GB2089397A - High density wellbore fluids - Google Patents

Abstract

An aqueous wellbore fluid for use as a drilling, well completion, packing, perforating or workover fluid or the like, and preferably having a specific gravity of not less than 1.190, contains a density increasing agent comprising potassium carbonate. The density increasing agent may be potassium carbonate alone or a mixture of potassium carbonate with sodium or potassium chloride, bromide or bicarbonate or with sodium carbonate. The fluid gives good corrosion resistance, is not highly toxic and absorbs toxic hydrogen sulphide. It is also stable over a wide range of temperature.

Description

SPECIFICATION High density wellbore fluids This invention concerns improved high density wellbore fluids for drilling, preparing for production and revitalising wells penetrating subterranean strata for the purpose of producing oil, gas or other natural resources.

Wellbore fluids for oil and gas wells include drilling, well completion, packing, perforating and workover fluids and also fluids used in sand control operations.

An oil or gas well is generally drilled by means of a bit which is rotated in the drill hole by means of a "string" of connected hollow rods. Down the bore of the hollow rods is pumped a drilling fluid comprising a liquid and various mineral or chemical additives which may be soluble or insoluble in the liquid. The function of the drilling fluid or "mud" is to line the walls of the hole in order to stabilise the formations through which the hole passes, to help to prevent the escape of gases and liquids under pressure up the hole, to carry away the drill cuttings or pieces of rock dislodged by the rotating bit and to cool and lubricate the bit.In order to contain the pressure of gases and liquids in the formations through which the hole passes it is often necessary for the drilling fluid to be of high specific gravity so that the hydrostatic pressure of the column of drilling fluid in the hole exceeds the pressure of the fluids in the formations. In general the hydrostatic head provided by the column of drilling fluid should exceed the pressure of the fluids in the formations by about 100--200 psi (690-1 380 kPa).

When the hole has been drilled to the required depth it is "cased" with steel tubing of diameter a little less than that of the hole, and, in order to seal the casing to the walls of the hole, Portland cement is pumped down the inside of the casing and allowed to flow upwards through the annular space between the casing and the walls of the hole. Rubber plugs are inserted into the casing to separate the cement from the drilling mud. After the cement has set, the drilling mud is generally flushed out from the interior of the casing by lowering a pipe to the bottom of the well and pumping down naturally avc.ilable water, such as sea or river water.

The flushing water is then replaced by a high density fluid known as a completion fluid, the function of which is to contain the pressure of the gas, oil or other fluids in the formation through which the hole passes.

The well may be "completed" or prepared for production for example by perforating the casing and surrounding cement so that the oil or gas-bearing formation communicates with the interior of the casing. This may be achieved by lowering to the depth of the oil- or gas-bearing formation a perforator which may comprise, for example, a plurality of barrels from which hard-tipped bullets are propelled through the casing and the cement and some distance into the formation by means of explosive charges fired by remote control from ground level. Again it is generally necessary that the completion fluid has a relatively high specific gravity in order to contain the pressure of fluids in the formation.

Oil or gas wells in production are often found to decrease in productivity or to become unsafe and it is necessary to perform operations in the well at the level of the oil- or gas-bearing formation in order to improve the productivity or safety. For this purpose the well is "killed" by pumping into the well a high density "workover" fluid which effectively overcomes the fluid pressure in the formation by its own hydrostatic head.

Other operations for which high density well-bore fluids are required include underreaming in which a fluid is required to contain the pressure while the wellbore is widened in the region of the producing formation, and the placing of a gravel bed in the bottom of the well to provide a bed through which the oil or gas can filter while solid material is retained.

It is inevitable that the porous nature of the formation will be affected by the drilling operation, in which a cake of the solids contained in the drilling mud forms on the walls of the hole, and by the cementing operation, but the damage to the formation will generally extend not further than about 50 mm from the outer wall of the casing. In order to avoid more extensive damage to the formation by plugging capillaries with solid matter and thus restricting the channels through which oil and gas can pass to the casing of the well, it is desirable that the wellbore fluid used contains substantially no suspended solids. It is therefore desirable that the material which is added to increase the specific gravity of the wellbore fluid should be soluble in the liquid vehicle used for the fluid.Thus, in the case of an aqueous wellbore fluid, the density increasing agent should be water-soluble.

Examples of commonly used density increasing agents for aqueous wellbore fluids include halides such as chlorides and bromides of sodium, potassium, calcium and zinc and mixtures thereof. The following Table gives examples of density increasing agents for wellbore fluids and the approximate maximum fluid specific gravity which each agent can usefully provide.

TABLE Density increasing agent Max. specific gravity Potassium chloride 1.176 Sodium chloride 1.200 Sodium chloride/calcium chloride 1.320 Calcium chloride 1.405 Calcium chloride/zinc chloride 1.700 Calcium chloride/calcium bromide 1.811 Calcium bromide/zinc bromide 2.305 Although solutions of suitable density can be provided in this manner the halides have certain disadvantages when used as density increasing agents in wellbore fluids.For example the water-soluble salts which give solutions of the highest specific gravity, the bromides and zinc chloride, are expensive and zinc chloride, in particular, is highly corrosive and toxic. Aiso the solutions of calcium halides absorb carbon dioxide with resultant precipitation of calcium carbonate and also produce sparingly soluble calcium sulphates by double decomposition with sulphuric acid or soluble sulphates in the rock formations through which the well passes.

An object of the invention is to provide an aqueouswellbore fluid which overcomes or ameliorates these disadvantages.

According to the present invention, there is provided an aqueous wellbore fluid in which the density increasing agent comprises potassium carbonate.

Potassium carbonate has a solubility in water at 200C such that a wellbore fluid of maximum specific gravity 1.558 is obtainable using potassium carbonate as the sole density increasing agent. A saturated aqueous solution of potassium carbonate at 200C contains 52.5% by weight of anhydrous potassium carbonate.

The density increasing agent may be potassium carbonate alone or may comprise a mixture of potassium carbonate with a known density increasing agent such as the chloride or bromide of sodium or potassium, or with potassium bicarbonate or sodium carbonate or bicarbonate.

The specific gravity of the wellbore fluid will generally be not less than 1.190. This specific gravity may be provided by a solution containing 20% by weight of potassium carbonate.

The wellbore fluid may contain other water-soluble species such as water-soluble polymeric viscosifiers; in order, for example to increase the viscosity of the fluid for the purpose of removing debris from the wellbore. Suitable viscosifiers include xanthan gum, carboxymethyl cellulose, guar gum and the like. Water-soluble filtrate loss reducers such as starch, starch derivatives and lignosulphonates may also be included.

The wellbore fluid may also contain insoluble viscosifiers such as attapulgite, sepiolite or asbestos, insoluble density increasing agents such as calcium carbonate, ferrour carbonate or barium sulphate, or temporary "bridging" material. Bridging materials are intended to form a temporary seal over the exposed face of the formation and must be capable of subsequent removal. For example a bridging material may be an acid-soluble solid such as calcium carbonate, an oil-soluble solid such as an oleophilic polymer or may be particles of a water-soluble salt such as sodium chloride or potassium chloride suspended in the potassium carbonate solution in a quantity such that the solubility of the salt in the potassium carbonate solution is exceeded.

Potassium carbonate gives a solution of high natural pH which inhibits corrosion of the ferrous metals used for drill bits, casing, production tubing and the like. Solutions of potassium carbonate have the additional advantage that they absorb the highly toxic hydrogen sulphide gas, which is commonly encountered when drilling for oil and gas, as the harmless sulphide ion. Potassium carbonate solutions also show no seriously disadvantageous effect in the presence of carbon dioxide gas. Potassium carbonate solution in the presence of large quantities of carbon dioxide gas will slowly absorb carbon dioxide to form potassium bicarbonate and under certain conditions of temperature and pressure the bicarbonate may precipitate. However, in the lower regions of a borehole the temperature is usually sufficiently high to keep the bicarbonate in solution and even if small amounts of the precipicate do form they are generally removed by water which occurs naturally in the formation, or, if necessary, by injecting water down the well. Potassium carbonate is of relatively low cost compared with bromides and soluble zinc salts and is readily available in substantially pure form so that even the technical grade provides a clear solution substantially free of suspended solids.

Potassium carbonate is not considered to be a toxic material and has the additional advantage that it remains in the form of a free-flowing powder or granular material even in conditions of high humidity, because the solid material appears to absorb water from the atmosphere only very slowly. It is stable to changes in temperature over a wide range and suppresses by the common-ion effect the solution of limestones in the formation through which the well passes. The precipitation of insoluble sulphates by double decomposition with sulphuric acid or soluble sulphates encountered in the rock formations is also avoided. Potassium carbonate gives the further advantage that clays contained in the formations through which the well passes will be converted by ion exchange to the potassium form.It is well known that swelling clays swell much less readily, and non-swelling clays disperse less readily, when they are in the potassium form, and plugging of pores in the rock with clay is thereby inhibited.

Potassium carbonate has the additional advantage as a specific gravity increasing agent that its decrease in solubility in water with decreased temperature is relatively small over normal temperature ranges. For example, an aqueous solution containing 50.4% by weight of potassium carbonate (specific gravity 1.53 or 12.8 Ib/U.S. gallon) at 200C does not crystallise out any solid potassium carbonate until the temperature of the solution falls below-I 00C (140 F). By contrast, solutions containing a mixture of calcium chloride and calcium bromide must be formulated with great care if crystallisation to a slushy, unpumpable mass on cooling is to be avoided.

The invention will be illustrated further by the following Examples.

EXAMPLE 1 High density, solids free solutions of potassium carbonate in water were prepared at the concentrations shown in Table I below. The solutions were found to be suitable for use as completion and workover fluids and, after filtration, were found to be especially advantageous for use when perforation was being undertaken. Table I shows the quantities of water and dry potassium carbonate required to produce 1 barrel (42 U.S. gallons, 35 imperial gallons or 1 59 litres) of potassium carbonate solution at the densities shown. The crystallisation temperature, or the temperature at which some crystallisation of potassium carbonate or ice from the solution occurs, is also shown for each density.

TABLE I Crystallisation Density at 2O0C Quantities required temp.

Solid g/cc Ib/U.S.gall. water (barrels) K2CO3(lb) OC OF phase 1.200 10 0.949 89 -10 14 ice 1.321 11 0.898 150 -22 -8 ice 1.441 12 0.832 212 -27 -17 K2CO3.6H20 1.537 12.8 0.763 272 -10 14 K2CO3.6H20 1.549 12.9 0.753 280 10 50 K2CO3.6H20 These results show that potassium carbonate solutions, over the most useful density range, are stable down to low ambient temperatures.

EXAMPLE 2 Wellbore fluids of higher viscosity, suitable, for example, for removing debris out of a wellbore, were prepared by adding xanthan gum, a water soluble polymer formed as an extracellular coating on certain micro-organisms, to high density potassium carbonate solutions of the type shown in Example 1.

The rheological properties of a 12.0 Ib/U.S. gallon density potassium carbonate solution to which was added 2 Ib. of xanthan gum per barrel of solution were measured using a Fann Viscometer at 200C and the results are set forth in Table II below TABLE II Apparent Plastic Yield Gels Viscosity (A.V.) Viscosity (P.V.) Point (Y.P.) (lib/100 ft2) (centipoise) (centipoise) (lib./1 00 ft2) 10 sec 10 min 32 18 28 8 12 These solutions, although of increased viscosity, do not have any appreciable lubricating properties, nor is this intended.

EXAMPLE 3 Wellbore fluids for use where the strata are very permeable and where losses of potassium carbonate solution would otherwise be excessive were prepared by adding to a viscosified potassium carbonate solution of the type described in Example 2, ground calcium carbonate having a broad particle size distribution at a rate of 40 lb. per barrel of viscosified potassium carbonate solution. The rheological properties were measured using a Fann Viscometer at 200C and the A.P.I. Filtrate Loss was also determined.The results are set forth in Table Ill below: TABLE Ill Apparent Plastic Yield Gels A.P.I. Filtrate Viscosity Viscosity Point (Ib/1 00 ft2) Loss (centipoise) (centipoise) (lib/1 00 ft2) 10 sec 10 min (ml) 36 20 32 9 13 3.0 The fluids of the type described above were found to be very useful for bridging or forming temporary seals over permeable strata and also in certain drilling and underreaming operations.

EXAMPLE 4 A wellbore fluid for use as a packer fluid, i.e. a fluid which is intended to remain in place for many years in the annulus between the casing and the production tubing for the purpose of reducing differential pressures across the casing, production tubing and packer, was prepared according to the following formulation: Requirement/barrel Ingredient of fluid Water 0.832 barrel Potassium carbonate 212 lb.

Sodium sulphite 0.1-0.2 Ib.

Water soluble or dispersible film-forming 2.0 lb.

amine derivative The sodium sulphite was added as an oxygen scavenger and the film-forming amine derivative, which was added to protect the steel casing against corrosion, was the product sold by International Drilling Fluids Limited under the Trade Mark "IDFILM 220". It is unnecessary to add a bactericide because the presence of the potassium carbonate in the concentration indicated above is sufficient to prevent bacterial growth. The corrosion rate for steel samples in contact with a wellbore fluid of the above composition is very low.

In the above Examples the Apparent Viscosity, Plastic Viscosity, Yield Point and Gel Strength were measured in accordance with the procedures laid down in "Standard Procedure for Testing Drilling Fluids", American Petroleum Institute, 1978.

Claims (8)

1. An aqueous wellbore fluid in which the density increasing agent comprises potassium carbonate.

2. An aqueous wellbore fluid according to claim 1, wherein the density increasing agent consists substantially entirely of potassium carbonate.

3. An aqueous wellbore fluid according to claim 1, wherein the density increasing agent comprises a mixture of potassium carbonate with a material selected from the group comprising the chlorides, bromides and bicarbonates of sodium and potassium and sodium carbonate.

4. An aqueous wellbore fluid according to claim 1, 2 or 3, wherein the specific gravity of the fluid is not less than 1.190.

5. An aqueous wellbore fluid according to any preceding claim, wherein the fluid also comprises one or more water-soluble polymeric viscosifiers and/or one or more water-soluble filtrate loss reducers.

6. An aqueous wellbore fluid according to any one of claims 1 to 4, wherein the fluid also comprises one or more insoluble viscosifiers and/or one or more insoluble density increasing agents and/or temporary bridging material.

7. An aqueous wellbore fluid substantially as described in any one of the foregoing Examples.

8. An aqueous wellbore fluid as claimed in claim 1 and substantially as hereinbefore described.