CN115572587A

CN115572587A - Self-stabilizing drilling fluid system under acidic condition

Info

Publication number: CN115572587A
Application number: CN202211235467.5A
Authority: CN
Inventors: 王志祥; 韩庆; 欧涛; 张建东; 许非; 周小龙; 尚杨
Original assignee: Geological Team 403 Of Sichuan Geological And Mineral Exploration And Development Bureau
Current assignee: Geological Team 403 Of Sichuan Geological And Mineral Exploration And Development Bureau
Priority date: 2022-10-10
Filing date: 2022-10-10
Publication date: 2023-01-06
Anticipated expiration: 2042-10-10
Also published as: CN115572587B

Abstract

The invention discloses a self-stabilizing drilling fluid system under an acidic condition, which comprises the following components in part by weight: water, sodium rectorite, sulfonated lignite SMC and hydroxypropyl starch ether HPS; or water, sodium rectorite, sodium carboxymethyl cellulose Na-CMC and cationic polyacrylamide CPAM. The invention constructs a self-stabilizing drilling fluid system under acidic conditions through compounding optimization, and sodium-based rectorite, SMC, HPS, na-CMC and CPAM are respectively used as acid-attack-resistant basic pulping materials, non-tackifying filtrate reducer, tackifying filtrate reducer and flocculant, and the drilling fluid system has the advantages of common raw materials, easy obtainment, small addition and low cost. The system can actively adapt to an acidic environment, has strong acid attack resistance, and maintains stable performance indexes when the pH is = 5. The invention provides a new technical scheme for the acid formation drilling fluid, facilitates the field application, management and performance maintenance of the drilling fluid, and has important practical significance for maintaining the stability of the well wall.

Description

Self-stabilizing drilling fluid system under acidic condition

Technical Field

The invention belongs to the technical field of geological core drilling, and particularly relates to a self-stabilizing drilling fluid system under an acidic condition.

Background

The pH value of the drilling fluid is too high or too low, which can cause adverse effects on the performance of the drilling fluid and the stability of the well wall, and the pH value is generally required to be controlled within the range of 8.5-10. The problems of hydrolysis bond breaking failure of the organic treating agent, promotion of hydration of clay minerals in sedimentary rock stratum, induction of borehole wall instability and the like are easily caused by overhigh pH value, and the problems of obvious increase of water loss of the drilling fluid, rapid change of viscosity, obvious reduction of colloid rate and the like are caused by overlow pH value. The drilling fluid meets the factors of hydrogen sulfide, gypsum, humic acid and the like, or replaces the adsorbed H in the clay through exchange adsorption due to the increase of cations ⁺ This will bring about a rapid decrease in pH. The existing research mainly focuses on the aspects of influencing factors, influencing results, adjusting methods and the like of pH value reduction, and a processing method embodies a 'passive defense' idea, namely, buffering or pH adjusting materials are continuously added into the drilling fluid, the most widely applied method is to supplement NaOH timely, and the processing method can increase the difficulty of field maintenance of the drilling fluid. The prior experience shows that the pH value can be rapidly increased by supplementing NaOH into the drilling fluid, but the characteristic of easy rising and easy falling is obvious, and the performance index of the drilling fluid is obviously deteriorated. In addition, the mudstone can be hydrated in an accelerated manner under the action of NaOH, the stability of the well wall is poor, and the longer the exposed hole section of the drill hole is, the more obvious the influence is.

Disclosure of Invention

The invention aims to overcome the defects of the prior art and provide an acid-condition self-stabilizing drilling fluid system, which is not only convenient for field drilling fluid application, management and maintenance, but also can avoid the side effects of greatly changing the performance of the drilling fluid and weakening the stability of a well wall in the modes of adding NaOH, strong alkali and weak acid salt and the like.

The purpose of the invention is realized by the following technical scheme: an acid condition self-stabilizing drilling fluid system, the drilling fluid system being: water, sodium rectorite, sulfonated lignite SMC and hydroxypropyl starch ether HPS; or water, sodium rectorite, sodium carboxymethyl cellulose Na-CMC and cationic polyacrylamide CPAM.

Further, the sodium rectorite has a mass percentage of 2 to 5 percent.

Further, the mass percentage of the sulfonated lignite SMC is 1-3%, and the mass percentage of the hydroxypropyl starch ether HPS is 0.2-0.4%.

Further, the mass percent of the sodium carboxymethyl cellulose Na-CMC is 0.1-0.3%, and the mass percent of the cationic polyacrylamide CPAM is 0.01-0.03%.

Further, the acid condition self-stabilizing drilling fluid system is further a finely dispersed drilling fluid system: water +4% sodium rectorite +2% sulfonated lignite SMC +0.3% hydroxypropyl starch ether HPS.

Further, the acidic-condition self-stabilizing drilling fluid system is further a non-dispersed drilling fluid system: water +3% sodium rectorite +0.2% sodium carboxymethyl cellulose Na-CMC +0.02% cationic polyacrylamide CPAM.

The invention has the following advantages: the invention constructs an acidic self-stabilizing drilling fluid system through compounding optimization, and changes the traditional mode of adding NaOH, strong alkali and weak acid salt and the like to keep higher pH value to be a passive defense mode with strong acid-attack-resistant capability into an active adaptation mode with strong acid-attack-resistant capability, so that the drilling fluid system can normally play a role under the alkaline condition of higher pH value and the acidic condition of lower pH value, and sodium-based rectorite, sulfonated lignite SMC, hydroxypropyl starch ether HPS, sodium carboxymethyl cellulose Na-CMC and cationic polyacrylamide CPAM are respectively used as acid-attack-resistant basic pulping materials, non-adhesion-increasing filtrate reducer, adhesion-increasing filtrate reducer and flocculating agent. The constructed drilling fluid system can actively adapt to an acidic environment, has strong acid attack resistance, and has stable performance indexes under the acidic condition of pH = 5. The invention provides a new drilling fluid technical scheme for drilling the acid stratum, facilitates the field application, management and performance maintenance of the drilling fluid, and has important practical significance for maintaining the stability of the well wall.

Drawings

FIG. 1 is a graph showing the change of the colloidal rate of the slurry of the basic slurry-making material.

Figure 2 is a 24h colloid photograph of a base slurrying material slurry with acid/base.

Figure 3 is a photograph of a non-viscosifying fluid loss additive slurry plus acid for 24 hours.

Figure 4 is a photograph of viscosifying fluid loss agent slurry plus acid for 24 hours.

Fig. 5 is a photograph of flocculant slurry with acid added for 24 hours.

FIG. 6 is a photograph comparing filtrates before and after adding acid to an acid-conditioned self-stabilized drilling fluid system.

Detailed Description

The invention is further described with reference to the following figures and examples, without limiting the scope of the invention to the following: example 1: one type of dispersed drilling fluid is: water +4% sodium rectorite +2% sulfonated lignite SMC +0.3% hydroxypropyl starch ether HPS. Example 2: one type of dispersed drilling fluid is: water +2% sodium rectorite +1% sulfonated lignite SMC +0.2% hydroxypropyl starch ether HPS. Example 3: one type of dispersed drilling fluid is: water +5% sodium rectorite +3% sulfonated lignite SMC +0.4% hydroxypropyl starch ether HPS. Example 4: one non-dispersing drilling fluid is: water +3% sodium rectorite +0.2% sodium carboxymethyl cellulose Na-CMC +0.02% cationic polyacrylamide CPAM.

Example 5: one non-dispersing drilling fluid is: water +5% sodium rectorite +0.1% sodium carboxymethyl cellulose Na-CMC +0.03% cationic polyacrylamide CPAM.

Example 6: one non-dispersing drilling fluid is: water +2% sodium rectorite +0.3% sodium carboxymethylcellulose Na-CMC +0.01% cationic polyacrylamide CPAM.

The following experiments illustrate the beneficial effects of the present invention:

1 Experimental Equipment and method

1.1 Experimental Equipment

The test equipment comprises: ZNN-D12S intelligent digital display twelve-speed rotary viscometer, SD6B medium pressure water loss instrument, pH meter, EP-C extreme pressure lubricator, HS-17 magnetic stirrer, DQJ type low speed strong stirrer, su' S funnel viscometer, and dropper.

An experimental reagent: hydrochloric acid with the mass fraction of 30%, naOH alkaline solution with the mass fraction of 30%, bentonite A, bentonite B, sodium-based rectorite, sulfonated lignite SMC, potassium humate KHm, sulfonated phenolic resin SMP, sulfonated asphalt SAS, SM vegetable gum, welan gum, hydroxypropyl starch ether HPS, sodium carboxymethyl cellulose Na-CMC, xanthan gum, nonionic polyacrylamide PAM-3, anionic polyacrylamide PHP, cationic polyacrylamide DA-3 and cationic polyacrylamide CPAM.

1.2 Experimental methods

The drilling fluid is prepared according to the experimental formula and then stands for 24 hours to fully hydrate. Under the condition of stirring, dilute hydrochloric acid is dripped into the drilling fluid by a dropper to simulate acid invasion, and a pH meter is used for judging the change condition of the pH value of the drilling fluid in the dripping process. And (3) when the pH value of the drilling fluid is 5, testing various performance indexes of the drilling fluid, and accordingly evaluating the acid attack resistance of the drilling fluid.

2 acid attack resistant Material experiment

2.1 base pulping material

Selecting 110mL of each of bentonite A, bentonite B and sodium-based rectorite-based slurry with the addition of 4%, respectively dropwise adding hydrochloric acid (or NaOH aqueous alkali) to a set pH value, pouring 100mL of the solution into a measuring cylinder, and observing the colloid rate. The data of the number of the relevant slurry, the dropping amount of the hydrochloric acid and the NaOH alkali solution, the pH value and the like are shown in a table 1, the change rule of the colloidal rate of the base slurry is shown in a figure 1, and a 24-hour colloidal photo of the base slurry added with acid/alkali is shown in a figure 2.

TABLE 1 pH Change of base fluid of drilling fluid after acid/base addition

Remarking: the 50 drops were 2.559mL, with an average of about 0.0512 mL/drop

As can be seen from table 1, the amount of hydrochloric acid required for sodium rectorite is significantly lower for a base slurry pH =5 than for the other two bentonites, indicating that the acid buffer capacity of the sodium rectorite slurry is significantly less than for the bentonites. The reason is that the rectorite is a 1: 1 type regular interlayer mineral composed of a mica-like layer and a smectite-like layer, wherein the non-expansive mica-like layer is influenced by non-hydrated cation interlaminar substances to make the Cation Exchange Capacity (CEC) low, and the related data show that the CEC of the rectorite is 36.04mmol/100g, and the CEC of the bentonite mainly based on sodium montmorillonite is 80-150 mmol/100g. Thus, sodium-based rectorite-based drilling fluids are more likely to transition to pH levels comparable to the environment when subjected to acid attack.

The stability of the base slurry colloid includes sedimentation stability and aggregation stability. As can be seen from fig. 1, when the base slurry pH =5, the colloidal rates of bentonite a and bentonite B rapidly decrease within 12 hours, and the colloidal rates are 55% and 56% in 24 hours, respectively, and then gradually stabilize to about 50%. And the 24h colloidal rate of the sodium-based rectorite slurry is 97 percent, and the later period change is not large. After the bentonite slurry is attacked by acid, H ⁺ Generally expressed as H ₃ O ⁺ In the form of (1) to displace the same valence state of hydrated sodium ion [ Na (H) ₂ O)n] ⁺ (n = 3.84), the hydrated film thickness of the montmorillonite is reduced while ionizing the aluminum hydroxyl groups in the aluminous octahedron and adding Al (OH) ²⁺ The form leads the colloid to tend to show positive charge, the zeta potential is reduced, the electrostatic repulsion is reduced, and the physical adsorption of mutual Brownian motion and multi-molecular van der Waals force is gradually obvious, thereby leading the water and soil separation, the agglomeration and sedimentation of the bentonite colloid and the loss of the sedimentation stability to lead the colloid rate to be obviously reduced. The sodium rectorite also contains a smectite-like layer, and the above H is present ⁺ The effect of (2) is that the shape of the colloidal dispersed phase particles is more special probably because of the mixed-layer mica layer, the flaky particles are easier to be connected in a mode of partial plane to end face, partial plane to partial plane and end face to end face, and the method is more beneficial to forming a net structure relative to montmorillonite and maintains the sedimentation stability in a coarse-dispersed state to a gel state.

When the base slurry pH =9, the difference in the amount of the NaOH alkali solution required is small. In general, the amount of Na added ⁺ The displaced colloid originally adsorbed H ⁺ The effect of the sodium hydroxide is not obvious, and the pH value of the slurry can be increased by a small amount of NaOH alkali solution. At the same time, OH under alkaline conditions ^- Can increase negative charges through hydrogen bond adsorption with the surface of the clay mineral crystal lattice, thereby improving the hydration capability of the pulping material.Therefore, bentonite and rectorite slurries generally have better colloid rates than neutrality under alkaline conditions. From the change rule of the colloid rate of the base slurry within 24-144 h, the colloid rate of the sodium-based rectorite slurry is higher than neutral in both acid environment and alkali environment, the colloid rate is gradually increased along with the time extension and the advantages are gradually increased, and the colloid rate under the acid environment, the neutral environment and the alkali environment is respectively 93%, 80% and 93% in 144 h.

Therefore, sodium rectorite is obviously better than bentonite as a base pulping material resistant to acid attack.

2.2 non-tackifying filtrate reducer

Selecting 110mL of 2% addition SMC, KHm, SMP and SAS slurry, respectively dripping hydrochloric acid to a set pH value, pouring 100mL into a measuring cylinder, and observing. The data of hydrochloric acid dropping amount, pH value, 24h colloid rate and the like are shown in a table 2, and a 24h colloid photo of the non-tackifying filtrate reducer slurry added with acid is shown in a figure 3.

TABLE 2 pH and colloidal fraction changes of non-viscosifying fluid loss additive slurries after hydrochloric acid addition

As can be seen from FIG. 3, the SMC slurry was black, showed no rapid sedimentation after hydrochloric acid addition, had a higher acid buffer capacity than the other 3 materials, and had a slightly lower gel fraction at 24 h. The SMC is prepared by reacting sodium humate with sodium hydroxymethyl sulfonate, and although humic acid radicals are used as high-molecular weak acid radicals and are easy to condense when meeting acid, sulfonate groups on molecules belong to strong acid groups with strong water solubility, the high-molecular weak acid radicals can still keep good colloid rate even under acidic conditions, and a small amount of soluble substances still exist in light yellow upper clear liquid. 5363 the slurry of KHm is black, and has no rapid precipitation phenomenon after hydrochloric acid is dropped, but the colloid rate is obviously lower than SMC at 24h, and the supernatant is colorless and transparent. KHm is a complex mixture of high molecular hydroxycarboxylic acids, and fulvic acid, ulmic acid and fulvic acid generated under acidic conditions are difficult to dissolve and difficult to keep colloid stable. The SMP serous fluid is brownish red, quickly turns orange after hydrochloric acid is dropped, and has obviously light chroma and no precipitation phenomenon. SMP is a water-soluble irregular linear high polymer, which is easily degraded by reaction under acidic conditions, and a large amount of beneficial substances are reduced. The SAS slurry is brownish black, the precipitation phenomenon is obvious (2 mL of precipitate), and the chroma is further lightened after hydrochloric acid is dropped. The SAS is formed by introducing sulfonic acid groups with extremely strong water solubility into fused ring aromatic hydrocarbon compounds and heterocyclic compounds of asphalt, but the solubility of the SAS in water-based drilling fluid is poorer than that of other 3 types of compounds probably because sulfonation is incomplete.

Therefore, the sulfonated lignite SMC has better effect as the acid-attack-resistant non-tackifying fluid loss additive.

2.3 viscosity-increasing filtrate-reducing agent

And (3) selecting 110mL of each of SM vegetable gum, welan gum, HPS, na-CMC and xanthan gum serous fluid with the addition of 0.5%, respectively dropwise adding hydrochloric acid to a set pH value, pouring 100mL of the solution into a measuring cylinder, and observing. The data of the related hydrochloric acid dropping amount, the pH value, the funnel viscosity and the like are shown in a table 3, and the 24-hour photo of the viscosity increasing and fluid loss agent slurry added with acid is shown in a figure 4.

TABLE 3 pH of viscosifying fluid loss additive and funnel viscosity Change after hydrochloric acid addition

As can be seen from table 3, the funnel viscosity change was not significant before and after addition of the acid. The SM vegetable gum belongs to natural galactomannan, the acid buffer capacity of slurry of the SM vegetable gum is obviously larger and is 2.8-4.7 times of that of other filtrate reducers, the color of the SM vegetable gum is slightly lightened after acid addition, partial natural fine-particle vegetable debris is easy to be precipitated by acid, and the precipitate is about 6mL. Welan gum belongs to microbial polysaccharide, and the slurry is colorless and transparent, but a large amount of transparent agglomeration occurs when acid is added, so that the welan gum is not beneficial to field stirring. HPS is an anionic high molecular compound, the slurry of the HPS is colorless and transparent, the change before and after adding acid is not obvious, the HPS has a slight bubble phenomenon, but the viscosity is relatively low. Na-CMC is the carboxymethylated derivative of cellulose, and the slurry is transparent and colorless, has no obvious change before and after adding acid, and has relatively higher viscosity. Xanthan gum is a microbial extracellular polysaccharide, and the slurry of the xanthan gum is colorless and transparent, has no obvious change before and after acid addition, but has relatively low viscosity.

Therefore, the hydroxypropyl starch ether HPS, the sodium carboxymethyl cellulose Na-CMC and the xanthan gum have better effects as the acid-invasion-resistant viscosity-increasing fluid loss agent.

2.4 flocculating agent

Selecting 100mL of 0.3 percent addition PAM-3, PHP, DA-3 and CPAM serosity, respectively dripping hydrochloric acid to the set pH value, pouring 50mL of the solution into a measuring cylinder, and observing. The data of the related hydrochloric acid dropping amount, the pH value, the funnel viscosity and the like are shown in a table 4, and a 24-hour photo of the flocculant slurry added with the acid is shown in a figure 5.

TABLE 4 pH of flocculant and funnel viscosity change after hydrochloric acid addition

As can be seen from Table 4, the PHP slurry has the best viscosity-increasing effect, but after the hydrochloric acid is dropped, white flocculent insoluble substances are obviously generated, and the acid attack resistance is poor. PAM-3 and CPAM have reduced viscosity after acid addition, but can keep relative stability before and after acid addition, wherein CPAM slurry is easy to be turbid after being placed for a long time under a neutral condition, and has better stability under an acidic condition. DA-3 is the most difficult to dissolve compared with other 3 materials, and a large amount of bean-shaped transparent particles are easily formed during pulping and stirring, so that the pipeline is easily blocked during recycling, and the field use is inconvenient.

Therefore, the non-ionic polyacrylamide PAM-3 and the cationic polyacrylamide CPAM have better effects as the acid-attack-resistant flocculating agent.

3 acid-invasion-resistant drilling fluid formula optimization

The optimized anti-acid-invasion materials are compounded to prepare different types of anti-acid-invasion drilling fluid systems, and all performances of the drilling fluid systems are tested, and the experimental results are shown in table 5.

Table 5 performance test data table for compounded drilling fluid

Formulations 1-4 belong to the "finely divided drilling fluid system". As can be seen from Table 5, formula 1 has better performance indexes, more stable main performance indexes such as water loss after adding acid, colloid rate, funnel viscosity, dynamic-plastic ratio, lubricity and the like, and the formula is simplest.

Formulas

2, 3 and 4 are prepared by adding a viscosity increasing and fluid loss reducing agent on the basis of the formula 1, and properly increasing viscosity and further reducing the amount of water loss so as to deal with more complex stratum conditions. Wherein, the formula 2 is added with HPS, no obvious agglomeration phenomenon exists after acid addition, and the main index can be well maintained. Formula 3 is added with Na-CMC, and the Na-CMC is slightly agglomerated after acid addition, but is easy to redisperse after stirring, and the main index of the Na-CMC can be well maintained. The xanthan gum is added into the formula 4, so that the obvious agglomeration phenomenon occurs after acid addition, the stirring is not easy to disperse, the viscosity of the funnel is obviously increased, the blockage in a pipeline is easy to cause during the recycling, and the field use is inconvenient. The stability of the compound drilling fluid is observed after the compound drilling fluid is stored for a long time (1 month), and the performance of the formula 2 is more stable. A photograph of a comparison of the filtrates before and after addition of acid to the acid-stabilized drilling fluid systems under acidic conditions of formulations 1-4 is shown in FIG. 6.

The formula 5-6 belongs to a non-dispersed drilling fluid system. As can be seen from Table 5, the performance index itself is better, and the main indexes can be better maintained after adding acid. The preparation process finds that the performance of formula 5 is greatly influenced by the addition sequence of materials, and the stability of the two formulas is observed after long-term storage (1 month), so that formula 6 is more excellent. The filtrate of the self-stabilizing drilling fluid system under the acidic condition of the formula 5-6 is colorless transparent liquid before and after the acid is added, and the difference of the filtrate loss is very small.

Thus, formulation 2 was used as an acid-attack resistant "finely divided drilling fluid system" and formulation 6 was used as an acid-attack resistant "non-divided drilling fluid system".

The above description is only for the preferred embodiment of the present invention, but the scope of the present invention is not limited thereto, and any person skilled in the art can substitute or change the technical solution of the present invention and the inventive concept within the technical scope of the present invention.

Claims

1. An acid-condition self-stabilizing drilling fluid system, wherein the drilling fluid system is: water, sodium rectorite, sulfonated lignite SMC and hydroxypropyl starch ether HPS; or water, sodium rectorite, sodium carboxymethyl cellulose Na-CMC and cationic polyacrylamide CPAM.

2. The acidic condition self-stabilizing drilling fluid system according to claim 1, wherein the sodium-based rectorite is present in an amount of 2 to 5% by mass.

3. The acidic condition self-stabilizing drilling fluid system as claimed in claim 1 or 2, wherein the mass percentage of the sulfonated lignite SMC is 1-3%, and the mass percentage of the hydroxypropyl starch ether HPS is 0.2-0.4%.

4. The acid condition self-stabilizing drilling fluid system according to claim 1 or 2, wherein the sodium carboxymethyl cellulose Na-CMC is 0.1-0.3% by mass, and the cationic polyacrylamide CPAM is 0.01-0.03% by mass.

5. The acid condition self-stabilizing drilling fluid system of claim 1, further being a finely dispersed drilling fluid system: water +4% sodium rectorite +2% sulfonated lignite SMC +0.3% hydroxypropyl starch ether HPS.

6. The acid condition self-stabilizing drilling fluid system of claim 1, further being a non-dispersing drilling fluid system: water +3% sodium rectorite +0.2% sodium carboxymethylcellulose Na-CMC +0.02% cationic polyacrylamide CPAM.