Method for determining formation pressure of tight oil reservoirs

Abstract

The application discloses a method for determining formation pressure of a tight oil reservoir by well testing, which comprises the following steps: calculating the original reserves of the tight oil reservoir by using the static pressure value and the production value measured by pressure drop, blowout and shut-in recovery; calculating the pressure increase value of the formation during the fracturing process by using fracturing and pressure drop under the condition of obtaining the original reserves of the tight oil reservoir; and calculating the formation pressure of the tight oil reservoir by using the static pressure value measured by pressure drop and the pressure increase value. The method for determining the formation pressure of the tight oil reservoir by well testing combines the fracturing process characteristics of the tight oil and shale oil, designs a technological process, records and calculates the pressure in different stages of fracturing, pressure drop, blowout and shut-in recovery, calculates and analyzes the formation pressure of the reservoir, and solves the problem that the conventional well testing analysis technology cannot obtain the formation pressure of the tight oil.

Description

Technical Field

[0001] This invention relates to the field of petroleum exploration, specifically a well test method for determining formation pressure in tight oil reservoirs. Background Technology

[0002] Thanks to advancements in engineering technology, unconventional oil reservoirs such as tight oil and shale oil have achieved industrial exploration and development, changing the global oil landscape. Tight oil and shale oil reservoirs are also key strategic areas for oil exploration and development. Formation pressure in tight oil and shale oil are indispensable geological parameters for studying geological genesis, analysis, and the formulation and adjustment of development plans.

[0003] Currently, the conventional testing process for determining formation pressure in oil reservoirs involves conducting well tests with an open-close cycle to obtain pressure recovery data. The Horner method is then used to determine formation pressure, specifically by plotting a Horner curve and extrapolating the infinite shut-in time to determine the formation pressure. The Horner analysis method is suitable for medium- to high-permeability reservoirs, requiring a short open-close period and normal production. However, tight oil and shale oil reservoirs have very poor reservoir properties. Conventional perforation production often results in tight oil and shale oil being unable to flow or having extremely difficult flow within the reservoir, hindering normal production. Therefore, conventional well testing cannot determine the formation pressure of tight oil reservoirs.

[0004] Therefore, it is necessary to design and study unconventional testing processes and analytical methods to determine the formation pressure of tight oil reservoirs. Summary of the Invention

[0005] The purpose of this invention is to provide a well test method for determining formation pressure in tight oil reservoirs. By recording and calculating the pressure at different stages of fracturing, well shut-in, blowout, and well recovery, the reservoir formation pressure can be obtained through calculation and analysis.

[0006] This application provides a well test method for determining formation pressure in tight oil reservoirs. The method utilizes the static pressure and production values ​​obtained from well shut-in, blowout, and well recovery to calculate the original reserves of the tight oil reservoir. Under the condition of obtaining the original reserves of the tight oil reservoir, the method uses fracturing and well shut-in to calculate the pressure increase during fracturing. Finally, the method uses the static pressure and pressure increase values ​​obtained from well shut-in to calculate the formation pressure of the tight oil reservoir.

[0007] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes measuring the wellbore pressure recovery data after perforation to obtain the wellbore static pressure value P. j1 Formation permeability and formation energy value.

[0008] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes using hydraulic fracturing to measure pressure data and the total fracturing fluid volume N during fracturing and well shut-in processes. Z And the formation recovery pressure P1 after well closure.

[0009] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes obtaining the fracturing area S using well pressure drop data. RV , Modify volume V SRV The average effective permeability K and flow coefficient Kh / μ of the modified area were used to calculate the original formation pressure P of the shale oil. i1 Estimate N O1 N O1 m is the reserve of tight oil under surface conditions. 3 .

[0010] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes opening the well and releasing the blowout, measuring the flowing pressure and production data, and calculating the total production volume Q. t Q t = + ,in, —Water production volume (m³) 3 , —Oil production (m³) 3 ...

[0011] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes, when the well production pressure reaches the boundary of the stimulation range, the flow enters a quasi-steady flow phase, and the liquid volume V within the stimulation range can be calculated using the quasi-steady flow pressure equation for the boundary control flow phase. t， Estimate N O2 N O2 m is the reserve of tight oil under surface conditions. 3 .

[0012] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes measuring the stable formation recovery pressure P2 after blowout and the water volume factor under the formation pressure of P2. The compressibility coefficient of fracturing fluid under formation pressure P2 .

[0013] In some alternative embodiments, calculation The calculation equation is as follows: in, --Cumulative water production (m) 3 ; --The volume factor of water under formation pressure P2, m 3 / sm 3 ; --Cumulative oil production in m3 ; --The volume factor of oil under formation pressure P2, m 3 / sm 3 ; -- is the fracturing fluid volume in m 3 ; --The volume factor of the fracturing fluid under formation pressure P1, m 3 / sm 3 ; --Compressibility coefficient of fracturing fluid under formation pressure P2, 1 / MPa; --Formation pressure drop, MPa; -- represents the oil reserves under surface conditions (m) 3 ; --The volume factor of oil under formation pressure P1, m 3 / sm 3 ; S O —Oil saturation%; S wi —Bound water saturation%; --Volume of bound water expanding (m) 3 ; -- Rock pore shrinkage volume (m) 3 It includes the increased porosity resulting from the modification.

[0014] In some optional embodiments, the pressure increase ΔP2 in the formation during fracturing is calculated using the following formula:

[0015] In the formula: △P2 - Formation pressure rise, MPa; B0 - Original formation pressure volume coefficient, m 3 / sm 3 .

[0016] In some optional embodiments, the original formation pressure P of the shale oil well is estimated. i , P i =P 1— △P2 Estimate the original formation pressure P i The initial formation pressure P of shale oil was obtained through fitting and analysis.i1 Less than the preset error range.

[0017] This application has the following technical advantages over the prior art: The well test method for determining formation pressure in tight oil reservoirs includes at least the following steps: 1) Calculating the original reserves of the tight oil reservoir using static pressure values ​​and production values ​​obtained from well shut-in, blowout, and well recovery; 2) Calculating the pressure increase in the formation during fracturing using fracturing and well shut-in, given the original reserves; and 3) Calculating the formation pressure of the tight oil reservoir using static pressure values ​​and pressure increase values ​​obtained from well shut-in. This well test method for determining formation pressure in tight oil reservoirs, combined with the characteristics of fracturing technology for tight oil and shale oil, designs a process flow. By recording and calculating the pressure at different stages of fracturing, well shut-in, blowout, and well recovery, the reservoir formation pressure is calculated and analyzed, solving the problem that conventional well test analysis techniques cannot obtain the formation pressure of tight oil reservoirs. Attached Figure Description

[0018] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with the invention and, together with the description, serve to explain the principles of the invention.

[0019] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, for those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0020] Figure 1 This is a schematic flowchart of an embodiment of the present invention for analyzing oxygen activation spectra of low-injection fluids in wellbores. Detailed Implementation

[0021] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0022] Thanks to advancements in engineering technology, unconventional oil reservoirs such as tight oil and shale oil have achieved industrial exploration and development, changing the global oil landscape. Tight oil and shale oil reservoirs are also key strategic areas for oil exploration and development. Formation pressure in tight oil and shale oil are indispensable geological parameters for studying geological genesis, analysis, and the formulation and adjustment of development plans.

[0023] Currently, the conventional testing process for determining formation pressure in oil reservoirs involves conducting well tests with an open-close cycle to obtain pressure recovery data. The Horner method is then used to determine formation pressure, specifically by plotting a Horner curve and extrapolating the infinite shut-in time to determine the formation pressure. The Horner analysis method is suitable for medium- to high-permeability reservoirs, requiring a short open-close period and normal production. However, tight oil and shale oil reservoirs have very poor reservoir properties. Conventional perforation production often results in tight oil and shale oil being unable to flow or having extremely difficult flow within the reservoir, hindering normal production. Therefore, conventional well testing cannot determine the formation pressure of tight oil reservoirs.

[0024] Therefore, it is necessary to design and study unconventional testing processes and analytical methods to determine the formation pressure of tight oil reservoirs. This invention provides a well test method for determining the formation pressure of tight oil reservoirs.

[0025] This invention provides a well test method for determining formation pressure in tight oil reservoirs. It calculates the original reserves of the tight oil reservoir using static pressure values ​​and production values ​​obtained from well shut-in, blowout, and well recovery. Under the condition of obtaining the original reserves of the tight oil reservoir, it calculates the pressure increase in the formation during fracturing and well shut-in using fracturing and well shut-in methods. Finally, it calculates the formation pressure of the tight oil reservoir using the static pressure values ​​and pressure increase measured during well shut-in.

[0026] Specifically, for tight oil reservoirs employing large-volume fracturing technology, which introduces variations in fluid storage space, this paper improves the mass balance method and innovatively develops a formation pressure calculation method applicable to large-volume fracturing with variable volume. This method fully considers the impact of volume variations during fracturing.

[0027] Furthermore, the well test method for determining formation pressure in tight oil reservoirs, combined with the characteristics of fracturing technology for tight oil and shale oil, designs a process flow. By recording and calculating the pressure at different stages of fracturing, well shut-in, blowout, and well recovery, the reservoir formation pressure is obtained through calculation and analysis, solving the problem that conventional well test analysis techniques cannot obtain the formation pressure of tight oil reservoirs.

[0028] Furthermore, "shutting down the well" refers to the process of shutting down the well after the steam injection is completed, allowing the heat of the steam to fully exchange with the formation.

[0029] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes measuring the wellbore pressure recovery data after perforation and obtaining the wellbore static pressure value P. j1 Formation permeability and formation energy value.

[0030] Specifically, perforation is an operation that uses special shaped charge equipment to enter a predetermined layer in the wellbore to create an explosive opening, allowing fluid from the formation to enter the hole. It is commonly used in oil and gas fields and coalfields, and sometimes also in water extraction.

[0031] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes using hydraulic fracturing to measure pressure data and the total fracturing fluid volume N during fracturing and well shut-in processes. Z And the formation recovery pressure P1 after well closure. The steps for calculating the formation pressure of tight oil reservoirs also include measuring the volume factor of shale oil under the formation pressure of P1. The unit of the shale oil volume factor is m³. 3 / sm 3 The steps for calculating the formation pressure of a tight oil reservoir also include measuring the volume factor of the fracturing fluid under a formation pressure of P1. The unit of the volume factor of the fracturing fluid is m³. 3 / sm 3 .

[0032] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes obtaining the fracturing area S using well pressure drop data. RV , Modify volume V SRV The average effective permeability K and flow coefficient Kh / μ of the modified area were used to calculate the original formation pressure P of the shale oil. i1 Estimate N O1 N O1 The oil reserves m under surface conditions 3 .

[0033] Specifically, the modified volume V is obtained by analyzing the pump shutdown pressure drop data. SRV Area S to be renovated SRV The average formation pressure P within the modification area srv The average effective permeability K and flow coefficient Kh / μ of the modification area. Based on the modification volume V. SRV Area S to be renovated SRV The average formation pressure P within the modification area srv The average effective permeability K and flow coefficient Kh / μ of the modified area can be used to preliminarily fit and calculate the original formation pressure P of the shale oil. i1 Estimate N O1 N O1 m is the reserve of tight oil under surface conditions. 3 .

[0034] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes opening the well and releasing the blowout, measuring the flowing pressure and production data, and calculating the total production volume Q. t Q t = + ,in, - Production water volume (m³) 3 , -Oil production volume (m) 3 .

[0035] In some optional embodiments, the step of calculating the formation pressure of the tight oil reservoir further includes, when the well production pressure reaches the boundary of the stirred zone, the flow enters a quasi-steady flow phase, and the liquid volume V within the stirred zone can be calculated using the quasi-steady flow pressure equation for the boundary-controlled flow phase. t Estimate N O2 N O2 The oil reserves m under surface conditions 3 .

[0036] In some optional embodiments, the step of calculating the formation pressure of a tight oil reservoir further includes measuring the stable formation recovery pressure P2 after well shut-in and the water volume factor under the formation pressure of P2. The compressibility coefficient of fracturing fluid under formation pressure P2 .

[0037] In some optional embodiments, the calculation of tight oil reservoir reserves N o The equation is: in, --Cumulative water production (m) 3 ; --The volume factor of water under formation pressure P2, m 3 / sm 3 ; --Cumulative oil production in m 3 ; --The volume factor of oil under formation pressure P2, m 3 / sm 3 ; -- is the fracturing fluid volume in m 3 ; --The volume factor of the fracturing fluid under formation pressure P1, m 3 / sm 3 --Compressibility coefficient of fracturing fluid under formation pressure P2, 1 / MPa; --Formation pressure drop, MPa; -- represents the shale oil reserves under surface conditions (m). 3 --The volume factor of oil under formation pressure P1, m 3 / sm 3 ; S O —Oil saturation%; S wi —Bound water saturation%; --Volume of bound water expanding (m) 3 ; -- Rock pore shrinkage volume (m) 3 It includes the increased porosity resulting from the modification.

[0038] In some optional embodiments, the increase in formation pressure ΔP2 during fracturing is calculated using the following formula:

[0039] Where: △P2 -- formation pressure rise, MPa; B0 -- original formation pressure volume coefficient, m 3 / sm 3 ; -- is the fracturing fluid volume in m 3 ; --The volume factor of the fracturing fluid under formation pressure P1, m 3 / sm 3 ; -- represents the shale oil reserves under surface conditions (m). 3 .

[0040] In some optional embodiments, the original formation pressure P of the shale oil well is estimated. i , P i =P1-△P2, that is, P i Equals P1 minus ΔP2. Estimate the original formation pressure P. i The initial formation pressure P of shale oil was obtained through fitting and analysis. i1 Less than the preset error range.

[0041] It will be apparent to those skilled in the art that the present invention is not limited to the details of the exemplary embodiments described above, and that the invention can be implemented in other specific forms without departing from its spirit or essential characteristics. Therefore, the embodiments should be considered in all respects as exemplary and non-limiting, and the scope of the invention is defined by the appended claims rather than the foregoing description. Thus, all variations falling within the meaning and scope of equivalents of the claims are intended to be included within the present invention. No reference numerals in the claims should be construed as limiting the scope of the claims.

[0042] Furthermore, it should be understood that although this specification describes embodiments, not every embodiment contains only one independent technical solution. This narrative style is merely for clarity. Those skilled in the art should consider the specification as a whole, and the technical solutions in each embodiment can also be appropriately combined to form other embodiments that can be understood by those skilled in the art.

Claims

1. A well test method for determining formation pressure in tight oil reservoirs, characterized in that, The original reserves of tight oil reservoirs are calculated by using the static pressure and production values ​​measured during well shut-in, blowout, and well recovery. Under the condition of obtaining the original reserves of tight oil reservoirs, the pressure increase of the formation during the fracturing process is calculated by using fracturing and well shut-in. The formation pressure of tight oil reservoirs is calculated using the static pressure value and pressure increase value measured in the slack well. The step of calculating the formation pressure of tight oil reservoirs also includes using hydraulic fracturing to measure pressure data and the total fracturing fluid usage N during fracturing and well shut-in processes. Z And the formation recovery pressure P1 after well closure; The step of calculating the formation pressure of tight oil reservoirs also includes measuring the stable formation recovery pressure P2 after well shut-in and the water volume factor under the formation pressure of P2. The compressibility coefficient of fracturing fluid under formation pressure P2 ; calculate The calculation The equation is: in, --Cumulative water production (m) 3 ; --The volume factor of water under formation pressure P2, m 3 / sm 3 ; --Cumulative oil production in m 3 ; --The volume factor of oil under formation pressure P2, m 3 / sm 3 ; -- is the fracturing fluid volume in m 3 ; --The volume factor of the fracturing fluid under formation pressure P1, m 3 / sm 3 ; --Compressibility coefficient of fracturing fluid under formation pressure P2, 1 / MPa; --Formation pressure drop, MPa; -- represents the oil reserves under surface conditions (m) 3 N O2 For N O1 and N O2 The average value; --The volume factor of oil under formation pressure P1, m 3 / sm 3 ; S O --Oil saturation% S wi --Bound water saturation%% --Volume of bound water expansion, m 3 ; -- Rock pore shrinkage volume, m 3 This includes the increased porosity resulting from the modification; The formula for calculating the pressure increase ΔP2 during fracturing is as follows: In the formula: △P2 -- Formation pressure rise, MPa; B0 represents the original formation pressure volume coefficient, in m 3 / sm 3 ; Estimate the original formation pressure Pi of tight oil wells. P i =P1-△P2 Estimate the original formation pressure P i The initial formation pressure P of the tight oil was obtained through fitting. i1 Less than the preset error range.

2. The well test method for determining formation pressure in tight oil reservoirs according to claim 1, characterized in that, The step of calculating the formation pressure of tight oil reservoirs also includes measuring the wellbore pressure recovery data after perforation and obtaining the wellbore static pressure value P. j1 Formation permeability and formation energy value.

3. The well test method for determining formation pressure in tight oil reservoirs according to claim 1, characterized in that, The step of calculating the formation pressure of tight oil reservoirs also includes obtaining the fracturing area S using well pressure drop data. RV , Modify volume V SRV The average effective permeability K and flow coefficient Kh / μ within the modification area were used to calculate and obtain the original formation pressure P of the tight oil. i1 Estimate N O1 N O1 For the reserves of tight oil under surface conditions, m 3 .

4. The well test method for determining formation pressure in tight oil reservoirs according to claim 1, characterized in that, The steps for calculating the formation pressure of tight oil reservoirs also include well opening and venting, measuring flowing pressure and production data, and calculating the total production volume Q. t Q t = + ,in, —Cumulative water production, m 3 , —Cumulative oil production, m 3 .

5. The well test method for determining formation pressure in tight oil reservoirs according to claim 4, characterized in that, The step of calculating the formation pressure of tight oil reservoirs also includes, when the well production pressure reaches the boundary of the stimulation range, the flow enters the quasi-steady flow section, and the liquid volume V within the stimulation range is calculated using the quasi-steady flow pressure equation for the boundary control flow stage. t Estimate N O2 N O2 For the reserves of tight oil under surface conditions, m 3 .

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