WO1995016758A1

WO1995016758A1 - Drilling fluid

Info

Publication number: WO1995016758A1
Application number: PCT/GB1994/002694
Authority: WO
Inventors: Gerald Henry Meeten; Claude Joseph Vercaemer; Paul William Way
Original assignee: Sofitech N.V.; Schlumberger Canada Limited; Compagnie Des Services Dowell Schlumberger
Priority date: 1993-12-17
Filing date: 1994-12-09
Publication date: 1995-06-22
Also published as: GB2285074A; GB9325871D0; AU1196095A; GB2285074B

Abstract

A drilling fluid suitable for drilling through brittle shales comprises a mixed metal hydroxide fluid having dispersed therein a particulate plate-like mineral such as vermiculite or mica as a crack-blocking fluid-loss-control agent. The fluid can also include other drilling fluid additives, such as barite, bentonite and fluid-loss-control polymers.

Description

DRILLING FLUID

This invention concerns a drilling fluid and its manner of use. In particular, the invention relates to a mixed metal hydroxide drilling fluid which is suitable for drilling in intermediate permeability or microfractured formations.

Formations which have intermediate permeability typically have microfractures with aperture widths in the range of 25-1000 μm. These microfractures can either exist naturally or can be the result of the drilling operation. In cases where such formations occur, and in particular where the fractures are interconnected, wellbore stability problems can arise due to the pressurisation and wetting of the fractures by the drilling fluid. These effects can be particularly severe in microfractured shales although they are not confined to such formations. When fluid is lost to the formation, the invaded region possesses a lower mechanical stability due to the equalisation of pressures between the fluid in the borehole and the connate pore fluid in the formation. If the pressure in the borehole is higher than the pore pressure and a mudcake exists, the differential pressure causes the formation to increase its shear strength and to confer shear strength to a formation such as sand which completely lacks intrinsic strength. If the borehole and pore pressures are equal, no stresses arise in the solid part of the formation, and if the formation is weak, it is rendered fragile, with consequent wellbore instability problems.

In microfractured shales, pressure rise due to invasion of drilling fluid leaks away much more slowly than in permeable formations such as sandstone. In these shales, invasion of mud into microfractures can results in catastrophic failure of large portions of the wellbore by caving or sloughing reactions. This can cause significant delays in drilling with consequent additional drilling costs, and, in extreme cases, can result in loss of the well.

Loss of drilling fluid to the formation is normally controlled by selecting an appropriate drilling fluid formulation and/or by pill treatments with lost circulation materials. The materials used in drilling fluid formulation to control fluid loss can typically comprise polymers or other organic compounds, such as hydroxyethylcarboxymethyl cellulose, cornstarch, sodium-polyacrylate, starch, polyacrylate, and carboxymethyl cellulose (CMC). These materials will typically block pores of less than 1 μ m aperture. For larger pore apertures, the flow of fluid into the formation due to differential pressure will cause a mudcake to build up, formed from solid materials in the drilling fluid such as bentonite particles and barite particles. These will usually deal with pore apertures up to about 150 μm with the ability to prevent fluid loss becoming progressively worse as the aperture size increases. Above 150 μm such fluids are unable to prevent lost circulation, which then becomes substantially continuous.

Lost-circulation material is normally applied as a "pill" treatment - i.e. the material, often a fibrous material such as nut shells or vegetable fibres, is added to the drilling fluid only when lost circulation has been detected - and so by then a considerable amount of fluid will have entered the formation.

What is required is a drilling fluid in which the damaging effect of fluid entering the microfractures is minimised. Such a drilling fluid should have low viscosity while the fluid is being circulated so as to minimise the pressure increase above that of stationary mud. The circulating pressure is often referred to as equivalent circulating density (ECD). The Theological properties of a drilling fluid have a strong influence on ECD, and minimising the difference between the static pressure and that due to ECD will both reduce the risk of generating new fractures and reduce the rate at which existing and new fractures become pressurised. The fluid should also be able to form a firm gel quickly when circulation stops. This ensures that any fluid invading the fractures becomes effectively solid, and so minimises further disturbance of the rock by later pressure fluctuations and provides some additional strength to the rock. ECD and gelling properties such as these are provided by mixed metal hydroxide (MMH) drilling fluids such as are described in US Patents 4,664,843, 4,790,954, 4,990,268, 5,032,308, 5,094,778, and 5,196,143. However, such fluids are unsuitable for the large pore fractured formations discussed above because of the size of the fractures, which are such that the fluid can leak off into the formation without providing the benefit sought. It is also inappropriate to use "pill" type fluid-loss-control treatments since these are only applied after lost circulation has been detected, by which time sufficient fluid will have entered the fractures ("spurt") to exacerbate the problems which it is desired to avoid.

The invention proposes a novel drilling fluid having both the desired Theological properties and being such that the spurt fluid loss is minimised in microfractured formations, and to achieve this it suggests that there be incorporated into a mixed metal hydroxide drilling fluid an appropriate amount of a mineral having plate-like particles, such as vermiculite or mica.

In one aspect, therefore, the invention provides a drilling fluid which is a mixed metal hydroxide drilling fluid with the addition of an appropriate quantity of a mineral in plate-like particulate form. Typical such plate-like minerals are vermiculite or mica.

It is preferred that substantially all of the mineral have a face dimension of not less than 75 mm, and preferably greater than 150 μ m Such particles are of suitable dimensions to block microfractures quickly, yet neither vermiculite (at 0.2 to 0.5 μ m) nor mica particles of this size compromise the Theological properties of the fluid. Consequently, the mineral can be included in the fluid ab initio, and so is available to block fractures as soon as they are encountered, unlike a pill treatment which requires fluid loss to be detected.

The plate-like mineral can be added to the drilling fluid at a concentration of a few wt%, e.g. 3-10 wt%.

The drilling fluid may contain all the conventional ingredients - typically bentonite, barite and fluid-loss-control polymers. When vermiculite is employed in a bentonite- containing fluid, the ratio of vermiculite to bentonite is preferably not more than 4: 1.

The present invention will now be described both with regard to the following illustrative Examples and with reference to the accompanying Drawings in which:

Figure 1 shows a plot of spurt against crack width for vermiculite-containing drilling fluids; Figure 2 shows a plot of spurt against vermiculite concentration for two different crack widths; Figure 3 shows American Petroleum Institute (API) 30 min full area fluid loss tests of aqueous vermiculite-bentonite suspensions; Figure 4 shows a comparison of spurt and filtration fluid floss for varying vermiculite concentrations; Figure 5 shows a comparison of the effect of CMC (carboxymethyl cellulose) in the fluid loss of vermiculite slurries and bentonite slurries; Figure 6 shows the effect on fluid loss of adding IDBS (wopropylamine salt of dodecyl benzene sulphonate) to a vermiculite suspension; Figure 7 shows the change in plastic viscosity of vermiculite and bentonite slurries for changing CaCl2 concentrations; and Figure 8 show changes in API yield and of vermiculite and bentonite slurries for changing CaCl2 concentrations.

Example 1 - Mixed Metal Hydroxide / Mica Drilling Fluid

Tests were made on a laboratory MMH fluid (Visplex) made to a field specification, containing bentonite (121b/bbl), MMH (1.51b/bbl), a fluid-loss additive (51b bbl), barite varied to 1.3SG, drilled solids (301k/bbl), and the pH adjusted to 10.5 with caustic soda. Mica (MF20) was added at 5% wt. The Theology was practically unchanged; a few % increase in plastic viscosity (PV) and yield point (YP). The effect of the mica was to decrease the 30 min API fluid loss from 4.2 mL to 3.5 mL. The spurt loss on the 150 and 350 μ m cracks was infinite for the MMH drilling fluid without mica, and was reduced to 1.8 mL and 16 mL, respectively when the mica was added.

Example 2 - Mixed Metal Hydroxide / Vermiculite Drilling Fluids

Vermiculite is a mineral which is usually exfoliated prior to use by heating to produce a rapid expansion of the naturally-occurring material. In this state it readily absorbs water, and can be readily worked into a slurry. The particle face diameter can be adjusted by the duration and intensity of the working action, and is typically in the range 0.2-0.5 μm. Mixed metal hydroxide particles are cationic, and when used in conjunction with an anionic colloid, typically bentonite, produce a very-rapidly-gelling drilling fluid with a high gel strength. This gives a fluid of good suspending power, particularly valuable for the efficient hole-cleaning required for fragile formations. The vermiculite particle surface physical chemistry is known to be similar to that of bentonite, but owing to its (typically) larger particle size, the specific surface area is smaller. As a consequence, vermiculite can replace bentonite as a gelling agent in MMH, but, to attain the same gel properties, more vermiculite is required than bentonite. This is beneficial, as it allows the incorporation of more crack-blocking material without detriment to the drilling fluid's pumpability. Another aspect of the use of vermiculite with MMH fluid technology is its chemical compatibility with bentonite, as shown in the Example below. For this reason, when used with the MMH fluids bentonite could be used primarily as a means of attaining the high gel strength and thixotropy needed for good hole-cleaning, and vermiculite could be added primarily as a means of decreasing the spurt and blocking cracks too wide to be blocked by the other components of the drilling fluid.

The following Examples show the behaviour of vermiculite in different drilling fluids. Corresponding behaviour is found in mixed metal hydroxide drilling fluids according to the present invention.

Example 3 - Mudspurt

Figure 1 shows the effect of the crack width on the mudspurt when vermiculite is added to a KC1 -polymer drilling fluid. These measurements were taken using a 1/2 area API fluid- loss filter press, and the open area of the cracks was about 7% of the total open areas of the bore of the filter press. Depending on the details of the upper end of the barite particle size distribution, the 150 μm crack spurt without vermiculite can be very large - effectively infinite. Vermiculite is seen to reduce it to less than 10 mL. Even barite has an infinite spurt through the 350 μm crack; vermiculite is seen to reduce it to about 50 mL (with barite) or 80 mL (no barite).

Figure 2 shows the effect on the spurt of varying the vermiculite concentration in a glycol drilling fluid, using cracks of width 60 and 150 μm. The drilling fluid contained barite at a solidosity of 0.2, which was sufficient to obstruct the 60 μ m crack but not the 150 m crack. The vermiculite is seen to bring the spurt volume down to the 60 μ m crack level at a vermiculite concentration of about 100 g per L of drilling fluid. Example 4 - Fluid loss

Used neat, in an aqueous slurry, vermiculite has a very large API fluid loss, typically 100-200 mL. This can be reduced by blending it with bentonite, polymer or surfactant, as follows.

Figure 3 shows the API fluid loss as the vermiculite/bentonite ratio is varied. These measurements were made by taking two separate slurries of vermiculite and bentonite whose concentrations had been adjusted so as to obtain closely similar Theologies. Thus, as the vermiculite/bentonite ratio changed, the rheology (i.e. YP and PV) remained approximately fixed. For a material ratio of about 3:1 it shows that the fluid loss has a minimum, i.e. less than bentonite alone.

Figure 4 shows the compromise between spurt and fluid-loss control as the vermiculite/bentonite ratio is changed. The decrease in spurt on adding more vermiculite is accompanied by an increasing fluid loss arising from the poor fluid-loss performance of the vermiculite. This result, however, was obtained without using any fluid-loss-reducing additives such as polymer or surfactant, both which are shown below to have a strongly beneficial effect on the fluid loss of the vermiculite.

Example 5 - Effects of Polymer and Surfactant

Figure 5 shows the effect on the API fluid loss of adding a standard CMC fluid-loss- control polymer to slurries of both bentonite and vermiculite. As is well-known, the addition of more than 3g per L of CMC to the bentonite slurry is shown to have no further beneficial effect on the fluid loss. However, the beneficial effect of CMC is shown to be still increasing at lOg of CMC per L of vermiculite drilling fluid.

Figure 6 shows the effect on the API fluid loss of a vermiculite slurry of adding an anionic surfactant (IDBS, isopropylamine salt of dodecyl benzene sulphonate). At 10% IDBS, the API fluid loss is very low at 1 mL but the beneficial effect of the IDBS is still increasing.

Tests made on the effect of IDBS on the MMH drilling fluid also showed its fluid loss to be improved. With no IDBS the 30 min API fluid loss was 5.3 mL. On adding 2% vol IDBS the fluid loss reduced to 3.8 mL. Thus, the IBDS did not have a detrimental effect on the MHH drilling fluid. Example 6 - Rheologv

The useful effects associated with the use of vermiculite are not obtained at the expense of other important drilling fluid parameters, such as the rheology. Thus, CaCl2 was added to slurries of bentonite and vermiculite whose concentrations had been adjusted to obtain similar initial Theologies. This salt is a well-known gelling agent of bentonite water-base drilling fluid. The CaCl2 was added to each slurry, which was then rolled for about 20 min, and the resulting PV and YP measured in the API-prescribed manner using a Chan 35 oilfield rheometer.

Figure 7 shows the effect of the Ca⁺⁺ ions on the PV. Whereas bentonite shows a decrease of about 65%, the PV of the vermiculite slurry decreases by about 30%. Thus, the vermiculite is a factor of about 2 less sensitive to the Ca⁺⁺ ions than the bentonite.

Figure 8 shows the effects of the Ca⁺⁺ ions on YP. Whereas bentonite shows an increase of YP of about 70-80%, the YP of vermiculite decreases by about 30%. Thus, the vermiculite is a factor of about 2-2.5 less sensitive to the Ca "⁴" ions than the bentonite.

Claims

1. A drilling fluid composition comprising a mixed metal hydroxide drilling fluid and characterised bv having dispersed therein a particulate plate-like mineral as a crack blocking agent.

2. A drilling fluid as claimed in claim 1, wherein the particulate plate-like mineral is mica or vermiculite.

3. A drilling fluid as claimed in Claim 1 or 2, wherein most of the particulate plate-like mineral has a face dimension of not less than 150 μ m

4. A drilling fluid as claimed in any preceding Claim, further including one or more of bentonite, barite and fluid loss control polymers.

5. A drilling fluid as claimed in Claim 2 and Claim 4, containing vermiculite and bentonite present in a ratio of not more than 4: 1.

6. A drilling fluid as claimed in any preceding Claim, wherein the particulate plate-like mineral is present in an amount of 3 - 10 wt%.