NO347362B1 - Procedure for performing well operations - Google Patents

Description

Procedure for performing well operations

The present invention relates to methods for carrying out well operations and, more specifically, methods for carrying out drilling operations. The invention also relates to systems for carrying out the methods.

Background

Various borehole operations are carried out during the life cycle of a well, which naturally begins with the operation of drilling the well itself. Drilling can be followed by running a casing or casing into the borehole. In other phases, various intervention operations can be carried out, for example milling out a casing part in a closed well before drilling a new well trajectory from the old borehole. Various completion and cleaning processes may also be performed to prepare a well for production.

In such operations, and especially in drilling operations, long strings of equipment such as drill pipe or the like are driven into the well, often in a rotating mode guided by a suitable drill bit to penetrate the subsurface geological formation. To assist the process, a drilling fluid is typically pumped into the well through a central pipeline in the drill string and sent into the borehole through an outlet that connects the pipeline to the borehole near the drill bit. The fluid is forced upwards under pressure back along the string towards the surface in the annulus which is defined between an outer surface of the drill string and the mantle or formation wall. It can take the fluid several hours to complete the round trip from the drilling platform to the wellbore and back to the drilling platform.

The drilling fluid simplifies the well operation in a number of ways. A primary reason for circulating fluid in this manner is to remove cuttings (ie, particles of crushed or cut formation or rock produced by drilling) from the borehole as it is drilled. The drilling fluid is designed to keep floating or carry the drill cuttings. Therefore, the cuttings are removed from the borehole when the fluid is forced under pressure back to the surface. The drilling fluid is then typically filtered or screened using vibrators or other devices installed in a fluid handling apparatus on the drilling platform. Such devices remove the drill cuttings from the drilling fluid. The fluid is then typically reused, i.e. circulated back to the borehole.

If cuttings are not effectively removed from the borehole, they can interfere with the correct operation of the drill bit and can significantly slow down the progress of the drilling operation, e.g. the rate of penetration into the formation. In some cases, where cuttings removal has been ineffective, it may be necessary to carry out a cleaning operation before the well is completed. Improving a drilling fluid's ability to remove cuttings from a borehole therefore has a huge potential impact on the cost effectiveness of a drilling operation.

As for other functions, the drilling fluid pumped into a borehole also helps to drive the bit into the borehole and to cool and lubricate the bit. It can also be used to equalize hydrostatic pressure in the borehole to thereby prevent blow-out. The drilling fluid also functions to maintain borehole stability by generating pressure against the borehole wall and thereby preventing it from collapsing. It also provides fluid loss control, i.e. it prevents loss of fluid into the formation, and it provides chemical stability to the formation thereby preventing chemically induced wellbore instability.

These functions should ideally be achieved while minimizing formation damage. Damage can be caused by drilling fluids entering the formation, by the drilling fluids causing clay occurring in the formation to swell and/or by leading to the release of insoluble solids in the formation. In addition, the generation of emulsions in the formation should also be avoided.

The particular composition of the drilling fluid can significantly affect its ability to perform these various functions while minimizing formation damage. At the same time, downhole conditions such as borehole mineralogy, temperature and pressure, drilling rates and trajectories, well length and volume, etc., can affect fluid efficiency. It is obviously desirable to use a drilling fluid that is suitable for given down-hole conditions and achieves one or more of the functions above.

Drilling fluids are typically water- or oil-based compositions that comprise a mixture of chemicals designed to achieve a variety of functions. For example, fluids may be formulated with certain viscosities, densities, fluid loss control properties and chemical contents to attempt to provide the desired performance.

However, well and borehole conditions are constantly changing during the execution of a borehole operation when, for example, drilling advances and different geological intervals are entered. Drill cuttings from the formation can also be mixed into and held suspended in the fluid and recycled back into the borehole if not effectively removed on the surface. Borehole pressure and temperature also affect the fluid as well as the character of the formation. Consequently, the properties of the drilling fluid, e.g. viscosity, changes significantly during the drilling operation and affect its subsequent performance when recycled back into a borehole.

As a result, it can be difficult for operators to select a suitable fluid for a well operation such as drilling, and once a particular fluid has been selected by an operator, it is uncertain whether it will continue to be a suitable fluid when subjected to the borehole environment. As a result, the productivity of drilling or other downhole operations may be adversely affected.

It is common practice to take samples of return drilling fluid and subject them to a series of tests, usually in a laboratory, to determine values for their properties, i.e. viscosity, density, etc. Based on the results of these tests, the drilling fluid can then be treated, e.g. . by changing the proportion of components or by adding different compounds to bring the properties back into the appropriate ranges.

However, subjecting fluids to a series of tests, interpreting the results obtained from the tests, and the subsequent manual adjustment of the drilling fluid is time consuming and labor intensive. Critically, it does not make quick response or intervention to changes in a drilling fluid's properties possible.

Various systems and methods for drilling systems are described in US 6 176 323, US 2009/0 188 718, US 2009/0 293 605, GB 2 441 069, US 2004/0 236 513, US 6 443 001, WO 01/67 068 and US 2008/0 099 241. The applicant has realized the need for an improved automated method and system.

EP 0211112 A1 describes a system for real-time measurement of several properties of drilling fluids from a single sampling point.

Summary of the invention

Accordingly, the present invention provides a method for performing a well operation, where the method comprises the steps according to claim 1.

In preferred methods, the fluid is recycled during the execution of the well operation.

Viewed from another aspect, the present invention provides a system for controlling the properties of a drilling fluid according to claim 13.

The invention further provides a program code for a computer according to claim 15.

Related hereto, but not part of the invention, is processor control code for implementing the methods described above, more specifically on a data carrier such as a disk, CD or DVD-ROM, programmed memory such as read-only memory (firmware) or on a data carrier such as an optical or electrical signal carrier. Code (and/or data) to implement embodiments of the invention may include source code, object code or executable code in a traditional programming language (interpreted or compiled) such as C, or assembly code, code to set up or control an ASIC (Application Specific Integrated Circuit) or FPGA (Field Programmable Gate Array) or code for a hardware description language such as Verilog (trademark) or VHDL (Very high speed integrated circuit Hardware Description Language). As those skilled in the art will appreciate, such code and/or data can be distributed among a plurality of connected components in communication with each other.

Description

The well operation can be any operation, but an operation in which cuttings or residues are produced and which it is desirable to remove from the borehole is preferred. The well operation can, for example, be drilling, completion, milling or hole cleaning. The fluid is then respectively drilling, finishing, milling or cleaning fluid. Preferably, however, the well operation is drilling and the fluid is a drilling fluid. The drilling operation can be the drilling of an oil or gas well or the drilling of an exploration well. More often, the methods according to the invention are used in the drilling of oil and gas wells.

Drilling fluid is sometimes referred to as drilling mud. Drilling fluids are also sometimes referred to in the art as being gel-forming. As used herein, the term drilling fluid includes drilling mud and drilling fluids capable of forming gels. The drilling fluid is preferably used to keep it suspended and to transport cuttings produced during drilling out of the borehole.

In preferred well operations, the fluid supplied to the borehole is recycled, preferably continuously recycled. Thus, the fluid is preferably provided to the borehole, it is produced from there, possibly cleaned (e.g. filtered) and reintroduced into the borehole. Well operations based on such recycling techniques are advantageous as they are cost-effective compared to techniques that only use fresh supplies of fluids. The typical disadvantage of recycling fluid is that its properties may change during use and no longer be ideal for the purpose it is intended to serve. A major advantage of the methods according to the present invention is that they enable regular or continuous monitoring of the fluid's properties and, if necessary, regular or continuous adaptation or change to ensure that the fluid's characteristics are optimized even when it is recycled.

An important feature of the methods according to the invention is that the measurement of at least one property of the fluid or of the drill cuttings is carried out during the execution of the borehole operation. Thus, at least one characteristic is measured, and the measurement is achieved while the borehole operation is in progress. The measurement of at least one property of the fluid or of the cuttings in real time is therefore preferred. This differs from procedures in which a sample of fluid is taken, and a measurement is taken at a later time, e.g. after the fluid has been transported to a laboratory.

Thus, in a preferred method according to the present invention, the measurement step comprises measuring at least one property of the fluid or of the cuttings at intervals, e.g. regular intervals, during the execution of the operation. The interval can be, for example, 5 seconds–2 hours, 1 minute–1.5 hours, 5 minutes–1 hour or about 15–30 minutes, depending on, for example, the property being measured and the measuring equipment used. However, preferably the interval is less than 20 minutes, even more preferably less than 10 minutes, e.g. less than 5 minutes. In methods according to the invention in which step c. includes measuring more than one property of the fluid or cuttings, the interval between measurements of the properties can be the same or different depending on the equipment used.

Particularly preferably, the measuring step comprises measuring at least one property of the fluid or the cuttings essentially continuously (e.g. continuously) during the execution of the borehole operation. To enable such measurement, it is preferably automated.

In preferred methods according to the invention, the step of measuring at least one property of the fluid or drill cuttings is not performed by detecting a nuclear magnetic resonance signal, i.e. it is not performed by a technique that uses NMR.

The step of measuring at least one property of the fluid or the cuttings can be performed after the fluid leaves the borehole and/or before the fluid enters the borehole. A sample of fluid leaving the borehole can, for example, be taken before it enters the filtering apparatus to remove drill cuttings and/or after the filtering apparatus. When the sample is taken before the filtration step, the property that is measured can be a property of the fluid or the cuttings, but is preferably a property of the fluid. When the sample is taken after filtration, the property being measured can also be a property of the fluid or of the drill cuttings. When measuring a property before the fluid enters the borehole, the sample can be taken from the tank of the fluid handling apparatus (eg, the mixer) or from the pipe that supplies it to the formation. Traditional sampling equipment can be used in both cases. Optionally, a bypass can be formed in one or more supply lines to simplify sampling.

When the step of measuring at least one property of the fluid or cuttings is performed after the fluid leaves the borehole, a direct measure of how the operation affects its properties is obtained. In this way, the measurements contain the response of the fluid exposed to the borehole. When the step of measuring the at least one property is carried out before the fluid enters the borehole, a measurement of whether a suitable fluid is used is obtained. In the latter case, a measurement of how the operation affects its properties is also obtained. However, this measurement is typically less informative than the measurement of the fluid as it leaves the borehole, as the fluid will have been mixed with fluid from the tank to the fluid handling apparatus and the effect of changes diluted.

The step of measuring at least one property of the fluid or the cuttings is performed before the fluid enters the borehole. In particular, a step of measuring the at least one property is performed after the fluid leaves the wellbore (eg, after filtering), and a step of measuring the at least one property is performed before the fluid enters the wellbore. The measured properties can be the same or different.

In preferred methods according to the invention, the at least one measured property is selected from the group consisting of:

- fluid viscosity;

- fluid density;

- fluid loss control properties;

- fluid acidity;

- fluid H2S content;

- fluid oil content;

- fluid water content;

- fluid's emulsion stability;

- fluid's sand content and/or barite content;

- fluid Cl--, K<+>- and/or lime content;

- size distribution of particles in the fluid;

- sawdust' particle size distribution;

- Borkaks' morphology;

- Borkaks' mineralogy; and or

- amount of boron cake.

These properties can be measured according to methods known in the art and using commercially available equipment. For example, fluid viscosity can be measured using a viscometer, fluid density using a densimeter, fluid loss using a fluid loss system, acidity using a pH meter, oil and water content as well as solids content can be measured using a retort test (eg API 13B-1 standard for water-based drilling fluids and API 13B-2 standard for oil-based fluids), emulsion stability using an electrical stability meter, chemical content (including H2S content) using specific probes and tests ( e.g. methylene blue test), size distribution of particles in the fluid using laser diffraction, sawdust particle size distribution using laser diffraction or ultrasound techniques, sawdust morphology using a morphology analyzer, sawdust mineralogy using a Raman spectroscope or X-ray diffraction; and/or boron cake amount by using a weight sensor.

In a preferred method according to the invention, the at least one measured property can be measured by using nuclear magnetic resonance. In this method, a property of a drilling fluid is determined during the execution of a drilling operation by detecting a nuclear magnetic resonance signal from out-of-hole drilling fluid. Out-of-hole drilling fluid means that the determination is on the drilling fluid before it enters the borehole or after it has left the borehole. The part of the wire where the NMR measurement is performed should be made of a non-magnetic material. Optionally, a bypass line can be used.

The NMR signal detector may be any NMR apparatus capable of causing a drilling fluid to emit a detectable NMR signal, and capable of detecting the signal. Generally, it will include a magnet, a high frequency detector and a high frequency transmitter. The device can also be provided with high-frequency coils that impose space-dependent, static or pulsating magnetic field gradients in any direction, strength, shape or duration. The magnet can have any of the formats common in NMR or MRI apparatus, e.g. hollow cylindrical or open (e.g. horseshoe), and the magnetic field may be permanent or may be created by electric current, e.g. in superconducting or non-superconducting coils. The use of open magnets is particularly preferred as they can easily be placed at desired locations along a line to detect signals from drilling fluid therein. The magnetic strength will typically be in the range 1 to 100 MHz, preferably 2 to 20 MHz. The signal detector will typically be a magnetic resonance tomograph or an NMR apparatus capable of detecting a relaxation time-dependent signal or a high-frequency-dependent signal, either in one spatial dimension or spatially resolved (e.g. two or three-dimensional) such as an NMR spectrometer or a magnetic resonance tomograph.

The NMR parameters measured will generally be water proton relaxation times, ie T1, T2 and T2*, signal amplitudes/intensities and the translational diffusion coefficient. Chemical shift and peak propagation can also be measured. The NMR signals from other active nuclei can also be detected.

Correlation between the NMR measurements and the properties of the drilling fluid (eg, viscosity, density, etc.) can easily be obtained by comparison with standards, i.e., samples that have a range of values for these properties as measured by other means. Preferably, the NMR parameters are measured for a large range of standards and then, using multivariate analysis, a prediction matrix is generated. This can then be used to generate values for the desired parameters of the "unknown" sample.

In order to differentiate between different drilling fluid properties, the method of NMR measurement and the measured data values can be manipulated to extract the correct correlation. Thus, for example, different T1 or T2 measurement techniques can be used and different setup parameters, e.g. magnetization, echo distance or pulse gradient direction, shape and strength can be used. With signals measured by two or more such techniques, evaluation algorithms can then be used to calculate the value of the desired drilling fluid property.

In preferred methods according to the invention, a number of properties of the fluid or drill cuttings are measured. When quantity properties are measured, one or more measurement techniques can be used. Particularly preferably, at least 2 are measured, more preferably at least 3, e.g. 2 or 3, properties of the fluid or cuttings.

In particularly preferred methods, the at least one measured property is a property of the fluid. Thus, the at least one measured property is preferably selected from fluid viscosity, fluid density, fluid loss control properties, fluid acidity, fluid H2S content, fluid oil content, fluid water content, fluid emulsion stability, fluid sand and/or barite content, fluid K<+>-, Cl- and/or lime content, size distribution of particles in the fluid, and the amount of particles in the fluid. The particles that occur in the fluid include sawdust as well as other particulate material, e.g. solids added to achieve a particle size distribution. Particularly preferred is the at least one measured property selected from fluid viscosity, fluid density, fluid loss control properties and chemical content, especially fluid viscosity and fluid density.

In some preferred methods, the at least one measured property is not the density of the fluid.

In methods in which the at least one measured property is a property of the sawdust, it is preferably sawdust's particle size distribution or sawdust quantity. When the at least one measured property is a property of the drill cuttings, the measurement can be carried out on the drill cuttings which are held suspended in, or carried by, the fluid, or can be done after separation of the drill cuttings from the fluid. Separation can be carried out by any method conventional in the art, e.g. by filtering.

According to the invention, at least one property of the fluid or cuttings measured during the execution of the well operation is converted into a fluid characteristic. In other words, a fluid characteristic is calculated from the measured property. A fluid characteristic is a property of the fluid per se under standard conditions, e.g. ambient temperature, such as 20 <o>C, and pressure. The standard conditions may vary between different fluid characteristics. Typically, fluid characteristics are used by suppliers to describe their fluid products, e.g. drilling fluid, and is listed in a fluid's specifications. Representative examples of fluid characteristics include viscosity, density, acidity (pH), fluid loss control, chemical content, oil-water ratio, emulsion stability, solids content, particle size distribution, and particle content.

Thus, methods according to the invention include the further step of estimating or calculating the at least one fluid characteristic based on the measured property of the fluid or the cuttings. In some cases, this is a simple conversion. For example, if the measured property is fluid viscosity or density, then they can be converted to the fluid characteristics of viscosity and density, respectively, using a factor that takes into account the temperature and pressure at which the measurement is made. In other cases, the conversion is more complex. When, for example, a characteristic of the drill bit is measured, the conversion can be to any of e.g. viscosity, density or oil-water ratio. Thus, particularly preferred methods according to the invention comprise a step of using a model of the behavior of fluid in a borehole to estimate the at least one fluid characteristic of the fluid entering or leaving the borehole, based on the measured property.

The following measured properties are typically used to estimate the fluid characteristics listed in the table below:

When operators initially decide which fluid to use in a particular well operation, they will typically have an "ideal" fluid specification in mind. Thus, for each fluid characteristic (e.g. viscosity, density, acidity, etc.) there will be a range within which they want the fluid characteristic of the fluid used to fall. Operators may develop this specification, for example, as a result of previous experience in performing the well operation, or similar operations, or derive it from laboratory testing.

An example specification for a water-based drilling fluid could be:

Viscosity: Shear load of 80-100 lb / 100 ft<2 >at 1021 s<-1>

Density: 1450 kg/m<3>

Oil-water ratio: 78/22–82/18

Emulsion stability: >500 mvolt

Particle size distribution: d90 280–350 µm

Solids content: 20–25 vol-%

Thus, in preferred methods according to the invention, in step b, the fluid which is supplied to the borehole has at least one (e.g. 1) fluid characteristic in a predetermined area. In more preferred methods according to the invention, in step b the fluid which is provided to the borehole, 2-6, more preferably 2, 3, 4 or 5, has fluid characteristics in a predetermined range.

Preferred methods according to the invention comprise the further step of assessing whether the estimated fluid characteristic falls within the predetermined range. Thus, when at least one characteristic of the fluid or cuttings is measured during the performance of the operation and is used to estimate or calculate a fluid characteristic, this estimate is compared to the predetermined range. This assessment step can be performed by the equipment used to perform the measurement. More preferably, the evaluation step can be performed by a computer arranged to receive signals (ie data) from the measuring device. In cases where the assessment is that the fluid characteristic falls within the predetermined range, it is not necessary to modify the fluid supplied to the borehole. When the assessment on the other hand is that the fluid characteristic does not fall within the predetermined range, the fluid supplied to the borehole is preferably modified. Preferably, the modified fluid has fluid characteristics within the predetermined range. In other words, the step of modifying the fluid involves changing the fluid characteristic.

Thus, a preferred method according to the invention includes the step of assessing whether the fluid to be supplied to the borehole has at least one fluid characteristic within the predetermined range, and the modification step optionally includes changing the at least one fluid characteristic so that it falls within the predetermined range.

According to the invention, the step of modifying the fluid is carried out during the execution of the borehole operation. This is very advantageous as it means that the fluid supplied to the borehole is optimized (i.e. is within the predetermined range) throughout the operation regardless of, for example, changes in well or borehole conditions and the presence of cuttings in the fluid. This enables rapid intervention to counteract, for example, the effects of chemical reactions between the fluid and the formation and loss of fluid or components of the fluid to the formation.

Thus, in particularly preferred methods according to the invention, the modification step is carried out at (e.g. regular) intervals between 5 seconds - 6 hours, more preferably 1 minute - 2 hours, even more preferably at intervals of 5 minutes - 1 hour, e.g. . intervals between 10 minutes–30 minutes during the performance of the operation. Even more preferably, the modification step is carried out substantially continuously. This can be achieved, for example, when the step of modifying the fluid is automated.

In particularly preferred methods according to the present invention, both the measurement and modification steps are automated. Thus, preferably at least one property of the fluid or drill cuttings is measured at intervals, or more preferably continuously, and the fluid supplied to the borehole is modified if necessary.

A preferred method, e.g. an automated method, according to the present invention therefore comprises the steps of:

a. perform a borehole operation using a borehole apparatus located in a borehole; b. providing a fluid to the wellbore to facilitate the wellbore operation, wherein the fluid has at least one fluid characteristic in a predetermined range;

c1. measuring at least one property of the fluid or of the cuttings carried by the fluid, while performing the well operation;

c2. estimating the at least one fluid characteristic based on the measured property of the fluid or the cuttings;

c3. assessing whether the estimated fluid characteristic falls within the predetermined range;

d. possibly (e.g. if necessary) modify the fluid that is provided to the borehole, in response to at least one measured property of the fluid or the cuttings.

The step of modifying the fluid supplied to the wellbore in response to the at least one measured property may involve, for example, changing the proportions of the components of the fluid, adding one or more additional components to the fluid, or removing (eg, stopping the supply of one or more components). The preferred response is to change the proportions of the fluid's components.

Representative examples of modifications that can be made in response to various measured properties are listed below:

Too low viscosity: Increase the amount of clay mineral or add clay mineral

Too low density: Amount of weighting agent is increased, or weighting agent is added Too high acidity (pH): Amount of acid (e.g. citric acid) is increased and/or amount of alkali is reduced

Too high an oil-water ratio: Water content (brine) is increased

Too low emulsion stability: Shear energy or specific solids, e.g.

clay minerals, are added

Not suitable particle size distribution in fluid: Amount of particulate materials, e.g.

calcium carbonate, graphites, etc., are changed or such materials are added. Alternatively, the sights that occur in the vibrator can be changed.

Unsuitable particulate content in fluid: Amount of particulate materials, e.g.

calcium carbonate, graphites, etc., are changed or such materials are added

In preferred methods according to the invention, a fluid mixing model is used to determine the change necessary to modify the at least one fluid characteristic. Preferred fluid mixing models are therefore able to calculate the compositional change necessary to cause the required change in a fluid characteristic, e.g. viscosity and density.

A simple example of how this can work is the following. A drilling fluid may initially comprise components A, B and C in amounts of 10, 10 and 80% by weight respectively and have a viscosity of X and a density of Y. During use in a drilling operation, however, the viscosity of the fluid increases to X+10, and the density increases to Y+20. The change in the fluid properties is measured, and the corresponding change in the fluid characteristics is estimated. Therefore, if the viscosity of X+10 and the density of Y+20 are outside the predetermined viscosity and density range, the step of evaluating whether the fluid characteristics fall within their predetermined ranges gives rise to a negative result. The computer that performs the assessment therefore uses a fluid mixing model to calculate what compositional change is necessary to reduce viscosity and density by the required amount. Optionally, the model or algorithm that does this may take into account factors that include the volume of fluid contained in the fluid handling apparatus tank, the flow rate of the fluid into the wellbore, the flow rate of the fluid out of the wellbore, the total volume of fluid in circulation, etc. The output of the model can for example be that the proportion of A should be increased to 15% and the proportion of B reduced accordingly to 5%. This information is sent by the computer to the fluid handling apparatus and more specifically the feed lines supplying the fluid handling apparatus tank, and the flow of A and B into the mixing tank can be adjusted accordingly. The information can be sent continuously. Alternatively, the model can calculate the average of the input over a period of time, e.g. 10 minutes – 1 hour, and send average output to the fluid handling apparatus.

The fluid mixture models can be prepared on the basis of tests carried out in laboratories and/or previous work carried out in the formation. The person skilled in the art can easily generate suitable algorithms to act as the model. Multivariate models are preferred as they enable the simultaneous optimization of a number of fluid characteristics.

The methods according to the present invention therefore ensure that the fluids supplied to the borehole are optimized for a considerable part of the time that the operation is run. In particularly preferred methods in which the steps of measuring and modifying are automated, the fluid can be optimized for the entire well operation. This ensures that cuttings are removed effectively, so that the borehole is clean, the borehole is stable, the borehole is drilled efficiently and the formation is not damaged at the same time. The duration of a typical borehole operation can be 12 hours–7 days, e.g.

24 hours–5 days.

In particularly preferred methods according to the invention, the at least one measured property of the fluid or cuttings is used to report back information about the efficiency of the fluid and/or the operation. Such a method can be described as a self-improving or self-learning method because the measured property of the fluid or cuttings is used to determine the optimal fluid specification for use in the operation. In such methods, an initial fluid specification is used at the start of the operation, and then as data is generated and reported back, the specification can be modified. This in turn induces changes in the fluid that is supplied to the borehole, using the method of measurements, assessments and modifications described above. The process is thus iterative.

For example, if a measured viscosity is low and cuttings mineralogy measurements indicate that a transition from sand into a shale formation has occurred, the feedback system can estimate a desired fluid specification that has a higher viscosity than the fluid from earlier phases of the operation.

The self-improving or self-learning approach can also be used to continuously update the fluid mixing model.

Such methods can also be adapted to optimize the fluid so that it suits the operating parameters of the operation, e.g. to maximize the rate of penetration. Alternatively, or in addition, the methods can optimize the fluid to achieve specific well conditions. Examples of well conditions include wellbore stability, wellbore cleanliness, wellbore pressure and the level of formation damage. This may include geological conditions. The method may include estimating the well ratio, e.g. based on the measurements of the fluid property or the cuttings.

Thus, according to the invention, the range of at least one characteristic of the fluid to be provided to the borehole is determined using the measurement of at least one characteristic of the fluid or the cuttings carried by the fluid, during the execution of the borehole operation. In particularly preferred methods, at least one borehole operating parameter is also measured. In such cases, the at least one measured property of the fluid or drill cuttings and the at least one measured well operating parameter are used to determine the range of at least one fluid characteristic of the fluid to be supplied to the well.

In such methods, the at least one borehole operating parameter is preferably selected from the group consisting of:

- penetration rate;

- hole diameter;

- well track;

- borehole pressure;

- borehole temperature;

- borehole mineralogy;

- borehole length;

- drilling fluid pump speed; and

- drill string rotation speed.

Preferably, the borehole operating parameter is selected from borehole pressure and borehole temperature. These operating parameters, and the others listed above, can all be determined using conventional apparatus and methods known in the art. Such parameters are traditionally monitored by the system that controls a well operation, e.g. drilling. In the methods according to the invention, these parameters are preferably measured continuously.

More preferably, the well condition is selected from borehole stability and borehole cleanliness, especially borehole cleanliness. Borehole cleanliness provides a measure of the effectiveness of a fluid, such as a drilling fluid, to remove cuttings from a borehole and produce it on the drilling platform. Borehole cleanliness can be estimated from the level of drill cuttings removed from the fluid, e.g. using the filtering device. Thus, the weight of cuttings removed from the fluid can be determined to obtain a measure of the efficiency of their removal. In a similar way, well stability can be estimated from cuttings morphology. The reading log that is typically kept during an operation can alternatively provide an estimation of well stability. Additional formation damage can be estimated from filter losses.

Preferably, a model of the behavior of fluid in a borehole is used to estimate or determine the range of at least one characteristic of the fluid to be provided to the borehole, based on the measured property of the fluid or the cuttings and/or the at least one borehole operating parameter. A model can be generated on the basis of data generated during previous operations in the formation, during operations in similar formations and/or during previous phases of the ongoing well operation. The latter is preferred. The self-improving or self-learning method described above can also be used to update the fluid mixture model continuously.

The model can be a real-time hydraulic model that is initialized with borehole objects, which describe the geometry, geology and other properties of the well. Real-time drilling fluid data can also be input to the model. More than one real-time hydraulic model/simulator can be used. The models can be moved forward in time, and the properties (eg pressure, flow, depth or drilling fluid parameters) can thus be predicted from the models. Consequently, there is the advantage of being able to look ahead and prepare for performance optimization. The results from different models (data sets) can be displayed and can be connected to each other. This has the advantage that the uncertainty of depending on only a simple hydraulic model in real time is reduced with the overall benefit of reducing the drilling operation risk.

Particularly preferred models are capable of determining the range of one or more fluid characteristics that optimize one or more well conditions. When such a model is used, step d. in the methods described herein includes the step of optimizing the fluid to achieve that well ratio. Thus, when the model optimizes the well ratio borehole stability, step d. includes optimizing the fluid to maintain stability in the borehole. Similarly, when the model optimizes well cleanliness, step d. includes optimizing the fluid to increase the efficiency of cuttings removal from the borehole. Naturally, simultaneous optimization of more than one well relationship can be carried out.

Preferred methods according to the invention include the further step of selecting a quantity of the measured properties of the drilling fluid or cuttings which together are indicative of a condition in the borehole, and processing the quantity of measured properties for user interpretation/visualization.

Preferred methods, apparatus and systems according to the invention use a control system comprising a computer arranged to receive signals from the drilling fluid measuring apparatus to calculate whether the fluid meets at least one predetermined criterion and send signals to the fluid handling apparatus to modify the fluid.

The fluid handling apparatus preferably comprises a storage or mixing tank, means for mixing the contents of the tank and feed lines which are connected to supplies of fluid components. The fluid handling apparatus also includes preferred filtering apparatus, e.g. vibrators.

The vibrator may optionally include sieves with different "Cutt" points or hole openings. Screens with different Cutt points generally function to remove cuttings larger in size than a varying minimum from the fluid while allowing cuttings in the fluid below this minimum size to pass through the vibrator to reenter the well. The sieves can be automatically controlled and selectable, so that cuttings that have a particular size or particle size distribution (PSD) can be retained in the drilling fluid. In this way, the particle size distribution, e.g. to drill cuttings, in which the fluid is controlled and modified.

Based on the measurement of the PSD, an automatic recommendation for sight selection can be given. For example, if the PSD measurement shows that the proportion of larger particles is not sufficient, this will lead to an automatic recommendation to change the sieve to a coarser vibrator sieve.

Description of preferred embodiments

It will now be described, by way of example only, embodiments of the invention with reference to the accompanying drawings, in which:

Figure 1 is a schematic representation of a drilling system showing the circulation of drilling fluid;

Figure 2 is a flowchart representation of a modeling sequence for the drilling process in Figure 1;

Figures 3a and 3b show the variation of a drilling fluid's properties over time, and

Figure 4 shows a schematic block diagram of the computer as it calculates the modeling sequence.

First with reference to Figure 1, a drilling system 1 is shown in use during drilling of a well. A drill string 3 extending from a drilling platform (not shown) is equipped with a drill bit 3b and is placed in a drill hole 5, where the string and drill bit are rotated to drill into the subsoil 9. The drill hole 5 is typically drilled through a number of different geological formations in the subsoil 9. A drilling fluid is circulated under pressure into the borehole through a pipeline 3c in the drill string. For the purposes of this example, the drilling fluid is oil-based, but it can also be water-based. The fluid leaves the drill string near the drill bit 3b and moves back up towards the surface in an annulus 5a in the drill hole 5 which is defined between an outer surface of the drill string and the drill hole wall 5w. Drilling cuttings and other solid particles 7 produced as a result of drilling are held suspended in the drilling fluid and carried in the fluid towards the surface and out of the borehole.

Fluid handling apparatus 10 is provided on the platform to treat the drilling fluid that has passed through the borehole 5, before it is reused. The handling apparatus 10 includes a vibrator pit 12 in which fluid carrying cuttings and solids is received from the borehole annulus 5a. The vibrator trench 12 includes various vibrators equipped with screens (not shown) including a shale vibrator, which removes solid particles and cuttings from the borehole fluid. From the vibrator pit, the drilling fluid is sent into a mixing pit 14 where the fluid is prepared and can be modified for reuse in the well. The mixing pit 14 may comprise a mixing tank to store fluid drilling fluid during mixing. Such a tank can typically have a capacity of 30–40 m<3>. Fluid then leaves the mixing trench 14 and back into the drill string pipeline 3c.

It may also be desirable to configure the one or more vibrators 30 with sieves with different "cutt" points or hole openings for use on the fluid to remove cuttings above a certain size from the fluid, while allowing cuttings in the fluid below that size to pass through the vibrator and re-enter the well. The different sieves can be automatically controlled and selected, so that the drill cuttings get a particular size or particle size distribution (PSD). In this way, the particle size distribution, e.g. to drill cuttings, in which the fluid is controlled and modified. It is often useful to have particles of a certain size present in the drilling fluid to seal micro-fractures in the formation and to prevent circulation loss events.

A number of measurements are performed on the drilling fluid as it passes through the vibrator 12 and before it enters the mixing pit 14 using measuring device 20. Properties of both the drilling fluid and the cuttings carried by the drilling fluid are measured. The measurements are automated and are carried out in real time, during drilling, and are carried out essentially continuously, depending on the sampling speed limitation of the measuring tools. The measured properties are used to determine how it may be necessary to modify the fluid to ensure that the fluid is suitable for the drilling operation being performed. Thus, the fluid in the mixing pit 14 can be modified in response to the measured properties, for example by changing the quantities of components that are supplied from one or more chemical storage tanks 30a-c which are fluidly connected to the mixing pit 14. These tanks can have a capacity of about 20 m3. The modification of fluid is similar to an automated process, which takes place in real time and on a continuous basis during the drilling of the well.

The properties measured in this example include fluid viscosity and temperature, density, emulsion stability, particle size distribution, fluid loss, pH, H2S content, borax morphology, mineralogy, oil-water ratio and solids content. All these characteristics of the fluid can be changed.

To take such measurements, the measuring apparatus 20 includes a viscometer 20v which is connected to the line 22, which connects the vibrator and the mixing pit. For example, the viscometer 20v can take the form of an inline automated Couette viscometer that provides measurements at different shear rates, covering the API standard shear rate range of 5 : 1022 s<-1>. Such a viscometer is currently manufactured by Brookfield, Coriolis and others. The viscometer includes a temperature probe so that the viscosity measurements, which are strongly dependent on temperature, can be used to derive a suitable viscosity curve for other prescribed temperatures.

A densimeter 20d is provided which is used to measure the density of the fluid. A Coriolis mass flow meter, for example, can be used to do this by measuring the natural frequency of the filled Coriolis tube.

Fluid loss is measured using an automated fluid loss system (AFLS) 20f designed to autonomously measure the high temperature and high pressure fluid loss (HPHT) characteristics of water- and oil-based fluids at discrete real-time intervals. As an alternative to measuring fluid loss, the fluid loss can be estimated or simulated using other real-time measurements. The fluid loss can be simulated (not measured) by measuring other fluid properties such as PSD, viscosity, etc. and using the measurements of these properties to provide an estimate of the fluid loss.

An automated, self-cleaning instrument is chosen so that it can be controlled and used for continuous repeated measurement. The AFLS can, for example, be controlled via a SCADA system and a Mitsubishi Q-series PLC with a Modbus TCP interface.

The particle size distribution of the fluid is measured using a particle size distribution measuring device 20p. Such a device can take the form of a fluid particle analyzer where a sampling system takes samples of a constant volume of drilling fluid. The sample is diluted and fed down to a flow cell, where images of the particles are taken with a camera. Image elements are counted in different directions to determine the length scales of the particles. Other techniques that can be used to determine particle size distribution include laser diffraction and ultrasound techniques.

The measuring device 20 further comprises an electrical stability meter 20e which is used to measure the emulsion stability of the drilling fluid. For example, an automated version of a Fann Model 23D electrical stability tester can be used, where an automated brush spring for cleaning electrodes is fitted and control electronics are provided for continuous measurement. Furthermore, such a tester is modified to output readings automatically and to transmit them in real time.

A flow meter 20c is installed at the vibrator 12. This device collects cuttings at the outlet of a shale vibrator. Weight sensors connected to a mud logging acquisition system for the platform allow the weight of the cuttings to be determined. The amount of cuttings in terms of mass can then be determined by combining the weight with cuttings bulk density measurements carried out on the cuttings.

The shape of cuttings removed from the fluid by the vibrators is evaluated using a cuttings morphology analyzer 20m. The length-thickness ratio (L/T ratio) of cuttings provides information about the down-hole processes. Samples for this purpose are collected in a cup from various layers of vibrators in the vibrator pit 14 and emptied into a liquid particle analyzer where images of the drill cuttings are taken with a camera, and analyzed in a similar way in the particle size distribution device 20p.

Analysis of oil, water and solids content can be performed with a retort test according to the API 13B-1 standard for water-based drilling fluids and API 13B-2 for oil-based fluids. From this, the proportion of oil, water and solids content can be derived and used to provide measurements of oil-water ratio and solids content. The sampling of the drilling fluid for the retort test is automated in this system, so that regular sampling and measurement of these properties is carried out throughout the drilling process.

Sawdust flow can also be measured, e.g. using ultrasound technology.

The mineralogy of particles is analyzed using a Raman spectroscope 20r. Cuttings are moved from the morphology analyzer to the Raman spectroscope, which analyzes the cuttings directly with little or no preparation. An alternative method for determining mineralogy is XRF.

It should be understood that other properties can also be measured. For example, pH can be measured in water-based drilling fluids. For such measurements, an ion-specific field effect transistor (eng.: Ion Specific Field Effect Transistor) can be used. The presence of H2S can also be measured using probes equipped with ceramic oxides and fluorides. Alternatively, the fluid or cuttings properties can be determined using methods such as nuclear magnetic resonance (NMR) or ultrasound techniques.

The measured properties are sent from the measuring device's 20 instruments to a control system where the measured parameters can be monitored externally on a continuous basis and in real time. The measurements can also be stored as data for later use, but in the present process they are used in real time to determine how the fluid supplied into the borehole pipeline 5c may need to be changed to ensure that the fluid has a suitable composition at all times.

To this end, the control system is arranged to monitor and process the measurements to determine what needs to be done in the mixing pit 14, for example to determine whether the proportions of the components need to be changed, whether an additional component is to be injected or whether a component is no longer to be supplied, and to decide how much should be added/removed. Alternatively, or in addition, the measurements can also be used to change the sieves that occur in the vibrator.

The procedure for processing the measurements and determining how to modify the fluid can be seen with further reference to Figure 2. This part of the system is implemented using two models, first a "well model" 50 and then a "mixing model" 60. The measurements taken with the measuring device 20, provides a first input 46 to the well model. In addition, various physical borehole operating parameters provide a second input 48 to the well model. The physical borehole operating parameters are measured and monitored by the control system during the drilling operation and include, for example, the penetration rate, hole diameter, wellbore trajectory, pressure and temperature. Changes in such parameters can have a considerable impact on the drilling process. Accordingly, both the measured characteristics 46 and the operating parameters 48 provide information about conditions in the well, which are important to take into account in the well model 50 to determine a suitable fluid.

Based on the input 48 of physical borehole operating parameters and the input 46 of measurements of the drilling fluid and cuttings, an estimation of the well model 50 is performed to determine and then output a desired fluid specification or characteristic 52 for the drilling fluid to be provided into the well, given the well conditions derived from the input parameters 46, 48 and/or a given desired ratio. Thus, the well ratio can be estimated based on the measurements. The well model 50 can, for example, be used to optimize the density of the drilling fluid in order to maximize the penetration rate in the formation. Alternatively, the well model 50 can be adapted to estimate a specification for the fluid that will provide, for example, the best possible hole cleaning performance or minimum fluid loss, given the measured borehole operating parameters. The desired ratio for optimization, using the well model, can be specified by an operator as an additional input to the well model, for example entered via a control panel, and can be changed during the drilling operation. The well model can also optimize for a number of desired conditions.

Borehole stability can, for example, be carefully controlled by using the drilling fluid. For example, a density for the fluid can be specified to increase borehole pressure so as to maintain overpressure conditions, prevent formation collapse into the annulus and to limit fluid loss into the formation. It is clear, however, that a special specification should therefore also take into account the geological conditions, because the different formations may for example be more susceptible to fluids than others, so in this example it is useful in the present system to use measured properties such as mineralogy as a guide, for example, to the formation's fluid receptivity, which in turn guides the estimation of a suitable fluid.

The well model "simulates" downhole conditions and how certain fluid characteristics affect downhole conditions. It comprises an algorithm for determining a suitable fluid, which in this example may contain the theoretical relationships between: 1) well fluid properties (eg viscosity and density) and borehole pressure for a given operating parameter; 2) borehole pressure and the stability of the geological formation; 3) the geological formation's stability and formation type; 4) formation type and core measurements. In addition, it may incorporate a number of other relationships or correlations that connect the well fluid parameters with the measured properties 26 and/or borehole operating conditions 48. The fluid specifications determined from the well model are such as to ensure that safe and efficient drilling can be performed. The fluid specification 52 typically specifies a range of desired values for fluid characteristics. During drilling, the operating parameters 48 and the requirements for safe drilling will change, and consequently the fluid specifications 52 necessary for safe drilling will also change automatically.

The fluid specification 52 which is fed out from the well model 5 is used as an output to the mixing model 60. In addition, the measurements 46 are fed into the mixing model.

An assessment step 62 is first performed to assess whether the fluid measured is within specification 52. The measurements 46 fed to the model 60 provide the information about the "start" conditions of the drilling fluid. The measured properties of the fluid are compared to the predetermined ranges defined in the fluid specification 52. If the fluid is within the fluid specification, no modification of the fluid is necessary. If the fluid does not meet the fluid specification, it is necessary to determine how the fluid can be changed to bring it within specification before it is sent into the wellbore 5. The mixing model provides a "sensitivity map" of how chemical changes to drilling fluids of different types and compositions control the fluid characteristics. More specifically, the model can incorporate compounds in the form of specific correlations that describe the effect of a chemical additive on a characteristic of the fluid. For example, a polymer such as a xanthan polymer can be correlated to the viscosity of a water-based slurry. In such an example, the addition of xanthan polymer can have the following effect on viscometer readings of 3 rpm and 600 rpm in the fluid: addition of 1 kg/m<3> increases 3 rpm by 1 and 600 rpm by 8. This relationship can be tabulated and programmed to form a "viscosity-increasing" or "viscosifying" correlation in the mixing model.

To provide a further example, a correlation between the addition of a polymer and the fluid characteristic for fluid loss control can be specified in the mixing model. If one assumes that a fluid property measurement for fluid loss is 8 ml, then the addition of 3 kg/m<3 >PAC ELV can reduce fluid loss by half (i.e. that the addition of 3 kg/m<3 >gives a fluid loss of 4 ml, addition of 6 kg/m<3 >gives a fluid loss of 2 ml). This relationship between amount of PAC ELV additive and reduction in fluid loss can similarly be tabulated and programmed into the mixing model so that the fluid can be modified with the appropriate addition of polymer to bring it within the required specification.

Consequently, when presented with the drilling fluid measurements, the mixing model can determine which additives are necessary to add, in what quantity and under what conditions to modify the fluid to bring it within specification. These additives include both solid materials such as weight materials, e.g. in powder form, and fluid chemicals. Once this is determined, a corresponding control signal is sent to the flow valves 16 on the injection line 18 to open them as necessary and add an additive to the fluid in the mixing pit 14. The flow valves can be controlled and adapted externally, so that additives can be added at a certain flow rate.

Where the specification of fluid from the well model makes it necessary that there is a certain particle size distribution or quantity of articles in the fluid (e.g. if morphology measurements such as size and shape and content/size distribution of particles fed into the mixing model indicate that the fluid is out of specification) , the control system can send control signals to control the vibrators and select suitable sieves to modify the particle content of the fluid in the correct way. The mixing model can be programmed to determine whether particle size distribution should be controlled by using sieves and/or by adding solids to the mixing pit.

In other embodiments, a premix can be used and added to the fluid to modify it and bring it within specification. Such a premix is a fluid mixture in which constituent chemicals occur in predetermined proportions. It is a "ready-to-use" additive that may have been tested and is known to provide a particular effect on a drilling fluid or the characteristics of the drilling fluid. In typical embodiments, the premix consists of a fluid mixture of the chemicals that normally occur in a drilling fluid, but without weight materials such as barite. The viscosity of the premix can be higher than the drilling fluid specification or lower, e.g. to increase or decrease the viscosity of the drilling fluid. In this way, the premix can be used according to the mixing model to control properties such as the viscosity and density of the drilling fluid and at the same time control the chemical composition. Viscosity can be controlled, for example, by adding a suitable amount of premix with either high or low viscosity from a storage tank 30a-c. Control of density can be carried out by using a special premix in combination with the addition of dry weight material such as baryte to the fluid. Different types of premixes can be used, which can be prepared away from the fluid process system and transported to the process plant as needed.

The implementation of the well model and mixing model can be as programmed microprocessors in part of the control system or part of the control system software. The measurements of the fluid are sent to the control system and monitored throughout the process. They are fed directly into the well model algorithm in the software or programmed microprocessors to determine the desired fluid specification, which is then fed directly into the mixing model algorithm's control system by following the logic described above, and control signals are then sent to the mixer to change the drilling fluid characteristics appropriately.

The drilling fluid is a complex system with mutual dependence between the various measurable properties. Consequently, the behavior of the fluid after its modification with the additives can be unpredictable. As shown in Figure 2, the process can be iterative. In other words, after the mixing model has determined whether the fluid should be modified or not, another measurement is taken, and the process begins again. Thus, the additives can be added over a period of time until the predetermined criteria that are desirable for the measured fluid are achieved.

During the iterative process, the dynamics of the fluid property can behave as shown in either figure 3a or 3b. In Figure 3a, the property of the fluid being measured is gradually brought down towards the predetermined criterion or set point over time. In Figure 3b, a quick adaptation is sought, and the characteristic initially falls below the desired set point. Then the behavior of the property becomes oscillatory as it approaches the set point. The set points can be set by an engineer operating the system. The set points can be constant values or varying curves or sequences that are pre-programmed. Alternatively, suitable curves can be calculated by the control system where the overall system stability is taken into account. The curves can be updated based on measured values, e.g. adaptations of the curves can be made if measured properties deviate from assumed values.

The iterative process can be used to continuously update the models, i.e. the well and mixing models. These models can be optimized in terms of response to enable good control over property transients and to reduce such typical oscillatory behavior. These iterative processes may involve the use of multiple additives simultaneously and may require monitoring of multiple properties to achieve an ideal fluid and optimize the use of additives.

A schematic block diagram of a computer for processing the data is shown in Figure 4. As will be understood, the term computer is generally intended and may cover a server, stand-alone computer or other processing devices. The computer comprises a processor 602 connected to working memory 604, a data store 608 and permanent program memory 606. The data store 608 contains information about the fluid characteristics, for example the different properties and the suitable ranges for their values. The program memory 606 stores various elements of the code that cause the processor to perform the necessary steps. For example, there is a program code for the well and mixer models that can be adaptive to respond to changes programmed by a user, or self-learning to respond to information learned from the real-time measurements. By using these models, the processor is configured to calculate whether the fluid meets at least one predetermined criterion, i.e. whether or not one of the measured properties lies within a target range or approaches a set point. If the fluid does not meet the criterion, the processor is configured to determine a change to the fluid using the models.

There is also data communication control code with which the processor connected to a communication link 600 communicates with other parts of the system. The processor is thus configured to receive signals from the various measuring devices of the drilling fluid measuring device via the communication connection. The processor is also configured to send signals to the fluid handling apparatus to modify the fluid. In this way, the control of the fluid is automated. The communication link also allows the system to be monitored locally or remotely, for example by accessing one or more live databases containing real-time data streamed from the measuring device.

The computer also includes a user interface 612 which can also be accessed from one or more locations. The interface can provide an overview of the system and the various measurements and an indication of the changes that have been calculated and are to be applied. The interface may allow user input, for example, to specify a well condition for optimizing the well fluid, updates to the model and/or the properties to be measured. Access to drilling data can be obtained in a common way, and it can be used in combination with the measurements of fluid measurements to determine the well condition to be optimized.

Some or all of the contents of the permanent program memory and working memory may also be provided on a portable storage medium such as a floppy disk 607.

Automating the processes above provides considerable improvements to the drilling process. More precisely, better decisions about the suitable drilling fluid can be made, and the fluid can be automatically and continuously optimized for a required performance as the process progresses. It also provides considerable efficiency improvements.

There are also logistics improvements. For example, the amount of additives used can be monitored and used to predict when additional supplies are needed. In this way, the amount of additives stored at the plant can be minimised, which is particularly important in marine operations where storage space is limited. There can be an automated connection to the additive suppliers to order additional additives when needed to ensure that the additives are received when needed. By having full control over all volumes and chemicals sent to and from the rig, it will be possible to connect this directly with invoicing, and thus the automated connection can provide for automatic invoicing. For example, if all volumes and chemicals are "labelled", the ordering and invoicing can be automated.

Having full control over all available volumes at base facilities and on the drilling rigs also allows for further logistics optimization. For example, a specific volume of fluid with certain properties can be allocated to the rig that needs this volume. Likewise, when handling waste, improved management of waste composition will optimize logistics by providing automated recommendations for where the waste should ideally be sent.

Claims (15)

Patent claims 1. Procedure for performing a well operation, where the procedure comprises the steps: a. performing a borehole operation using a borehole apparatus (3) placed in a borehole (5); b. providing a fluid to the borehole (5) to facilitate the borehole operation; c. to measure at least one property of the fluid or of the drill bit (7) carried by the fluid, during the execution of the borehole operation; d. determining whether the measured fluid meets predetermined criteria; e. determining a change in the fluid supplied to the wellbore (5) using a fluid mixing model (60) when the measured fluid does not meet the predetermined criteria; and f. to modify the fluid supplied to the borehole (5), using the determined change, where at least one characteristic of the fluid to be supplied to the borehole (5) is determined using the measurement of the at least one characteristic of the fluid or the cuttings (7) carried by the fluid, wherein the measurement is carried out under operating conditions found during the execution of the borehole operation and a said characteristic of the fluid is a said property under standard conditions, wherein at least one measured borehole operating parameter is measured and the at least one measured characteristic of the fluid or cuttings (7) and the at least one measured borehole operating parameter are used to determine the at least one characteristic of the fluid to be provided to the borehole (5), wherein determining whether the fluid meets the predetermined criteria include determining whether each said particular characteristic is in a predetermined range; where the method is characterized in that: the method comprises a first measurement outside the borehole (5) of at least one property of the fluid or of cuttings (7) carried by the fluid, during the execution of the borehole operation, and a second measurement outside the borehole (5) of at least one property of the fluid or of cuttings (7) carried by the fluid, during the execution of the borehole operation, where the fluid is filtered by a filter (12) to remove cuttings (7), and where the first measurement is performed before the filtration after the fluid leaves the borehole ( 5), and the second measurement is performed after the filtration before the fluid enters the borehole (5), where determining whether the measured fluid meets predetermined criteria is based on the first and second measurements, where modifying automatically controls and selects the filter in the filter (12) based on the determination of whether the measured fluid meets predetermined criteria, so that sawdust (7) which has a certain size or particle size distribution is retained in the fluid. 2. Method according to claim 1, where the at least one borehole operation parameter is measured during execution of the borehole operation and comprises one or more of: – well track; – well path trajectory; – borehole length; and or – hole diameter. 3. A method according to any preceding claim, wherein the at least one borehole operating parameter is measured during execution of the borehole operation and comprises borehole mineralogy. 4. A method according to any preceding claim, wherein the at least one borehole operating parameter is measured during execution of the borehole operation and comprises penetration rate. 5. Method according to any preceding claim, wherein the at least one borehole operating parameter is measured during execution of the borehole operation and comprises one or more of: – drilling fluid pump speed; and or – drill string rotation speed. 6. Method according to any preceding claim, where the fluid is recycled during the execution of the well operation. 7. Method according to claim 1, wherein the first measurement and the second measurement measure viscosity. 8. Method according to any preceding claim, where step c. comprises measuring at least one property of the fluid or the cuttings substantially continuously during the execution of the borehole operation. 9. A method according to any preceding claim, wherein the step of modifying the fluid is performed during the execution of the borehole operation. 10. Method according to any preceding claim, wherein the at least one measured property is selected from the group consisting of: – fluid viscosity; – fluid density; – fluid loss control properties; – fluid acidity; – fluid H2S content; – fluid oil content; – fluid water content; – fluid's emulsion stability; – fluid's sand and/or barite content; – fluid K<+>-, Cl-- and/or lime content; – fluid particle size distribution; – sawdust's particle size distribution; – sawdust's morphology; – Borkaks' mineralogy; and or – amount of boron cake. 11. Method according to any preceding claim, wherein step d. comprises the steps: estimating at least one said characteristic of the fluid based on the measured characteristic of the fluid or the cuttings; and to assess whether the estimated characteristic falls within the predetermined range. 12. Method according to any preceding claim, where a model of the behavior of the fluid in a borehole is used to estimate or determine at least one characteristic of the fluid to be supplied to the borehole. 13. System (1) for controlling the properties of a drilling fluid to facilitate a borehole operation, wherein the system comprises: drilling fluid measuring apparatus which is arranged to measure at least one property of the fluid or the cuttings (7) carried by the fluid, during the execution of the well operation; fluid handling apparatus (10) for modifying the fluid in response to the at least one measured property of the fluid or the cuttings (7); and a computer (602) configured to: receiving signals from the drilling fluid measuring device; calculating whether the fluid meets at least one predetermined criterion; determining a change of the fluid using a fluid mixture model (60) when the measured fluid does not meet the predetermined criterion; and send signals to the fluid handling apparatus (10) to modify the fluid, wherein the system (1) is configured to: determining at least one characteristic of the fluid to be provided to the borehole (5), using the measurement of the at least one characteristic of the fluid or the cuttings carried by the fluid, wherein the characteristic of the fluid is a said characteristic under standard conditions; and determine, based on measuring at least one borehole operating parameter and the at least one measured property of the fluid or drill cuttings (7), at least one characteristic of the fluid to be supplied to the borehole (5), performing the calculation of whether the fluid meets the at least one predetermined criterion by determining whether each said determined characteristic is in a predetermined range; where the system is characterized in that it is configured to: obtain a first measurement outside the borehole (5) of at least one property of the fluid or of cuttings (7) carried by the fluid, during the execution of the borehole operation, and obtain a second measurement outside the borehole (5) of at least one property of the fluid or of cuttings (7) carried by the fluid, during the execution of the borehole operation, where the first measurement is performed before filtering by means of a filter (12) to remove cuttings (7) after the fluid leaves the borehole (5), and the second measurement is a measurement carried out after the filtration before the fluid enters the borehole (5), perform the calculation of whether the measured fluid meets at least one predetermined criterion based on the first and second measurements, control the modification by automatically controlling and selecting the filter in the filter based on determining whether the measured fluid meets the at least one predetermined criterion, so that cuttings (7) having a certain size or particle size distribution are retained in the fluid. 14. System according to claim 13, where the system is for performing a well operation, where the system comprises: borehole apparatus provided in a borehole through which a fluid is to be circulated to facilitate the borehole operation. 15. Program code for a computer (602) which when executed on a computer (602) causes the computer (602) to: receiving signals from drilling fluid measuring apparatus arranged to measure at least one property of the fluid or the cuttings (7) carried by the fluid, during the execution of a borehole operation; calculating whether the fluid meets at least one predetermined criterion; determining a change of the fluid using a fluid mixture model (60) when the measured fluid does not meet the predetermined criterion; and send signals to a fluid handling apparatus (10) to modify the fluid, and cause the computer (602) to: determine at least one characteristic of the fluid to be provided to the borehole (5), using the measurement of the at least one characteristic of the fluid or the cuttings (7) carried by the fluid, wherein the measurement is performed under operating conditions found during the execution of the borehole operation and the characteristic of the fluid is a stated property under standard conditions; and measure at least one borehole operating parameter and the at least one measured property of the fluid or drill cuttings (7), and use these to determine at least one characteristic of the fluid to be supplied to the borehole (5), wherein calculating whether the fluid meets the at least one predetermined criterion comprises determining whether each said particular characteristic is in a predetermined range characterized in that the program code is to, when executed on a computer (602), cause the computer (602) to: obtain a first measurement outside the borehole (5) of at least one property of the fluid or of cuttings (7) carried by the fluid, during the execution of the borehole operation, and obtain a second measurement outside the borehole (5) of at least one property of the fluid or at cuttings (7) carried by the fluid, during the execution of the borehole operation, where the first measurement is performed before filtering by means of a filter (12) to remove cuttings (7) after the fluid leaves the borehole (5), and the second measurement is carried out after the filtration before the fluid enters the borehole (5), perform the calculation of whether the measured fluid meets the at least one predetermined criterion based on the first and second measurements, bring about the modification by automatically controlling and selecting the filter in the filter based on determining whether the measured fluid meets the at least one predetermined criterion, so that sawdust (7) having a certain size or particle size distribution is retained in the fluid.