GB2600439A - Drilling fluid - Google Patents

Abstract

A drilling fluid for borehole operations comprising a carrier fluid and a shale hydration inhibitor comprising chitosan and/or a carboxyl substituted chitosan derived compound. The inhibitor may comprise carboxymethyl chitosan, carboxyethyl chitosan, or N-succinyl chitosan. The carrier fluid may be water or an aqueous solution (e.g. potassium chloride brine, sodium chloride brine). The fluid may further comprise viscosifiers (e.g. dituan gum, guar gum, hydroethyl cellulose, locust bean gum, pre-gelatinised starch, xanthan gum), fluid loss additives (e.g. amphoteric cellulose, carboxymethyl starch, carboxymethyl cellulose, polyanionic cellulose), water softeners (e.g. potassium carbonate, sodium carbonate), filtration control polymers, encapsulating polymers, lubricants, pH control additives, and a biocidal additives. The drilling fluid may be used in subterranean wells for exploiting hydrocarbons or geothermal resources.

Description

Intellectual Property Office Application No G132017134.4 RTM Date:26 March 2021 The following terms are registered trade marks and should be read as such wherever they occur in this document: PureB ore Intellectual Property Office is an operating name of the Patent Office www.gov.uk/ipo Drilling fluid

Technical Field

The present invention relates to improved drilling fluids for boreholes. More specifically, the invention relates to additives for forming improved drilling fluids.

Background

Subterranean wells, such as for exploiting hydrocarbon or geothermal resources, are usually created by rotary drilling. In rotary drilling processes, a rotary cutting head or drill bit is rotated and driven through the ground either via mechanical torque or via fluid pressure from a drilling fluid. The drilling fluid also has other functions, such as lubricating and cooling the cutting head, transporting rock debris to the surface, and preventing formation fluids from entering the borehole.

Drilling fluids can be water based, non-water based, or pneumatic, and in each case comprise a variety of additives. The chemical composition of the drilling fluid determines the physical properties of the drilling fluid, which in turn affects the efficiency of the drilling process.

During drilling operations with aqueous fluids, wellbore stability issues are often encountered during shale sections, for example, due to water ingress and absorption of water into the shale matrix and within the clay platelets (shale hydration). Shale hydration has negative effects on the mechanical strength of the shale formation and/or layer and can result in a wellbore collapsing or fracturing. An additional problem is that clay particulate matter can adhere to the mechanical equipment downhole, which also reduces drilling efficiency.

Typically, shale hydration can be minimised by the absorption of polymers onto the shale surface. This thin film of polymer can act as a physical barrier to the ingress of water into the shale matrix thus preventing damage to the wellbore. Existing additives for reducing shale hydration are based on partially hydrolysed polyacrylamide (PHPA).

Summary of Invention

PHPA causes environmental problems due to its toxicity and has a detrimental effect on the rheological properties of the drilling fluid. For example, the present inventors have found that PHPAs adversely affect the plastic viscosity (PV) of the fluid because of their Newtonian linear rheology.

The present invention seeks to resolve or ameliorate one or more of the above problems, or provide a useful alternative thereto.

According to a first aspect of the invention there is provided a drilling fluid for borehole operations comprising: a carrier fluid, and a shale hydration inhibitor comprising chitosan and/or a carboxyl-substituted chitosan-derived compound.

The carboxyl-substituted chitosan-derived compound may be a chitosan-based compound in which the hydrogen atom of one or more of the hydroxy and/or amine groups is substituted by a moiety containing at least one carboxyl group, for example an etherified chitosan derivative The shale hydration inhibitor may comprise one or more compounds selected from a group consisting of: carboxymethyl chitosan, carboxyethyl chitosan, and N-succinyl chitosan.

The carrier fluid may be water or an aqueous solution. For example, the carrier fluid may comprise a potassium chloride brine or sodium chloride brine.

The shale hydration inhibitor may have a concentration of from 0.1 to 10 lbs per barrel. In some embodiments, the shale inhibitor may have a concentration of 1 to 3 pounds per barrel.

The drilling fluid may comprise one or more further additives selected from the group consisting of: further shale inhibitors, viscosifiers, fluid loss additives, and water softeners.

The viscosifier may comprise one or more compounds selected from a group consisting of: diutan gum; guar gum; hydroyethyl cellulose; locust bean gum; pre-gelatinised starch; and xanthan gum.

The fluid loss additive may comprise one or more compounds selected from a group consisting of: amphoteric cellulose; carboxymethyl starch; carboxymethyl cellulose; polyanionic cellulose; and pre-gelatinised starch.

The water softener may comprise one or more compounds selected from a group consisting of: potassium carbonate; and sodium carbonate.

The drilling fluid may further comprise one or more additives selected from a group consisting of: a filtration control polymer; an encapsulating polymer; an extended inhibitor; a lubricant; a formation stabiliser; a bridging solid; a pore plugging additives; a temperature stabilisers; a pH control additive; and a biocidal additive.

According to a second aspect of the invention, there is provided a process comprising the use of chitosan and/or a carboxyl-substituted chitosan-derived compound as a shale inhibitor in a drilling fluid.

According to a third aspect of the invention, there is provided a drilling fluid additive comprising 0 wt% to 75 wt% of chitosan and/or a carboxyl-substituted chitosan-derived compound. For example, the drilling fluid additive may comprise from 1 to 75, 5 to 70, 10 to 65, 15 to 60, 20 to 55, 25 to 50, 30 to 45, or 35 to 40 wt% of chitosan and/or a carboxyl-substituted chitosan-derived compound.

The carboxyl-substituted chitosan-derived compound of the second and third aspects may comprise one or more compounds selected from a group consisting of: carboxymethyl chitosan, carboxyethyl chitosan, and N-succinyl chitosan The drilling fluid additive may further comprise one or more compounds selected from the group consisting of: further shale hydration inhibitors, viscosifiers, fluid loss additives, and water softeners. The shale hydration inhibitors, viscosifiers, fluid loss additives, and water softeners may be one or more of those described above.

The drilling fluid additive may further comprise one or more additives selected from a group consisting of: a filtration control polymer; an encapsulating polymer; an extended inhibitor; a lubricant; a formation stabiliser; a bridging solid; a pore plugging additives; a temperature stabilisers; a pH control additive-and a biocidal additive.

Examples

Example la -Carboxymethyl Chitosan Synthesis With reference to the reaction shown in Figure 1, 12 g of chitosan powder (90% degree of deacetylation) and 260 ml isopropanol were stirred together at 22 °C to form a chitosan slurry. 14.58 g (365 mmol) of sodium hydroxide was dissolved in 65 ml water (65 ml) and subsequently added to the chitosan slurry. The mixture was warmed and stirred at 50 °C for 1 hour to form a modified chitosan slurry.

Separately, a solution of chloroacetic acid (16.2 g, 171 mmol) in isopropanol (22 ml) was added to the modified chitosan slurry over 20 minutes. The reaction was held at 50 °C for 4 hours. After 4 hours, the reaction was cooled to 25 °C and neutralized to pH 7 with glacial acetic acid.

The slurry was filtered and the filter cake washed with 70% methanol (2 x 150 ml). The filter cake was reslurried in 100 ml methanol, filtered and washed with a further volume of methanol (100 ml) before being dried in a vacuum oven at 55 °C to give carboxymethyl chitosan (CMC) as an off-white solid (13.1 g).

The off-white solid was tested using an FTIR spectrometer with an Attenuated Total Reflection attachment. The sample exhibited peaks at the following frequencies:

Table I

Frequency / cm-I Functional group 3355 0-H stretch 3290 0-H stretch 2918 C-H stretch 2883 C-H stretch 1583 carboxylate asymmetrical stretch 1407 carboxylate symmetrical stretching overlapping N-H bending 1321 C-N stretching 1058 C-0-C and 0-0 glycosidic bond symmetric stretch Example lb -N-Succinyl Chitosan Synthesis With reference to the reaction shown in Figure 2, succinic anhydride (4 g, 40 mmol) was added to a stirred slurry of 90% chitosan powder (4.4 g) in dimethylsulfoxide (80 ml) at 25 °C. The resulting slurry was warmed to 70 °C and held at this temperature for 6 hours.

The resulting slurry was cooled to 25 °C and then left to stand overnight. Subsequently, the slurry was diluted with 95% ethanol (20 ml) and stirred for 5 minutes. The precipitate was filtered off, washed with 95% ethanol (50 ml) and the filter cake was maintained under suction until the filter cake was dry. The filter cake was then suspended in 95% ethanol (100 ml) with stirring and stirred for 1 hour at 25 °C. The solids were filtered off, the filter cake was washed with 95% ethanol (2 x 20 ml) and the filter cake was allowed to air dry overnight.

The dried filter cake was added portion-wise to water (150 ml) with stirring to form a succinyl chitosan solution. The pH of the solution was adjusted to pH 10 using 1 M sodium hydroxide solution. 450 ml of acetone was added in a thin stream to the succinyl chitosan solution causing solids to precipitate. The slurry was stirred at 25 °C for 30 minutes, the solids were filtered off and the cake was washed with 70% methanol (100 m1).

The wet cake was reslurried in acetone (200 ml), filtered and then washed with a further volume of acetone (100 ml). The cake was dried in a vacuum oven at 55 °C to give the N-succinyl chitosan as an off-white, powdery solid (6.7 g).

The off-white, powdery solid was tested using an FTIR spectrometer with an Attenuated Total Reflection attachment. The sample exhibited peaks at the following frequencies:

Table 2

Frequency / cm-I Functional group 3265 0-H stretch 2916 C-H stretch 2871 C-H stretch 1730 ester carbonyl stretch 1647 axial stretching of carbonyl bonds of amide group 1558 N-H bending of succinyl group 1398 asymmetric stretching of carboxylate group 1153 0-0-0 and 0-0 glycosidic bond symmetric stretch 1106 C-0-C, C-0 glycosidic bond symmetric stretching 1025 C-0 stretch Example 2 -Water Tests A series of comparative fluids were prepared using the compounds produced in examples 1 and 2 according to the following compositions to assess the impact of the shale inhibitors compared to the PHPA inhibitors currently commercially available. Due to the volume of water used below, each gram of the compounds added is equal to a concentration of 1 lb per barrel (e.g. Formulation 2 has a concentration of 2 lbs per barrel, Formulation 4 has a concentration of 3 lbs per barrel).

Table 3

Compound Formulation 1 2 3 4 5 6 7 Water /ml 350 350 350 350 350 350 350 Partially Hydrolysed PolyAcrylate (PHPA) /g 1 2 - - - - - Carboxymethyl Chitosan (CMC) /g - - 2 3 - - -Succinyl Chitosan /g 2 3 Carboxyethyl Chitosan (C EC) /g 3 To each of Formulations 1 to 7 was added 20 g of Arne clay to simulate drill cuttings.

The rheology of the samples was measured using an OFITE Model 900 Viscometer fitted with an R1 spring and B1 bob configuration. The pH was measured using a conventional pH sensor. Once the rheology and pH were measured, the shale recovery was measured according to the standard American Petroleum Institute shale dispersion test. The test comprises hot rolling the Arne clay in a stainless steel cell (400 ml) at approximately 300 rpm, the moisture content of the clay is measured and the clay is added to the fluid. The clay is rolled for 16 hours at room temperature, then the fluid is filtered through a 500 micron sieve. The filtrate is washed and dried, then weighed and compared to the original starting weight. The I% recovery is understood to be a proxy value for the effectiveness of the fluid at preventing shale hydration within a borehole, with a high "% recovery" indicating that the fluid additives are effective at preventing the shale from absorbing water from the fluid and thus dissolving therein.

The results of the rheology tests are set out in Table 4 and shown in Figure 3. Formulations 3 and 4 were found to have shale recovery comparable to Formulations 1 and 2 respectively, and more specifically, Formulations 2, 4, 6 and 7 were shown to have a % recovery above 80% and thus demonstrate excellent shale inhibition properties. The rheometer readings for Formulations 2, 4, 6 and 7 are plotted on the graph in Figure 3 -as is clear, Formulations 4, 6 and 7 demonstrate lower viscosities and at all shear rates than the PHPA-containing Formulation 2. The viscosity of Formulations 4, 6 and 7 has been found to be lower than the PHPA-containing Formulation 2, while having comparable clay recovery properties. Thus, the use of a chitosan-derivative compound is understood to have a lower negative effect on the rheology of a drilling fluid while still providing the same high levels of shale hydration inhibition In drilling applications, the composition of the drilling fluid is dynamic. A drilling fluid engineer is responsible for monitoring the fluid composition and properties, and adapting both to the changing borehole conditions. The use of PHPA to increase the shale hydration inhibition also has the side-effect of increasing the viscosity of the fluid, which thus requires the drilling fluid engineer to adjust the composition further to compensate e.g. by adding further additives or by dilution of the drilling fluid. Thus, the presently discussed is easier for a drilling fluid engineer to use, and can be more cost effective, since the need to compensate for the side effects with further additives is reduced.

Table 4

Rotational speed Formulation /rpm 1 2 3 4 5 6 7 600 15.3 45.0 5.6 17.8 9.7 25.6 19.2 300 10.6 24.5 2.7 9.1 5.1 13.8 9.9 8.6 20.6 1.9 6.3 3.4 9.2 6.7 6.9 16.1 1.2 3.1 1.7 4.8 3.2 5.2 14.3 0.8 1.8 1.2 2.9 1.8 4.1 12.2 0.6 1.2 0.8 1.6 1.1 6 2.5 9.5 0.5 0.4 0.5 0.5 0.3 3 2.3 8.9 0.4 0.4 0.5 0.4 0.3 pH 8.3 8.5 8.0 8.0 8.0 8.0 9.0 % recovery 53.3 94.8 49.1 92.0 61.0 80.3 97.2 Example 3-PHPA Comparison A comparative and an exemplary drilling fluid were prepared according to the following compositions. In each case, the dry materials were combined and mixed with 322 g of an aqueous brine (7% potassium chloride). The PureBoreTM, PureBore ULVTm, and PHPA or CMC are dissolved in the aqueous brine. The high modulus prima (HMP) clay was added to simulate drilling cuttings and suspended in the solution.

Table 5

Compound Supplier Formulation 8 Formulation 9 PureBoreTm Clear Solutions Ltd 2g 2g Partially Hydrolysed 1g 0 Polyacrylate (PHPA) Carbon/methyl Chitosan (CMC) 0 2g PureBore ULVTM Clear Solutions Ltd 2g 2g High Modulus Prima (HMP) Clay 10g 10g In example 3, PureBoreTM and PureBore ULVTM are included as examples of commercially available additives from the present Applicant which are typically used as viscosifiers and/or fluid loss additives. Formulation 8 thus represents a conventional drilling fluid using existing available additives.

The rheology of the two formulations was tested using an OFITE Model 900 Viscometer fitted with an R1 spring and B1 bob configuration as previously described.

The viscosity of the fluids were measured, and subsequently the fluids were subjected to the previously discussed standard American Petroleum Institute shale dispersion test. The viscosity was then measured again (after hot rolling), the fluid loss measured and gel strength measurements taken.

The results of the rheometry tests are set out in Table 6. Formulation 9, comprising 2 g CMC was shown to have a plastic viscosity and yield point substantially similar to the comparative example containing PHPA.

Table 6

Rotational Formulation 8 Formulation 8 Formulation 9 Formulation 9 speed /rpm After Hot Rolling After Hot Rolling 600 57.3 51.7 53.2 46.8 300 39.5 37.1 36.5 32.3 32.5 30.7 29.7 26.3 23.9 22.3 21.1 18.3 6 8.2 6.6 5.9 5.5 3 6.8 4.9 4.2 4.3 Plastic Viscosity 17.8 14.6 16.7 14.5 Yield Point 21.7 22.5 19.8 17.8 Fluid Loss - 16.8m1 - 6.6m1 Gels (after - 5.6/6.5 - 4.9/6.7 10s/10mins) A high amount of the HMP clay was unhydrated in the PHPA fluid compared to the CMC containing fluid. This is believed to be a factor in why the fluid loss of the PHPA fluid was poor. Despite this, the shale recovery is high in both fluids, due in part to the inhibitive properties of KCI brine and the action of the PureBoreTM and PureBore ULV-rm additives.

The gel strength measurements were recorded after 10 seconds and 10 minutes respectively. The fluid was left static in the OFITE Model 900 Viscometer for the prescribed time periods, and subsequently the viscosity was measured at 3 rpm (5.11 s-1). The results show that the gelling effect of the additives is relatively low. Gelling is undesirable, since it would cause increases in viscosity when the fluid is static and the fluid pumps are not running. When the fluid pumps are restarted, it can cause significant pressure spikes due to the more viscous fluid which can in turn damage or fracture the borehole.

Example 4-Shale Recovery Table 7 shows a series of tests was carried out using 7% potassium chloride brine. KCI brine is a common aqueous carrier fluid used in drilling operations and is known to have a mild inhibitive effective with respect to shale hydration. Formulation 10 is 7% KCI brine with no further additives. Formulations ha and 11 b are 7% KCI with a CMC additive in a concentration of 2 lbs per barrel (5.706 grams per litre). Formulations 12a and 12b are 7% KCI with a N-succinyl chitosan additive in a concentration of 2 lbs per barrel (5.706 grams per litre). The recovery tests were carried out according to the standard API shale dispersion test described above.

Table 7

Formulation Additive % recovery None 13 11a Carboxymethyl Chitosan 76 11 b Carboxymethyl Chitosan 84 12a N-Succinyl Chitosan 71 12b N-Succinyl Chitosan 94 The recovery tests were carried out twice for formulations 11 and 12. Greater familiarity with the reaction is believed to have lead to a better work up and thus improved shale recovery in the second tests for each additive, as shown in Formulation 11 b and 12b.

The data shows high levels of shale recovery even when unfamiliar with the reaction, indicating a robust performance and that high levels of inhibition can be achieved even in sub-optimal condition such as in situ during drilling operations. Furthermore, the data also shows that extremely high recovery is achievable with these additives, even at concentrations of only 2 lbs per barrel. This is comparable to the addition rates and concentrations of PHPA used commercially.

Table 8 shows a further series of Formulations comparing CMC containing drilling fluids with commercially available shale inhibitors. Values in Table 8 relate to concentrations in lbs per barrel (1 lb per barrel = 2.853 g/L). The data shows that the inhibitive characteristics of CMC containing fluids are not negatively affected by the presence of other common drilling fluid additives, such as PureBoreTM and PureBore ULVTM. The performance of the CMC containing drilling fluid was found to be superior than two alternative shale inhibitors (Formulations 15 and 16), and achieved at drastically lower concentrations.

Table 8

Compound Formulation 13 14 15 16 PureBoreTm 2.5 2.5 2 2 PureBore ULVTM 3 3 2.5 2.5 Carboxymethyl Chitosan (CMC) - 2 - -Prime-S001 10 PEG-S002 10 Shale recovery 66% 89% 85% 58% Prime-500 is a commercially available amine based shale inhibitor.

2 Polyethylene glycol, average MN -500

Example 5 -Rheology

Three further Formulations were mixed according to Table 9. The rheology of the three fluids were measured as previously described as set out in Table 10 below. Values in Table 9 relate to concentrations in lbs per barrel (1 lb per barrel = 2.853 g/L). The fluid used was 7% potassium chloride brine. The final fluid was thus 99% KCI brine with the remaining 1% comprising the additives in Table 9.

Table 9

Compound Formulation 17 18 19 PureBoreTm 2 2 PureBore U LVTm 2.5 2.5 -Carboxymethyl Chitosan (CMC) 2 5 PEG-3003 10 10 -High Mod Prima 10 Clay 3 Polyethylene glycol, average MN -300

Table 10

Rotational speed Formulation /rpm 17 18 19 600 41.5 29.5 6.4 300 27.7 20.6 3.2 22.2 16.3 2.1 15.3 12 1.2 6 3.8 3.2 0.5 3 2.8 2.5 0.5 Plastic Viscosity 13.8 8.9 3.2 Yield Point 13.9 11.7 0 Table 10 shows us that CMC does not have a significant impact on the overall rheology of the drilling fluid, with the values of Formulation 17 and 18 being largely similar. Formulation 19 shows us that a fluid containing only CMC has a very thin (i.e. low viscosity) rheological profile even at relatively high concentrations.

Example 6-Additive composition A fluid additive was prepared by blending together dry powders comprising: 40 wt% viscosifier; 25 wt% fluid loss additive; and 35 wt% shale hydration inhibitor. The shale hydration inhibitor was chitosan. A second additive was prepared according to the same ratios wherein the hale hydration inhibitor was a carboxyl-substituted chitosanderived compound. The fluid additives were packaged and stored and found to be shelf stable.

Claims (1)

1. CLAIMS: 1. 2. 4. 7. 8. 9.A drilling fluid for borehole operations comprising: a carrier fluid, and a shale hydration inhibitor comprising chitosan and/or a carboxyl-substituted chitosan-derived compound.The drilling fluid according to claim 1, wherein the shale hydration inhibitor comprises one or more compounds selected from a group consisting of: carboxymethyl chitosan, carboxyethyl chitosan, and N-succinyl chitosan.The drilling fluid according to any one of the preceding claims, wherein the carrier fluid is water or an aqueous solution.The drilling fluid according to claim 3, wherein the carrier fluid is a potassium chloride brine or sodium chloride brine.The drilling fluid according to any one of the preceding claims, wherein the shale hydration inhibitor has a concentration of from 0.1 to 10 lbs per barrel.The drilling fluid according to claim 5, wherein the shale inhibitor has a concentration of 1 to 3 pounds per barrel.The drilling fluid according to any one of the preceding claims, comprising one or more further additives selected from the group consisting of: further shale inhibitors, viscosifiers, fluid loss additives, and water softeners.The drilling fluid according to claim 7, wherein the viscosifier comprises one or more compounds selected from a group consisting of: diutan gum; guar gum; hydroyethyl cellulose; locust bean gum; pre-gelatinised starch; and xanthan gum.The drilling fluid according to claim 7 or 8, wherein the fluid loss additive comprises one or more compounds selected from a group consisting of: 10. 11. 12. 13. 14.amphoteric cellulose; carboxymethyl starch carboxymethyl cellulose; polyanionic cellulose; and pre-gelatinised starch.The drilling fluid according to any one of claims 7 to 9, wherein the water softener comprises one or more compounds selected from a group consisting of: potassium carbonate; and sodium carbonate.The drilling fluid according to any one of the preceding claims, further comprising one or more additives selected from a group consisting of: a filtration control polymer; an encapsulating polymer; an extended inhibitor; a lubricant; a formation stabiliser; a bridging solid; a pore plugging additives; a temperature stabilisers; a pH control additive; and a biocidal additive.The use of chitosan and/or a carboxyl-substituted chitosan-derived compound as a shale inhibitor in a drilling fluid.A drilling fluid additive comprising 1 to 75 wt% of chitosan and/or a carboxyl-substituted chitosan-derived compound.The drilling fluid additive according to claim 13, further comprising one or more compounds selected from the group consisting of: further shale hydration inhibitors, viscosifiers, fluid loss additives, and water softeners.