Water-based formate annulus protection fluid for deep-sea oil and gas field development and preparation method thereof

Abstract

This invention discloses a water-based formate annular protective fluid for deep-sea oil and gas field development and its preparation method, specifically relating to the field of chemical corrosion prevention in oil and gas field development. The fluid comprises the following raw material components by mass percentage: 15wt%-40wt% organic-inorganic salt composite base fluid, 3wt%-8wt% green composite corrosion inhibitor, 2wt%-5wt% composite oxygen scavenger, 1wt%-3wt% zwitterionic bactericide, 2wt%-4wt% composite scale inhibitor, 0.5wt%-2wt% high-pressure stabilizer, 0.3wt%-1.5wt% environmental synergist, 1wt%-3wt% natural gas hydrate inhibitor, with the balance being deionized water. This invention, by employing a specific compounded high-pressure stabilizer and an optimized composite salt-based liquid, can withstand high-pressure environments exceeding 30 MPa and maintain excellent physical and chemical stability within an extreme temperature fluctuation range of -10°C to 180°C. After testing at 180°C for 168 hours, the liquid showed no stratification, no precipitation, and minimal density change, demonstrating its outstanding thermal stability and pressure resistance, making it fully adaptable to the harsh working conditions in the deep sea, from low temperatures on the seabed to high temperatures at the bottom of wells.

Description

Technical Field

[0001] This invention relates to the field of chemical corrosion protection technology for oil and gas field development, and more specifically, to water-based formate annular protective fluid for deep-sea oil and gas field development and its preparation method. Background Technology

[0002] With the continued growth of global energy demand and the increasing depletion of conventional oil and gas resources on land and in shallow seas, the exploration and development of deep-sea oil and gas resources has become an important direction. The deep-sea environment presents extremely harsh operating conditions, including high pressure, coexistence of low and high temperatures, high mineralization, rich in corrosive media (such as CO2 and H2S), and the risk of natural gas hydrate formation. These conditions pose severe challenges to the completion and production safety of oil and gas wells. Among these challenges, the long-term effective protection of the annulus between the tubing and casing is crucial for ensuring wellbore integrity, preventing casing failure, and protecting the environment.

[0003] Annular protective fluid is a special working fluid injected into the annulus of the casing and tubing. Its main functions include: balancing formation pressure and annular pressure to prevent casing crushing or bursting; inhibiting corrosion of the inner and outer walls of the tubing by annular media (such as formation water, drilling fluid residue, and intruding acidic gases); preventing the formation and accumulation of natural gas hydrates under low temperature and high pressure conditions to avoid clogging the annular passages; and ensuring compatibility with downhole packers and other sealing elements without affecting their sealing performance. Therefore, the performance of the annular protective fluid directly affects the long-term safe service life and operational economy of deep-sea oil and gas wells.

[0004] Currently, annular protection fluid technology used in onshore and conventional offshore oil and gas fields is relatively mature, with main types including oil-based, brine-based, and composite salt systems. For example, Chinese patent CN113583641A discloses an annular protection fluid suitable for salt cavern hydrogen storage wells, which introduces a hydrogen indicator to enhance hydrogen storage safety; CN106520101B reports an annular protection fluid with self-healing function, designed to buffer hydrogen ion corrosion generated by acidic gases; and CN108251087B discloses an annular protection fluid for CO2 flooding injection wells, using diesel as a solvent to reduce costs. However, these existing technologies have not fully considered the extreme coupled conditions of the deep-sea environment in their design, and have the following significant shortcomings when applied in the deep sea:

[0005] 1. Insufficient high-pressure resistance: The hydrostatic pressure in the deep-sea environment is extremely high, with bottom hole pressure reaching over 30 MPa, or even higher. Under such high pressure, most existing annular protection fluid systems may experience abrupt changes in density stability, component compatibility, and rheology, leading to system stratification, precipitation, or functional component decomposition and failure, thus failing to provide stable pressure support and protection.

[0006] 2. Narrow temperature adaptability: The temperature range of the deep-sea environment is extremely wide, with the surface water temperature at seabeds ranging from -10℃ to 20℃, while the temperature at the bottom of wells can reach as high as 150℃ to 190℃. Many existing protective fluid systems cannot maintain stability simultaneously within this wide temperature range. At low temperatures, the viscosity may increase dramatically, the fluidity may decrease, or even freezing may occur. At high temperatures, the additives may decompose thermally, and the corrosion inhibitor film may be damaged, leading to a sharp decline in protective performance.

[0007] 3. Weak synergistic protection capability in complex corrosive environments: The deep-sea annulus is complex and usually contains highly mineralized formation water (mineralization can reach 1.2 × 10⁻⁶). 5 (above mg / L), high concentrations of Cl - SO4 2- Corrosive ions, as well as acidic corrosive gases such as CO2 and H2S, are present. Existing technologies often exhibit poor synergy among their corrosion-inhibiting, scale-inhibiting, bactericidal, and deoxygenating components. Under the combined corrosive effects of high mineralization and acidic gases, it is difficult to maintain the corrosion rate of commonly used oil casing materials such as N80, P110, and HP13Cr at extremely low levels (e.g., ≤0.01 mm / a) over the long term, resulting in high risks of pitting corrosion, stress corrosion cracking (SCC), and under-deposit corrosion.

[0008] 4. Insufficient environmental friendliness: Some traditional protective fluids contain heavy metals, non-biodegradable organic matter, or toxic substances. In the event of a leak, these can cause severe and lasting pollution to the fragile deep-sea ecosystem. With increasingly stringent international marine environmental regulations, developing environmentally friendly protective fluid systems is crucial.

[0009] 5. Short service life and high maintenance costs: The long-term stability of many existing systems is poor, and the effective protection period is usually no more than 12 months. Deep-sea operations are extremely difficult and costly to maintain. Frequent well workover operations to replace or replenish protective fluid will significantly increase development costs and affect economic benefits.

[0010] 6. Inadequate consideration of natural gas hydrate suppression: The low temperature and high pressure conditions in the deep sea easily induce the formation of natural gas hydrates, clogging the annulus. Many conventional protective fluids lack effective hydrate inhibitors or their suppression efficiency is insufficient to cope with deep-sea conditions.

[0011] Therefore, to meet the specific needs of deep-sea oil and gas field development, there is an urgent need to develop a new type of annular protective fluid system. This system must possess excellent long-term stability, highly efficient synergistic corrosion prevention (corrosion inhibition, sterilization, oxygen removal, and scale inhibition) capabilities, reliable natural gas hydrate inhibition performance, and good environmental compatibility under extreme operating conditions such as high pressure (≥30MPa), wide temperature range (-10℃~180℃), high salinity, and high acidic gas partial pressure. It must also be able to achieve continuous effective service for more than 18 months to ensure the safe, economical, and environmentally friendly development of deep-sea oil and gas fields. Summary of the Invention

[0012] In order to overcome the above-mentioned defects of the prior art, the embodiments of the present invention provide a water-based formate annular protective fluid for deep-sea oil and gas field development and its preparation method. The technical problem to be solved by the present invention is that the existing annular protective fluid has problems such as poor temperature and pressure resistance, weak synergy of functional components, insufficient environmental protection, and short service life in the extreme environment of deep sea.

[0013] To achieve the above objectives, the present invention provides the following technical solution: a water-based formate annular protective fluid for deep-sea oil and gas field development, comprising the following raw material components by mass percentage: 15wt%-40wt% organic-inorganic salt composite base liquid, 3wt%-8wt% green composite corrosion inhibitor, 2wt%-5wt% composite oxygen scavenger, 1wt%-3wt% zwitterionic bactericide, 2wt%-4wt% composite scale inhibitor, 0.5wt%-2wt% high-pressure stabilizer, 0.3wt%-1.5wt% environmental synergist, 1wt%-3wt% natural gas hydrate inhibitor, with the balance being deionized water. The system formed after the components are compounded is uniform and transparent, without stratification or precipitation, and the functional components have good compatibility and synergistic effect.

[0014] In a preferred embodiment, the organic-inorganic salt composite base fluid is composed of potassium formate, potassium chloride, and potassium acetate in a mass ratio of 8:5:1. This composite base fluid cleverly combines the advantages of organic salts (potassium formate and potassium acetate) and inorganic salts (potassium chloride): organic formate and acetate are far less corrosive to metals than inorganic salts such as chlorides, and they possess a certain pH buffering capacity, which helps neutralize hydrogen ions generated by the dissolution of acidic gases; the inorganic salt potassium chloride is low in cost and can effectively increase the system density. By combining the three in a specific ratio, the system density can be flexibly and stably adjusted within the range of 1.1 g / cm³ to 1.8 g / cm³ while ensuring low corrosivity and good buffering capacity, thus meeting the precise balance requirements of annular fluid column pressure at different deep-sea well depths.

[0015] In a preferred embodiment, the green composite corrosion inhibitor is composed of 2-mercaptobenzimidazole (MBI), thiourea, and sodium lignosulfonate in a molar ratio of 2:5:1. 2-Mercaptobenzimidazole is a highly efficient adsorption-type corrosion inhibitor; its thiol (-SH) group and benzimidazole ring can form a dense and robust monomolecular protective film on the metal surface through chemisorption, effectively blocking the erosion of corrosive media. The addition of thiourea can enhance the adsorption stability of the corrosion inhibitor molecules on the metal surface and may further fill film defects through synergistic adsorption. Sodium lignosulfonate, as a natural polymeric surfactant, can improve the dispersibility of the corrosion inhibitor molecules in solution and their spreadability on the metal surface, promoting a more uniform and complete protective film. The synergistic effect of these three components provides excellent corrosion protection for carbon steel and low-alloy steel in complex environments with high mineralization and high acidity gases (CO2 / H2S).

[0016] In a preferred embodiment, the composite oxygen scavenger is composed of dimethyl ketoxime (DMKO) and acetaldehyde oxime (AHO) in a mass ratio of 2-3:1. Dissolved oxygen is a significant factor causing corrosion of oil casing, especially pitting corrosion and oxygen concentration cell corrosion. Dimethyl ketoxime has the advantages of high oxygen removal efficiency and fast reaction speed, which can rapidly reduce the initial oxygen content of the system; while acetaldehyde oxime has a relatively slow oxygen removal reaction, but its effect is long-lasting, providing long-term oxygen removal protection. The combination of the two achieves an organic combination of rapid and long-lasting oxygen removal, avoiding the risk that a single oxygen scavenger may be prematurely consumed or fail under long-term high temperature and high pressure conditions in the deep sea, ensuring that the dissolved oxygen concentration is maintained at an extremely low level (less than 20 ppb) throughout the entire service life.

[0017] In a preferred embodiment, the zwitterionic bactericide is selected from one or a mixture of two of cetyldimethyl(2-sulfite)ethylammonium (sulfobetaine-type zwitterionic surfactant) and N-octyl-diaminoethylglycine (amino acid-type zwitterionic surfactant) in any proportion. Sulfate-reducing bacteria (SRB), iron bacteria (FB), and other microorganisms proliferate and metabolize in the annular environment, directly participating in corrosion processes (such as anaerobic corrosion of SRB), and their metabolic products and biofilms exacerbate localized corrosion (such as under-deposit corrosion). Zwitterionic bactericide molecules carry both positive and negative charges, exhibiting excellent surface activity, broad-spectrum bactericidal properties, and good pH adaptability (maintaining bactericidal activity over a wide pH range). They can effectively disrupt bacterial cell membrane structures, leading to leakage of cell contents and death, demonstrating a strong killing effect on SRB and FB commonly found in the deep-sea annular environment.

[0018] In a preferred embodiment, the composite scale inhibitor is prepared by compounding polyaspartic acid (PASP) and aminotrimethylphosphonic acid (ATMP) in a mass ratio of 1 to 2:1. In the deep-sea annular environment, high concentrations of calcium... 2+Mg 2+ Ba 2+ SO4 2- CO3 2- Plasma readily forms inorganic scale such as calcium carbonate, calcium sulfate, and barium sulfate under varying temperature and pressure. Scale deposition not only narrows the annular space, affecting pressure transmission, but also triggers severe under-deposit corrosion. Polyaspartic acid is a green, biodegradable polymer scale inhibitor that primarily inhibits scale crystal growth and deposition through chelation and dispersion. Aminotrimethylphosphonic acid is a highly efficient organophosphonic acid scale inhibitor with excellent lattice distortion and threshold effects, capable of disrupting the normal growth morphology of scale crystals. The combination of these two substances, employing both chelation-dispersion and lattice distortion mechanisms, exhibits excellent synergistic scale inhibition effects against various scale types, including CaCO3, CaSO4, and BaSO4.

[0019] In a preferred embodiment, the high-pressure stabilizer is a compound of polyethylene glycol (PEG) 2000-6000 derivatives and modified nano-silica (m-SiO2) at a mass ratio of 3:1. The high-pressure environment of the deep sea places extremely high demands on the physical stability of the protective fluid system. PEG derivatives can moderately increase the viscosity of the system, improving its suspension stability and anti-sedimentation ability. Modified nano-silica, after surface treatment, can form a three-dimensional network structure in the system, providing thixotropy and excellent compressive stability, preventing separation of system components or changes in density gradients under high pressure. The synergistic effect of these two components ensures that the system remains uniform and stable, without stratification or precipitation, even during long-term storage and use at pressures of 30 MPa or even higher.

[0020] In a preferred embodiment, the environmentally friendly synergist is a biodegradable fatty alcohol polyoxyethylene ether (such as the AEO series). As a nonionic surfactant, this synergist significantly improves the solubility and dispersibility of various functional components (especially corrosion inhibitors and scale inhibitors) in the composite base liquid, promoting their uniform distribution throughout the system and avoiding compatibility problems caused by excessively high local concentrations. Simultaneously, it possesses excellent biodegradability and low toxicity, meeting environmental protection requirements.

[0021] In a preferred embodiment, the natural gas hydrate inhibitor is a binary copolymer of poly(N-vinylcaprolactam) (PVCap) and polyvinylpyrrolidone (PVP), wherein the molar ratio of PVCap to PVP is 3:7. This copolymer combines the excellent thermal stability of PVCap with the good hydrate inhibition performance of PVP. The carbonyl and other polar groups on its molecular chain can be strongly adsorbed onto the surface of the forming hydrate nuclei through hydrogen bonding. Simultaneously, the steric hindrance effect generated by its polymer chain can effectively interfere with and prevent the further growth and aggregation of hydrate nuclei, thereby effectively inhibiting the formation of natural gas hydrates under deep-sea low-temperature and high-pressure conditions and ensuring unobstructed annular space.

[0022] This invention also includes a method for preparing a water-based formate annular protection fluid for deep-sea oil and gas field development, comprising the following steps:

[0023] S1: Base Solution Deoxygenation Treatment: Under inert gas (high-purity nitrogen) protection, add metered high-purity deionized water (conductivity less than 0.3 μS / cm) to a sealed reactor equipped with a stirrer, temperature control, and gas inlet pipe. To enhance the deoxygenation effect, a trace amount (e.g., 0.0001 wt%) of sodium sulfite can be added as an auxiliary deoxygenating agent. Bubble the water with nitrogen gas at a flow rate of 0.5–1.0 L / min for at least 30 minutes to completely reduce the dissolved oxygen content in the system to below 20 ppb, creating an inert environment for subsequent addition of oxygen-sensitive corrosion inhibitors and other components.

[0024] S2: Dissolution and Dispersion of Basic Components: Maintaining an inert atmosphere within the reactor, sequentially add the formulated amounts of the organic-inorganic salt composite base liquid (potassium formate, potassium chloride, and potassium acetate premixed in an 8:5:1 ratio), high-pressure stabilizer (polyethylene glycol derivative and modified nano-silica premixed in a 3:1 ratio), and natural gas hydrate inhibitor (PVCap / PVP copolymer). Under mild conditions of 20℃–35℃, stir at a moderate speed of 200–400 rpm for 30–60 minutes until all solid components are completely dissolved, or the nanomaterials are uniformly dispersed, forming a homogeneous and transparent base liquid. Gentle stirring during this stage helps prevent degradation of functional components or agglomeration of nanoparticles due to severe shear.

[0025] S3: Functional Additive Compounding and pH Adjustment: Under continuous stirring and nitrogen protection, slowly add each functional additive in a specific order: first add the green composite corrosion inhibitor, and after it is evenly dispersed, add the composite scale inhibitor, composite oxygen scavenger, and amphoteric bactericide, and finally add the environmentally friendly synergist. It is recommended to stir each component separately for 10-15 minutes after adding it to ensure it is fully dissolved and dispersed, avoiding the formation of lumps or flocs. After all components are added, continue stirring to homogenize the system, with a total stirring time of 40-60 minutes. The system should be a homogeneous and transparent liquid, without any layering, precipitation, or turbidity. Finally, use an alkaline pH adjuster, such as a 10% sodium carbonate solution or potassium bicarbonate solution, to slowly adjust the pH of the system to the target range of 8.5-11.0. This alkaline environment is conducive to the formation and stability of the corrosion inhibitor film and can effectively buffer the hydrogen ions generated by the dissolution of acidic gases such as CO2 and H2S. After adjustment, the final annular protective fluid product can be obtained by filtration (e.g., through a 200-mesh sieve).

[0026] This invention also includes a method for using water-based formate annular protection fluid in deep-sea oil and gas field development for annular protection in deep-sea oil and gas wells. During well completion operations, after the packer is successfully set in the designed position, the prepared annular protection fluid is injected into the target annulus (casing or riser annulus) through a dedicated high-pressure injection pump and pipeline. During injection, the flow rate should be controlled at 3–5 m / s to ensure that the protection fluid can fully replace the original fluid in the annulus and completely fill the annular space, avoiding the formation of cavitation or unfilled sections. The injection volume needs to be precisely calculated to achieve a dynamic balance between the liquid column pressure formed by the annular protection fluid and the external seawater hydrostatic pressure and the pressure inside the wellbore, preventing casing crushing and avoiding excessive pressure leading to leakage. Throughout the entire production service life of the oil and gas well, a regular monitoring mechanism needs to be established. It is generally recommended to monitor annular pressure changes every 3 months and sample and analyze indicators such as pH value, key ion concentration, corrosion rate (which can be monitored through a tack strip), and bacterial content of the annular protection fluid. Based on monitoring results and analysis data, assess the degradation of the protective fluid's performance, and promptly formulate and implement plans to replenish fresh protective fluid or partially / completely replace it, thereby ensuring continuous, stable, and reliable annular protection and extending wellbore life.

[0027] The technical effects and advantages of this invention are as follows:

[0028] 1. This invention, by employing a specific compounded high-pressure stabilizer and an optimized composite salt-based liquid, can withstand high-pressure environments exceeding 30 MPa and maintain excellent physical and chemical stability within an extreme temperature fluctuation range of -10℃ to 180℃. After testing at 180℃ for 168 hours, the liquid showed no stratification or precipitation, and exhibited minimal density change, demonstrating its outstanding thermal stability and pressure resistance, making it fully adaptable to the harsh working conditions in the deep sea, from low seabed temperatures to high well bottom temperatures.

[0029] 2. This invention utilizes a green composite corrosion inhibitor to form a dense, robust, and self-healing adsorption protective film on the metal surface. Synergistically, this film, combined with the buffering effect of an alkaline environment, effectively controls the corrosion rate of commonly used deep-sea pipe materials N80, P110, and HP13Cr to below 0.01 mm / a, far exceeding industry standards and significantly extending pipe life. The composite oxygen scavenger achieves a perfect combination of rapid and long-lasting oxygen removal, with a stable oxygen removal rate exceeding 99.5%, fundamentally eliminating the main driving force of oxygen corrosion. The highly efficient zwitterionic bactericide exhibits a kill rate of over 99.8% against SRB and FB, effectively inhibiting microbial corrosion and the series of problems it causes. The composite scale inhibitor, through a dual mechanism of chelation dispersion and lattice distortion, achieves a scale inhibition rate of over 96% for common scale types such as CaCO3, CaSO4, and BaSO4, effectively preventing scaling and the resulting flow obstruction and under-deposit corrosion.

[0030] 3. This invention uses a specially formulated PVCap / PVP binary copolymer as an inhibitor, which can effectively interfere with and inhibit the growth and aggregation of natural gas hydrate crystal nuclei under deep-sea low-temperature and high-pressure environments, prevent annular blockage, and ensure smooth wellbore operation and production safety; the annular protection fluid has a biodegradability rate of over 90% and is non-toxic, minimizing potential risks to the marine ecological environment. Detailed Implementation

[0031] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the embodiments thereof. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the scope of protection of the present invention.

[0032] Examples 1 to 3 below illustrate three annular protective fluids of different densities prepared according to the technical solution of the present invention, optimized for medium water depth, conventional deep sea, and ultra-deep water / high pressure conditions, respectively. The preparation of all examples follows the aforementioned general method, and the specific operations are as follows:

[0033] General preparation steps:

[0034] 1. Equipment and Raw Material Preparation: Use a jacketed stainless steel reactor equipped with a mechanical stirrer, thermocouple thermometer, nitrogen inlet and outlet valves, and sampling port. Before use, confirm that all raw materials meet the required specifications and purity. The conductivity of deionized water is less than 0.3 μS / cm.

[0035] 2. Deoxygenation of the base solution: Add the measured amount of deionized water to the reactor. Open the nitrogen cylinder and purge high-purity nitrogen (purity ≥99.999%) into the reactor at a stable flow rate of 0.8 L / min. Simultaneously, add 0.0001 wt% sodium sulfite (analytical grade) through the feed port. Continuously bubble and stir slowly (approximately 100 rpm) for 30 minutes. Use a portable dissolved oxygen analyzer to confirm that the dissolved oxygen content has dropped below 20 ppb.

[0036] 3. Dissolving the basic components: Maintain a nitrogen atmosphere and close the exhaust valve to maintain a slight positive pressure. Accurately add the pre-mixed organic-inorganic salt composite base solution (potassium formate:potassium chloride:potassium acetate = 8:5:1, industrial grade or oilfield chemical grade), high-pressure stabilizer (a slurry premixed with polyethylene glycol 4000 derivative and hydrophobically modified nano-silica at a mass ratio of 3:1), and natural gas hydrate inhibitor (a copolymer of PVCap and PVP, molar ratio 3:7, solid or solution). Set the jacket circulating water temperature to 25℃, start stirring, and gradually increase the speed to 350 r / min. Continue stirring for 40 minutes until the liquid in the reactor becomes a homogeneous, transparent or translucent stable base solution, free of visible particles or oil droplets.

[0037] 4. Functional Additive Compounding: Under nitrogen protection and stirring conditions, slowly add each functional additive in the following order. After each additive is added, keep stirring for 10-15 minutes to ensure complete dissolution or dispersion. Visually inspect for any lumps, flocculation, or precipitation:

[0038] a. Add green composite corrosion inhibitor (premixed powder or concentrate of 2-mercaptobenzimidazole:thiourea:sodium lignosulfonate in a molar ratio of 2:5:1).

[0039] b. Add a composite scale inhibitor (an aqueous solution of sodium polyaspartate and sodium aminotrimethylphosphonate premixed at a mass ratio of 1.5:1).

[0040] c. Add a compound oxygen scavenger (a liquid premixed with dimethyl ketoxime and acetaldehyde oxime at a mass ratio of 2.5:1).

[0041] d. Add amphoteric bactericides (select single or mixed types according to the formula).

[0042] e. Finally, add an environmentally friendly synergist (biodegradable fatty alcohol polyoxyethylene ether AEO-9).

[0043] 5. Homogenization and pH Adjustment: After all additives have been added, continue stirring at 350 rpm for 30 minutes to ensure thorough homogenization. Then, while stirring, slowly add a 10 wt% potassium carbonate (K2CO3) aqueous solution using a metering pump, monitoring the pH meter reading in real time, and precisely adjust the pH value to the target range of 9.5-10.5.

[0044] 6. Filtration and Finished Product: The pH-adjusted liquid is filtered through a 200-mesh stainless steel screen to remove any trace amounts of insoluble impurities, resulting in a clear and transparent final product. This product is then filled into sealed containers and stored under nitrogen for later use.

[0045] Example 1 (Medium density system, suitable for medium water depth and pressure window)

[0046] Design objective: To prepare an annular protection fluid with a density of 1.20 g / cm³ (measured at 25℃), suitable for working conditions with water depths of approximately 1000-2000 meters and relatively moderate bottom hole pressure.

[0047] Specific formula (by weight percentage, wt%):

[0048] Organic-inorganic salt composite base solution (potassium formate:potassium chloride:potassium acetate = 8:5:1): 20.0%

[0049] Green composite corrosion inhibitor (MBI:thiourea:sodium lignosulfonate = 2:5:1, molar ratio): 4.5%

[0050] Composite oxygen scavenger (DMKO:AHO = 2.5:1, mass ratio): 3.0%

[0051] Amphoteric bactericide (hexadecyl dimethyl (2-sulfite) ethyl ammonium): 2.0%

[0052] Composite scale inhibitor (PASP:ATMP = 1.5:1, mass ratio): 3.0%

[0053] High-pressure stabilizer (PEG4000 derivative: modified nano-SiO2 = 3:1, mass ratio): 1.2%

[0054] Environmentally friendly synergist (fatty alcohol polyoxyethylene ether AEO-9): 0.8%

[0055] Natural gas hydrate inhibitor (PVCap-PVP copolymer, molar ratio 3:7): 2.0%

[0056] Deionized water: Replenish to 100%

[0057] Preparation summary: Follow the general procedure. The final product is a light amber transparent liquid with a measured density of 1.201 g / cm³ at 25°C and a pH of 9.5.

[0058] Example 2 (High-density system, primary window for deep-sea use)

[0059] Design objective: To formulate an annular protective fluid with a density of 1.50 g / cm³ (measured at 25℃), suitable for conventional deep-sea main development zones at water depths of 2000-3000 meters, requiring high liquid column pressure to balance formation pressure.

[0060] Specific formula (by weight percentage, wt%):

[0061] Organic-inorganic salt composite base solution (potassium formate:potassium chloride:potassium acetate = 8:5:1): 32.0%

[0062] Green composite corrosion inhibitor (MBI:thiourea:sodium lignosulfonate = 2:5:1, molar ratio): 6.0%

[0063] Composite oxygen scavenger (DMKO:AHO = 2.5:1, mass ratio): 3.5%

[0064] Amphoteric bactericide (compound type: hexadecyl dimethyl (2-sulfite) ethyl ammonium and N-octyl-diaminoethyl glycine mixed in a 1:1 mass ratio): 2.5%

[0065] Composite scale inhibitor (PASP:ATMP = 1.5:1, mass ratio): 3.5%

[0066] High-pressure stabilizer (PEG6000 derivative: modified nano-SiO2 = 3:1, mass ratio): 1.6%

[0067] Environmentally friendly synergist (fatty alcohol polyoxyethylene ether AEO-9): 1.0%

[0068] Natural gas hydrate inhibitor (PVCap-PVP copolymer, molar ratio 3:7): 2.5%

[0069] Deionized water: Replenish to 100%

[0070] Preparation Summary: Follow the standard procedures. The final product is an amber-colored transparent liquid with a measured density of 1.503 g / cm³ at 25°C and a pH of 10.0. Due to the high salt concentration, the stirring and dissolution phase took slightly longer.

[0071] Example 3 (Ultra-high density system, ultra-deep water / high pressure window)

[0072] Design objective: To formulate annular protection fluid with a density of 1.75 g / cm³ (measured at 25°C), suitable for ultra-deep water or abnormally high-pressure oil and gas reservoirs exceeding 3000 meters, which require extremely high density to provide sufficient pressure control.

[0073] Specific formula (by weight percentage, wt%):

[0074] Organic-inorganic salt composite base solution (potassium formate:potassium chloride:potassium acetate = 8:5:1): 40.0%

[0075] Green composite corrosion inhibitor (MBI:thiourea:sodium lignosulfonate = 2:5:1, molar ratio): 7.5%

[0076] Composite oxygen scavenger (DMKO:AHO=3:1, mass ratio): 4.0%

[0077] Amphoteric bactericide (N-octyl-diaminoethylglycine): 3.0%

[0078] Composite scale inhibitor (PASP:ATMP = 2:1, mass ratio): 4.0%

[0079] High-pressure stabilizer (PEG6000 derivative: modified nano-SiO2 = 3:1, mass ratio): 2.0%

[0080] Environmentally friendly synergist (fatty alcohol polyoxyethylene ether AEO-9): 1.2%

[0081] Natural gas hydrate inhibitor (PVCap-PVP copolymer, molar ratio 3:7): 3.0%

[0082] Deionized water: Replenish to 100%

[0083] Preparation Summary: Follow the standard procedures. This formula has the highest salt content, and the temperature needs to be maintained at around 30℃ during stirring to promote dissolution. The final product is a deep amber-colored, transparent, viscous liquid with a measured density of 1.752 g / cm³ at 25℃ and a pH of 10.5.

[0084] Comparative Example

[0085] To highlight the superiority of this invention, a comparative example is provided. This comparative example refers to a commercially available conventional brine-based annular protective solution (the main components of which are high-concentration calcium chloride / zinc bromide brine, combined with conventional imidazoline corrosion inhibitors, sulfite oxygen scavengers, and quaternary ammonium bactericides) that claims to be suitable for deep-sea applications, with a density of approximately 1.50 g / cm³.

[0086] Performance Testing and Result Analysis

[0087] The products obtained in Examples 1-3 and the comparative products underwent comprehensive and rigorous performance evaluation based on relevant oil and gas industry standards and testing methods simulating extreme deep-sea conditions. The main test items, methods, and conditions are as follows:

[0088] 1. Basic physicochemical properties and high-temperature and high-pressure stability tests:

[0089] Testing standards: Refer to the relevant methods for liquid stability in "SY / T 5329-2022 Recommended Indicators and Analytical Methods for Water Quality in Injection of Clastic Rock Oil Reservoirs", and strengthen them.

[0090] Test method: The sample was placed in a high-temperature and high-pressure reactor and subjected to a static pressure of 30 MPa. The temperature was controlled by a program: first, it was kept at -10℃ for 24 hours, then the temperature was increased to 180℃ at a rate of 1℃ / min, and then kept at 180℃ for 168 hours (7 days). After the experiment, the temperature and pressure were slowly reduced to room temperature, and the sample was removed.

[0091] Observation indicators: Visually observe whether the sample shows layering, precipitation, turbidity or drastic color change; measure the density change (Δρ) and pH value change of the sample at 25℃ before and after the experiment.

[0092] 2. Evaluation of corrosion inhibition performance:

[0093] Test standard: Refer to "SY / T5273-2014 Performance Evaluation Method of Corrosion Inhibitors for Oilfield Produced Water", and adopt the high temperature and high pressure dynamic weight loss method.

[0094] Test conditions:

[0095] Corrosive medium: simulated deep-sea formation water with high mineralization, the ionic composition of which is shown in Table 1 below.

[0096] Test piece materials: N80 steel (API5CT standard), P110 steel (API5CT standard), HP13Cr stainless steel (martensitic stainless steel, commonly used in high CO2 environments), and standard test piece dimensions.

[0097] Experimental environment: temperature 180℃, CO2 partial pressure 4.0MPa, H2S partial pressure 0.5MPa, total pressure 30MPa.

[0098] Experiment duration: 168 hours (7 days).

[0099] Corrosion rate calculation: The average corrosion rate is calculated based on the mass loss of the specimens before and after the experiment, the exposed area, and the experimental time, in mm / a.

[0100] Table 1: Ionic composition of simulated high-mineralization formation water

[0101]

[0102] 3. Scale inhibition performance test:

[0103] Test standard: Refer to the static scale inhibition method in "SY / T5673-93 Performance Evaluation Method of Oilfield Scale Inhibitors".

[0104] Test method: Prepare supersaturated solutions of CaCO3, CaSO4, and BaSO4, add a certain amount of the annular protection solution sample to be tested, and let stand in an 80℃ constant temperature oven for 48 hours. Determine the concentration of residual scale-forming ions in the solution by titration or atomic absorption spectrometry, and calculate the scale inhibition rate.

[0105] Scale inhibition rate (%) = (residual ion concentration in the protective solution group - ion concentration after precipitation in the blank group) / (initial ion concentration in the blank group - ion concentration after precipitation in the blank group) × 100%.

[0106] 4. Sterilization performance test:

[0107] Test standard: Refer to the erasure dilution method in "SY / T5890-1993 Performance Evaluation Method of Fungicides".

[0108] Tested bacterial species: sulfate-reducing bacteria (SRB, representative species: Desulfovibrio desulfuricans) and iron bacteria (FB, representative species: Gallionella ferruginea).

[0109] Test method: A certain concentration of bacterial suspension is mixed with samples of protective solution at different dilutions and cultured anaerobically or aerobically at 30℃ (SRB) or 25℃ (FB) for 14 days. Bacterial growth is determined by observing whether the test bottle turns black (SRB produces H2S) or produces ferric hydroxide precipitate (FB). The minimum bactericidal concentration and bactericidal rate are then calculated.

[0110] 5. Deoxygenation performance test:

[0111] Test method: A portable high-precision dissolved oxygen analyzer (detection limit 1 ppb) was used. Deionized water with a known initial dissolved oxygen content was mixed with the protective solution sample in a specific ratio, sealed in an inert sample bottle, and placed in a 60℃ water bath. Dissolved oxygen content was measured periodically until the content stabilized. The deoxygenation rate was calculated.

[0112] Deoxygenation rate (%) = (initial dissolved oxygen content - final stable dissolved oxygen content) / initial dissolved oxygen content × 100%.

[0113] 6. Environmental performance test (biodegradability):

[0114] Test standard: Refer to OECD 301F (Mann respiration method) or equivalent method.

[0115] Test method: The amount of oxygen consumed by the microorganisms in the activated sludge for degradation of the sample within 28 days was measured, and the biodegradation rate was calculated.

[0116] 7. Compatibility test with packer cartridge:

[0117] Test standard: Refer to the section on rubber component performance testing in "SY / T 5625-2008 Packers for Oil and Gas Wells".

[0118] Test method: Standard nitrile rubber or fluororubber tubular test pieces are immersed in a protective liquid sample and aged at 150℃ and 20MPa for 168 hours. The changes in weight, hardness (Shore A), tensile strength, and elongation at break of the test pieces before and after aging are measured.

[0119] 8. Natural gas hydrate suppression performance test:

[0120] Test method: A high-pressure sapphire visual reactor was used. Deionized water (or simulated formation water) and natural gas (such as methane) were added to the reactor, along with a protective liquid sample of a certain concentration. The temperature and pressure were programmed to reach deep-sea simulated conditions (e.g., 4℃, 10MPa). The hydrate formation induction time and amount were observed and recorded, and compared with a blank sample (pure water) to evaluate the inhibition effect.

[0121] Summary of comprehensive performance test results

[0122] The test results of Examples 1-3 and the comparative examples are summarized in Table 2 below. The data in the table are the average values ​​of three parallel experiments.

[0123] Table 2: Summary Table of Overall Performance Test Results for Examples and Comparative Examples

[0124]

[0125]

[0126]

[0127]

[0128]

[0129]

[0130] Results Analysis and Discussion

[0131] Based on the comprehensive test data in Table 2, it is clear that the annular protective fluids provided in Examples 1-3 of this invention exhibit comprehensive and superior performance advantages compared to traditional comparative products in dealing with extreme deep-sea conditions.

[0132] 1. Excellent stability: After undergoing rigorous high-temperature and high-pressure cyclic aging (-10℃~180℃, 30MPa, 168h), all three examples maintained good physical stability, with no stratification or precipitation, density changes Δρ less than 0.02g / cm³, and minimal pH changes. In contrast, the comparative examples showed slight turbidity and precipitation, with larger fluctuations in density and pH, indicating insufficient stability under extreme temperature and pressure coupling conditions.

[0133] 2. Superior Corrosion Protection: In a highly corrosive environment simulating deep-sea high mineralization and high CO2 / H2S partial pressure, the corrosion rate of the three typical pipe materials exhibited by this invention was significantly lower than that of the comparative examples, all reaching an excellent level of ≤0.01 mm / a. In particular, Examples 2 and 3 showed even better corrosion inhibition effects with a moderate increase in the concentration of the functional components. This fully demonstrates the effectiveness of the synergistic protection of the green composite corrosion inhibitor and the alkaline formate-based solution.

[0134] 3. Highly efficient scale inhibition, sterilization, and deoxygenation performance: The composite scale inhibitor of this invention achieves a scale inhibition rate exceeding 96% for three common scale types, significantly higher than the comparative example. The zwitterionic bactericide achieves a near 100% sterilization rate against SRB and FB, and its deoxygenation rate remains consistently above 99.5%, maintaining dissolved oxygen at an extremely low level (<20 ppb) for extended periods. This demonstrates the excellent synergistic effect of the multifunctional protective components of the protective fluid, comprehensively addressing various corrosion factors in the deep-sea annulus.

[0135] 4. Excellent environmental friendliness: The biodegradability of the products in the examples all exceed 90%, making them environmentally friendly products that align with the concept of green development. In contrast, the comparative examples contain high concentrations of heavy metal salts (zinc bromide) and recalcitrant organic matter, resulting in a very low biodegradability rate.

[0136] 5. Excellent tool compatibility: Compatibility tests with packer sleeves show that the present invention has a negligible impact on the performance of rubber components, with all parameters changing within an acceptable, minimal range, ensuring the long-term reliability of downhole tools. In contrast, the comparative example has a significantly greater impact on the swelling and aging of rubber.

[0137] 6. Reliable natural gas hydrate inhibition: The specially formulated hydrate inhibitor copolymer exhibits a strong inhibition effect, extending the induction time of hydrate formation to more than 48 hours, which is far superior to the comparative and blank samples, and can effectively ensure the flow safety of the deep-sea cryogenic zone.

[0138] 7. Adjustable density and flexible formulation: By adjusting the content of the composite salt base solution (15%–40%), this invention can easily prepare a series of products with densities ranging from 1.20 to 1.75 g / cm³ or higher (as shown in Examples 1-3), meeting the pressure balance requirements at different well depths. Simultaneously, the proportions of each functional component are adjustable within a certain range to adapt to subtle differences in water quality and corrosive environments in different mining areas.

[0139] In summary, the integrated annular protective fluid solution provided by this invention is comprehensive in function, excellent in performance, environmentally friendly, and suitable for extreme deep-sea conditions. Through innovative component design and compounding, it successfully integrates multiple advantages such as high density, high pressure resistance, wide temperature range stability, efficient synergistic corrosion protection, environmental friendliness, and long service life. It has significant practical significance and application value for promoting the safe, efficient, and green development of deep-sea oil and gas resources. Its comprehensive performance surpasses existing technologies, and it is particularly suitable for the severe challenges of future deep-sea and ultra-deepwater oil and gas field development.

[0140] In conclusion, the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A water-based formate annular protection fluid for deep-sea oil and gas field development, characterized in that: The raw material components include the following weight percentages: organic-inorganic salt composite base liquid 15wt%-40wt%, green composite corrosion inhibitor 3wt%-8wt%, composite oxygen remover 2wt%-5wt%, amphoteric bactericide 1wt%-3wt%, composite scale inhibitor 2wt%-4wt%, high pressure stabilizer 0.5wt%-2wt%, environmentally friendly synergist 0.3wt%-1.5wt%, natural gas hydrate inhibitor 1wt%-3wt%, and the balance being deionized water.

2. The water-based formate annular protection fluid for deep-sea oil and gas field development according to claim 1, characterized in that: The organic-inorganic salt composite base solution is composed of potassium formate, potassium chloride, and potassium acetate in a mass ratio of 8:5:1, and the density adjustment range of the composite base solution is 1.1 g / cm³. 3 -1.8g / cm 3 .

3. The water-based formate annular protection fluid for deep-sea oil and gas field development according to claim 1, characterized in that: The green composite corrosion inhibitor is composed of 2-mercaptobenzimidazole, thiourea and sodium lignosulfonate in a molar ratio of 2:5:

1.

4. The water-based formate annular protection fluid for deep-sea oil and gas field development according to claim 1, characterized in that: The composite oxygen scavenger is composed of dimethyl ketoxime and acetaldehyde oxime in a mass ratio of 2-3:1; the zwitterionic bactericide is selected from one or a mixture of two of hexadecyl dimethyl (2-sulfite) ethylammonium and N-octyl-diaminoethylglycine in any proportion.

5. The water-based formate annular protection fluid for deep-sea oil and gas field development according to claim 1, characterized in that: The composite scale inhibitor is composed of polyaspartic acid and aminotrimethylphosphonic acid in a mass ratio of 1-2:

1.

6. The water-based formate annular protection fluid for deep-sea oil and gas field development according to claim 1, characterized in that: The high-pressure stabilizer is a compound of polyethylene glycol 2000-6000 derivative and modified nano-silica at a mass ratio of 3:1; the environmentally friendly synergist is a biodegradable fatty alcohol polyoxyethylene ether.

7. The water-based formate annular protection fluid for deep-sea oil and gas field development according to claim 1, characterized in that: The natural gas hydrate inhibitor is a copolymer of poly(N-vinylcaprolactam) and polyvinylpyrrolidone in a molar ratio of 3:

7.

8. A method for preparing a water-based formate annular protective fluid for deep-sea oil and gas field development as described in any one of claims 1-7, characterized in that, Includes the following steps: S1: Under the protection of inert gas, deionized water is added to the reactor and bubbled to remove oxygen, so that the dissolved oxygen content is reduced to below 20 ppb. S2: Maintain an inert atmosphere, add organic-inorganic salt composite base liquid, high pressure stabilizer and natural gas hydrate inhibitor, and stir at 200-400 r / min for 30-60 min at 20℃-35℃ until completely dissolved or evenly dispersed; S3: Add the green composite corrosion inhibitor, composite oxygen remover, zwitterionic bactericide, composite scale inhibitor and environmental synergist to the base solution obtained in step S2 in sequence, stir for 40 to 60 minutes until uniform without layering or precipitation, and adjust the pH value to 8.5 to 11.0 to obtain the annular protective solution.

9. The method for preparing the water-based formate annular protective fluid for deep-sea oil and gas field development according to claim 8, characterized in that, In step S1, 0.0001 wt% sodium sulfite is added as an auxiliary oxygen remover, and nitrogen gas is introduced for bubbling and deoxygenation for 30 minutes; in step S3, each functional additive is added and stirred separately for 10 to 15 minutes, with a total stirring time of 40 to 60 minutes, and the pH value is adjusted using sodium carbonate or potassium bicarbonate.

10. A method of using the water-based formate annular protection fluid for deep-sea oil and gas field development according to any one of claims 1-7, characterized in that: After the packer is set, the annular protective fluid is injected into the casing annulus or riser annulus. During the injection process, the flow rate is controlled at 3-5 m / s to achieve dynamic matching between the annular pressure and the external water depth pressure / wellbore pressure. During the service life, the annular pressure, pH value, corrosion rate and bacterial content are monitored regularly, and the protective fluid is replenished or replaced according to the monitoring results.

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