Some standard content:
ICS 75.180. 94
Registration No.: 10470--2002
Standards of the People's Republic of China for the petroleum and natural gas industry
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SY/T 6533-2002
Testing and interpretation methodfor systematic well testing
2002-05-28 Issued
State Economic and Trade Commission
2002-08-01 Implementation
2 Normative reference documents
3 Stability test test method
4 Requirements for obtaining data from stability test
5 Stability test data collation
6 Qualitative interpretation method of stability test data
7 Quantitative interpretation method of indicator curve of oil production well in single-phase flow stability test 8 Quantitative interpretation method of rising hill line in oil and gas two-phase flow stability test Excerpt A (Normative Appendix) Symbols and Notes
SY/T 6533—2002
SY/T 6533—2002
Stability test, also known as system test or back pressure test, is a commonly used off-site test method for oil and gas production or water injection. Stability test is to establish the production capacity or injection capacity equation, so the measured stability test results are important basic data for optimizing oil and gas production wells and injection operation system. This standard specifies the stability test methods and data interpretation methods for oil production and water injection to regulate this aspect.
Appendix A of this standard is a normative appendix.
This standard is proposed and coordinated by the Oil and Gas Field Development Professional Standardization Committee. The unit of this standard: Exploration and Development Research Institute of North China Oilfield Branch of China National Petroleum Corporation. The main drafters of this standard: Zhu Yadong, Zhang Hui, Yu Jieming. This standard is published for the first time.
1 Scope
Stability well test and interpretation methods
SY/T 6533—2002
This standard specifies the test force method and test result data interpretation method for oil production wells and water injection wells: This standard applies to the stability test of oil production wells and water injection wells, the requirements for on-site porcelain material sampling and data interpretation methods. 2 Normative references
The clauses of the following documents become the clauses of this standard through reference in this standard. For all dated referenced documents, all subsequent amendments (excluding errata) or revisions are not applicable to this standard. However, the parties to the agreement based on this standard are encouraged to study whether the latest versions of these documents can be used. For all undated referenced documents, the latest versions Applicable to this standard. SY/T5387 Technical requirements for geological production of conventional crude oil reservoirsSY/T5968 Quality assessment method for oil test and production dataSY/T6013 Specification for the admission of conventional oil test dataSY/T6221 Technical requirements for the design of monitoring system and dynamic monitoring of oil well development3 Stable well test test method
3.1 Stable well test principlewww.bzxz.net
Stable well test is to predict the production capacity and injection capacity of the harmonic layer through the prescribed test and analysis and interpretation procedures. The relationship between the stable flow rate and the pressure difference in this capacity is expressed.
3.2 Stable well test test method
3.2.1 Determine the work system| |tt||The standard stipulates that the surface flow rate and the corresponding stable bottom pressure need to be measured under 4 or more different working systems, the indication curve needs to be drawn, the indication mountain line type needs to be determined, the production capacity equation needs to be established, and the working system and the distribution of measuring points need to be determined according to the stable test design. The bottom hole pressure and production data of 4 to 5 measuring points should be obtained for each working system, and the distribution should be uniform.
3.2.2 Test procedure
Before the test, the stable formation pressure should be measured first; the working system should be changed from small to large flow, and the stable production, flow pressure and other related data should be measured; after the last working system test, the formation pressure or pressure recovery should be measured, 3. 3 The test method of water injection and full well visual indication curve adopts the pressure reduction method. Before the test, the water injection volume should be released at the highest pressure for 8 hours. The water injection volume at the first point should be selected, and the working system should be changed to measure the remaining points. It is necessary to measure 4 or more working systems. Each working system should reach the stability of the injection volume and the parallel port pressure.
3.4 The test method requirements for the stratified visual indication curve of the water injection well are the same as those for measuring the full rise visual indication curve, but it is necessary to calculate and verify the stratified water injection volume according to the different downhole water distribution pipes.
4 Requirements for obtaining data from stable well testing
4.1 Requirements for obtaining data from stable well testing of oil production wells1
SY/T 6533—2002
Exploration and test wells
For exploration and test wells with production capacity, stable test data should be obtained during the oil test and test production period. The requirements for data collection shall be implemented in accordance with SY/T5387, SY/T5968 and SY/T6013. 4.1.2 Oil production wells
After production is put into production according to the development plan, stable test can be carried out according to the production situation and the results of development dynamic analysis. The requirements for data collection shall be implemented in accordance with SY/T6221.
4.2 Requirements for data collection of stable test of water injection wells
In the initial stage of injection, each water injection well should be tested once for the visual indication curve of the whole well or layer. Later, the visual indication curve test of the whole well or layer should be arranged according to the needs. The requirements for data collection shall be implemented in accordance with SY/T6221. 5.1 Stable well test curves
Stable well test data should be sorted out into the following curves: production pool and indication curve: production pressure difference and production curve: production well system test curve: production, flow pressure, water content, production gas-oil ratio and other working system curves; flow dynamic curve (IPR curve): flow pressure and production curve: - water injection and full and layered indication curve or visual indication mountain line. 5.2 Treatment of formation pressure when continuing to make test and typical curves When the difference between the two formation pressures P1 and Pk measured before and after the stable well test is within the pressure measurement error range, the formation pressure in all working systems can take the same formation pressure value. When the difference between PB1 and PR exceeds the pressure measurement error range, except for the first working system taking R1 value and the last working system taking Pk value, the formation pressure of the remaining working systems is determined by formula (1): Ni- Ne(pri - prn)
PR = PR- Np-Nl
i = 1,2,-.,n
5.3 Oil well indication curve
Oil well indication curves are divided into the following four categories: linear type (see Figure 1 curve 1), curve type (see Figure 1 curve IⅡ), mixed type (see Figure 1 curve III) and abnormal type (see Figure 1 curve IV). The above indication curves can be used to analyze the flow conditions of oil wells. Production, /d
Figure 1 Type of oil well indication curves
5.4 Oil well system test curve
A typical oil well system test curve is shown in Figure 2, which can be used to determine the reasonable working system of the oil well. 2
5.5 Oil well inflow dynamic curve [EPR curve] Working system (oil diameter,)
Figure 2 System well test curve
Production well
Water content
Water content ratio
Gas-oil ratio
SY/T 6533—2002
Bottom hole flowing pressure
Figure 3 is a schematic diagram of the oil well inflow dynamic curve under different formation pressure conditions, which can be used for oil production and capacity prediction. IPR(P.)
IPR(p2)
Production, five*/d
Figure 3 Predicted IPR curves for different formation pressures 5.6 Injection well indication curve
5.5.1 Injection well true indication curve
If the stable flow pressure of the injection well is measured under each working system, the injection well indication curve can be made like the above-mentioned oil production well, which is called the true indication curve.
The injection flow pressure of the water absorbing layer can also be obtained by considering the water column pressure, pipe loss, nozzle loss, etc. through the wellhead pressure, so as to make the injection well true indication curve without measuring the flow pressure, 5.6.2 Visual Indicator Curve of Water Injection Wells
If the bottom flow pressure of the water injection well is not measured under each working system, and only the parallel port pressure and the corresponding injection volume are measured, the visual indicator curve of water injection wells can be made:
The visual indicator curve of the whole well of the water injection well is usually divided into the first line type and the broken line type. The layered visual indicator curve is divided into the self-line type, the broken line type and the vertical type (see Figure 4, Figure 5, Figure 6). When using the indicator curve to analyze the water absorption capacity and judge the working condition of the parallel tool, it is necessary to put the indicator curves of the same parallel layer at different times on the 3-graph for comparative analysis. Mercury, m*/d
Figure 4 Linear indicator curve
6 Qualitative interpretation method of stable well test material
6.1 Indicator curve of oil production well
6.1.1 Linear
Ice injection amount, \/d
Figure 5 Broken line indicator curve
Water grass, d
Figure 6 Vertical indicator curve
Characteristic is a straight line passing through the origin (see curve I in Figure 1), which is generally formed by single-phase seepage under small production pressure difference conditions. 6.1.2 Curve type
Characteristic is a curve convex to the production axis through the origin (see curve II in Figure 1). This type of line generally reflects the flow characteristics of single-phase non-Darcy or oil and gas two-cabinet seepage, which is formed when the production pressure difference is large or the flow pressure is less than the saturation pressure. 6.1.3 Mixed type
is characterized by a straight line passing through the origin first, followed by a curve convex to the production axis (see curve III in Figure 1). The straight line part is single-phase Darcy seepage, and the curve part includes single-phase and non-Darcy seepage and oil-gas two-phase seepage. 6.1.4 Abnormal type
is characterized by a line passing through the origin and convex to the pressure axis (see curve in Figure 1). The reasons for this type of curve include the test work system not reaching stability, the gradual decrease of wellbore pollution in the new well during the test, and the new layers being put into production as the production pressure difference increases. Therefore, abnormal curves do not necessarily not exist. They should be analyzed in detail according to the actual situation. If the test is not stable, they should be retested: 6.2 Water injection well full well visual indication curve
6.2.1 Straight type
is characterized by a straight line with a slope greater than zero, which does not necessarily pass through the origin: It reflects the situation that a certain permeable layer accounts for a large proportion or a single layer is the main water-absorbing layer. When the permeability is high, the straight line is close to the injection volume axis; on the contrary, it is close to the wellhead pressure axis. 6.2.2 Broken line type
The broken line (downward) type reflects that after the injection pressure increases to a certain extent, the injection volume and water absorption index increase with the pressure. The reasons include: the increase in the number of water absorption layers, the injection pressure of some water absorption layers reaches the fracture pressure of the layer, and the heterogeneity of the water absorption layer. The broken line (upward) type reflects the increase in formation blockage, the reduction of water absorption layers or the decrease in the permeability of the water absorption layer. 6.3 Water injection well stratification visual indication curve
6.3.1 Straight line type
Reflects that the formation water absorption is linearly related to the injection pressure (see Figure 4). This situation often occurs when there are few water-absorbing layers in the layer section and the injection pressure is less than the fracture pressure:
6.3.2 Broken line (downward) type
reflects that the injection pressure has increased to a certain value, the water absorption capacity of the oil layer has begun to increase, or a new water-absorbing layer has been added to the injection layer section (see line 4
Figure 5)
6.3.3 Broken line (upward) type
SY/T 6533—2002
Occurs when the nozzle diameter is small and the oil layer has strong water absorption capacity (see curve " in Figure 5). The reason is that the positive force of water injection increases, which increases the nozzle loss, resulting in a slow increase in water injection volume. 6.3.4 Vertical type
When the oil layer has strong water absorption capacity and the nozzle diameter is small (not more than 2nm), it is easy to measure this type of visual indication curve (see Figure 6). This type of visual indication curve reflects that with the increase of water injection pressure, the nozzle loss also increases accordingly. However, the water injection volume does not change much. 7 Single-phase flow stable test and oil production and indication curve positioning interpretation method 7.1 Straight line indication curve
For the straight line part of the straight line indication curve or the mixed platform indication curve, the oil production index " can be calculated. , layer permeability K and calculated formation pressure
7.1.1 Oil production index
Take any test point (.,) on the straight line, then, is J, = 4p
7.1.2 Reservoir Port Permeability
Using the obtained oil production index. , the average reservoir permeability K can be obtained from the pseudo-steady-state flow equation: K
1.842 B[1n()- 3 + S
For partially drilled block reservoirs, the oil production index J is used. When calculating the average reservoir permeability, the impact of imperfect drilling on production should be considered. In this case, the following Muskat formula can be used to calculate the average reservoir permeability: JoBG
K=0.0864h
嘉(Ci - C2)-h(
Ci- in
C2 yuanIn
7.1.3 Formation pressure
0.875hg+4
\+(0.875h,)4
+(0.125h.)3
1-0.875he)
(t - 0.125 )
Extrapolate the straight line part of the indication curve to 2, = 0 to obtain the pw, which is the formation pressure pR. 7.2 Curve-type indication curve
For the Shanzang fluid as a single-phase non-two-phase seepage, the curve-type indication curve can be expressed by the binomial: (4)
App -- aq + b?
This can calculate the oil layer permeability K, non-Darcy flow coefficient L), flow coefficient β and the production g under any flow pressure pw.n7.2,1 Oil layer permeability
7.2.2 Non-Darcy flow coefficient
D) = 6Kh /(1.842Bz)
SY/T6533—2002
7.2.3 End flow coefficient [or turbulence coefficient]
7.2.4 Production under any flow pressure P9c
7.80 × 10-11 F3 g
Va -4b(pR - pu)
The condition of this formula is that the formation pressure r remains unchanged during the test period. If P- is the minimum white spray pressure of the oil, then formula (12) can be used to calculate the maximum self-flowing production of the oil.
7.3 Mixed indicator curve
can be decomposed into two parts, linear and curved, to solve and combine with formation parameters: 8 Quantitative interpretation method of oil and gas two-phase flow stable well test curve 8.1 Stable well test interpretation under the condition that the ground pressure is lower than the saturation pressure 8.1.1 Vogel equation
When the reservoir fluid is oil and gas two-phase, the Vogel equation can be used to organize the stable test data. The Vogel equation is: =1-0.2
The curve represented by formula (13) is also called PR curve, that is, the flow dynamic curve, which can be used to calculate the oil production base 403 under any flow pressure Pi
8.1.2 Felkovich equation This equation is similar to the exponential equation of gas wells, and its expression is: = J(- t)n
This equation can also calculate the production under any flow pressure. 8.2. Interpretation of stable well test under the condition that the flow pressure is lower than the saturation pressure and the formation pressure is higher than the saturation pressure. At this time, the Vogel equation is rewritten as:
qu = Qb / (qo,max - Qb)
And Qb,9o,mac can be calculated by the following formula:
qb = J(Pr - pb)
9u. max = 5 +
The " in formula (16) is still the oil recovery index, and the calculation formula is J=a4(pR p0)+[1-02()-08(
· (17)
Appendix A
(Normative Appendix]
Symbol Notes
Coefficient of binomial capacity equation, MPa/(rnr/d); Coefficient of binomial capacity equation [see formula (8)], MPa/(m/d)?-Crude oil formation volume coefficient, m/m;
Total effective compressibility coefficient of the system. MPaI
-Non-Darcy flow coefficient, (m3/d)-2: Shape coefficient, see formula (5);
h—Effective thickness of reservoir , m;
Thickness of the first drilling, m;
Oil recovery index, mr/(d-MPa);
-Coefficient of Fetkovich equation, (tn2/d)/(MPa)zn; K—Effective permeability, 10-\μum3;
Cumulative production at the end of the first working system, m2 or t; Index of Fetkovich equation;
Pressure, MPa;
Saturation pressure, MPa;
Formation pressure, MPa:
Flowing pressure, MPa
Production pressure difference, MPa;
Ap=p-pwf
-Oil well production, m2/d:
Supply radius, m;
-Oil well conversion radius, m;
S—Skin coefficient;
-Vasocsity of formation crude oil, mPa\s;
-Density of formation crude oil, t/m2;
Effective porosity,
SY/T 65332002
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