RU2521259C1 - Drilling mud - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: drilling mud containing hydrocarbon phase and surface-active substances, weighing agent, mineral salts, a stabilising agent and water includes MULTIOL additive as hydrocarbon phase and surface-active substances, MULTISTAR additive, xanthane gum and additional sodium hydroxide as a stabilising agent with the following ratio of the components, wt %: MULTIOL additive 8.5-25, MULTISTAR stabilising agent 1.5-2.0, xanthane gum 0.2-0.5, calcium carbonate 5-20, magnesium chloride 4-15, sodium hydroxide 1-2, water - the remaining quantity. Invention is developed in dependent claims.

EFFECT: improvement of inhibiting and lubricating properties.

8 cl, 2 ex, 2 tbl

Description

The invention relates to the oil and gas industry, namely, clay-free gel-emulsion drilling fluids for drilling directional and horizontal oil and gas wells with various deviations from the vertical. The solution is suitable for drilling the main trunk, and for opening productive formations. Moreover, the solution is ideally suited for drilling unstable clay deposits, such as: the Koshai pack of the Alym suite, the Yanostanov suite, the “Kyn clays”, the “chocolate clays” of Western Siberia, the Achimov mudstones and others.

Known emulsion drilling fluid (RF patent No. 21114889, IPC C09K 7/02, publ. 07/10/1998), comprising a dispersion medium, a dispersed phase and an emulsifier. Known drilling fluid has the following disadvantages: a narrow range of densities, which narrows the scope of this fluid, high nominal viscosity (up to non-fluid fluid), which creates problems when pumping the fluid.

The closest in composition and technological essence is an emulsion drilling fluid (RF patent No. 2213761, IPC C09K 7/06, publ. 10.10.2003) containing the hydrocarbon phase, calcium carbonate, mineral salt, stabilizer, surfactant and mineralized water. Known drilling fluid has a fairly low coefficient of recovery of core permeability, that is, causes pollution of the reservoir. In addition, low values of static shear stress (SSS) indicate possible problems with the removal of sludge and its subsidence during circulation stops.

The objective of the invention is to develop a highly effective gel-emulsion drilling fluid, suitable for drilling active and unstable clay deposits, horizontal shafts and opening a reservoir with enhanced inhibitory and lubricating properties, and acting as an alternative to hydrocarbon-based solutions.

The problem is solved in that the drilling fluid containing the hydrocarbon phase and surfactants, calcium carbonate, mineral salts, stabilizer and water, according to the invention, contains the MULTIOL reagent as the hydrocarbon phase and surfactants, and MULTISTAR as the stabilizer and , additionally, sodium hydroxide and xanthan gum, in the following ratio of components, wt.%:

Reagent MULTIOL 8.5-25 STABILIZER MULTISTAR 1.5-2.0 Xanthan gum 0.2-0.5 Calcium carbonate 5-20 Magnesium chloride 4-15 Sodium hydroxide 1-2 Water Rest

Additionally, calcium chloride may be contained with a total chloride content of not more than 40 wt.%, Or potassium chloride with a total chloride content of not more than 30 wt.%, Or sodium chloride with a total chloride content of not more than 45 wt.%

Additionally, calcium and potassium chloride, or calcium and sodium chloride may be contained with a total chloride content of not more than 55 wt.%

Additionally, potassium and sodium chloride may be contained with a total chloride content of not more than 50 wt.%

Additionally, calcium, sodium and potassium chloride may be contained with a total chloride content of not more than 55 wt.%

As a stabilizer, a polysaccharide reagent is used, for example, starch modified for drilling MULTISTAR (TU 2458-029-50783875-2012), and additionally xanthan gum, for example, Zibaxan manufactured by Deosen.

MULTIOL drilling fluid additive is used as the hydrocarbon phase and surfactant; it is produced according to TU 2458-032-50783875-2012. Additive for drilling fluids MULTIOL, designed to improve lubricating properties, reduce contamination of the bottom-hole zone of the formation, increase the stability of the walls of the borehole, prevent gland formation. The additive is a mixture of non-polar fluids of natural or synthetic origin with surfactants intended for its emulsification in aqueous drilling fluids and hydrophobization of contact surfaces. According to physico-chemical parameters, the additive meets the following requirements and standards given in TU:

Name of indicator Value table 1. Appearance Homogeneous clear liquid dark brown without strangers inclusions 2. Density at 20 ° C, g / cm ³ , no more 1.10 3. Kinematic viscosity at 40 ° C, mm ² / s, within 30-300 4. Pour point, ° C, not higher -twenty

Calcium carbonate (ground marble, chalk (TU 5716-001-05494314-2010)) is used as a weighting agent and colmatant. Also, the necessary density can be achieved by adding mineral salts.

Chlorides of sodium, calcium, magnesium, potassium in various combinations can be used as mineral salts.

The following salts were used to prepare the solution under laboratory conditions:

Magnesium chloride (CAS # 7786-30-3, MERCK) in the presence of sodium hydroxide is a gelling agent.

Calcium chloride (according to GOST 450-77) acts as a weighting agent for drilling mud and an inhibitor of swelling of shale.

Potassium chloride (according to GOST 4568-95) acts as a weighting agent for drilling mud and an inhibitor of swelling of shale.

Sodium chloride (according to TU 2111-006-00352816-2008) acts as a weighting agent for drilling mud and an inhibitor of swelling of shales.

Sodium hydroxide (according to TU 2132-185-00203312-99). It is a pH regulator and causes gelation.

To prevent biodegradation of polymers, it is possible to add a bactericide, for example, LPE-32 according to TU 2458-039-00209295-02.

There is an emulsion drilling fluid based on a polysaccharide polymer (US Pat. RF No. 2255105), where gelation is achieved by the interaction of a biopolymer and a salt of boric acid and is not the main property. In the inventive solution, a hydrogel is formed, stabilized by specially selected nonionic polymers. Hydrogels have high pseudoplastic properties, i.e., at rest, structural and mechanical properties increase due to the growth of Mg (OH) ₂ crystals and oxychlorides and their splicing with each other according to the coagulation principle, which ensures high quality of wellbore cleaning.

In the MULTIBUR solution, a mixture of salts is used, which are simultaneously weighting agents and inhibitors of clay swelling. Due to the use of monovalent and divalent metal cations, the solution allows to ensure the activity of the filtrate equal to or lower than the activity of the formation fluid saturating clay rocks, which eliminates the swelling of clay minerals due to adsorption-osmotic processes on the well wall and prevents the occurrence of related problems.

The prevention of gland formation, increased lubricity and stability of the well walls when using the inventive MULTIBUR solution is achieved by hydrophobization and a change in the type of wetting of the capillaries of the rock by emulsion of the first kind. The dispersed phase is MULTIOL, an additive for drilling fluids.

Due to the presence of MULTIOL drilling fluid additives in the MULTIBUR solution, a hydrophobic filter cake is formed at the reservoir-well boundary, which has a reduced permeability to water, which reduces the pollution of the reservoir.

Patents for hydrogel and polymer-hydrogel drilling fluids were studied (Pat. RF №2135542, ZI №97100696, №2000109400). Existing hydrogel solutions do not contain emulsions of the first kind that can form a hydrophobic film. Thus, MULTIBUR has a new property, which determines the inventive step.

A method of preparing a drilling fluid is as follows.

Example 1

1.0 g of Zibaxan xanthan gum, 12 g of MULTISTAR stabilizer, 20 g of magnesium chloride, 200 g of calcium carbonate are added to 507 g of water with stirring. After the introduction of each component, the solution is stirred with a laboratory stirrer for 15-20 minutes. 255 g of MULTIOL additive is added to the aqueous solution and stirred for 30 minutes with a high-speed mixer. 5 g of NaOH are added. The finished solution is left for 16 hours under normal conditions in a closed container. After which the solution is stirred for 5 minutes and its parameters are measured.

Example 2

In 568 g of water, 2.0 g of Zibaxan xanthan gum, 15 g of MULTISTAR stabilizer, 50 g of magnesium chloride, 100 g of calcium carbonate, 100 g of calcium chloride are added with stirring. After the introduction of each component, the solution is stirred with a laboratory stirrer for 15-20 minutes. To the resulting solution was added 150 g of MULTIOL additive and stirred for 30 minutes with a high-speed mixer. 15 g of NaOH are added. The finished solution is left for 16 hours under normal conditions in a closed container. After which the solution is stirred for 5 minutes and its parameters are measured.

Similarly prepared other compositions of the inventive drilling fluid with a different ratio of ingredients. Table 1 shows the data on the component compositions of the investigated solutions. Solutions 2-17 contain components of the proposed formulation in various concentrations. Solutions No. 1 and 18 are shown in the table as experimental and contain components in amounts below the lower and outside the upper limits, respectively, but with such ratios the task is not achieved.

Table 1 The composition of the solution, wt.% No. p.p. one 2 3 four 5 6 7 8 9 10 eleven 12 13 fourteen fifteen 16 17 eighteen Prototype Xanthan gum 0.1 0.2 0.5 0.2 0.5 0.5 0.2 0.5 0.2 0.5 0.2 0.3 0.5 0.5 0.2 0.2 0.5 0.7 MULTISTAR 1,2 1,5 2.0 1,5 2.0 1,5 2 1,5 2.0 1,5 2.0 1,5 2.0 1,5 2 2 1,5 2,5 Magnesium chloride 2 5 5 fifteen four four fifteen four fifteen four fifteen four fifteen four fifteen four fifteen 17 10 Calcium chloride 0 10 3 25 25 3 3 25 25 3 35 Potassium chloride fifteen 3 fifteen 3 fifteen 3 3 fifteen 5 Sodium chloride thirty 5 5 twenty 5 twenty 5 10 Calcium carbonate twenty 10 10 twenty 5 5 twenty twenty 5 twenty 5 twenty 5 5 5 10 5 2 5 MULTIOL 25.5 fifteen 10 10 25 twenty 8.5 8.5 25 25 8.5 25 8.5 fifteen 10 8.5 fifteen 5 NaOH 0.5 1,5 2 2 2 one 2 2 2 one 2 one 2 one 2 2 2 2 Water 50.7 56.8 70.5 33.3 33.5 38 47.3 33.5 27.8 28 44.3 45,2 42 58 62.8 40.3 33 35.8 49 Oil twenty Starch Phyto RK four Surfactant PKD-515 7

Concentrations of polymers are taken in accordance with the recommendations of the manufacturers. The crystalline hydrates formed in the solution have an excess supply of free energy and therefore are unstable neoplasms subject to thermal and mechanical degradation. A decrease in the concentration of xanthan gum below 0.2 wt.% Will lead to a deterioration in rheological parameters due to thermal and mechanical destruction of the crystallization-coagulation structure. An increase in the concentration of xanthan gum above 0.5% will cause a strong thickening of the solution. A decrease in the concentration of the MULTISTAR stabilizer below 1.5 wt.% Will lead to an increase in the filtration rate. An increase in the content of the MULTISTAR stabilizer above 2.0 wt.% Is impractical, since it does not cause a significant decrease in the filtration rate.

The content of the additive MULTIOL is due to the density of the solution and the hydrophobization of the clay surface. When pieces of sludge get into MULTIBUR, a hydrophobic film is formed on their surface, which performs the function of an encapsulator. At a concentration of MULTIOL reagent below 8.5 wt.%, The necessary hydrophobization of the rock will not be achieved, that is, the percentage of dispersed sludge in the solution will increase, and at a concentration above 25 wt.% The stability of the emulsion and its parameters deteriorates, and the cost of the solution increases.

The content of magnesium chloride depends on the water content. For the formation of a hydrogel, adding 4 wt.% With respect to water is sufficient. An increase in the concentration of magnesium chloride above 15 wt.% Leads to a significant increase in viscosity and loss of fluidity of the solution.

The concentration of calcium chloride affects the density of the solution and the activity of the filtrate. The more calcium chloride, the lower the activity of the solution, the higher its inhibitory ability with respect to shales. Therefore, the minimum content of calcium chloride is 3 wt.%. The maximum concentration is due to the solubility of salts and the effect on polymers. The addition of more than 25 wt.% Calcium chloride may not dissolve in the presence of other salts.

The concentration of potassium chloride in the solution is less than 3 wt.% Or sodium chloride less than 5 wt.% Does not allow to achieve the required level of inhibition of the drilled rocks, and the addition of potassium chloride more than 15 wt% or sodium chloride more than 30 wt.% May not dissolve in the presence of other salts .

The concentration of calcium carbonate is due to the required density of the solution. In this case, the concentration of chalk for the formation of a crusting crust should be at least 5 wt.%. Adding more than 20 wt.% Chalk can adversely affect the rheological parameters of the solution.

Assessment of the main technological parameters of the studied fluids was carried out using standard instruments and techniques (Ryazanov Y.A. Guide to drilling fluids. M .: Nedra, 1979; Recommended practice for laboratory research of drilling fluids 13I / ISO 10416: 2002; Recommended practice for field research hydrocarbon-based solutions 13 B-2). In laboratory conditions, the following properties of drilling fluids were analyzed:

- specific gravity (ρ, g / cm ³ ) was determined using lever weights;

- conditional viscosity (HC, s) was measured using VP-5;

- the filtration rate (PF, cm ³ at a pressure drop of 0.7 MPa) was measured on an OFITE filter press;

- rheological properties — plastic viscosity (PV, mPa · s), dynamic shear stress (YP, dPa) and static shear stress after 10 s and 10 min (CHC _10/10 , dPa), were measured on an OFITE rotational 8-speed viscometer ;

- pH (pH) was measured on an ACORN instrument;

- the recovery coefficient of the permeability of the bottom-hole formation zone (β,%) was determined using the FDS-350 installation on cores of terrigenous reservoirs;

- the activity of the solution (A) was measured using a Sensing GE electro-hygrometer;

- the percentage of retained sludge (D,%) (dispersing ability) was determined using aging cells and a roller kiln according to the following procedure.

The test solution is placed in a metal cell aging drilling fluids. A suspended compressed sample of PBN bentonite (ml) simulating sludge is also placed in the cell. The cell with the test solution and clay slurry is rotated in a roller furnace for 16 hours at 50 ° C. After the set time has elapsed, the solution is removed from the cell and filtered through a mesh with a mesh size of 1 mm. The remainder of the sludge sample is removed, washed with a stream of water with a low pressure and dried for 16 hours at a temperature of 105 ° C. The influence of the test solution on the dispersion of clay mud in the drilling fluid medium is estimated by the residual clay mass (m2) (expressed as a percentage) after the experiment that has not passed through the grid:

D = (m2 ∗ 100) / m1,%.

Table 2 provides information on the technological parameters of the investigated solutions.

table 2 one 2 3 four 5 6 7 8 9 10 eleven 12 13 fourteen fifteen 16 17 eighteen Prototype ρ, g / cm ³ 1.10 1.18 1.09 1.35 1.27 1.22 1.17 1.39 1.23 1.25 1.29 1.14 1.38 1.13 1.16 1.16 1.33 1.49 1.18 HC, sec 40 55 45 54 42 43 53 62 52 60 54 51 65 45 55 48 68 150 thirty PD cm ^3/30 minutes at 0.7 MPa 10 3 2,4 2.2 2.6 2.9 1,6 2.7 1.9 2,8 1.7 3 2,5 2,5 1,5 2.7 2.9 2,4 2 SNA _10/10 , dPa 10/10 30/40 10/12 38/57 26/35 24/33 39/56 27/35 40/59 29/37 21/29 19/27 45/65 19/27 42/60 29/38 48/67 55/75 1.1 / 1.4 PV, MPa · s 13.5 17 fourteen 21 16 eighteen 22 24 twenty 27 eighteen 16 25 fourteen 21 16 27 45 YP, dPa 5 twenty 26 27 21 24 26 23 27 26 17 fourteen 35 16 29th eighteen 36 fifty pH 8.2 8 8.4 8.1 8.3 8.3 8.5 8.6 8.4 8 8 8.5 8.2 8.1 8.3 8 8.1 8.3 β,% 90 92 95 95 94 93 95 96 94 96 94 95 94 94 93 94 92 91 87 BUT 0.9 0.85 0.94 0.84 0.38 0.74 0.89 0.36 0.68 0.88 0.64 0.89 0.4 0.8 0.9 0.32 0.43 0.3 D% 96 95 95 95 97 96 95 94 95 97 93 97 94 96 95 95 96 88 After incubation for 16 hours at 95 ° C PV, MPa · s 13 eighteen fifteen 19 19 21 eighteen 23 17 twenty 19 fourteen 23 twenty 16 17 twenty 42 YP, dPa one 10 24 16 12 fourteen 17 19 19 17 fifteen 12 32 16 21 10 33 49

The data shown in tables 1-2 show that the inventive solution has low values of the filtration rate at a pressure drop of 0.7 MPa, i.e. forms a fairly strong polymer crust. The inventive drilling fluid has a wide range of densities, which makes it possible to use it when drilling wells with different reservoir pressures. In addition, it has high values of SNA in comparison with the prototype, that is, it provides the retention of the solid phase in suspension and good cleaning of the wellbore from cuttings. The recovery coefficient of permeability of the bottom-hole formation zone for the claimed solution is higher than for the prototype and is on par with hydrocarbon-based solutions.

Claims (8)

1. A drilling fluid containing a hydrocarbon phase and surfactants, a weighting agent, mineral salts, a stabilizer and water, characterized in that the additive contains MULTIOL as the hydrocarbon phase and surfactants, MULTISTAR and xanthan gum as stabilizer, and additionally sodium hydroxide in the following ratio, wt.%:
Reagent MULTIOL 8.5-25 STABILIZER MULTISTAR 1.5-2.0 Xanthan gum 0.2-0.5 Calcium carbonate 5-20 Magnesium chloride 4-15 Sodium hydroxide 1-2 Water Rest 2. The drilling fluid according to claim 1, characterized in that it further comprises calcium chloride in a concentration with a total chloride content of not more than 40 wt.% 3. The drilling fluid according to claim 1, characterized in that it further comprises potassium chloride with a total chloride content of not more than 30 wt.% 4. The drilling fluid according to claim 1, characterized in that it further comprises sodium chloride with a total chloride content of not more than 45 wt.% 5. The drilling fluid according to claim 1, characterized in that it further comprises calcium and potassium chloride with a total chloride content of not more than 55 wt.% 6. The drilling fluid according to claim 1, characterized in that it further comprises calcium and sodium chloride with a total chloride content of not more than 55 wt.% 7. The drilling fluid according to claim 1, characterized in that it further comprises potassium chloride and sodium with a total chloride content of not more than 50 wt.% 8. The drilling fluid according to claim 1, characterized in that it further comprises calcium, sodium and potassium chloride with a total chloride content of not more than 55 wt.%