AU2021266329A1 - Improvements in or in relation to remediation of drilling fluids - Google Patents

Abstract

Figure 7 The process of applying fertiliser components in drilling fluids and then thereafter, when finished drilling, the resulting fluid and cutting are beneficial to be land spread as fertiliser. The resulting fluid is spread at a predetermined rate in accordance with the fertiliser components in the resulting fluid or the resulting fluid is altered and spread at a predetermined rate in accordance with the fertiliser components in the altered fluid. Fertiliser or fertiliser chemicals providing nitrogen, phosphorus and potassium are used. These are blended with carbonates or bicarbonates of nitrogen or potassium to improve inhibition and buffered to provide a drilling fluid with a pH of about 8. The inhibition quality of the drilling fluid is bencmakerked against KLC drilling fluids. 1/7 FIG. 1 {FIG.3 FIG. 4 I-s FIG. 4

Description

1/7

FIG. 1

{FIG.3

FIG.4

I-s FIG. 4

Improvements in or in relation to remediation of drilling fluids

TECHNICAL FIELD

[0001] THIS INVENTION relates to improvements in or in relation to the remediation of drilling fluids and in particular but not limited to drilling fluids that may be disposed of as unregulated spent drilling fluids and dispersed as fertiliser at measured spread rates.

BACKGROUND

[0002] Potassium Chloride (KCI) drilling fluid systems have historically been seen as the backbone of inhibitive water-based Drilling Fluid systems. This Drilling Fluid system has been used for many years and it works well with respect to inhibition of clay and silt formations in many wells.

[0003] Drilling fluids generally comprise water and various treating agents which control the physical and/or rheological properties of the drilling fluid of well bores. The drilling fluid assists in keeping the drill bit cool during drilling, keeping the well clear of solds ensuring well stability for the drilling period. Drilling fluid is circulated from the surface of the well, through the drill string, and out through openings in the drill bit such that the drilling fluid is then circulated upwards in the annulus between the side of the well bore and the rotating drill string, back into the circulating suction tank. The spent drilling fluid contains chips, cuttings and other components produced by the drill bit and the various concentrations of components is generally dependent on the particular formation being drilled. This means that although there is an input drilling fluid, the spent drilling fluid produced on site is site specific in terms of the various concentrations of components due to the contribution to the input drilling fluid of the formation being drilled. In addition the components can vary as different strata is encountered as the drill proceeds through the formations.

[0004] Potassium chloride based drilling fluids is one of the most common drilling fluids used. These and other drilling fluids are considered as "regulated" due to the high chloride base and salinity concentrations and for this reason have regulated disposal requirements. There are wide ranges of variables that affect the final drilling fluid that is for disposal and generally these must be post treated prior to disposal.

[0005] Many additives have been used to try to mitigate against adverse effects on the drilling fluid and ultimately the efficiency of the drilling operation. For example, Potassium carbonate and various polymers have been used. Efforts have also been made to reduce particulate swelling by the addition of salts such as potassium chloride, sodium chloride, ammonium chloride, all dissolved in the drilling fluid. The amounts of the salts can be more than 10% usually resulting in an environmentally toxic and unacceptable fluid that cannot be directly discarded into the environment. These additives create a drilling fluid generally known as an "inhibited" drilling fluid.

[0006] The production and use of drilling fluids is a very well known art since drilling has been around for many years and it could be said that efforts to treat and produce environmentally friendly outcomes have been well researched and could be described as a "mature" and "crowded" art.

[0007] As examples GB2153411 uses potassium carbonate rather than potassium chloride as the swelling inhibitor in addition to other additives. This type of drilling fluid must be post treated before it can be disposed of.

[0008] GB2448683 gives a good summary of the prior art approach to post treatment of drilling fluids for environmentally safe disposal as well as providing in that invention a final disposable drilling fluid by post treatment to remove carbonate and/or sulphate ions. According to this patent this can result in treated cuttings that may be used as a topsoil or topsoil fertiliser. Chlorides are eliminated by using potassium sulphate or potassium carbonate as additive and then post treatment removes the sulphates and carbonates as the case may be.

[0009] US2011/0124531 observes that additives based on phosphate salts of potassium may be used near crops by reason of them being present in plant fertilisers, the main reason given for using these salts compared to KCI is that they are environmentally friendly.

[0010] Environmental requirements vary according to the local laws.

[0011] In regulated areas of Australia, such as Queensland, New South Wales, etc., the residue after drilling with KCI Drilling Fluid systems are deemed as regulated waste. This is described in detail in the document "End of Waste Code, Coal Seam Gas Drilling Mud (ENEW07543018), Waste Reduction and Recycling Act 2011". This document addresses the issue of drill cuttings and drilling fluids after a well is drilled. The document further states on Page 4, Point no. 1, "It supports the vision of Queensland's Waste Strategy for Queensland to become a national leader in avoiding unnecessary consumption and waste generation by adopting innovative resource recovery approaches and managing all products and materials as valuable and finite resources".

[0012] When KCI drilling fluid systems are used, then such systems come with a tremendous drawback. The cuttings residues and drilling fluids at end of well, must be carted away from the rig site as they are deemed as regulated wastes as per EPA document cited above. The criteria to determine when a product becomes regulated waste is given in the document "Environmental Protection Act 1994". This document gives the main "approved quality criteria" for the purposes of residual drilling materials, page 71, Table Part A, as the pH to be 6 - 10.5, Electrical conductivity as < 20 dS/m (20,000 pS/cm = 20 mS/cm = 20 dS/m) and Chlorides < 8,000 mg/It. Any residue drilling materials out of this scope is treated as regulated waste and must be disposed of in a regulated waste area. These waste areas are normally a distance from the drilling sites and thus it is expensive to cart the fluids and cuttings to the disposal site. In the process personnel are also exposed to excessive time on the road and personnel safety is a concern. The aim is thus for companies to save money by reducing carting costs for the cuttings and fluids as well as decreasing kilometers that cuttings and fluids are carted to reduce the risk that the personnel are exposed to.

[0013] The causal factor for waste being regulated is thus the fact that KCI drilling fluids are used. If alternative drilling fluid systems were to be used that are more environmentally friendly and comply with the EPA guidelines of what a regulated waste is, then the above problems are solved.

OUTLINE

[0014] It is an object of the present invention to distinguish the inhibition capabilities of nitrogen and/or phosphorous and/or potassium containing chemicals and how well the products can inhibit coated bentonite pellets relative to 4% KCI as screening process.

[0015] The nitrogen and/or phosphorus and/or potassium containing products as set out in the method of the present invention can then be utilised as drilling fluids to drill oil and gas wells in Australia and then be afterwards be directly or indirectly (after further processing) utilised as fertiliser.

[0016] It is a further object that the aforementioned drilling fluids and cuttings would then contribute to the cuttings and fluids, after the well has been finished, being able to be used as fertiliser for land spreading purposes and would be deemed as unregulated waste. This allows operating companies in Australia to cart less cuttings and fluids in Australia around as is current practices. The savings for the operators is not only financial but also a safety factor in that personnel do not need to cart drill cuttings and fluids long distances due to the drilling fluids and cuttings being deemed to be unregulated.

[0017] A still further object is to provide a completed drilling fluid so that after a well has been completed and the nitrogen and/or phosphorous and/or potassium concentrations have been analysed for, a maximum land spreading (spray) rate can then be determined and the drilling fluid and cuttings can be used as a fertiliser in or over any soil to be beneficial for all plant growth.

[0018] Alternative drilling fluids would be fluids that are both clay inhibitors and have nitrogen and/or phosphorous and/or potassium as part of the chemical composition so that the products may after drilling fluid use, be used as fertilisers by anybody that land spreads, (or sprays) the cuttings or fluids. At the level of generality or as a principle of general application, there is provided the process of applying certain fertiliser components in drilling fluids and then thereafter, when finished drilling, the resulting fluid and cutting are beneficial to be land spread as fertiliser. Typically, the resulting fluid is spread at a predetermined rate in accordance with the fertiliser components in the resulting fluid or the resulting fluid is altered and spread at a predetermined rate in accordance with the fertiliser components in the altered fluid. In one preferred implementation, fertiliser or fertiliser chemicals providing nitrogen, phosphorus and/or potassium are blended with carbonates or bicarbonates of nitrogen or potassium to improve inhibition and buffered to provide a drilling fluid with a pH of about 8.

[0019] It is general knowledge that any products that contain nitrogen and/or phosphorus and/or potassium are beneficial to plants and are classed as fertilisers. Examples of such products could be the following but are not limited to these products.

[0020] With the above objects in mind there is provided a method of drilling fluid remediation comprising the steps of: A. Providing fertiliser components as a fertiliser or fertiliser chemicals having selected from the following: a. Diammonium Phosphate b. Monoammonium Phosphate c. Dipotassium Phosphate d. Monopotassium Phosphate e. Tripotassium Phosphate f. Tetrapotassium Pyrophosphate g. Monopotassium Pyrophosphate h. Dipotassium Pyrophosphate i. Tripotassium Pyrophosphate j. All potassium and ammonium polyphosphates k. Mono and diamines containing either a multiple carbon chain attached to the amine or in between the diaimine groups B. Blending the fertiliser components with other ingredients selected from the following in the range of quantities listed to then provide a drilling fluid with predetermined inhibition characteristics; a. Ammonium carbonate, >0% to 10% b. Ammonium bicarbonate, >0% to 10% c. Potassium carbonate, >0% to 10% d. Potassium bicarbonate, >0% to 10% e. Modified starches containing nitrogen in the chemical structure >0%-0% C. Using the drilling fluid in a wellbore; D. Recovering the drilling fluid upon completion of drilling; E. Determining the concentration of fertiliser components in the drilling fluid recovered in step E; F. Spreading the recovered drilling fluid at a spread rate in accordance with the concentrations determined in step E.

[0021] After step E there may be a step of further processing including reducing the fertiliser to a dry form or taking a step that alters the concentrations measured in step E. If the recovered drilling fluid is altered after step E, then step E may be repeated on the recovered drilling fluid and step F then involves spreading the altered drilling fluid in accordance with its concentrations of fertiliser companies determined in the repeated step E.

[0022] In a preferred form the process employs a modified DAP (Di-Ammonium Phosphate) containing pH buffering products selected from Potassium carbonate, Ammonium carbonate, Potassium bicarbonate, Ammonium bicarbonate, modified starches containing nitrogen in the chemical structure and Di-Potassium Phosphate are blended are blended with a commercial fertiliser which contains 21% Nitrogen and 23% Phosphorous.

[0023] In a further preferred form the process employs a modified DAP (Di-Ammonium Phosphate) containing pH buffering products selected from Potassium carbonate, Ammonium carbonate, Potassium bicarbonate, Ammonium bicarbonate, modified starches containing nitrogen in the chemical structure and Di-Potassium Phosphate are blended with proprietary diamine containing about 1.3% Nitrogen.

[0024] In another preferred form the process employs aThe process of claim 1 a blended MAP (Mono-Ammonium Phosphate) containing 12% Nitrogen, and 26% Phosphorous.

[0025] In a still further preferred form the process employs a blended DPP (Di-Potassium Phosphate) containing 17% Phosphorous and 44% Potassium.

[0026] In another preferred form the process employs a blended MPP (Mono-Potassium Phosphate) containing 22% Phosphorous and 28% Potassium.

[0027] In a preferred form the process uses an aqueous form such that, prior to mixing with water at a concentration, generally, between 0.25% to 0.5% (m/v). ingredients have the following: A. Nitrogen content 19.1% - 21.0% B. Phosphorus content 21.2% - 21.3% C. mixed with buffers at a concentration of 80% to 99% (m/m) being selected from i. Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of 8 ii. Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of 8 iii. modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition.

[0028] In a preferred form the process uses another aqueous form such that, prior to mixing with water at a concentration, generally, between 0.25% to 0.5% (m/v). ingredients have the following: a. Nitrogen content 1.1%- 1.2% b. mixed with the buffers selected for the below at a concentration of 80% to 99% (m/m) i. Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of 8 ii. Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of 8 iii. modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition

[0029] In a preferred form the process uses still another aqueous form such that, prior to mixing with water at a concentration, generally, between 0.25% to 0.5% (m/v). ingredients have the following: a. Phosphorus content 16.0% - 17.6% b. Potassium content 40.4% - 44.5 c. mixed with buffers below at a concentration of 80% to 99% (m/m) i. Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of about 8 ii. Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of about 8 iii. modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition

BRIEF DESCRIPTION OF THE DRAWINGS

[0030] In order that the present invention may be more readily understood and put into practical effect reference will now be made to the accompanying drawings and examples which illustrate preferred aspects of the invention and wherein:

Figures 1 through 4 illustrate the experimental set up for comparative inhibition efficiency testing benchmarked against a KCI based drilling fluid; Figures 5A-5C is a table of the inhibition efficiency test results; Figure 6 is a table comparison of exemplary measured spread rates; Figure 7 is a table showing inhibition performance of drilling fluids according to the present invention compared with water and 4% KCI (both in bold). Figures 8 and 9 are flow diagrams comparing a regulated KCI based process in Figure 8 to the present method in Figure 9.

METHODOFPERFORMANCE

[0031] The following description provides for use of MAP (Mono-Ammonium Phosphate), DAP (Di-Ammonium Phosphate), MPP (Mono-Potassium Phosphate), DPP (Di-Potassium Phosphate), mono, di, tri and/or tetrapotassium pyrophosphate, all potassium and ammonium polyphosphates, Amines (comprising either mono or di-Amines within a hydrocarbon structure) or any other salt or organic compositions that contain Nitrogen and/or, Phosphorous and/or Potassium and does qualify as a drilling fluid clay inhibitor.

Chemicals used

[0032] For the tests later shown below, F2V 2NP (where F2V stands for Fertiliser To Vegetation) DF is a modified DAP (Di-Ammonium Phosphate) containing pH buffering products such as Potassium carbonate, Ammonium carbonate, Potassium bicarbonate, Ammonium bicarbonate, modified starches containing nitrogen in the chemical structure and Di-Potassium Phosphate, all grades, bought commercially off the shelf and blended to give an optimum inhibition product.

[0033] The blended product for F2V 2NP contains 21% Nitrogen and 23% Phosphorous. F2V N12 is a proprietary diamine bought commercially and contains 1.3% Nitrogen.F2V 1NP is a blended MAP (Mono-Ammonium Phosphate) containing 12% Nitrogen, and 26% Phosphorous, F2V P2K is a blended DPP (Di-Potassium Phosphate) containing 17% Phosphorous and 44% Potassium and F2V P1K is a blended MPP (Mono-Potassium Phosphate) containing 22% Phosphorous and 28% Potassium.

[0034] The blended products contain 80% to 100% of the products discussed above and 0% to % of either/or ammonium carbonate, ammonium bicarbonate, potassium carbonate, modified starches containing nitrogen in the chemical structure and/or potassium carbonate. These products are added to buffer the pH of the combination and to optimise the inhibition properties.

Example 1 - F2V 2NP

Nitrogen content 19.1% - 21.0% Phosphorus content 21.2% - 21.3% F2V 2NP mixed with buffers below at a concentration of 80% to 99% (m/m) Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of 8 Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of 8 modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition

The above mixtures are used in water at a concentration, generally, between 0.25% to 0.5% (m/v).

Example 2 - F2V N12

Nitrogen content 1.1% - 1.2% F2V N12 mixed with the buffers below at a concentration of 80% to 99% (m/m) Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of 8 Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of 8 modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition

The above mixtures are used in water at a concentration, generally, between 0.125% to 0.25% (m/v).

Example 3 - F2V P2K

Phosphorus content 16.0% - 17.6% Potassium content 40.4% - 44.5% F2V P2K mixed with buffers below at a concentration of 80% to 99% (m/m) Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of 8

Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of 8 modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition

The above mixtures are used in water at a concentration, generally, between 0.25% to 0.5% (m/v).

Inhibition tests

[0035] Inhibition tests were done using coated %" bentonite pellets so that a relative comparison could be made between 4% KCI and any other inhibitor. The %" coated bentonite pellets (Figure 1) were commercially bought off the shelf in Australia. Ten of the coated bentonite pellets were weighed before use and then suspended on a sieve (Figure 2 and 3) above a magnetic stirrer in a solution of different concentrations of the various inhibitor/fertiliser products (Figure 4).

[0036] Ten pellets were used every time as this was a good number of pellets to test on the sieve and did not occupy such a large area that one had to double stack the pellets on the sieve. They could be stacked in a single layer. Secondly, the pellets are not exactly the same size and the coating is not homogeneous. Thus 10 pellets will give a good average impression of how well the fluid inhibits the coated bentonite pellet.

[0037] Five to ten ml aliquot portions are withdrawn from the inhibition solutions by pipet during the test and used to determine the Turbidity of the sample in 1 minute or longer time intervals utilising a Turbidity meter giving the Turbidity in FAU units (Hach DR 900 model). The aliquot sample used for the determination of the Turbidity is returned to the solution and the Turbidity vs time is noted. Photos are taken of the samples before immersion, at the end of the test, after removal from the test vessel to show what was left on the sieve. The samples that are immersed in the inhibiting fluid are run for a duration of time until the Turbidity appears to be flattening out and then the test is stopped. As 4% KCI was the benchmark against which all the other products were measured, the end time used for 4% KCI was used for all the other tests so that all could be compared to 4% KCl. For 4% KCI case, the reaction time was standardised at 45 min and all other products measured accordingly.

[0038] The stirrer speed of the magnetic stirrer must be such that it suspends colloidal clay particles that have been removed from the coated bentonite pellets, but does not mix fast enough to keep heavier particles that have broken away from the coated bentonite pellets suspended in the test-fluid but rather allows them to settle at the bottom, not contributing to the Turbidity readings. In this way the Turbidity readings then give a quantitative value of how many colloidal particles that are either only partially inhibited or are not inhibited in the solution vs. time. The stirrer speed was kept constant at 475 RPM to 490 RPM.

[0039] At the end of the test period, the stirrer was stopped and the sieve with the residue of the bentonite tablets were removed. A photo was taken and the number of pellets that could visibly be counted that were left and had retained the original coated pellets shape were then noted. The pellet residue on the sieve was transferred on to either a filter paper or aluminum foil to be dried and re-weighed.

[0040] Thus for these inhibition tests as a relative comparison, the start time of the turbidity readings, the last 10 minutes average Turbidity values, the visual appearance of the pellets, the amount of visually countable pellets and the mass loss of the pellets through the sieve are compared to 4% KCI and based on these results it is determined what concentration of modified alternative products would give an equivalent level of inhibition relative to 4% KCl.

[0041] A second inhibition test was run as per test method API RP 131/ ISO 10416:2002 (Shale particle disintegration test by hot rolling). In this test shale samples received from the field were sieved to have a particle size > 2mm and < 4mm. The shale samples were analysed to have a clay content of between 8% and 12 % of the samples. The shale samples were then placed in a hot rolling cell with or without chemicals and hot rolled at 50° C for 8 hours. The cells were allowed to cool and the contents of the cell were run over pre-weighed 500-micron sieves to retain all the particles > 500-micron. The sieves were dried and the mass retained calculated relative to the starting mass. The results were compared with water alone and 4% KCI as benchmarks.

[0042] Alternatively, any other type of inhibition test known to be used for water-based Drilling Fluid could be run to determine what concentration of alternative inhibitor can be run to give the same level of inhibition as 4% KCl. Be that with linear swelling tests, bentonite powder tests, visual test with core pieces, etc.

Drilling fluid Analysis

[0043] Once the concentration is determined for the alternative drilling fluids to give the same level of inhibition as 4% KCl, a pH, electrical conductivity (EC in either dS/m or mS/cm, they are equivalent) and the chlorides (where appropriate) must be measured. These values would then be used to determine the spread rate of the drilling fluid and cuttings as proposed spread rates. This would have to be done in the field as well and based on the limits set for classification of cuttings and drilling fluids as regulated and non-regulated.

Recommended Spread rates

[0044] If the products contain fertiliser components and do not contribute to chlorides, but for the chlorides that come from the makeup water (thus low chlorides less than 8,000 ppm), but still have EC values > 20 dS/m, then an application would need to be made to the EPA for approval that the cuttings and fluids are not regulated as the component are fertiliser components.

[0045] If the cuttings and fluids are below or within the stipulated pH, EC and chloride specifications then these fluids and cutting will be deemed to be unregulated and thus may be land spread at recommended concentration of < 60 Kg/Hectare Nitrogen.

Advantages of F2V DF system above KCI DF systems

F2V DF systems are superior inhibitive systems relative to KCI DF systems F2V DF system cuttings and fluids will be unregulated once a well is completed F2V DF systems will be beneficial for any soils and contribute to soil fertilisation F2V DF systems require less chemicals than KCI DF systems F2V DF systems require less lease space for storage F2V DF systems require less cartage costs due to less chemicals being used F2V DF systems leaves a much smaller carbon footprint than KCI DF systems F2V DF systems are environmentally friendly F2V DF systems will cost less than KCI DF systems per bbl Drilling Fluid used

Typical examples

[0046] Typical examples are shown in Table 1 (Figures 5A-5C) where 4% KCI was used as a benchmark and other chemicals were tested relative to 4% KCI using the bentonite pellets. The results must be interpreted in the following manner:

1. The higher the time for Turbidity to be recorded, the better. Thus a time of 45 min would be preferable and a time of 1 minute is the worst case scenario.

2. The turbidity reading should be as low as possible. Thus a zero FAU value for Turbidity would be the best and a value of above about 50 FAU would be worse than the average values for 4% KCI and would thus be deemed worse than 4% KCl.

3. The mass loss is an indication of what percentage of the coated bentonite pellets was not retained on the sieve and thus the lower the mass loss, the better. The average mass loss for 4% KCI was an average of about 44% and any mass loss greater than 44% would be deemed to have less inhibiting power than 4% KCl.

4. Lastly the amount of pellets retaining the original coated bentonite pellet shape are visibly noted and a photo is retained as evidence.

[0047] The results in Table 1 show that the alternative products when compared to 4% KCI may be used at lower concentrations to attain better inhibitive results when coated bentonite pellets are used as the base for the test.

[0048] In comparison, looking at Table 1, F2V 2NP and F2V P2K at 0.5% are better inhibitors than 4% KC. Table 1 results also show that F2V N12 is a better inhibitor at 0.25% than 4% KCI. Thus the ratio of F2V 2NP would always be about 8 times less than any KCI concentration that a company was used to use KCI for and the F2V N12 will always be 16 times less than a company was used to use the KCI concentration for. As an example, if a company was used to using 2% KC, then the company could use F2V 2NP at 0.25% and F2V N12 at 0.125% concentrations.

[0049] As further comparison, Table 2 shows the concentrations of the products after being used as drilling fluids and the application and spread rates as fertilisers.

[0050] As further example, the F2V products inhibition performance were compared to 4% KCI and water alone by shale dispersion method. The results are shown in Table 3. This table shows that F2V 2NP A, F2V P2K A and F2V N12 A are better to equivalent to 4% KCI at a concentration of 1%. The formulations F2V 2NP C, F2V P2K C and F2V N12 C are even better than 4% KCI and the F2V 2NP A, F2V P2K A and F2V N12 A formulations giving retained solids of 95% to 96%.

[0051] Further typical examples are shown below as to how a KCI DF system (Figure 8) would need to be carted to a regulated waste facility incurring the extra cost of cartage and storage and the negative consequences of using this Drilling Fluid system vs. the F2V system (Figure 9) which after drilling can be disposed of in an environmentally friendly and beneficial way to the soil.

[0052] Whilst the above has been given by way of illustrative example many variations and modifications will be apparent to those skilled in the art without departing from the broad ambit and scope of the invention as herein set out in the appended claims.

Claims (13)

1. The process of applying fertiliser components in drilling fluids and then thereafter, when finished drilling, the resulting fluid and cutting are beneficial to be land spread as fertiliser.

2. The process of claim 1 wherein the resulting fluid is spread at a predetermined rate in accordance with the fertiliser components in the resulting fluid or the resulting fluid is altered and spread at a predetermined rate in accordance with the fertiliser components in the altered fluid.

3. The process of claim 1 involving a method of drilling fluid remediation comprising the steps of: A. Providing fertiliser components as a fertiliser orfertiliser chemicals having selected from the following: a. Diammonium Phosphate b. Monoammonium Phosphate c. Dipotassium Phosphate d. Monopotassium Phosphate e. Tripotassium Phosphate f. Tetrapotassium Pyrophosphate g. Monopotassium Pyrophosphate h. Dipotassium Pyrophosphate i. Tripotassium Pyrophosphate

j. All potassium and ammonium polyphosphates k. Mono and diamines containing either a multiple carbon chain attached to the amine or in between the diamine groups B. Blending the fertiliser components with other ingredients selected from the following in the range of quantities listed to then provide a drilling fluid with predetermined inhibition characteristics; a. Ammonium carbonate, >0% to 10% b. Ammonium bicarbonate, >0% to 10% c. Potassium carbonate, >0% to 10% d. Potassium bicarbonate, >0% to 10% e. Modified starches containing nitrogen in the chemical structure >0%-10% C. Using the drilling fluid in a wellbore; D. Recovering the drilling fluid upon completion of drilling; E. Determining the concentration of fertiliser components in the drilling fluid recovered in step D; and F. Spreading the recovered drilling fluid at a spread rate in accordance with the concentrations determined in step E.

4. The process of claim 2 where after step E there may be a step of further processing including reducing the fertiliser to a dry form or taking a step that alters the concentrations measured in step E.

5. The process of claim 2 wherein after step E, taking a further step that alters the concentrations measured in step E to provide an altered recovered drilling fluid, then step E is repeated on the altered recovered drilling fluid and step F then involves spreading the altered recovered drilling fluid in accordance with its concentrations of fertiliser components determined in the repeated step E.

6. The process of claim 1 wherein a modified DAP (Di-Ammonium Phosphate) containing pH buffering products selected from Potassium carbonate, Ammonium carbonate, Potassium bicarbonate, Ammonium bicarbonate, modified starches containing nitrogen in the chemical structure and Di-Potassium Phosphate are blended are blended with a commercial fertiliser which contains 21% Nitrogen and 23% Phosphorous.

7. The process of claim 1 wherein the drilling fluid includes a modified DAP (Di-Ammonium Phosphate) containing pH buffering products selected from Potassium carbonate, Ammonium carbonate, Potassium bicarbonate, Ammonium bicarbonate, modified starches containing nitrogen in the chemical structure and Di-Potassium Phosphate are blended with proprietary diamine containing about 1.3% Nitrogen.

8. The process of claim 1 wherein the drilling fluid uses a blended MAP (Mono-Ammonium Phosphate) containing 12% Nitrogen, and 26% Phosphorous.

9. The process of claim 1 wherein the drilling fluid uses a blended DPP (Di-Potassium Phosphate) containing 17% Phosphorous and 44% Potassium.

10. The process of claim 1 wherein the drilling fluid uses a blended MPP (Mono-Potassium Phosphate) containing 22% Phosphorous and 28% Potassium.

11. The process of claim 1 wherein prior to mixing with water at a concentration, generally, between 0.25% to 0.5% (m/v). ingredients have the following: a. Nitrogen content 19.1% - 21.0% b. phosphorus content 21.2% - 21.3% c. mixed with buffers at a concentration of 80% to 99% (m/m) being selected from i. Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of 8 ii. Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of 8 iii. modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition.

12. The process of claim 1 wherein prior to mixing with water at a concentration, generally, between 0.25% to 0.5% (m/v). ingredients have the following: a. Nitrogen content 1.1%- 1.2% b. mixed with the buffers selected for the below at a concentration of 80% to 99% (m/m) i. Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of 8 ii. Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of 8 iii. modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition

13. The process of claim 1 wherein prior to mixing with water at a concentration, generally, between 0.25% to 0.5% (m/v). ingredients have the following: a. Phosphorus content 16.0% - 17.6% b. Potassium content 40.4% - 44.5 c. mixed with buffers below at a concentration of 80% to 99% (m/m) i. Potassium carbonate added as 1% - 10% (m/m), buffered to a pH of about 8 ii. Ammonium bicarbonate added as 1% - 10% (m/m), buffered to a pH of about 8 iii. modified starches containing nitrogen in the chemical structure as 1%-10%, enhancing performance of the composition.