Research on the Water Injection Pressure Reducing and Increasing Injection System for Low Permeability Reservoirs in Fushan Oilfield

In response to the problems of increased injection pressure, decreased injection volume, and stopped injection caused by scaling and impurity blockage during the water injection process in the low permeability reservoir of HuaX block in Fushan Oilfield, water quality analysis and scaling experiments were conducted on the injected water in the block to determine the cause of scaling. Secondly, core displacement damage experiments were conducted using natural rock cores and on-site injected water to determine the degree of permeability damage during the water injection process, with a permeability damage rate greater than 70%, Finally, based on the causes of scaling and core displacement experiments, scale inhibitors, anti expansion agents, and surfactants were selected. Through orthogonal experiments, the optimal system formula was determined. The scale inhibition rate was greater than 90%, the anti expansion agent was greater than 90%, and the interfacial tension was less than 0.01mN/m. Core displacement experiments showed that the permeability damage rate of the system to the core was less than 15%, which can achieve the effect of reducing pressure and increasing injection in water injection wells.


Introduction
Water injection operation is an important means for oil fields to maintain stable production and increase production.There are currently 6 water injection wells in the HuaX block of Fushan Oilfield.During the water injection process, due to water quality reasons, scaling, clay expansion, and other reasons, the water injection pressure of the water injection wells continues to increase and the water injection volume sharply decreases.The well repair operation of the water injection wells shows that there are severe scaling and blockage phenomena in the wellbore of the water injection wells in this block.The main reason is that the injected water contains a large amount of scaling ions, During the process of water injection, changes in water injection volume and pressure cause formation backflow and blockage of the wellbore, resulting in the phenomenon of no injection [1][2][3] .

Analysis of reservoir characteristics
The HuaX fault block structure is a fault block structure sandwiched by two north-south faults, with the strata uplifting to the east and tilting to the west.The oil layers of each oil formation are developed in layers (without a unified oil-water boundary), and the main type of oil reservoir is lithologic structural oil reservoir.The buried depth of the oil reservoir is 2590-3145m, the effective thickness is 14.6m, the oil saturation is 59.6%, the original formation pressure is 30.45MPa, the pressure coefficient is 1.02, the original formation temperature is 109.41℃, and the formation water type is NaHCO3; There are currently 6 water injection wells, mainly in the IV oil formation, with an average porosity of 14.8% and a permeability of 7.6 × 10-3 μ m 2 .

Analysis of scaling factors
The injected water in the HuaX block is the post-treatment water produced by the oilfield, and the quality of the treated water and the content of scaling ions directly affect the quality of the water injection.Historical assignments have shown varying degrees of scaling, resulting in an increase in injection pressure, a decrease in injection volume, and even inability to inject.As for Well X-1, the water injection volume exceeded 70 cubic meters per day during the initial injection period, but after a period of injection, the water injection volume sharply decreased.During the workover operation, the original well string showed severe scaling and blocked the wellbore.

Analysis of scaling and blockage
The scaling ion analysis was conducted on the HuaX Joint Station, HuaX-1 Well, and HuaX-2 Well, and the results showed that the injected water type was calcium chloride type.The scaling anion bicarbonate ion content of HuaX Joint Station was 1232.7mg/L, the scaling cation calcium ion was 661.3mg/L, the magnesium ion content was 182.3mg/L, and the total mineralization degree was 23184.2.
Table 1.Water quality analysis results  Inject 50ml of water into wells HuaX-1 and HuaX-2 to simulate formation temperature, and conduct a scaling test at 70 ℃.The test shows that scaling occurs 72 hours later.

Evaluation of injected water quality and blockage
Water quality analysis was conducted on water samples from HuaX Joint Station, HuaX-1, and HuaX-2 wells.The results showed that the injected water contains a large amount of suspended solids, oil, and mechanical impurities, which can easily block the formation channel during the water injection process.

Experimental evaluation of injection system
Based on the results of scaling ion analysis and water quality analysis of the injected water, the optimization of scale inhibitors, waterproof locking agents, and anti swelling agents was carried out, and natural rock cores were used for core displacement testing

Formation Water Compatibility
Scale inhibitors can effectively inhibit the crystal formation of inorganic salts (such as calcium carbonate, barium sulfate, etc.) in water, preventing scaling and blockage.It forms a complex by combining with cations in water, thereby reducing the precipitation and crystallization of inorganic salts.Simultaneously generate a protective film to prevent electrochemical reactions and corrosion that occur when metals come into contact with water, reducing the corrosion rate of metals in water.
According to the types of scaling ions in the water injection of HuaX block, 5 different types of scale inhibitors were selected for scale inhibition tests.The scale inhibition effect for 72 hours at 120 ℃ is shown in the table below [4]  Through scale inhibition experiments on these five types of scale inhibitors, it was found that the first type of scale inhibitor had no scale inhibition effect, the second type of scale inhibitor had scale inhibition effect at a concentration of 0.8%, the third type of scale inhibitor had scale inhibition effect at a dosage of 0.4%, and the fourth and fifth types of scale inhibitors had scale inhibition effect at a dosage of 0.6%.Therefore, scale inhibitor A was selected as the optimal scale inhibitor.

Selection of waterproof locking agents
Due to the fact that this block belongs to a low porosity and low permeability reservoir, the water injection pressure of the low permeability reservoir increases due to capillary resistance and Jamin effect during the water injection process.Therefore, adding an appropriate amount of waterproof locking agent in the water injection can effectively reduce capillary resistance and eliminate the Jamin effect.Optimizing temperature and salt resistant waterproof locking agents to reduce interfacial tension to 10-2 orders of magnitude, while coordinating the proportion of each component in the system, the salt resistance can reach 35000mg/L, and the temperature resistance can reach 150 ℃, effectively reducing displacement resistance.

Selection of waterproof locking agents
Anti swelling agents have the ability to prevent clay expansion and migration, stabilize clay with a long shelf life, and maintain stable molecular structure.When combined with other additives, they not only meet the requirements of high permeability oil fields, but also are suitable for medium and low permeability oil layer clays.Gemini quaternary ammonium salt type anti swelling agents are preferred, which have extremely high Zeta potential and are easy to adsorb onto clay particles through intermolecular forces, preventing clay particles from migrating due to electrostatic repulsion, This effectively prevents the expansion of clay, reduces the hydration, expansion, and dispersion of shale, and is beneficial for the stability of sensitive sandstone clay minerals.91% anti expansion rate, 89% water washability.

Figure7 . Picture of comparison test of anti swelling agent
7-1 used drilling fluid test to mix bentonite and distilled water, with an anti expansion rate of 9%.7-2 used HuaX-1 core powder and distilled water, with an anti expansion rate of 42%.7-3 used HuaX-1 core powder and 1% anti expansion agent, with an anti expansion rate of 91%.

Core displacement experiment
Based on the selected scale inhibitors, waterproof locking agents, and anti expansion agents above, the dosage of scale inhibitor is determined to be 0.4%, anti expansion agent is determined to be 1%, and waterproof locking agent is determined to be 0.5.A core displacement test is conducted using the natural core of HuaX-1 well to verify the injection effect of the system.Experimental Procedure Displacement purpose: To evaluate the effectiveness of acid solution+depressurization and injection enhancement system on core plugging removal and injection enhancement.Displacement system: 8% KCL saline+injected water+mud acid system+depressurization and injection increase system.Displacement core: Hua 117-21X Reduced pressure and increased injection system: 0.4% scale inhibitor+1% anti swelling agent+0.5% surfactant+reinjection water.Figure8 .Picture of core displacement experiment The selected natural core was first displaced with 8% KCL saline water to a permeability of 4.5 millidarcy.Then, water injection was used to displace the core in HuaX-1 well, with a pressure increase from 0.8 MPa to 4.4 MPa and a permeability decrease to 0.9 millidarcy.Then, a 15% hydrochloric acid acid system was used for unblocking.After 30 minutes of displacement, the pressure decreased to 2.35 MPa and the permeability increased to 2.53 millidarcy.Then, 0.4% scale inhibitor, 1% anti expansion agent, 0.5% waterproof locking agent, and reinjection water were used for

Conclusion
(1) The main reason for the increase in water injection pressure and difficulty in water injection volume in HuaX block is scaling, followed by clay expansion and blockage of impurities in the injected water (2) The optimal scale inhibitor has a scale inhibition rate greater than 90%, an interfacial tension of less than 0.01mN/m for waterproof locking agents, and an anti expansion rate greater than 90% for anti expansion agents (3) The core displacement test shows that adding 0.4% scale inhibitor, 1% anti swelling agent, and 0.5% waterproof locking agent to the reinjection water can effectively suppress the increase of water injection pressure

Figure 1 .
Figure 1.Picture of oil pipe scaling

Figure 2 .
Figure 2. Picture of injected water scaling

Table 2 .
Results of Reinjection water quality

Table 3 .
Evaluation results of scale inhibition effect The pressure remains constant and the injection rate slowly increases, indicating that the system has a certain effect