Yang Yong et al.: Practice and understanding of pressure flooding development technology for low permeability reservoirs in Shengli Oilfield
abstract
The low permeability reservoirs in Shengli Oilfield are rich in resources. The geological reserves have been used up to 9.4 × 108 t, the degree of recovery is 13.3%, and the unused reserves are 2.1 × 108 t. There are many problems in improving oil recovery and using efficiency. In order to improve the development effect of low permeability reservoirs, Shengli Oilfield has tackled innovative pressure flooding technology.
Comprehensive application of geology, seepage mechanics and reservoir engineering theories and methods, and the combination of physical simulation and numerical simulation techniques have formed a series of technologies such as pressure flooding reservoir adaptability evaluation standards, indoor experimental technology systems, and reservoir engineering scheme optimization design methods. The technology series is supported by stratified pressure flooding, combined fracture network volume fracturing, and displacement regulation.
Mine tests show that pressure flooding can quickly replenish formation energy and greatly improve oil well productivity and recovery. Since March 2020, 450 well groups have been cumulatively implemented in low-permeability reservoirs, with a cumulative water injection of 1384 × 104m3 and a cumulative oil increase of 55.7 × 104t. Pressure flooding development technology is gradually becoming a leading new development technology for low-permeability reservoirs.
0
Introduction
The low permeability reservoir in Shengli Oilfield has abundant reserves, with 9.4 × 108 t of geological reserves used and 2.1 × 108 t of unused reserves. Due to the limitations of reservoir conditions and engineering technology, its development effect is poor, and the characteristics of low energy and low liquid are prominent [1-3]. The average recovery degree is only 13.3%. The main reason is that the reservoir is difficult to seep, resulting in slow pressure conduction and poor liquid supply. At the same time, the rock pores and throats are narrow, and it is vulnerable to damage, resulting in more significant injection and production problems [4-8]. It is urgent to seek new energy replenishment methods and enhanced oil recovery methods.
In 2017, Daqing Oilfield first proposed a large-volume water injection and throughput technology [9-10]. The main mechanism is to use capillary pressure to absorb and drain oil in hydrophilic reservoirs under the condition of replenishing formation energy, so that the injected water is sucked into the matrix and retained, thereby displacing the crude oil into the high-permeability layer and realizing the redistribution of oil and water. Finally, the crude oil replaced by osmosis is recovered together with the injected water. The application of this technology includes three stages: "injection", "stuffy" and "production".
In the injection stage, a large amount of liquid is injected, and the injection pressure reaches the reservoir fracture pressure. Through the working system of "more injection and less stuffiness", the purpose of "high strength, short period and fast effect" is achieved, and the formation energy of tight oil reservoirs is effectively improved. After 3 years of implementation in the mine, significant oil increase effect and economic benefits have been achieved. Statistics of 83 wells, the cumulative oil increase in the stage is 12.42 × 104 t, the input-output ratio is 1:1.5, and the recovery efficiency is increased by 2.5%.
The pressure-flooding huff and puff test was carried out in 7 wells in the Santanghu Basin, Xinjiang. The average daily oil increase of a single well was 10.3 t/d, and the cumulative oil increase of a single well was 805 t, which achieved good results. The analysis found that the cumulative oil increase of a single well was positively correlated with the water throughput. When the injection pressure reached more than 48 MPa (super-formation fracture pressure), the output increase of a single well exceeded 800 t.
Pressure flooding development technology is to use hydraulic fracturing equipment to inject water, through high pressure (wellhead injection pressure is generally greater than 35 MPa), high speed (single well daily water injection is generally greater than 1 000 m3 /d), to achieve rapid replenishment of reservoir energy in a short time, improve reservoir pressure, and then improve oil well production pressure difference and liquid production, oil production [10-13].
Since March 2020, through indoor evaluation, technical research and pilot tests, a series of technologies such as pressure flooding experimental technology, reservoir engineering optimization design method, pressure flooding process string, dynamic monitoring and regulation have been initially formed [14-17]. The field test of this technology has achieved good results, providing favorable technical support for the effective development of low-permeability reservoirs in Shengli Oilfield.
1
Adaptability Evaluation Criteria for Pressure Displacement Reservoir
In order to determine whether the low permeability reservoir in Shengli Oilfield is suitable for pressure flooding, it is necessary to establish an adaptability evaluation standard for pressure flooding reservoirs.
According to the laboratory experimental research and the summary of mine practice, two key evaluation parameters are determined. The first key evaluation parameter is the lower limit of penetration rate. According to the laboratory experimental research, a fracture area will be formed near the well after water well pressure flooding, and the size of the fracture area is negatively correlated with the penetration rate of the reservoir. The lower the reservoir penetration rate, the larger the fracture area scale. Compared with the matrix area, the oil displacement efficiency and ripple coefficient in the fracture area are reduced (Fig. 1), resulting in a decrease in oil recovery (Fig. 2). The lower limit of penetration rate for pressure flooding is 1.5 mD, corresponding to 15% recovery.
The second key evaluation parameter is the reservoir condition of the block. The technical well spacing can be greatly improved when the fracture zone is formed by pressure flooding and the high pressure drive system is established. While expanding the injection-production well spacing, it is necessary to ensure a high reservoir connectivity ratio to improve the degree of water flooding reserve control. Generally, the reservoir connectivity ratio between oil and water wells is required to reach more than 70%.
In addition, the direction of deposition and the direction of in-situ stress need to be clearly implemented. The propagation direction of pressure-flooding cracks is generally affected by the direction of in-situ stress and the direction of deposition. The design of the pressure-flooding scheme needs to implement the direction of in-situ stress and the direction of deposition. Reasonable avoidance of well pattern deployment can effectively prevent water channeling.
Fig. 1 Histogram of oil displacement efficiency, sweep efficiency, and recovery in fracture and matrix areas
In addition, the application of pressure drive technology also requires complete ground support. The daily water injection volume of pressure drive reaches more than 1,000 square meters, and the water injection volume of single well group reaches 2 × 104~ 4 × 104m3, which has high requirements on the surface water supply capacity. The use of electric drive equipment for pressure drive also needs to ensure that the ground power supply system is complete.
2
Laboratory experiment of pressure drive mechanism
The physical simulation experiment of pressure flooding is an important means to understand the rock breaking mechanism of pressure flooding. Carrying out the physical simulation experiment of pressure flooding under simulated formation conditions can monitor the actual physical process of fracture initiation and expansion, and directly observe the formed cracks.
2.1 Law of increasing permeability of pressure-driven fractures
Samples from Well Fan 121-Yi 80 in Shengli Oilfield were selected to carry out pressure flooding laboratory experimental simulation. The constant overlying pressure of the reservoir was simulated by keeping the confining pressure constant, and the injection pressure change during the field pressure flooding water injection process was simulated by gradually increasing the pore pressure. The difference between the confining pressure and the pore pressure is the net horizontal stress (Figure 3). When the pore pressure exceeds the confining pressure, the net horizontal stress is negative. During the experiment, the confining pressure was 66 MPa and remained unchanged. The initial pore pressure was 60 MPa, the initial net horizontal stress was 6 MPa, and the initial penetration rate was 13.2 mD.
When the pore pressure increases gradually, the net level stress on the reservoir rock gradually decreases, the influence of reservoir stress sensitivity is gradually weakened, and the penetration rate increases slowly. When the net level stress reaches -4 MPa, the penetration rate curve appears an inflection point, and the reservoir rock is slightly damaged. The corresponding pore pressure of 70 MPa is the damage pressure point of the reservoir rock, and the penetration rate of the reservoir rock increases to 29.5 mD.
Continue to increase the pore pressure, when the pore pressure reaches 72 MPa, the net level stress is -6 MPa. At this time, it can be seen from the CT scan image of the sample that cracks are opened around the injection point in the sample, and the crack opening is 56 μm. The corresponding pore pressure of 72 MPa is the fracture pressure point of the reservoir rock, and the penetration rate of the reservoir rock increases to 65.1 mD.
When the net level pressure reaches -7 MPa, the crack opening is further improved, and the crack opening is 185 μm, and the penetration rate of the reservoir rock increases to 160 mD; when the net level pressure reaches -7.5 MPa, the crack opening is 281 μm, and the penetration rate of the reservoir rock increases to 650 mD.
From the above indoor experimental simulation, it can be seen that with the increase of pore pressure during the pressure flooding water injection process, the crack opening increases from tens of microns to hundreds of microns. The purpose of weakening the adverse effects of reservoir stress sensitivity and opening reservoir cracks can be greatly improved by gradually increasing the on-site injection pressure.
Fig. 3 Effect of increasing pore pressure on permeability and fracture openings of pressure driven reservoirs
2.2 Law of enhanced oil recovery by pressure flooding
The high displacement pressure in the process of pressure flooding makes the micro-fracture reformed area around the water injection well, and the area far from the water injection well is still the matrix area because the pressure does not reach the fracture pressure point, and there is no micro-fracture formation. Samples from Well Fan 121-80 in Shengli Oilfield were selected to carry out oil-water relative penetration rate experiments in the matrix area and the micro-fracture area, respectively, to analyze the change law of oil-water seepage capacity and oil displacement efficiency during pressure flooding.
The displacement pressure difference during the low pressure difference relative penetration rate experiment in the substrate area (Fig. 4a) was 0.32 MPa; the displacement pressure difference during the high pressure difference relative penetration rate experiment in the substrate area (Fig. 4b) was 15.2 MPa.
As can be seen from the comparison of Figures 4a and 4b, after the pressure layer in the matrix area doubles during pressure flooding, the final residual oil saturation is reduced from 39.8% to 29.6%, and the oil displacement efficiency is increased by 16.8%; after overcoming the low-speed non-Darcy effect, the water phase seepage capacity is increased from 0.019 1 to 0.190, which is nearly 10 times higher, and the oil well production is greatly increased.
The low pressure drop relative penetration rate experiment in the micro-fracture area (Fig. 4c) adopts the constant pressure method, and the displacement pressure difference during the experiment is 0.32 MPa; it can be seen from the comparison of Fig. 4a and Fig. 4c that after the micro-fracture occurs during the pressure flooding process, the final residual oil saturation in the micro-fracture area is almost unchanged, but the water phase seepage capacity is increased from 0.019 1 to 0.873, which is increased by 45.7 times.
It can be seen from the above indoor experiment simulation that the pressure-driven high-displacement pressure water injection greatly improves the oil displacement efficiency in the matrix area, and at the same time greatly improves the water phase seepage capacity in the fractured area, and the oil well productivity increases significantly.
Fig. 4 Relative permeability curves under different pressure differences in matrix and micro-fracture areas
3
Numerical simulation method of pressure drive
Pressure flooding water injection and production process are different from conventional water injection and traditional fracturing. First, rock fracture and fracture expansion will occur during the injection process. The fracture propagation law is affected by factors such as long injection time, large total amount and no proppant, which is more complicated than fracturing. Second, the pressure change range and influence range during the injection and production process are large, and it is necessary to consider the dynamic change law of physical properties in the matrix area and the fracture area at the same time. Third, the processes of "pressing" and "flooding" occur synchronously and affect each other. The process of "pressing" causes changes in effective stress, resulting in changes in fracture transformation zones and physical properties, which in turn affect
The process of "displacement" is established; "displacement" in turn affects the in-situ stress, thereby affecting the changes in cracks and reservoir physical properties.
The numerical simulation method of pressure flooding formed in this study takes the in-situ stress simulation as a link, and establishes a numerical simulation method of pressure flooding coupled with three fields of stress field, fracture area and fluid field, so as to realize the synchronous simulation of fracture propagation and pressure and saturation changes.
3.1 Establishment of in-situ stress model
Firstly, the layer data, single well data, single well stratification data and longitudinal mesh data in the 3D geological model are imported into the model. Based on the high-precision layer velocity volume of seismic interpretation, the sequential Gaussian simulation method is used to establish a three-dimensional density attribute model. The overlying layer pressure is obtained from the surface to the reservoir through density integration, and then the three-dimensional pore pressure is calculated according to the Eaton model and density trend line combined with the overlying layer pressure; based on the single well rock mechanical parameters, the three-dimensional rock mechanical parameter field is calculated by the interpolation method of inverse distance weighted average. Finally, the maximum and minimum horizontal principal stresses are calculated by the combined spring model, and the three-dimensional
Initial ground stress model.
3.2 Establishment of discrete seam network model
The simulation of complex fracture propagation can fully consider the influence of natural fracture and weak stress on hydraulic fracture propagation. The simulation of artificial hydraulic complex fracture network propagation process can be realized through integrated simulation of geology and engineering, and a discrete fracture network model that can precisely characterize the spatial distribution of complex fracture network can be established. This technology has been widely used in fracturing simulation process.
The commercial simulation software cannot fully satisfy the simulation of the fracture propagation process during the injection process of unpropped water pressure flooding in the function of simulating fracture propagation. By analyzing the simulation mechanism of the software and combining the simulation results of different injection parameters, it is found that the fracturing simulation software can only consider simple filtration loss, and cannot consider the influence of filtration loss on the reservoir matrix. Therefore, the fracture propagation simulation method that has been mature in fracturing engineering is optimized to form a fracturing fracture propagation simulation method that can fully reflect the injection characteristics of small displacement, long cycle and large cumulative injection.
It should be noted that this model is not a pressure-driven seam model, but a prediction of crack propagation paths in numerical emulators.
3.3 Establishment of seepage model in pressure drive zone
Micro-seismic monitoring and physical simulation experiments show that the reservoir can be divided into three types of seepage mode areas after rupture, namely matrix area, micro-fracture area, and main fracture area. The experimental results show that the three areas have different pore-permeability physical properties, rock mechanical properties, and stress sensitivity. Referring to the results of physical simulation experiments, the prediction model of pressure-driven discrete fracture network is divided according to the matrix area, micro-fracture area, and main fracture area, and the regional pore-permeability and pressure-sensitive model is established to characterize the physical stress sensitivity of different zones.
The simulation results show that the increase of displacement will promote the crack propagation, and the crack propagation is not obvious after more than 1 m3 /min. When the displacement is 0.5~ 2 m3 /min, the crack half length is 150~ 200 m.
Based on seam mesh transformation belt