Numerical simulation of lower Triassic gas cap reservoir in Akkule oil and gas field

(Planning Institute of Northwest Petroleum Bureau of Urumqi 8300 1 1)

Akkule oil and gas field is one of the earliest oil and gas fields put into development in northern Tarim. By studying the single well model and three-dimensional well group model, the sensitivity analysis of the production mechanism and influencing factors in the production process of this oil and gas field is carried out by using the reservoir numerical simulation method, and the reasonable oil recovery rate, perforation position, perforation degree, water injection timing and injection-production ratio are determined.

Numerical simulation; Bottom water coning development; Limit output

1 Overview of oil and gas fields

Akkule oil and gas field encountered industrial oil and gas flow in Ordovician and Triassic, and Triassic is the main oil and gas producing series. There are two groups of oil-producing intervals revealed by Triassic oil and gas reservoirs: the first sand body of Upper Triassic Halahatang Formation and the first sand body of Akkule Formation; In the division of oil and gas groups, they are called Upper Oil Group (T-Ⅰ) and Lower Oil Group (T-Ⅲ). The sand body of Lower Oil Formation (T-Ⅲ) is 95 ~ 165 m thick and stably distributed in the plane, which is the main producing layer of this oil and gas field.

The properties of crude oil in each block of Lower Oil Formation (T-III) are quite different. The test and production test data show that the areas Ⅳ, Ⅴ and ⅶ have gas caps, thick bottom water and sufficient energy supply, which are saturated reservoirs with sandstone porous elastic bottom water drive. Ⅰ, Ⅱ, Ⅲ, ⅵ and ⅷ are sandstone porous elastic bottom water drive unsaturated reservoirs.

Since 1992 Akkule oil and gas field entered the stage of rolling development, bottom water coning has become the main problem in development. At present, the recovery rate of Lower Oil Formation (T-III) is 38%, and the comprehensive water cut is 85%.

Study on numerical simulation of reservoir 2

2. 1 single well model-research on production mechanism

The single well model is mainly used for the study of gas-water coning. In order to make the calculation results more universal, the prototype of single well model is abstracted, and the specific treatment methods are as follows:

(1) In logging interpretation, the thickness of oil, gas and water layers remains unchanged.

(2) According to the logging interpretation results, vertically divide the homogeneous sections with different thicknesses, and read the physical parameters of each section.

(3) On this basis, appropriate merging or splitting is carried out to form a longitudinal grid with a thickness of about1m.. The principle of merging or splitting is that the grid thickness near the fluid interface should not exceed 1m, and the grid thickness should be appropriately increased at the position far from the fluid interface.

(4) The control radius of a single well is 550m, which is divided into 20 grids along the radial direction, and the grid size increases geometrically. The innermost grid size is about 0.2m, and the outermost grid size is 100 ~ 150 m. ..

(5) According to the above grid division, the grid of oil-gas-water model is 20×20, including 8 gas layers, 9 oil layers and 3 water layers.

(6) The physical parameters are transformed into underground effective values, and each layer is given a grid.

(7) Adjust the layer with low permeability in the prototype to make the permeability not lower than 30× 10-3μm2.

In the simulation calculation, the vertical and horizontal permeability ratio of oil layer is 0.2; For the layer with low permeability interlayer, the ratio of vertical permeability to lateral permeability is 0.015 ~ 0.087; The ratio of vertical and horizontal permeability of water layer is 0. 1.

2.2 Limit production of bottom water coning and water coning

The example results show that the recovery ratio of T-Ⅲ oil formation is very low by solution gas flooding, but the ultimate recovery ratio can be improved by water flooding. Large water body is beneficial to the development effect of depletion mining. For a certain scale of water body, the conductivity between water body and oil layer generally has little influence on pressure transmission, but it has great influence on the flow between water layer and oil layer. Therefore, the low vertical conductivity is beneficial to improve the development effect of oil layer, but when the vertical conductivity is too low and the pressure transmission is difficult, the situation of dissolved gas drive will be formed in oil layer, which will reduce the development effect.

In the model, the oil well has a fixed production of 55t/d. Through the calculation of development index, according to the distribution of water saturation in each time step on the profile, it can be concluded that the rising process of formation bottom water can be roughly divided into four stages: coning stage, advancing stage, coning stage and water-bearing stage. Within 37 d, bottom water coning, with the increase of oil recovery, the oil-water interface far away from the well shaft slowly rises, and then the oil-water interface rises to the advancing stage, which is 142d. When the production reaches 240d, bottom water coning into the bottom of the well makes the oil well contain water and enters the coning stage, with the coning height on the well shaft of 5m and the coning stage of 6 1d, and then enters the water-cut stage.

When the output reaches 85t/d, the bottom water conically enters the bottom of the well within 60 d, and there is no obvious lifting period. Therefore, under the current perforation conditions of the model, the limit production of water cone is about 85t/d.

2.3 Selection of perforation position of oil well

For sandstone reservoirs with bottom water, the bottom boundary of perforation should be higher than the oil-water interface, so as to prevent bottom water from rapidly injecting into the oil well after the oil well is put into production, shorten the waterless oil production period and reduce the waterless oil production. Water-free production period is usually calculated according to the following formula:

Essays on exploration and development of oil and gas fields in northern Tarim basin

Where: t—— waterless oil production period (d);

HP-hydrophobic thickness (m);

△p—— production pressure difference (MPa);

μ o-viscosity of underground crude oil (MPa s);

φ —— Porosity (%);

K- formation permeability (10-3 μ m2);

KH- formation horizontal permeability (10-3um2);

Kv-vertical permeability of formation (10-3μm2).

As can be seen from the above formula, the two parameters that can be manually controlled are hydrophobic thickness and production pressure difference. The influence of hydrophobic thickness on waterless oil production period is greater than the production pressure difference, because the waterless oil production period in the formula is proportional to the square of hydrophobic thickness.

In the simulation calculation of perforation scheme, the development effects of four perforation positions are calculated. In each scheme, the drilling degree of the oil well is 30% and the fixed output is 55 t/d, and the main calculation indexes are shown in Table 1.

Table 1 Development Index Table of Different Perforation Parts 1 Development Quotation of Different Perforation Parts

According to the relationship between water cut and recovery degree, the closer the perforation position is to the oil-water interface, the higher the water cut is at the same recovery degree. When the recovery ratio is greater than 28%, with the extension of production time, the development effect of scheme A2 is better than that of A 1, that is, when the water cut of the oil well is less than 35%, the bottom water effect is the main factor. By comparing the recovery rates of four perforation schemes under different production conditions, it can be seen that the ultimate recovery rate of scheme A2 is obviously higher than other schemes, and the formation pressure is maintained to a higher degree after 10 years of production.

2.4 opening sensitivity calculation

In order to optimize the opening of oil well, the thickness of oil layer is 12m, the opening is 20% ~ 50%, and the oil well is produced at a constant output of 55t/d, and four schemes are calculated. See Table 2 for the comparison of development indicators of each scheme.

Table 2 Development Indicators with Different Openness (t = 10a) Table 2 Development Bidding with Different Perfection (t = 10a)

It can be seen from the calculation results that with the increase of opening, the water content and cumulative water production increase, the waterless period shortens, and the cumulative gas production and recovery degree decrease. Therefore, in the process of exploitation, the opening of oil well should be properly controlled to prevent the bottom water from coning and delay the water breakthrough time.

In order to find a reasonable opening, the relationship between production pressure difference and opening is calculated. Under certain production conditions, with the decrease of opening, the production pressure difference increases, especially when the opening is 20% ~ 30%, the production pressure difference changes greatly. Because of the low opening of the oil well, the bottom hole may be imperfect and the wellbore resistance is large, a large production pressure difference is needed to meet the production requirements. The comparison results show that when the opening of the oil well is 20%, the perforation section is far from the bottom water, and its water-free period is the longest, and the recovery rate is the highest within 10 years of development. When the opening is 50%, the water-free period of the oil well is shortened by one third and the oil recovery is reduced by about 3%, so the optimal opening of the oil well should be controlled between 20% and 30%.

2.5 Determination of reasonable oil recovery rate

In the study of oil recovery rate, the supply radius of a single well is 400m, the perforation scheme is the aforementioned B2 scheme, and the designed oil recovery rate is 1.3% ~ 2.8%. Six schemes are calculated. The calculation results are shown in Table 3, Table 4 and Table 5.

Table 3 Calculation of oil production speed sensitivity Table 3 Sensitivity analysis of different oil production speeds

Table 4 Relationship between oil recovery and water cut at different oil recovery rates Table 4 Relationship between oil recovery and water cut at different oil recovery rates

Table 5 Pressure changes at different oil recovery rates

The calculation results show that for bottom water reservoir, when the oil production rate is low, the pressure difference required for production is small, and then the bottom water rises gently, and the development effect is good. The higher the oil recovery rate, the faster the water cut increases with the cumulative oil production. When the oil recovery rate is 1.6% ~ 1.9%, the water cut changes greatly. When the oil recovery rate is v when =1.6%, the water-free recovery rate can reach 3.2%. When the oil recovery is 20%, the water cut of the oil well is only 3.4%. When the oil production rate is 1.3% ~ 1.6%, the formation pressure decreases slowly, and the flowing production can last for nearly 10 years. When the oil recovery rate is 1.9%, the pressure drops rapidly and the flow period is shortened to 8 years. When the oil recovery rate exceeds 2%, the flow period is 3 ~ 6 years.

Comprehensive analysis shows that the crude oil recovery ratio is less than 1.9%, and a higher ultimate recovery ratio can be obtained. For Akkule Oilfield, it is appropriate to control the oil production rate at 1.6%, so that the pressure difference can be controlled below 3.0MPa and the single well output can be 60t/do.

2.6 Interlayer influence

The study of interlayer mainly considers two factors: one is the number of interlayer, and the other is the length of interlayer. In the simulation scheme, there are three situations between the designed oil layer and the water layer, 1 and no interlayer. Interlayer length is designed to be 0, 25, 100, 200 and 350m, with the same width. The permeability between oil layer and water layer is less than 5× 10-3μm2.

The calculation results show that if the interlayer length is the same, the number of interlayers has little effect on the development index. When the interlayer length is more than 200m, the interlayer has obvious influence on water cut and crude oil recovery.

Research on mining mode of three-dimensional well group unit model

The three-dimensional well group model assumes that nine Faber wells are used in T-Ⅲ oil group. Due to the symmetry of streamline, only the 1/4 element with nine normal areas is selected in the simulation calculation. The model adopts equally spaced grids, with the number of grids in the X direction of 12, the well spacing of 800m, the number of grids in the δ x direction of 88.9 m, the well spacing of 600 m, and the δ y of 100 m. It is vertically divided into 10 layers, including 3 layers of gas cap, 5 layers of oil reservoir and 2 layers of bottom water. The total number of grids in the model is 1080.

3. 1 bottom water energy analysis

In the model calculation, the oil well is designed to produce with natural energy under different water-oil volume ratios. By fitting the measured pressure, it is considered that the oil-water volume ratio of T-III reservoir in Akel Oilfield is greater than 150, and the water body with 170 times is selected for simulation in the later stage.

3.2 Water injection timing

Three schemes are studied and calculated for water injection timing, and the injection-production ratio is 0.8. Scheme D 1 is depletion mining, scheme D2 is designed to start water injection after the fifth year of production, scheme D3 is designed to start water injection after the fifth year of production, and the water injection scheme adopts reservoir water injection.

From the calculation results of three schemes, it can be seen that the timing of water injection has great influence on the ultimate oil recovery. After the fifth year of natural energy exploitation, when the total formation pressure drops to 3MPa, water injection will reach the highest oil production. Due to the pressure supplement measures taken earlier in oil and gas reservoirs, the occurrence of formation degassing in saturated oil and gas reservoirs is slowed down and its cumulative gas production is the least. At the same time, the relationship between recovery degree and water content also reflects that the comprehensive water content of D2 scheme is the lowest under the same recovery degree. Therefore, for saturated reservoirs, early water injection and maintaining a certain formation pressure will achieve good development results. 3.3 Sensitivity calculation of injection-production ratio

In order to study the injection-production ratio, four schemes were calculated, in which water injection began in the fifth year after production, and the results are shown in Table 6. The calculation results of four schemes show that when the injection-production ratio is greater than 0.8, the formation pressure can be kept high, and the recovery degree is the highest when the water cut reaches 75%. If the injection-production ratio is 1, the bottom water may be activated, which will lead to the increase of water cut in the oil well and stop injection prematurely. Therefore, the injection-production ratio of T-Ⅲ reservoir in Akol Oilfield should reach 0.8 in the future, so as to achieve good results.

Table 6 Formation pressure changes with different injection-production ratios Table 6 Development plans with different perfection levels

4 conclusion

(1) The limit production of water cone in Lower Triassic Formation (T-Ⅲ) in Akkule oil and gas field is 85t/d.

(2) The perforation position of the oil well should be in the middle of the oil layer, and the optimal opening is 20% ~ 30%.

(3) The injection-production ratio of oilfield water injection development is 0.8, and water injection will be implemented after 5 years of development.

refer to

Chen Yueming. Fundamentals of reservoir numerical simulation. Beijing: Petroleum University Press, 1994.

Numerical Simulation of Lower Triassic (T-Ⅲ) Formation in Akkule Oil and Gas Field

Yang

Planning and Design Institute of Northwest Petroleum Geology Bureau? rümqi 8300 1 1)

Abstract: Based on the study of single well and multi-well models by reservoir simulation method, the sensitivity of development theory and influencing factors to development is analyzed, and the reasonable development speed, development performance, development speed, water injection time and water injection quantity are determined.

Keywords: numerical simulation of critical yield of bottom water coning