference and the liquid absorption amount of the liquid absorption section are the same as those in the embodiment 1.
By using packing particles in a coiled tubing flushing flow-back shaft, the descending position of the coiled tubing can represent the accumulation position of the packing particles, so that the packing particles pass through deltatThe change value of the running depth of the coiled tubing washing pipe in the shaft within the time is obtained to obtain deltatLength of flooded section in time.
Calculating delta through the running depth of the coiled tubing washing pipetThe length of flooding in time L.
L＝l2-l1
In the formula: l1Is t1The running depth of the flushing pipe of the continuous oil pipe at any moment2Is t2And the running depth of the coiled tubing washing pipe is kept.
The method and process for calculating the formation imbibition index are the same as those in example 1, except that the formation imbibition amount is divided by the bottom hole pressure difference at different times to obtain the formation imbibition index participating in seepage. Absorption index per meter equal to deltatCumulative fluid uptake of the formation over time divided by ΔtReduction of length of submerged section and bottom hole pressure difference
Calculating delta by using a steady-state yield formula of the vertical well and the horizontal welltThe specific calculation method and process for the formation permeability with time-dependent seepage is the same as in example 1.
The specific drawing method and process of the liquid absorption index and permeability per meter and the distribution of the wellhole are the same as in the example 1.
This embodiment can be regarded as the reverse process of embodiment 1, namely, the parameter distribution measurement is completed by gradually reducing the flooding section. In specific application, the method described in example 1 can be used to perform a first measurement, after which the wellbore is filled with packing particles; then, when the method of the embodiment is used for carrying out the second measurement, the measurement result can be used as the verification of the first measurement, and the well bore after the measurement is finished can directly have the production condition.
Example 4:
this example presents another specific method for measuring wellbore reservoir parameter distribution based on packing particle packing.
In this example, the structure of the well bore was the same as in example 2, and the inner space and the outer annulus of the seepage testing string were filled with packing particles by the process of example 2. Through the seepage flow test pipe column flowback process, flowback fluid is injected into the annulus through a flowback hole of the seepage flow test pipe column, part of the flowback fluid returns out of a wellhead through a shaft, and part of the flowback fluid is absorbed by the stratum. The backflow liquid gradually peels off the packing particles fully accumulated in the shaft and carries the packing particles out of the shaft, so that the submerged section formed by the accumulated packing particles is continuously shortened from outside to inside.
The specific calculation process and principle are as follows:
in the flow-back process, the pumping-in amount and the backflow amount are recorded in real time through a wellhead flowmeter, and then the stratum liquid absorption amount is calculated; and recording the pressure through a wellhead pressure gauge or a bottom hole pressure gauge so as to obtain the bottom hole pressure difference.
The well head pressure, the pumping amount and the reflux amount at different moments are recorded in the flowback process, the well bottom pressure difference and the stratum liquid absorption amount of the seepage section are calculated, and the specific calculation method and the specific calculation process are the same as those in the embodiment 1
Testing the reflux quantity Q of the pipe column by seepage02The length of the test pipe column participating in the flow can be calculated
To obtain DeltatLength L of the flooded section in time.
In the formula: l0For a single flow control device length, a is the flow control device coefficient
In the formula:
is t1The length of the seepage flow string participating in the flow,
is t2The method and the process for calculating the stratum imbibition index are the same as those in the embodiment 1, wherein the stratum imbibition index at different moments is obtained by dividing the stratum imbibition amount of the flowing seepage string length by the bottom hole differential pressure. Absorption index per meter equal to deltatCumulative fluid uptake of the formation over time divided by ΔtLength reduction of submerged section and bottom hole pressure difference in time
Calculating delta by using a steady-state yield formula of the vertical well and the horizontal welltThe formation permeability with time-related seepage, and the specific calculation method and process thereof are the same as those of example 1
The specific drawing method and process of the liquid absorption index and permeability per meter and the distribution of the wellhole are the same as in the example 1.
This embodiment can be regarded as the reverse process of embodiment 2, namely, the parameter distribution measurement is completed by gradually reducing the flooding section. In specific application, the method described in example 2 can be used to perform a first measurement, after which the wellbore is filled with packing particles; then, when the method of the embodiment is used for carrying out the second measurement, the measurement result can be used as the verification of the first measurement, and the well bore after the measurement is finished can directly have the production condition.
Example 5:
this example shows a specific implementation of the method described in example 2 for measuring a well.
As shown in FIG. 3, the structure of the shaft of a certain oil well is schematically shown, the well completion depth is 2015 meters, and the length D of the open hole horizontal section 3LThe diameter r of the open hole is 8-1/2in, the diameter of the packing particles 5 is 50 meshes, and the outer diameter of the seepage test pipe column is 172 mm. The effective thickness h of the reservoir is 19 m, and the volume coefficient B of the filling liquid01.0, a filling liquid viscosity mu of 1 mPas, a driving radius rehIs 30 meters.
The operation steps are as follows:
firstly, a seepage test pipe column of 5-1/2in is put into a horizontal section in the well, and the seepage test pipe column divides a shaft into a pipe column inner annular space and an outer annular space between the pipe column and a well wall. And injecting the filling liquid containing the packing particles into the shaft by surface equipment, wherein a part of the filling liquid returns to the surface through the seepage test string, and a part of the filling liquid permeates into the stratum. The filling liquid can smoothly pass through the seepage test pipe column, and the packing particles can not pass through the pipe column, so that the packing liquid is continuously deposited and piled from the far end to the near end in the annular space of the pipe column and the well wall to form a submerged section.
In the filling process, the pumping amount and the reflux amount are recorded in real time through a wellhead flowmeter, and the liquid absorption amount is further calculated; and recording the pressure through a wellhead pressure gauge or a bottom hole pressure gauge so as to obtain the bottom hole pressure difference. From the measurement results, it is possible to plot the change in the liquid suction amount and the bottom hole differential pressure with the filling time.
The method and process for calculating the liquid absorption index per meter are the same as those in example 2, and the calculation result is shown in figure 4; the method and process for calculating the formation permeability are the same as in example 1, and the calculation results are shown in FIG. 5.
By analyzing the attached figures 4 and 5, the reservoir stratum of the oil reservoir can be judged to have heterogeneity, and the imbibition index per meter and the formation permeability change greatly. The section of the 158-sand 191-meter interval and the 442-sand 475-meter interval is a strong liquid absorption section, the permeability is high, and the reservoir is preliminarily judged to have cracks; the interval of 380 meters in 310-reservoir is a weak imbibition segment, and the permeability is low, which indicates that no crack exists in the reservoir and a separation layer is possible.
The foregoing is a more detailed description of the invention in connection with specific preferred embodiments and it is not intended that the invention be limited to these specific details. For those skilled in the art to which the invention pertains, several simple deductions or substitutions can be made without departing from the spirit of the invention, and all shall be considered as belonging to the protection scope of the invention.
Claims (14)
1. A method for measuring shaft oil reservoir parameter distribution based on packing particle accumulation is characterized in that: the method comprises the following steps:
filling liquid or flowback liquid is injected into the shaft, and the length of the submerged section of the packed particles in the shaft is changed;
measuring and calculating the bottom hole pressure difference and the stratum liquid absorption of the unsubmerged section in the shaft;
and calculating the distribution of the imbibition index per meter and the formation permeability in the shaft along the shaft.
2. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 1, wherein: the method for changing the length of the submerged section on which the packing particles are piled in the well bore comprises the following steps: and injecting a filling liquid containing packing particles into the well bore, wherein the packing particles are accumulated in the well bore from the far end to the near end, and the length of the submerged section is increased.
3. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 2, wherein: the shaft is an open hole well; in the process of filling the filling liquid, the accumulated volume (accumulation volume) of the packing particles injected into the shaft is divided by the sectional area of the shaft, so that the length of the submerged section of the packing particles accumulated in the shaft at any time is obtained.
4. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 2, wherein: a seepage test pipe column is arranged in the shaft; filling liquid containing packing particles is injected into an annulus between the seepage testing pipe column and a well wall, and the packing particles are accumulated in the annulus from inside to outside; and the length of the submerged section accumulated by the packing particles in the shaft at any moment can be obtained through the backflow amount of the well mouth filling liquid and the pressure difference between the inner side and the outer side of the seepage test pipe column.
5. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 1, wherein: for a wellbore filled with packing particles, the method for changing the length of the submerged section of packing particle accumulation in the wellbore comprises the following steps: and (4) the packing particles fully accumulated in the shaft are discharged back to the wellhead, and the length of the submerged section is reduced.
6. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 5, wherein: the shaft is an open hole well; by lowering the coiled tubing into the wellbore, packer particles fully accumulated in the wellbore are discharged back to the wellhead, thereby reducing the length of the submerged section.
7. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 6, wherein: and calculating the length of the submerged section of the packed particles in the shaft at any moment by calculating the length of the coiled tubing.
8. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 5, wherein: a seepage test pipe column is arranged in the shaft; the outer ring space between the seepage test pipe column and the well wall is filled with packing particles; by injecting the backflow liquid into the annulus between the seepage testing pipe column and the well wall, the backflow liquid flows into the annulus through the seepage holes, and then the packed particles fully accumulated in the annulus are discharged back to the well head, so that the length of the submerged section is reduced.
9. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 8, wherein: and solving the length of the submerged section accumulated by the packing particles in the shaft at any moment through the backflow amount of the wellhead flowback fluid and the pressure drop inside and outside the seepage test pipe column.
10. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 1, wherein: the packing particles have a density of 0.95 to 1.05g/cm3(true density rather than bulk density) particle size of 40-70 mesh; the packing particles form a submerged section in the shaft stack, and the seepage of the wall of the submerged section is prevented.
11. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 1, wherein: the method for measuring the bottom hole pressure difference comprises the following steps: subtracting the on-way friction resistance from the injection pressure of the wellhead filling liquid/flowback liquid; alternatively, the measurements are made directly by a downhole pressure gauge mounted on the seepage test string.
12. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 1, wherein: the method for measuring the stratum liquid absorption amount comprises the following steps: and subtracting the backflow amount of the wellhead filling liquid or the flow-back liquid from the injection amount of the wellhead filling liquid or the flow-back liquid.
13. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 1, wherein: the method for calculating the distribution of the imbibition index and the formation permeability per meter in the wellbore along the wellbore comprises the following steps of:
calculating to obtain a stratum liquid absorption index according to the ratio of the stratum liquid absorption amount to the bottom hole pressure difference;
calculating to obtain a liquid absorption index per meter according to the ratio of the accumulated liquid absorption amount of the stratum in a period of time to the length change value of the submerged section in the period of time and the bottom hole pressure difference;
calculating and obtaining the permeability of the imbibition layer section through a steady-state yield formula of the vertical well or the horizontal well;
and (5) drawing a distribution curve of the imbibition index per meter and the formation permeability in the shaft along the shaft.
14. The method for measuring wellbore reservoir parameter distribution based on packing particle packing of claim 13, wherein: the method for calculating and obtaining the permeability of the imbibition interval through the steady-state production formula of the vertical well or the horizontal well comprises the following steps of:
assuming that the stratum participating in imbibition is uniform and has the same thickness, providing plane radial flow of a boundary for a circle, and participating in seepage by the length of the submerged section in a period of time;
and (3) through a steady-state yield formula of the vertical well or the horizontal well, the stratum liquid absorption amount is the oil well yield in the period of time, and the permeability of the liquid absorption layer section in the period of time is reversely calculated.
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