NO20170933A1

NO20170933A1 - Method and system for determining downhole pressure in drilling operations

Info

Publication number: NO20170933A1
Application number: NO20170933A
Authority: NO
Inventors: Kristian Gjerstad
Original assignee: Mhwirth As
Priority date: 2017-06-08
Filing date: 2017-06-08
Publication date: 2018-10-25
Also published as: GB2564253B; GB201808753D0; GB2564253A

Abstract

A method for determining a hydrostatic Component (PHs) of a downhole pressure during a drilling operation, comprising the steps: extending a drill string (1) into a borehole (2), the drill string (1) having a tool (3) comprising a pressure sensor (6), a transmitter (5) and a power generator (4) configured to receive drilling fluid from the drill string (1) and generate electric power to operate the tool (3); pumping a drilling fluid through the drill string (1) at a predetermined flow rate (Qpump); calculating a motive speed (u, m) for the drill string (1), moving the drill string (1) at the calculated motive speed (u, m) while operating the tool (3) to transmit a measured downhole pressure (PpWd) to a surface location (7); and determining the hydrostatic component (PHs), the hydrostatic component being calculated as a function of the measured downhole pressure(PpWd).A method for determining a hydrostatic component (PHs) of a downhole pressure during a drilling operation, comprising the steps of: extending a drill string (1) into a borehole (2), the drill string (1) having a tool (3) a pressure sensor (6), a transmitter (5) and a power generator (4) configured to receive drilling fluid from the drill string (1) and generate electric power to operate the tool (3); pumping a drilling fluid through the drill string (1) at a predetermined flow rate (Qpump); calculating a motive speed (u, m) for the drill string (1), moving the drill string (1) at the calculated motive speed (u, m) while operating the tool (3) to transmit a measured downhole pressure (PpWd) to a surface location (7); and determining the hydrostatic component (PHs), the hydrostatic component being calculated as a function of the measured downhole pressure (PpWd).

Description

METHOD AND SYSTEM FOR DETERMINING DOWNHOLE PRESSURE IN

DRILLING OPERATIONS

The present invention relates to a method of determining downhole pressure in drilling operations.

BACKGROUND

Controlling the downhole pressure within certain margins is crucial in petroleum drilling operations in order to maintain the stability of the formation, avoid loss of drilling fluid (commonly known as mud), and avoiding uncontrolled influx of reservoir fluids into the wellbore. Knowledge about how the pressure develops as the downhole conditions changes is important to achieve such accurate control, and various methods and tools exist to aid the drilling operator in this respect. In conventional plants (i.e. with no wired drill pipe) it is common to have measurements while drilling (MWD) tools arranged near the lower end of the drill string to measure and transmit measurements of pressure and other downhole properties to surface.

As regulatory safety requirements become ever-more stringent, while petroleum exploration takes place in more challenging areas (such as deepwater fields or arctic areas) and the demands for operational efficiency (e.g. high uptime) remain high, there is a continuous need for improved systems and techniques for determining downhole pressure, either via measurements or estimates/calculations, or a combination of these. There is also a drive towards automation in the industry, which sets additional requirements to safety and systems to provide improved control and early warnings of potential risks.

Documents which can be useful for understanding the background include:

- Godhavn, J.-M. (2009). Control requirements for high-end automatic MPD operations. SPE/IADC Drilling Conference and Exhibition.

Amsterdam.

- Tarr, B., Ladendorf, D., & Sanchez, D. (2016). Next-Generation Kick Detection During Connections: Influx Detection at Pumps Stop Software. SPE Drilling and Completion, 250-260.

- Crespo, F., & Ahmed, R. (2013). A Simplified Surge and Swab Pressure Model for Yield Power Law Fluids. Journal of Petroleum Science & Engineering, 101, 12-20.

- Gjerstad, K. (2014). Simplified Flow Equations for Single-Phase non-Newtonian Fluids in Couette-Poiseuille Flow and in Pipes. University of Stavanger.

- Gjerstad, K., & Time, R. W. (2015, June). Simplified explicit flow equations for Herschel-Bulkley fluids in Couette-Poiseuille flow. Journal of Non-Newtonian Fluid Mechanics, 20(3), 610 - 627.

- Liu, Y.-Q., & Zhu, K.-Q. (2010). Couette Poiseuille flow of Bingham fluids through concentric annuli. Journal of Non-Newtonian Fluid Mechanics, 165, 1494-1504.

- Malik, R., & Shenoy, U. V. (1991). Generalized annular couette flow of a power-law fluid. Industrial and Engineering Chemistry Research, 30, 1950-1954.

- Ramadan, A., & Miska, S. (2008). Experimental Study and Modeling of Yield Power-Law Fluid Flow in Annuli with Drillpipe Rotation. IADC/SPE Drilling Conference. Orlando, Florida.

- Whittaker, A. (1985). Theory and applications of drilling fluid hydraulics.

Dordrecht: Reidel.

The present invention has the objective to provide a method of determining downhole pressure in drilling operations which provides advantages over known solutions and techniques.

SUMMARY

In certain embodiments according to the present invention, there is provided a method utilizing measurement-while-drilling (MWD) functionality comprising a downhole pressure sensor connected to a transmission system driven by the circulating drilling fluid. The method provides an improved way to operate a drilling plant to obtain accurate information on downhole pressure. In some embodiments, the method comprises moving the drill string according to calculated motive translational and/or rotational speeds while obtaining pressure measurements from a downhole tool. A system operating according to the method may transmit pressure measurements at certain intervals to the surface, where these pressure samples can be used in the methods described here.

In an embodiment, there is provided a method for determining a hydrostatic component of a downhole pressure during a drilling operation, comprising: extending a drill string into a borehole, the drill string having a tool comprising a pressure sensor, a transmitter and a power generator configured to receive drilling fluid from the drill string and generate electric power to operate the tool; pumping a drilling fluid through the drill string at a pre-determined flow rate; calculating a motive speed for the drill string, the motive speed being calculated as a function of a drill string and borehole geometry, fluid properties and the pre-determined flow rate, wherein the step of calculating the motive speed comprises:

(i) determining a motive speed which minimizes a frictional pressure component of the downhole pressure at the pre-determined flow rate and/or

(ii) determining a motive speed which minimizes a non-linear component of the relationship between a flow rate through an annulus formed between the drill string and the borehole and the frictional pressure component of the downhole pressure; moving the drill string at the calculated motive speed while operating the tool to transmit a measured downhole pressure to a surface location; and determining the hydrostatic component, the hydrostatic component being calculated as a function of the measured downhole pressure.

The appended claims outline further embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

Illustrative embodiments of the present invention will now be described with reference to the appended drawings, in which:

Figure 1 shows a typical flow characteristics for drilling mud in an annulus with a stationary inner drill string, with the relationships between flow rate, frictional pressure drop and hydrostatic pressure emphasised.

Figure 2 illustrates flow patterns of fluid flow in an annulus between a borehole and a drill string with and without axial drillstring motion.

Figure 3 illustrates a drill string having a tool.

Figure 4 illustrates a drill string rotating in a borehole at an angular velocity . Figure 5 illustrates the round trip of drilling mud in a well and aspects of a method according to an embodiment.

Figure 6 illustrates typical flow characteristics for drilling mud in an annulus with an axially moving inner drillstring. The linearized range for the relationships between flow rate and frictional pressure drop in the centre is emphasised.

DETAILED DESCRIPTION

Controlling the downhole pressure or Equivalent Circulation Density (ECD) within certain margins is important in many drilling operations. In order to do this is it necessary to have knowledge about how the pressure develops as the conditions changes. At conventional fixed rigs (no wired drill pipe) it is common to have Measurements While Drilling (MWD) tools to measure and transmit measurements of pressure and other downhole properties to surface. However, MWD tools often require mud circulation above a certain flow rate, here denoted the minimum MWD rate, in order to be able to transmit the measurements. Hence, in periods when the mud pumps are turned off, like during connections, no measurements about downhole conditions are received to surface. In this situation, there is no frictional pressure component in the borehole, only the hydrostatic pressure is present. Due to this reduced pressure/ECD during connections, many kick problems start in this situation. The fact that no measurements are transmitted in these periods complicates the problem.

By providing a way to find the hydrostatic pressure ( ) before shutting down the pumps, it can be compared to the anticipated pore pressure, and the probability of having a kick when the pumps are shut down can be determined more accurately. Moreover, when is known the Equivalent Static Density (ESD) / average mud density can easily be calculated. This calculated density can then be compared to the theoretical density which is the expected density when no event has occurred. If the calculated density is lower than expected, that could be an indication that gas or lightweight oil has already entered the well. In this case, a flow check or other precautions can be taken before continuing the operations.

Estimation of current ESD can also give other useful information about the well conditions. If ESD is higher than the expected theoretical density, it may be because of poor cutting transportation. If corrective actions are not taken in such cases, the result could be cuttings “pack off” which will give a sudden increase in the downhole pressure and can further potentially fracture the well. Another problem related to insufficient pressure control is that a too high pressure in the wellbore/annulus can cause problems like loss of drilling mud to the formation.

During drilling, the circulation rate must be high enough to flush and transport the cuttings up the annulus. A high flow rate gives a higher pressure/ECD. If a MWD tool is used, the downhole pressure measurements are normally received at surface in this situation. However, in order to control the pressure below critical margins, it is useful to know how large parts of the total ECD that is caused by the frictional pressure component (due to circulation) and the ESD respectively. In some wells, the ESD part contributes with more than 90% of the total ECD. As a consequence, the effect of adjusting the pump rate for reducing the ECD is limited. Hence, good knowledge of the downhole pressure at hydrostatic conditions (ESD) is advantageous also for pressure control during circulation and to determine the total pressure in the well.

The usefulness of better knowledge of /ESD is not limited to the examples above. For example, by combining reliable /ESD information with modelling and estimation technology, a lot of advanced tools for better control of the drilling operations can be developed.

Determining the by estimation or prediction based on pressure measurements taken above the minimum MWD-limit can, however, be challenging. Figure 1 shows a typical relationship between flow rate and the total pressure for drilling mud in an annulus with stationary drillstring. The total pressure can, as illustrated, be divided into two components, the hydrostatic component and the frictional pressure drop , i.e.,

Figure 1 shows a typical drilling mud which exhibits both yield effect and shear thinning properties. Even if a number of sampling points (in the figure exemplified by two sampling points 10 are available for flow rates above the minimum MWD rate, extrapolation to estimate the hydrostatic pressure at very low or zero flow rate 11 can give results that differ significantly from the real hydrostatic pressure 12. The reason for this is that the behavior of the drilling mud is normally strongly non-linear in this context. Because of yield properties of the mud, these non-linearities are often, as illustrated in Figure 1, particularly strong close to zero flow (below the minimum MWD-limit). Therefore, such extrapolation will normally give significant errors in the estimated /ESD.

In embodiments described herein, a more accurate method for determining the hydrostatic pressure , and consequently the equivalent static density (ESD) in the bottom of the well is provided. In an embodiment it is based on: 1) running the mud pump just above the minimum MWD rate; and 2) at the same time slowly moving the drill string upwards. By moving the string, the frictional pressure component from the circulating mud can be cancelled out party or entirely. Ideally, only the hydrostatic pressure component will remain, and the pressure signals received from the MWD tool will be substantially the hydrostatic pressure only. In general can be optained by,

When moving the string axially during pumping at low flow rates, a laminar flow situation in the annulus that is denoted generalized Couette flow is obtained. A flow pattern for Couette flow in an annulus between a borehole and a drill string is illustrated on the left hand side of Figure 2. In this particular example it is assumed that the string is moved upwards and that = 0. Due to the assumption of no-slip by the walls, some mud will follow the string upwards. On the right hand side of Figure 2 the string is stationary and > 0, which gives a normal Poiseuille flow pattern.

According to theory for generalized Couette flow, there will always exist a specific relationship between the bulk flow rate in the annulus and the string speed that gives zero frictional pressure gradient over the length of an annulus with homogenous geometry (as illustrated on the left hand side of Figure 2). This relationship is dependent on geometry parameters (diameters, eccentricity) and fluid properties (viscosity, rheology). For a concentric annulus an effective flow velocityeffis defined as

where vais the bulk flow velocity in the annulus (see Figure 4), is the string speed, CClis the clinging constant for the fluid, is the flow rate in the annulus, and is the cross-sectional area of the annulus. Assuming the flow is steady in the entire circulating loop gives,

for all (4) is cross-sectional area of the drillstring (see Figure 4). From the definition of the clinging constant (Whittaker, 1985, ss.111-117), it follows that

veff= 0 gives Pf= 0 ( CClis a negative constant between -0.5 and 0). When using a MWD tool, the flow rate is limited downwards by the minimum flow needed for MWD to transmit measurements. The zero-friction string speed is here defined as the speed which gives zero frictional pressure gradient for a given flow rate.

By setting veff= 0 in Eq. (3) and inserting Eq. (4) a motive string speed can be found. Assuming homogenous diameters and approximating the clinging factor to a typical value gives the approximate string speed,

V CCl= -0.4 (5)

The clinging factor CC\will in general be dependent on drill string outer diameter, wellbore diameter, fluid properties, flow rate and eccentricity of the string. Since, these parameters may change along the well, this zero-friction string speed may be different in different sections of the well. If one divides the well into n sections with approximately homogeneous geometry, and index each section by i, this means that one single string speed that 100% cancels out the Pf(i ) in every section i (for a given flow rate) may not exist. This may not be material for accuracy, however if required this issue can be solved by evaluating Pf(i)for the different parts of the well, and finding the best suited string speed v based on some optimal criterion. Exactly how to formulate a criterion for v depends on a range of factors like complexity of the mud and geometry parameters as well as which level of accuracy is needed. A simple approach is to just compute v for the longest well section. Other options are to find the speed v that minimizes the sum of Ρf(i)or the sum of squares of Pf(i).

When a motive string speed v is selected from the optimal criteria, the small residuals Pf(i)can be calculated and subtracted from the PWD readings to obtain the hydrostatic pressure PHS(when the string is pulled at speed v). Ideally all Pf(i)are then zero, but in practice some of them may have small non-zero values. These values can now be computed very accurately since the magnitudes of all Pf(i)are significantly reduced, so that any percentage error in the calculations of Pf(i)will have less effect on the final estimate of the hydrostatic pressure.

In addition, the non-linear characteristics due to the yield properties of the mud (illustrated in Figure 1) are changed. In generalized Couette flow there will be a range close to veff= 0 (zero-friction string speed), where the friction loss as function of flow rate (the flow characteristics) will be linear or very close to linear. (See Figure 6, which shows the typical strong non-linear relationship between flow rate Qaand frictional pressure drop Pffor drilling mud in an annulus with a axial moving inner drillstring (generalized Couette flow). Fig. 6 shows results from 4 different models which show almost the same behavior.) This linearizing effects will contribute to more accurate calculations of Pf(iand thereby PHS- (If the drilling mud does not exhibit yield properties, the flow characteristic will be closer to linear over the entire flow range).

The hydrostatic downhole pressure PHSmay be calculated as the difference between the measured downhole pressure PPWDand the calculated frictional pressure over the entire well Pf. Assuming the well is divided into n sections with homogenous geometry, we get:

Dependent on the fluid properties, it is not always possible to express the clinging factor CC\or the frictional pressure loss Ρf(i)as an explicit function of the other parameters. Analytical approaches for Power-law and Bingham plastic fluids are complex as shown in (Malik & Shenoy, 1991) and (Liu & Zhu, 2010) respectively. For the more general Flerschel-Bulkley fluid the exact theory is even more complicated. In this case, the simplifications presented in (Gjerstad, 2014, ss. 80-90) may be used. Graphical overviews of typical values for the clinging factor for Power-law and Bingham plastic fluids are given in (Whittaker, 1985, ss. 115-116). A practical approach is to use such pre-calculated values and do interpolation/table look-up for each situation. Numerical calculations are also possible.

For any flow rate there is, as described above, a zero-friction string speed that cancels out the frictional pressure gradient. Flowever, by lowering the pumping rate to just above the rate required for operating the MWD tool, a lower string speed is obtained as optimal. A lower string speed has the advantage of giving more time for receiving PWD measurements. In addition, low flow rate and string speed gives less likelihood for non-linear turbulent effects. Hence, keeping the pump rate low can contribute to a more accurate prediction.

When pulling the drill string, the particular situation whereeff= 0 will have the characteristics that there will be a small return flow out of the annulus. Since the exact pump rate may not be measured/calculated as accurately as we want, increased accuracy may be achieved by evaluating the return flow. A flow sensor directly on the return line can be used if it is reasonable accurate for low flow rates. Alternatively, the level/volume measurements on the active pit/trip tank can be used to compute the return flow rate.

The upper section 1a of the drill string 1 can be withdrawn out of the borehole 2 with a string speed such that the product of the speed and a cross-sectional area of the drill string 1 is less than the circulation flow rate given byPump(ref. Eq. (5)). This ensures that the volume of drill string 1 removed from the lower part of the borehole 2 (the lower section 1b of the drill string 1 being withdrawn upwards in the borehole 2) is less than the volume flow rate of mud pumped into the borehole 2. Consequently, one can get a positive return flow which can be used to indicate which flow range is present in the flow characteristics of generalized Couette flow (see Figure 6).

Fig. 3 illustrates a drill string 1 having a measurement-while-drilling (MWD) tool 3, which is suitable for use with a method according to embodiments described herein. The MWD tool 3 has a fluid-driven generator 4, which is driven by drilling fluid pumped through the drilling string 1. The MWD tool 3 further has a transmitter 5 and a pressure sensor 6. The transmitter 5 is operable to transmit pressure readings to the surface, powered by the generator 4. The string itself has a transverse cross-sectional area as illustrated by the cut view B-B at the top of the figure. (The cross-sectional area is here the outer crosssectional area, i.e. including the drill string walls and not to be confused with the inner cross-sectional area forming the flow area in the string.)

Figure 5 illustrates one embodiment of determining a hydrostatic component Pfisof a downhole pressure during a drilling operation. A drill string 1 is extended into a borehole 2, the drill string 1 having a tool 3 comprising a pressure sensor 6, a transmitter 5 and a power generator 4 (see Fig. 3) configured to receive drilling fluid from the drill string 1 and generate electric power to operate the tool 3.

A drilling fluid is pumped through the drill string 1 at a pre-determined flow rate Qpump iand a motive speed (string speed) v for the drill string 1 is calculated as a function of the drill string 1 and borehole 2 geometry, the given fluid properties and the pre-determined flow rate Qpump· The pre-determined flow rate may be higher than a minimum MWD flow rate to ensure stable operation of the tool 3. Calculating the motive speed v comprises determining a speed v which minimizes a frictional pressure component Pfof the downhole pressure at the pre-determined flow rate Qpump, for example by use of Equation (5).

The embodiment further comprises moving the drill string 1 at the calculated speed v while operating the tool 3 to transmit a measured downhole pressure PPWDto a surface location 7, and determining the hydrostatic component PHsby calculating the hydrostatic component as a function of the measured downhole pressure PPWD. This may, for example, be done by use of Equations (5) and (2).

The embodiment may comprise determining a motive speed v which minimizes the frictional pressure components pf(i)of the downhole pressure at the predetermined flow rate Qpumpfor each of a plurality of well sections i, ii, iii. In this case a criterion for minimization of Pf(i)can be employed, as described above (for example minimizing the sum of squares of Pf(i)).

In an advantageous embodiment, the speed is in the range 0,1 - 0,5 m/s. This speed may be sufficiently low in certain applications to allow time for sufficient measurements over a typical lifting height of a hoisting system.

In an embodiment, if the tool 3 has a minimum drilling fluid flow rate required for powering the pressure sensor 6 and/or the transmitter 5, the drilling fluid can advantageously be pumped through the drill string 1 at a pre-determined flow rate Qpumpwhich is less than 200% of the minimum drilling fluid flow rate, less than 150% of the minimum drilling fluid flow rate, less than 120% of the minimum drilling fluid flow rate, or less than 110% of the minimum drilling fluid flow rate. A lower flow rate has the advantage of reducing frictional pressure losses, as noted above, and to provide more time for measurements during a hoisting action with a limited hoisting height.

Prior to carrying out the method, an ongoing drilling method may be stopped and the drill string 1 lifted off a bottom location (so-called “pick up off bottom”) and the pumping rate reduced to produce the pre-determined flow rate Qpump.

Advantageously, the drill string 1 can be moved at a number of translational speeds v and the return flow measurements Qreturnrecorded and analysed for each speed v. The string speeds are selected such that they produce return flow rates that are in a range that fulfills:

where Aa(i)is a cross-sectional area of the annulus 8 in a well section i and Ccl(i)is a clinging factor in the well section i. The final motive string speed v can be chosen to stay within the range of string speeds that fulfills Eq. (7).

An effect of the yield point properties in the laminar flow regime is that a certain shear stress between the fluid layers may need to be surpassed in order to get any flow at all. As described below, according to an embodiment, rotating the drill string will give linearizing effects and may contribute to more accurate calculations of( )and thereby . In some embodiments string rotation alone (no pulling) may be the preferred choice.

For one-dimensional longitudinal/axial flow in a conduit (no rotational flow), a certain magnitude of the pressure may need to be surpassed in order to initiate flow when the fluid has a yield point. As illustrated in figure 1, this feature manifests itself in a strong non-linear behavior since the frictional pressure component makes a “jump” when the flow rate changes from zero to nonzero. At the onset of flow during such conditions the shear stress is higher than the yield point in at least one part of the cross-sectional area of the conduit, giving a non-zero shear rate between the fluid layers. If the pressure now increases, a non-zero shear rate will be initiated in an increasingly larger part of the cross-sectional area. In this period, the effect of the yield point reduces quite fast and it approaches zero as the pressure approaches infinity. Similarly, the non-linear behavior caused by the yield point decreases and approaches zero in this period.

Assuming now an annulus with no longitudinal pressure gradient and an inner cylinder (like a drill string) that rotates. Due to no-slip conditions by the walls there will now, no matter how slowly the string rotates, be rotational flow in at least an area close to the inner cylinder. The faster the string rotates, the larger the shear stress between the fluid layers and the larger part of the annulus will have rotational flow. If a longitudinal pressure gradient is enforced to such rotational flow (due to a pump), the shear stress is already above the yield point in a part of the annulus. In these areas, an axial flow will be initiated for the slightest pressure gradient. Hence, the jump in pressure at the onset of axial flow will not be present anymore. There may still be a range with moderate nonlinear behavior as the pressure increases (if a significant portion of the outer part of the annulus was not rotating before the longitudinal pressure gradient was enforced). However, this will be reduced compared to the non-rotating case since now there are shear stresses in two perpendicular directions that work together to surpass the yield point. The faster the string rotates, the less is the non-linear effect in longitudinal direction due to the yield point properties.

In some cases, drill string irregularities and wobbling at high rotational rates may introduce disturbances to the flow that could give turbulent flow. This will introduce other non-linear effects. Hence, generally the rotational speed should due to these reasons be low. In a typical embodiment, rotational speeds within the range 5-30 RPM may be suitable, however it may be higher or lower than this depending on drilling system and well design. The advantageous effects of rotation are not very sensitive to the exact speed within the range above. For most fluids and geometry parameters a suitable value is

(8)

When the dominating non-linear effects of the frictional pressure loss (close to zero flow) are reduced by rotation this way, a more accurate calculated estimate of this frictional pressure loss can be obtained.

The embodiments described above may thus, alternatively to using a translational speed, comprise rotating the drill string 1 at an angular motive speed , for example that given in Eq. (8).

If the drillstring OD or well ID have different diameters in different sections along the wellbore, the frictional pressure loss( )has to be computed for each section separately. Input to these calculations are the angular velocity of the drillstring and the flow rate( )in section . An assumption of steady flow in the entire circulating loop will in this case give:

for all (9)

The exact approach for computing( )when the string is rotating depends on properties of the mud, requirements for accuracy and computational power etc. A presentation which includes analytical theory, numerical solutions and laboratory experiments for Herschel-Bulkley fluids are given in (Ramadan & Miska, 2008). No matter which technique is chosen, the estimated frictional pressure loss will be more accurate than before due to the linearization approach. The hydrostatic pressure component can then as before be computed fromPWDand Pfi according to Eq. (6).

Additional information about the flow characteristics can also be obtained from a plurality of PWD measurements. Due to the linearized characteristics, such measurements can now be extrapolated to obtain improved estimates for .

For the case of pulling the string and having a mud with yield point, the desired situation is to find a motive string speed that minimizes all( )and changes the flow characteristics and the working point such that the relationship between any small residual( )and the flow rate in the annulus( )can be represented by a near-linear function. For certain combinations of fluid properties and geometry parameters this may, however, not be possible to achieve simultaneously in the entire well (Gjerstad & Time, 2015). In these cases, the working point for some sections may stay in a non-linear range, which makes( )larger in amplitude and harder to estimate. In such situations, string rotation will (due to the physical effects described above) give additional linearization in flow ranges where the non-linearity is pronounced. This may again help in improving the accuracy of estimating the residuals of( ).

In one embodiment, it may therefore be advantageous to move the drill string 1 both translationally and rotationally to obtain best results. In any of the embodiments described above, a combination of translational speed and angular speed may therefore be calculated, for example using equation (5) for and equation (8) for . The drill string 1 may then be withdrawn while rotating in order to obtain more accurate results.( )may be computed by detailed numerical techniques or by simplified methods.

If the parameters and conditions in the well are unknown/ uncertain the calculations in which they are used may also be uncertain. Additional updated knowledge about the situation in the well can be achieved by recording and analyzing/plotting PWD measurements for different axial and angular string speeds.

In one embodiment, the estimation of the hydrostatic pressure component in drilling operation, comprising the step of moving the drill string 1 at a number of pre-calculated speeds , and recording and analysing/plotting PWD measurements from the tool 3 for each combination of speeds

By means of the recorded data, knowledge can be obtained about the relationship between the frictional pressure component in the annulus , the flow rate in the annulus , the translational string velocity and the angular string velocity , and in particular identification of linear/near-linear sub-ranges, the rate of change and the degree of non-linearity between and for different combinations of and . This knowledge about the flow characteristics between and can be used together with techniques like interpolation or extrapolation to get improved estimate of and thereby , and to identify parameter combinations which minimizes to the greatest possible degree.

The method may combine the recorded information with other parameters and/or measurements, for example return flow measurements, to obtain higher accuracy.

When used in this specification and claims, the terms "comprises" and "comprising" and variations thereof mean that the specified features, steps or integers are included. The terms are not to be interpreted to exclude the presence of other features, steps or components.

The features disclosed in the foregoing description, or the following claims, or the accompanying drawings, expressed in their specific forms or in terms of a means for performing the disclosed function, or a method or process for attaining the disclosed result, as appropriate, may, separately, or in any combination of such features, be utilised for realising the invention in diverse forms thereof.

The present invention is not limited to the embodiments described herein. Reference should be had to the appended claims.

Claims

CLAIMS 1. A method for determining a hydrostatic component ( PHs) of a downhole pressure during a drilling operation, comprising the steps: extending a drill string (1 ) into a borehole (2), the drill string (1 ) having a tool (3) comprising a pressure sensor (6), a transmitter (5) and a power generator (4) configured to receive drilling fluid from the drill string (1) and generate electric power to operate the tool (3), wherein the tool (3) has a minimum drilling fluid flow rate required for powering the pressure sensor (6) and/or the transmitter (5); pumping a drilling fluid through the drill string (1 ) at a pre-determined flow rate ( QpUmp) which is higher than the minimum drilling fluid flow rate; calculating a motive speed ( ν,ω ) for the drill string (1), the motive speed {ν, ω) being calculated as a function of a drill string (1) and borehole (2) geometry, fluid properties and the pre-determined flow rate (Qpump), wherein the step of calculating the motive speed ( ν,ω ) comprises: (i) determining a motive speed ( ν,ω ) which minimizes a frictional pressure component ( Pf) of the downhole pressure at the predetermined flow rate (Qpump), and/or (ii) determining a motive speed ( ν,ω ) which minimizes a non-linear component of the relationship between a flow rate through an annulus (8) formed between the drill string (1) and the borehole (2) and the frictional pressure component ( Pf) of the downhole pressure; moving the drill string (1 ) at the calculated motive speed ( v , ω ) while operating the tool (3) to transmit a measured downhole pressure ( PPWD) to a surface location (7); and determining the hydrostatic component ( PHs), the hydrostatic component being calculated as a function of the measured downhole pressure ( PPWD ).
2. A method according to claim 1 , wherein the step of determining a motive speed (v, ω) which minimizes a frictional pressure component ( Pf) of the downhole pressure at the pre-determined flow rate ( QpUmP) comprises determining a motive speed (v, ω) which minimizes a frictional pressure component (Pf(i)) of the downhole pressure at the pre-determined flow rate (Qpump) for each of a plurality of well sections (i,ii,iii).
3. A method according to claim 1 or 2, wherein the step of calculating a motive speed for the drill string (1) comprises calculating a translational motive speed ( v ) and the step of moving the drill string (1) at the calculated motive speed ( v ) comprises withdrawing an upper section (1a) of the drill string (1) out of the borehole (2) at the calculated motive speed (v).
4. A method according to the preceding claim, wherein the step of withdrawing an upper section (1a) of the drill string (1) out of the borehole (2) comprises withdrawing the upper section (1a) of the drill string (1 ) out of the borehole (2) with a speed ( v ) such that the product of the speed ( v ) and a cross-sectional area ( ADs) of the drill string (1) is less than the flow rate ( QpumP).
5. A method according to claim 3 or 4, wherein the translational motive speed is calculated according to a function:

where Aaand ADsare the cross-sectional areas of the annulus (8) and the drill string (1), respectively.
6. A method according to the preceding claim, wherein the function is

where Cclis a clinging factor.
7. A method according to any of claims 3-6, wherein the translational motive speed is in the range 0,1 - 0,5 m/s.
8. A method according to any preceding claim, wherein the step of calculating a motive speed for the drill string (1) comprises calculating an angular motive speed (ω) and the step of moving the drill string (1) at the calculated motive speed (ω) comprises rotating the drill string (1) at the calculated angular motive speed (ω).
9. A method according to the preceding claim, wherein the angular motive speed is less than 30 RPM, less than 20 RPM or less than 10 RPM.
10. A method according to any preceding claim, wherein the step of pumping a drilling fluid through the drill string (1) comprises pumping the drilling fluid through the drill string (1) at a pre-determined flow rate (Qpump) which is: less than 200% of the minimum drilling fluid flow rate, less than 150% of the minimum drilling fluid flow rate, less than 120% of the minimum drilling fluid flow rate, or less than 110% of the minimum drilling fluid flow rate.
11.A method according to any preceding claim, further comprising the steps: drilling a section of the borehole (2); stopping drilling and lifting the drill string (1) off a bottom location; and reducing the pumping of the drilling fluid through the drill string (1) to produce the pre-determined flow rate (Qpump)·
12. A method according to any preceding claim, further comprising the step of calculating a frictional pressure loss ( Pf), whereby the hydrostatic component ( PHs) is calculated as a function of both the measured downhole pressure ( PPWD) and the frictional pressure loss ( Pf).
13. A method according to the preceding claim, wherein the step of calculating the frictional pressure loss ( Pf) comprises calculating a frictional pressure loss component (Pf(i)) for each of a plurality of well sections.
14. A method according to any preceding claim, further comprising the step of measuring a return flow (Qret urn) from the borehole (2), and wherein the step of pumping a drilling fluid through the drill string (1) comprises pumping a drilling fluid through the drill string (1 ) at a rate which produces a positive return flow (Qretum) from the borehole (2).
15. A method according to the preceding claim, wherein the step of moving the drill string (1) at the calculated motive speed ( ν,ω ) comprises moving the drill string (1) at a number of translational speeds ( v ) and recording and analysing the return flow measurements (Qretum) for each speed ( v ).
16. A method according to the preceding claim, wherein the step of analysing the return flow measurements (Qretum) for each speed ( v ) comprises selecting a motive speed ( v ) which produces a return flow rate that is in a range defined by:

where Aa(i)is a cross-sectional area of the annulus (8) in a well section i and Ccl(i)is a clinging factor in the well section i.
17. A method according to any preceding claim, comprising moving the drill string (1) at a plurality of pre-calculated speeds ( ν,ω ) and recording measurements from the tool (3) for each of the pre-calculated speeds ( ν,ω ).
18. A system for analysing a drilling operation, comprising an input device for providing operational data of the drilling operation, and a computer device configured to perform a method as set forth in any of claims 1-17.