Methods for evaluating inflow and outflow in a subterranean wellbore

• US 9,394,783 B2
• Filed: 08/14/2012
• Issued: 07/19/2016
• Est. Priority Date: 08/26/2011
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: Rasmus, John, Lesso, William, James, John
• Primary Examiner(s): Lee, Paul D
• Application Number:
  US13/585,628
• Publication Number:
  US 20130090855A1
• Time in Patent Office: 1,435 Days
• Field of Search: 702/9
• US Class Current: 1/1
• CPC Class Codes: E21B 21/08 Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure valve arrangements therefor E21B21/10
• CPC Class Codes: E21B 34/06 in wells
• CPC Class Codes: E21B 43/12 Methods or apparatus for controlling the flow of the obtained fluid to or in wells E21B43/25 takes precedence; valve arrangements E21B34/00
• CPC Class Codes: E21B 47/04 Measuring depth or liquid level
• CPC Class Codes: E21B 47/06 Measuring temperature or pressure
• CPC Class Codes: E21B 47/10 Locating fluid leaks, intrusions or movements
• CPC Class Codes: E21B 49/003 by analysing drilling variables or conditions E21B49/005 takes precedence; systems specially adapted for monitoring a plurality of drilling variables or conditions E21B44/00
• CPC Class Codes: E21B 49/0875 determining specific fluid parameters
• CPC Class Codes: G01V 3/38 Processing data, e.g. for analysis, for interpretation, for correction

Abstract

A method for evaluating inflow or outflow in a subterranean wellbore includes acquiring first and second axially spaced pressure measurements in the wellbore. The pressure measurements may then be processed to obtain an interval density of drilling fluid between the measurement locations. A tool string including a large number of axially spaced pressure sensors (e.g., four or more or even six or more) electronically coupled with a surface processor via wired drill pipe may be used to obtain a plurality of interval densities corresponding to various wellbore intervals. The interval density may be measured during static conditions or while drilling and may be further processed to compute a density of an inflow constituent in the annulus. Changes in the computed interval density with time may be used as an indicator of either an inflow event or an outflow event.

Claims

1. A method for computing a density of an inflow constituent in a subterranean wellbore, the method comprising:

(a) rotating a drill bit in a subterranean wellbore, the drill bit being deployed in a drill string including first and second axially spaced along string pressure sensors, said rotating operative to drill the wellbore and produce formation cuttings which are transported to a surface location via drilling fluid in a wellbore annulus;

(b) using the first and second spaced along string pressure sensors to make first and second subsurface annular pressure measurements at corresponding first and second measured depths in the wellbore;

(c) transmitting the first and second pressure measurements to a processor;

(d) causing the processor to process the first and second annular pressure measurements to compute an annular interval density between the first and second measured depths in the wellbore; and

(e) causing the processor to process the annular interval density, a volume fraction of drilling fluid in the annular region, a density of the drilling fluid in an annular region of the wellbore, a volume fraction of the cuttings in the annular region, a density of the cuttings in the annular region, and a differential flow rate to compute the density of the inflow constituent.

2. The method according to claim 1, wherein:

the drill string includes first, second, and third axially spaced along string pressure sensors;

(b) further comprises using the first, second, and third annular pressure sensors to make first, second, and third annular pressure measurements at corresponding first, second, and third measured depths in the wellbore;

(d) further comprises causing the processor to process the first, second, and third annular pressure measurements to compute first and second annular interval densities, the first annular interval density between the first and second measured depths and the second annular interval density between the second and third measured depths; and

(e) further comprises causing the processor to process the first and second annular interval densities to compute first and second densities of the inflow constituent, the first density of the inflow constituent between the first and second measured depths and the second density of the inflow constituent between the second and third measured depths.

3. The method according to claim 1, wherein the first and second annular pressure measurements are acquired in (b) while drilling the subterranean wellbore in (a).

4. The method according to claim 1, wherein the annular pressure measurements are received at a surface processor in (c) via a wired drill pipe communications channel.

5. The method of claim 1, wherein the differential flow rate is a difference between a flow rate out of an annular region of the wellbore and a flow rate into a tool string deployed in the wellbore.

6. The method according to claim 1, wherein the density of the inflow constituent is computed according to the following mathematical equation:

7. The method according to claim 1, wherein the density of the drilling fluid in the annular region is acquired from a hydraulics model.

8. The method according to claim 1, wherein the volume fraction of drilling fluid, the volume fraction of cuttings, and volume fraction of the inflow constituent in the annular region are estimated from a drilling fluid flow rate, a rate of penetration of drilling, and the differential flow rate.

9. The method according to claim 1, further comprising:

(d) evaluating the density of the inflow constituent computed in (c) to identify the inflow constituent.

10. The method according to claim 9, wherein a density of the inflow constituent less than about 0.6 g/cm³ indicates a gaseous inflow constituent, a density of the inflow constituent in a range from about 0.6 g/cm³ to about 0.8 g/cm³ indicates an oil inflow constituent, and a density of the inflow constituent greater than about 1 g/cm³ indicates a connate water inflow constituent.