COMPOSITION FOR MAKING A DRILLING FLUID A NON-INVASIVE DRILLING FLUID

Abstract

A composition is for making a drilling fluid a non-invasive drilling fluid. The composition has a first component comprising particles having a scratch hardness above 2 Mohs and a second component comprising particles selected from the group of fragmented seeds of Tamarindus indica, comminuted bark from Litsea glutinosa, or comminuted Ocimum tenuiflorum. Also disclosed is a non-invasive drilling fluid having the composition, and a method for drilling a wellbore.

Claims

1. A composition for making a drilling fluid a non-invasive drilling fluid, the composition comprising: a first component comprising particles having a scratch hardness above 2 Mohs; and a second component comprising particles selected from the group of comminuted seeds of Tamarindus indica, comminuted bark from Litsea glutinosa, or comminuted Ocimum tenuiflorum.

2. The composition according to claim 1, wherein the composition additionally comprises a third biogenic component having anisotropic mechanical properties or shape and a modulus of elasticity which is greater than 2000 MPa and less than 40000 MPa.

3. The composition according to claim 1, wherein the components have a size and shape which allow the particles to pass a dry sieve with 60 mesh screen.

4. The composition according to claim 1, wherein particles of the composition are biogenic.

5. The composition according to claim 1, wherein the concentration of the first component is 15-99% by weight, of the second component is 1-30% by weight, and of the third component is 0-80% by weight.

6. A non-invasive drilling fluid comprising a composition, the composition comprising: a first component comprising particles having a scratch hardness above 2 Mohs; and a second component comprising particles selected from the group of comminuted seeds of Tamarindus indica, comminuted bark from Litsea glutinosa, or comminuted Ocimum tenuiflorum, wherein the total concentration of the components is less than 30 pounds per barrel, corresponding to 85.5 kg/m3.

7. The non-invasive drilling fluid according to claim 6, wherein the total concentration of the components is in the range of 4-10 pounds per barrel, corresponding to 11.4-28.5 kg/m3.

8. The non-invasive drilling fluid according to claim 6, wherein the drilling fluid is a solids-free drilling fluid which does not require drill cuttings or comprise additional solids as a weighting agent or bridging agent to make the fluid a non-invasive fluid.

9. A method for drilling a wellbore, wherein the method comprises the step of using a non-invasive drilling fluid comprising a composition, the composition comprising: a first component comprising particles having a scratch hardness above 2 Mohs; and a second component comprising particles selected from the group of comminuted seeds of Tamarindus indica, comminuted bark from Litsea glutinosa, or comminuted Ocimum tenuiflorum, wherein the total concentration of the components is less than 30 pounds per barrel, corresponding to 85.5 kg/m3 when drilling at least a portion of the wellbore.

10. The method according to claim 9, wherein the method additionally comprises the step of treating the portion of the wellbore with a liquid comprising sodium hypo-chlorite.

11. The composition according to claim 2, wherein the components have a size and shape which allow the particles to pass a dry sieve with 60 mesh screen.

12. The non-invasive drilling fluid according to claim 7, wherein the drilling fluid is a solids-free drilling fluid which does not require drill cuttings or comprise additional solids as a weighting agent or bridging agent to make the fluid a non-invasive fluid.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0062] In the following is described aspects of the invention illustrated in the accompanying drawings, wherein:

[0063] FIG. 1a shows the composition of a typical prior art non-invasive drilling fluid without a differential pressure is applied;

[0064] FIG. 1b shows the sealing mechanism of the prior art non-invasive drilling fluid of FIG. 1a after a differential pressure is applied;

[0065] FIG. 2a shows the composition of an embodiment of the invention dispersed in a drilling fluid before differential pressure is applied; and

[0066] FIG. 2b shows the expected sealing mechanism of the drilling fluid of FIG. 2a after a differential pressure is applied.

DETAILED DESCRIPTION OF THE DRAWINGS

[0067] FIGS. 1a and 1b demonstrate the sealing mechanism of a typical prior art non-invasive drilling fluid 1 comprising a bridging agent 2 and additional solid particles 3 from the drilling fluid. The bridging agent 2 and solid particles 3 enter a fracture 4 in a well wall 5 and forms a relatively tight seal 6 (shown in FIG. 1b) in the opening of the fracture 4. Some solid particles 3 enters the fracture 4. The solid particles 3 may cause additional blocking of the fracture 4, which may be undesirable in e.g. a production zone of a well.

[0068] FIGS. 2a, and 2b show the expected sealing mechanism of an embodiment of the composition according to the invention. The composition comprises particles of a first component 7, a second component 8, and a third component 9. The particles of the three components interlock to form a film 10 (shown in FIG. 2b) across the fracture 4. The particles of the first component 7 function as a bridging agent, the deformable particles of the second component 8 deform to seal the small holes, and the particles of the third component 9 interlock with the other particles of the drilling fluid provide strength and elasticity to the film 10. The resulting film 10 is thus fluid-tight, flexible and able to withstand much higher pressure than prior art non-invasive fluids. Also, the resulting film 10 may be created without the presence of drill solids or weighting materials

[0069] In the following is described examples of preferred embodiments of the invention.

[0070] One way of mixing the components before adding it into the drilling fluid is to mix them in a ribbon blender. Another way of blending the components is air mixing.

[0071] In the examples 1 to 3, a reference to e.g. 80 mesh shall be understood as the component being ground to a size that will pass through an 80 mesh dry sieve.

[0072] In the examples, water-based solid-free mud was prepared containing the following: soda ash, Caustic soda, xanthan gum, low viscosity polyanionic cellulose (PAC LV), KCI. The mud was mixed for 1 hr and kept aside.

Example 1

[0073] Non-invasive drill-in fluid composition 1, wherein the components are ground, dried and sieved as follows are added to the water-based fluid: [0074] Almond shell dust (100 mesh): 75% (component one) [0075] Tamarind seed dust (100 mesh): 25% (component two)

Example 2

[0076] Non-invasive drill-in fluid compositions 2, wherein the components are ground, dried and sieved as follows are added to the water-based fluid: [0077] Almond shell dust (100 mesh): 75% (component one) [0078] Tamarind seed dust (100 mesh): 5% (component two) [0079] Coffee husk (120 mesh): 20% (component three)

Example 3

[0080] Non-invasive drill-in fluid composition 3, wherein the components are ground, dried and sieved as follows are added to the water-based fluid: [0081] Almond shell dust (100 mesh): 90% (component one) [0082] Tamarind seed dust (100 mesh): 10% (component two)

TABLE-US-00001 TABLE 1 important properties of the drilling fluids from example 1 to 3. BHR is before hot rolling, and AHR is after hot rolling. Date: 16 Oct. 2019 Solid Free WBM(8.6 ppg) Measured parameters @49° C. Example 1 Example 2 Example 3 Bpph NIF AHR @ AHR @ AHR @ BHR 90° C., 16 Hrs BHR 90° C., 16 Hrs BHR 90° C., 16 Hrs 600 rpm 41.3 55.5 42.3 35 37.7 50.8 300 rpm 31 42.2 31.6 28.2 28.8 39.5  6 rpm 7 8.5 8 5 6.7 9.1  3 rpm 5.3 6.7 6 4 5.2 7.2 Plastic Viscosity, cP 10.3 13.3 10.7 68 8.9 11.3 Yield Point, lb/100 ft2 20.7 28.9 20.9 21.4 19.9 28.2 pH 8.5 9.42 9.8 9.6 8.48 9.39 API Filtration loss(gram) 6.55 6.16 6.71 6.85 7.08 6.16 Invasion-100 psi (mm), 36.6 27 43 NC NC 30 38/40 mesh sand Comment: For 100 psi, NC = 60 mm

Example 4: Seepage Loss and Rheology Test

[0083] A sand bed test was conducted to establish a relative measure of seepage loss of a base fluid with different test additives, Additive A (a composition according to present invention) and Additive B (Registered trademark FEBRICOAT®). Reference is the mud without any additive, Additive A in concentration of 10 lbs/bbl (pounds per barrel) is a composition according to our present invention, Additive B in concentration of 10 lbs/bbl is a NIF for normal drilling, and NC is no control.

[0084] The water-based solid-free mud was prepared as described above. A filter press cylinder was filled with 20/40 mesh fraction sand up to 45 mm. The cell was topped with 118 g of mud to be tested, the lid was closed, and 100 psi was applied slowly. Filtrate invaded the sand for a short period of time and then completely ceased leaving the bottom section of the sand bed dry. The depth of invasion was recorded in mm, and the results are given in Table 2.

[0085] Another set of tests was done by using Water-based Bentonite mud. These results are given in Table 3.

TABLE-US-00002 TABLE 2 Performance test in solid-free mud Additive A Additive B Reference (10 lbs/bbl) (10 lbs/bbl) Measure parameters PV, cp 15 20 15 YP, lb/100 ft2 17 21 20 Invasion length @ 100 psi, mm NC 26 NC Invasion length @ 500 psi, mm NC 62 NC API Filtration loss, (mL) 35 9 11 HPHT Filtration loss at 500 psi 40 16.4 18.8 and 90° C.

TABLE-US-00003 TABLE 3 Performance test in 8.7 ppg (pounds per gallon) bentonite mud Additive A Additive B Reference (10 lbs/bbl) (10 lbs/bbl) Measure parameters PV, cp 15 21 18 YP, lb/100 ft2 20 22 22 Invasion length @ 100 psi, mm NC 19 30 Invasion length @ 100 psi, mm NC 58 64 API Filtration loss, (mL) 11 4.5 5.2 HPHT Filtration loss at 500 psi 29 14.2 16.0 and 90° C.

Example 5: Acid Degradability

[0086] Acid solubility was tested on two additives (Additive A and Additive B). Acid solubility was tested by placing the test additives in 16% HCl and 16% HCl+5% Na.sub.2S.sub.2O.sub.8 solution and heated at 90° C. for 8 hrs. The test additives were filtered, and solids collected on the filter paper were weighed. % of solubility was measured.

TABLE-US-00004 TABLE 4 % of solubility Test % of solubility % of solubility in 16% additive in 16% HCl HCl + 5% NA.sub.2S.sub.2O.sub.8 Additive A 78% 86% Additive B 48% 50%

Example 6

[0087] Complete solubility is achieved by dual treatment: Treating with 5% NaOCl solution for 3 hours at 90° C. followed by 16% HCl solution for 3 hours at 90° C.

TABLE-US-00005 TABLE 5 % of solubility Test wt % of solubility in 5% NaOCl additive followed by 16% HCl Additive A 97% Additive B 65%

[0088] The example shows that a drilling fluid comprising Additive A can seal the sand bed without the presence of drilled solids or other solids such as e.g. bentonite in the mud. This will enable drilling of a reservoir, e.g. containing hydrocarbons, without allowing a significant amount of drilled solids or other solids to enter the formation, which would likely reduce the natural permeability of the reservoir after drilling is completed. Additionally, the documented solubility of the film will allow the film to be removed by reverse pressure or by solubilization before production.

[0089] It should be noted that the above-mentioned embodiments illustrate rather than limit the invention, and that those skilled in the art will be able to design many alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. Use of the verb “comprise” and its conjugations does not exclude the presence of elements or steps other than those stated in a claim. The article “a” or “an” preceding an element does not exclude the presence of a plurality of such elements.