Treating agent for drilling fluid as well as preparation method and application of treating agent

Abstract

The invention discloses a treating agent for drilling fluid as well as a preparation method and application of the treating agent. The treating agent for the drilling fluid is prepared from the following raw materials in percentage by mass: 40 to 80 percent of wollastonite powder, 10 to 80 percent of sepiolite, 5 to 50 percent of basalt and 1 to 10 percent of sodium silicate. The treating agent for the drilling fluid not only can effectively improve the compactness and strength of a transition area between a cement sheath and a well wall in an oil and gas well, but also can improve the affinity between the cement sheath and the well wall so as to achieve the effect of blocking stratum cracks, and then the acting effects of improving the two-interface shear strength of the oil and gas well and improving the packing property of a shaft are achieved. The prepared treating agent for the drilling fluid has the dual effects of interface affinity and plugging performance and is good in compatibility with the water-based drilling fluid, the adding amount of the treating agent in the drilling fluid is 0.3-2 wt%, the well cementation two-interface shear strength can be improved by 20-30 times, the mud cake permeability is reduced by 30-50%, and the interface affinity and plugging performance effects are remarkable.

Description

Technical Field

[0001] The invention relates to a treating agent for drilling fluid and a preparation method and application thereof. Background Art

[0002] Improving cementing quality has always been a technical bottleneck in drilling operations, and the quality of cementing directly affects the results of oilfield exploration and development. With the continuous improvement of completion technology, the completion technology of perforation and fracturing has been applied on a large scale, and cementing quality is a crucial factor, which directly affects the effect of later fracturing. Common cementing quality problems are mainly reflected in four aspects: one is the interlayer channeling problem after the development well is put into production, the second is the problem of oil, gas and water leaking out of the pipe after cementing, the third is the sound change problem of the entire annulus, and the fourth is the sound amplitude problem of the cementing interface. The root cause of these cementing quality problems is the failure of the cementing interface sealing system.

[0003] With the continuous optimization of the wellbore structure of oilfield development wells, development wells within 3,800m have been changed from three openings to two openings, which has greatly reduced drilling costs while posing new challenges to cementing quality standards. At present, polymer drilling fluids are mostly used in development wells. The small solid particles in the completion stage are less than 1 micron, which corresponds to the estimated value of the sandstone pore throat radius of 10 to 15 microns, far less than the 1 / 3 rule, and are easy to enter the formation and form thick mud cakes. In addition, the polymer drilling fluid system has a high viscosity and a low flushing effect on the well wall. On-site drilling fluid testing shows that when the funnel viscosity is greater than 85s, the mud cake surface is prone to adhere to 2 to 3 mm thick drilling fluid. During the cementing process, a large amount of drilling fluid that cannot be replaced by clean drilling fluid remains on the well wall, resulting in the formation of loose and unsolidified mud cakes on the well wall. The mud cakes are basically not bonded to the cement slurry. During the solidification of the cement slurry, the water in the mud cakes slowly permeates into the formation and shrinks in volume, accompanied by varying degrees of pulverization. The unsolidified layer at the bonding surface forms varying degrees of peeling and microcracks, forming a weak cementing interface, which is particularly prominent for high-permeability formations and formations prone to leakage. The existence of a weak cementing interface leads to the failure of cementing at the cementing interface, becoming the weakest link in the entire annular sealing system, providing a channel for the cross-flow of oil, gas and water in the later stage, greatly reducing the effectiveness of production-increasing measures such as stratified injection and fracturing. Summary of the invention

[0004] In order to at least partially solve the above-mentioned technical problems existing in the prior art, an embodiment of the present invention provides a drilling fluid treatment agent and a preparation method thereof for improving interface affinity and enhancing wellbore sealing performance, so as to improve the shear strength of the interface between oil and gas wells and enhance the wellbore sealing performance.

[0005] As one aspect of the present invention, a treating agent for drilling fluid is provided, which comprises the following raw materials by mass percentage: 40-80% wollastonite powder, 10-80% sepiolite, 5-50% basalt and 1-10% sodium silicate.

[0006] In one or some possible embodiments, the particle size of the wollastonite powder is 200-1500 mesh.

[0007] In one or some possible embodiments, in the wollastonite powder, the content of SiO2 is not less than 50%, and the content of CaO is not less than 45%.

[0008] In one or some possible embodiments, the sepiolite is velvety, the velvet length of the velvet sepiolite is 0.15-0.85 mm, and the content of the velvet is not less than 60%.

[0009] In one or some possible embodiments, the basalt is in a fibrous shape, and the length of the basalt fiber is 3 to 12 mm.

[0010] In one or some possible embodiments, the modulus of the sodium silicate is 1-2.

[0011] As another aspect of the present invention, it relates to a method for preparing the above-mentioned treatment agent for drilling fluid. In the method, the component raw materials are mixed according to the formula amount to prepare the treatment agent.

[0012] As another aspect of the present invention, it relates to the use of the above-mentioned drilling fluid treatment agent in water-based drilling fluid.

[0013] As another aspect of the present invention, it relates to a water-based drilling fluid, wherein the water-based drilling fluid uses the above-mentioned drilling fluid treatment agent; wherein, in the water-based drilling fluid, the amount of the treatment agent is 0.3-2.0wt%.

[0014] The beneficial effects of the above technical solution provided by the embodiment of the present application include at least:

[0015] The drilling fluid treating agent of the present invention can not only effectively improve the density and strength of the transition zone between the cement sheath and the well wall in the oil and gas well, but also enhance the affinity between the cement sheath and the well wall to achieve the effect of sealing the formation cracks, thereby improving the shear strength of the two interfaces of the oil and gas well and enhancing the sealing effect of the wellbore.

[0016] The drilling fluid treating agent of the present invention has the dual effects of interface affinity and plugging performance, has good compatibility with water-based drilling fluid, and can increase the shear strength of the cementing interface by 20-30 times and reduce the mud cake permeability by 30-50% by adding 0.3%-2wt% of the treating agent to the drilling fluid, and has remarkable effects on interface affinity and plugging performance.

[0017] The treating agent for drilling fluid prepared by the invention is added into the mud pool through a feeding funnel before drilling to a formation prone to leakage. When used for on-site cementing, the construction is simple and a large amount of energy consumption is not required.

[0018] The drilling fluid treatment agent prepared by the invention has cheap and easily available raw materials, and the price per ton of the prepared treatment agent ranges from 3,000 to 7,000 yuan. The preparation cost is low, and better economic benefits can be achieved. DETAILED DESCRIPTION

[0019] The exemplary embodiments of the present disclosure will be described in more detail below. The following are exemplary embodiments of the present disclosure, but it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments set forth herein. On the contrary, these embodiments are provided to enable a more thorough understanding of the present disclosure and to fully convey the scope of the present disclosure to those skilled in the art.

[0020] It should be understood that the terms described in the present invention are only for describing special embodiments and are not intended to limit the present invention. In addition, for the numerical range in the present invention, it should be understood that each intermediate value between the upper and lower limits of the scope is also specifically disclosed. Each smaller range between the intermediate value in any stated value or stated range and any other stated value or intermediate value in the described range is also included in the present invention. The upper and lower limits of these smaller ranges can be independently included or excluded in the scope.

[0021] Unless otherwise indicated, all technical and scientific terms used herein have the same meanings as commonly understood by those skilled in the art to which the invention belongs. Although the present invention describes only preferred methods and materials, any methods and materials similar or equivalent to those described herein may also be used in the implementation or testing of the present invention. All documents mentioned in this specification are incorporated by reference to disclose and describe the methods and / or materials related to the documents. In the event of a conflict with any incorporated document, the content of this specification shall prevail.

[0022] In the description of the present invention, it should be noted that the terms "include", "including", "have", "contain" and the like are open terms, meaning including but not limited to.

[0023] The present invention is further described below in conjunction with specific examples, and the protection scope of the present invention is not limited by the following examples. The sources of materials mainly involved in the examples are all conventional commercial products.

[0024] Example 1

[0025] The raw materials of the treatment agent for drilling fluid of this embodiment include: 40% wollastonite powder, 40% velvety sepiolite, 15% basalt fiber, and 5% sodium carbonate. The above raw materials are mixed to obtain the treatment agent SSL1 of this embodiment.

[0026] The treatment agent SSL1 with different mass concentrations was added into the well slurry. The formula of the well slurry was as follows: bentonite: 20-40 kg / m3 、Na2CO3:2~4kg / m 3 , NaOH: 1~2kg / m 3 , Lifting agent: 3~6kg / m 3 , Viscosity reducer: 8~10kg / m 3 , Coating agent: 5~10kg / m 3 、PAC-LV: 10~20kg / m 3 , Salt-resistant fluid loss reducer: 10~15kg / m 3 , Filtrate reducer: 5~10kg / m 3 , Liquid lubricant: 10~20kg / m 3 , Solid lubricant: 5~15kg / m 3 , Anti-collapse agent: 10~20kg / m 3 , Fine mesh calcium carbonate: 15~30kg / m 3 .

[0027] The viscosity, density and six-speed parameters of the well slurry before and after the addition of the agent were measured; the API filtration and high-temperature and high-pressure filtration of the well slurry before and after the addition of the agent were measured, and the filtration loss was recorded; the above measurements were carried out in accordance with the relevant records in GB / T 16783.1-2014 Field Test of Drilling Fluids in the Petroleum and Natural Gas Industry Part 1: Water-Based Drilling Fluids;

[0028] In addition, the mud cake prepared by high temperature and high pressure filtration was placed in fresh cement filtrate at 120°C for 5 days to measure the strength, thickness and permeability of the mud cake. The determination method of the strength and thickness of the mud cake is based on Zhang Jianwei. Water-based drilling fluid mud cake performance control method and cementing weak interface enhancement technology research [D]. Northeast Petroleum University, 2020. The permeability was determined by referring to the relevant methods recorded in SY / T 6385-2016 Rock porosity and permeability determination method under overburden pressure.

[0029] The above test results are recorded in Tables 1 and 2 below.

[0030] Table 1 Results of determination of basic physical properties of well slurry

[0031]

[0032] Table 2 Mud cake performance test results

[0033]

[0034] Example 2

[0035] The raw materials of the treatment agent for drilling fluid of this embodiment include: 60% wollastonite powder, 20% velvety sepiolite, 17% basalt fiber, and 3% sodium carbonate. The above raw materials are mixed to obtain the treatment agent SSL2 of this embodiment.

[0036] 1.1wt% of treated SSL2 was added to the well slurry. The well slurry formula was as follows: Bentonite: 20-40kg / m 3 、Na2CO3:2~4kg / m 3 , NaOH: 1~2kg / m 3 , Lifting agent: 3~6kg / m 3 , Viscosity reducer: 8~10kg / m 3 , Coating agent: 5~10kg / m 3 、PAC-LV: 10~20kg / m 3 , Salt-resistant fluid loss reducer: 10~15kg / m 3 , Filtrate reducer: 5~10kg / m 3 , Liquid lubricant: 10~20kg / m 3 , Solid lubricant: 5~15kg / m 3 , Anti-collapse agent: 10~20kg / m 3 , Fine mesh calcium carbonate: 15~30kg / m 3 .

[0037] The shear strength of the treating agent SSL2 was tested. The test method was based on the relevant methods described in Zhang Jianwei. Water-based drilling fluid mud cake performance control method and cementing weak interface enhancement technology research [D]. Northeast Petroleum University, 2020. Specifically, the standard core column was soaked in the above-mentioned drilling fluid for a certain period of time, and then placed in a mold, and cement slurry was poured in the annular space between the mold and the core column. After curing at room temperature for 24 hours, the mold was placed at 120°C for constant temperature maintenance for 7 days, and then the mold was taken out, the maximum pressure when the core column was pressed out of the cement ring was measured, and the shear strength of the core column and the cement ring was calculated. The experimental results are shown in Table 3 below.

[0038] Table 3 Cement sheath-core shear strength determination

[0039]

[0040] Example 3

[0041] The raw materials of the treatment agent for drilling fluid of this embodiment include: 80% wollastonite powder, 10% velvety sepiolite, 9% basalt fiber, and 1% sodium carbonate. The above raw materials are mixed to obtain the treatment agent SSL3 of this embodiment.

[0042] The treatment agent SSL3 with different mass concentrations was added into the well slurry. The formula of the well slurry was as follows: bentonite: 20-30 kg / m 3 、Na2CO3:2~3kg / m 3 , NaOH: 1~2kg / m3 , Lifting agent: 1~3kg / m 3 , Viscosity reducer: 5~8kg / m 3 , Coating agent: 8~10kg / m 3 、PAC-LV: 10~20kg / m 3 , Salt-resistant fluid loss reducer: 13~17kg / m 3 , Filtrate reducer: 6~11kg / m 3 , Liquid lubricant: 10~20kg / m 3 , Solid lubricant: 5~15kg / m 3 , Anti-collapse agent: 15~20kg / m 3 .

[0043] The viscosity, density and six-speed parameters of the well slurry before and after the addition of the agent were measured; in addition, the well slurry before and after the addition of the agent was subjected to API filtration loss and high-temperature and high-pressure filtration loss, and the filtration loss amount was recorded. The mud cake prepared by high-temperature and high-pressure filtration loss was placed in fresh cement filtrate and maintained at a constant temperature of 120°C for 5 days, and the strength, thickness and permeability of the mud cake were measured. The results are shown in Tables 4 and 5.

[0044] Table 4 Results of determination of basic physical properties of well slurry

[0045]

[0046] Table 5 Mud cake performance test results

[0047]

[0048]

[0049] Example 4

[0050] The raw materials of the treatment agent for drilling fluid in this embodiment include: 80% wollastonite powder, 10% velvety sepiolite, 9% basalt fiber, and 1% sodium carbonate. The above raw materials are mixed to obtain the treatment agent SSL4 in this embodiment.

[0051] 2.0wt% of the treatment agent SSL3 was added to the well slurry. The formula of the well slurry was as follows: bentonite: 20-30kg / m 3 、Na2CO3:2~3kg / m 3 , NaOH: 1~2kg / m 3 , Lifting agent: 1~3kg / m 3 , Viscosity reducer: 5~8kg / m 3 , Coating agent: 8~10kg / m 3 、PAC-LV: 10~20kg / m 3 , Salt-resistant fluid loss reducer: 13~17kg / m 3, Filtrate reducer: 6~11kg / m 3 , Liquid lubricant: 10~20kg / m 3 , Solid lubricant: 5~15kg / m 3 , Anti-collapse agent: 15~20kg / m 3 .

[0052] The standard core column was soaked in the above drilling fluid for a certain period of time and then placed in a mold. Cement slurry was poured into the annular space between the mold and the core column. After curing at room temperature for 24 hours, the mold was placed at 120°C for constant temperature curing for 7 days. The mold was then taken out and the maximum pressure when the core column was pressed out of the cement ring was measured, and the shear strength between the core column and the cement ring was calculated. The experimental results are shown in Table 6.

[0053] Table 6 Cement sheath-core shear strength determination

[0054]

[0055]

[0056] It can be seen from Example 1 that after the dual-effect water-based drilling fluid treatment agent with interface affinity and plugging performance of the present invention is added to the drilling fluid in different amounts, the viscosity, density, six speed and other parameters of the drilling fluid are basically unchanged, indicating that the dual-effect water-based drilling fluid treatment agent with interface affinity and plugging performance of the present invention has good compatibility with the drilling fluid.

[0057] As can be seen from Example 1 and Example 3, the double-effect water-based drilling fluid treatment agent with interface affinity and plugging performance of the present invention can increase the strength of the mud cake to 15.5 times, 11.2 times and 17.8 times of the original when the addition amount is 0.3%, 1.1% and 2% respectively, the thickness of the mud cake is reduced by 21.7%, 40.1% and 49.8% respectively, and the plugging performance is improved by 44.4%, 46.0% and 46.2% respectively. Compared with the existing treatment agent with the same function, the double-effect water-based drilling fluid treatment agent with interface affinity and plugging performance of the present invention has significant effects in increasing the strength of the mud cake, reducing the thickness and improving the plugging performance.

[0058] It can be seen from Examples 2 and 4 that the dual-effect water-based drilling fluid treatment agent with interface affinity and plugging performance of the present invention improves the interface affinity effect to 25.8 times and 29.8 times that of the case without the addition of the agent; at the same addition dosage, compared with other existing interface enhancers, the interface affinity improvement ratio is 3.5 times and 4.1 times that of the former. The dual-effect water-based drilling fluid treatment agent with interface affinity and plugging performance of the present invention has good interface enhancement performance.

[0059] Although the description of the present invention has been quite detailed and has been described in particular with respect to several described embodiments, it is not intended to be limited to any of these details or embodiments or any particular embodiment, so as to effectively cover the intended scope of the present invention. In addition, the present invention is described above with the embodiments foreseeable by the inventors, and its purpose is to provide a useful description, and those non-substantial changes to the present invention that are not currently foreseen may still represent equivalent changes of the present invention.

[0060] In the description of this specification, the description with reference to the terms "one embodiment", "some embodiments", "illustrative embodiments", "examples", "specific examples", or "some examples" means that the specific features, structures, materials or characteristics described in conjunction with the embodiment or example are included in at least one embodiment or example of the present invention. In this specification, the schematic representation of the above terms does not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials or characteristics described may be combined in any one or more embodiments or examples in a suitable manner.

[0061] Although the embodiments of the present invention have been shown and described, it will be appreciated by those skilled in the art that various changes, modifications, substitutions and variations may be made to the embodiments without departing from the principles and spirit of the present invention, and that the scope of the present invention is defined by the claims and their equivalents.

Claims

1. A treatment agent for drilling fluid, characterized in that: The treating agent comprises the following raw materials by mass percentage: 40-80% of wollastonite powder, 10-80% of sepiolite, 5-50% of basalt and 1-10% of sodium silicate.

2. The drilling fluid treating agent according to claim 1, characterized in that: The particle size of the wollastonite powder is 200-1500 meshes.

3. The drilling fluid treating agent according to claim 1, characterized in that: In the wollastonite powder, the content of SiO2 is not less than 50%, and the content of CaO is not less than 45%.

4. The drilling fluid treating agent according to claim 1, characterized in that: The sepiolite is in a velvety state, the velvet length of the velvety sepiolite is 0.15-0.85 mm, and the content of the velvet is not less than 60%.

5. The drilling fluid treating agent according to claim 1, characterized in that: The basalt is in a fibrous shape, and the length of the basalt fiber is 3 to 12 mm.

6. The drilling fluid treating agent according to claim 1, characterized in that: The modulus of the sodium silicate is 1-2.

7. A method for preparing the drilling fluid treating agent according to any one of claims 1 to 6, characterized in that: The method comprises mixing the constituent raw materials according to the formula amount to prepare the treating agent.

8. Use of the drilling fluid treating agent according to any one of claims 1 to 6 in water-based drilling fluid.

9. A water-based drilling fluid, characterized in that: The water-based drilling fluid uses the drilling fluid treating agent according to any one of claims 1 to 6.

10. The water-based drilling fluid according to claim 9, characterized in that: In the water-based drilling fluid, the amount of the treating agent is 0.3-2.0 wt %.

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