ESTIMATING FLOW RATES FROM MULTIPLE HYDROCARBON RESERVOIR LAYERS INTO A PRODUCTION WELL

• US 20140365130A1
• Filed: 12/20/2012
• Published: 12/11/2014
• Est. Priority Date: 12/20/2011
• Status: Abandoned Application

• Current Assignee: BP Exploration Operating Company Limited (BP PLC)
• Original Assignee: BP Exploration Operating Company Limited (BP PLC)
• Inventors: Woods, Andrew W.
• Application Number:
  US14/366,939
• Publication Number:
  US 20140365130A1
• Time in Patent Office: Days
• US Class Current: 702/12
• CPC Class Codes: E21B 47/026 of penetrated ground layers
• CPC Class Codes: E21B 47/07 Temperature
• CPC Class Codes: E21B 47/103 using thermal measurements
• CPC Class Codes: G01F 1/6884 making use of temperature dependence of optical properties
• CPC Class Codes: G01F 1/74 Devices for measuring flow of a fluid or flow of a fluent solid material in suspension in another fluid

Abstract

There is provided a computer-implemented method for estimating flow of fluid into a production well extending into a reservoir comprising fluid, the well comprising a central tubing and an annulus surrounding the central tubing. The annulus is connected to the reservoir so as to receive fluid at one or more inflow locations. The central tubing has at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and is located downstream of the one or more inflow locations. The production well further comprises one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus. The method comprises: receiving temperature data from the one or more devices indicative of a temperature of fluid at a plurality of points along the length of the annulus identifying a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points; using a model to estimate heat transfer from the central tubing to fluid flowing within the annulus, said model being configured such that the heat transfer is assumed to be substantially constant along the length of the tubing; and estimating a rate at which fluid flows into the annulus from the reservoir at a first inflow location on the basis of the identified change in temperature between the points and the estimated heat transfer.

Claims

1-28. -28. (canceled)

29. A computer-implemented method for estimating flow of fluid into a production well extending into a reservoir comprising fluid, the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations, the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus,

the method comprising:

receiving temperature data from the one or more devices indicative of a temperature of fluid at a plurality of points along the length of the annulus;

identifying a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points;

using a model to estimate heat transfer from the central tubing to fluid flowing within the annulus, said model being configured such that the heat transfer is assumed to be substantially constant along the length of the tubing; and

estimating a rate at which fluid flows into the annulus from the reservoir at a first inflow location on the basis of the identified change in temperature between the points and the estimated heat transfer.

30. The method of claim 29, comprising using the model to determine a specific heat capacity of the fluid and thence estimating a composition of the fluid flowing from the reservoir into the annulus at the first inflow location.

31. The method of claim 29, comprising:

using the model to estimate a rate at which the fluid flows along the longitudinal axis of the annulus, whereby to estimate a rate at which fluid flows into the annulus at the first inflow location.

32. The method of claim 29, comprising:

identifying a temperature of fluid within the central tubing; and

determining a temperature gradient between the fluid within the central tubing and the fluid within the annulus, whereby to estimate heat transfer from the central tubing to fluid flowing within the annulus.

33. The method claim 29, comprising:

identifying a change in temperature of fluid within the annulus between a point upstream of the first inflow location and a point downstream of the first inflow location;

using a further model to estimate a change in temperature of the fluid in the annulus caused by fluid entering the annulus from the reservoir at the first inflow location; and

estimating a rate at which fluid flows into the annulus at the first inflow location on the basis of the identified change in temperature and the estimated change in temperature,

the method further comprising;

identifying a geothermal temperature at a depth corresponding to the first inflow location, whereby to estimate a temperature of fluid flowing into the annulus at the first inflow location, wherein the further model is configured to estimate the change in temperature of the fluid in the annulus based on the temperature of the fluid entering the annulus at the inflow location.

34. The method of claim 33, wherein the further model is configured such that fluid flowing within the annulus is assumed to mix with fluid entering the annulus at the first inflow location, and to associate the change in temperature of the fluid within the annulus with a rate of flow and a temperature of fluid flowing within the annulus upstream of the first inflow location and a rate of flow and a temperature of fluid flowing into the annulus at the first inflow location.

35. The method of claim 33, comprising using a yet further model to estimate a change in temperature of fluid flowing into the annulus at the first inflow location, the yet further model taking account of Joule-Thompson expansion of fluid flowing into the annulus at the first inflow location.

36. The method of claim 29, comprising using a said model to refine an estimate of a rate at which fluid flows into the annulus at the first inflow location generated by a further said model.

37. The method of claim 29, comprising using a said model and/or a said further model whereby to estimate a rate at which fluid flows into the annulus at one or more second inflow locations, wherein the model and/or further model are used to estimate a rate at which fluid flows into the annulus at one or more second inflow locations whereby to refine the estimate of the rate at which fluid flows into the annulus at the first inflow location.

38. The method of claim 29, comprising:

estimating a set of values for rates at which fluid flows into the annulus at the first inflow location, each value being associated with data indicative of a composition of the fluid flowing into the annulus at the first inflow location.

39. The method of claim 29, wherein the annulus is divided into a plurality of sections, each section having one or more inflow locations, and the central tubing has an inlet open to the annulus and located at the downstream end of each section, the method comprising:

estimating flow rates of fluid from the reservoir into a first said section;

estimating a flow rate of fluid from the first section into the central tubing through a first said inlet from the flow rates of fluid from the reservoir into the first section;

estimating a flow rate of fluid within the central tubing downstream of the first section based on the estimated flow rate of the fluid through the first inlet from the first section; and

estimating flow rates of fluid within a second said section using the estimated flow rate of fluid within the central tubing.

40. The method of claim 29, comprising:

receiving temperature data for fluid flowing into the annulus at the first inflow location at a plurality of points in time;

identifying a change over time in a temperature of the fluid flowing into the annulus at the first inflow location;

identifying a flow rate of fluid entering the production well at the first inflow location at each of the plurality of points in time;

identifying a geothermal gradient indicative of a change with depth in temperature of rock within and surrounding the reservoir; and

determining a measure of the tilt of a layer of the reservoir based on the change over

time in the temperature, geothermal gradient and flow rate.

41. A computer readable storage medium storing computer readable instructions thereon for execution on a computing system to implement a method for estimating flow of fluid into a production well extending into a reservoir comprising fluid, the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations, the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus,

the set of instructions being configured to cause the computing system to perform the steps of:

receiving temperature data from the one or more devices indicative of a temperature of fluid at a plurality of points along the length of the annulus;

identifying a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points;

using a model to estimate heat transfer from the central tubing to fluid flowing within the annulus, said model being configured such that the heat transfer is assumed to be substantially constant along the length of the tubing; and

estimating a rate at which fluid flows into the annulus from the reservoir at a first inflow location on the basis of the identified change in temperature between the points and the estimated heat transfer.

42. The computer readable storage medium of claim 41, wherein the set of instructions are configured to cause the computing system to use the model to determine a specific heat capacity of the fluid and thence estimate a composition of the fluid flowing from the reservoir into the annulus at the first inflow location.

43. The computer readable storage medium of claim 41, wherein set of instructions are configured to cause the computing system to:

use the model to estimate a rate at which the fluid flows along the longitudinal axis of the annulus, whereby to estimate a rate at which fluid flows into the annulus at the first inflow location.

44. The computer readable storage medium of claim 41, wherein the set of

instructions are configured to cause the computing system to:

identify a change in temperature of fluid within the annulus between a point upstream of the first inflow location and a point downstream of the first inflow location;

use a further model to estimate a change in temperature of the fluid in the annulus caused by fluid entering the annulus from the reservoir at the first inflow location; and

estimate a rate at which fluid flows into the annulus at the first inflow location on the basis of the identified change in temperature and the estimated change in temperature,

the set of instructions being further configured to cause the computing system to;

identify a geothermal temperature at a depth corresponding to the first inflow location, whereby to estimate a temperature of fluid flowing into the annulus at the first inflow location, wherein the further model is configured to estimate the change in temperature of the fluid in the annulus based on the temperature of the fluid entering the annulus at the inflow location.

45. The computer readable storage medium of claim 44, wherein the further model is configured such that fluid flowing within the annulus is assumed to mix with fluid entering the annulus at the first inflow location, and to associate the change in temperature of the fluid within the annulus with a rate of flow and a temperature of fluid flowing within the annulus upstream of the first inflow location and a rate of flow and a temperature of fluid flowing into the annulus at the first inflow location.

46. A system for estimating flow of fluid into a production well extending into a reservoir comprising fluid, the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations, the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus,

the system comprising:

an interface arranged to receive temperature data, the temperature data having being collected by the one or more devices and being indicative of a temperature of fluid at a plurality of points along the length of the annulus; and

a processor arranged to;

identify a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points;

execute a model to estimate heat transfer from the central tubing to fluid flowing within the annulus, said model being configured such that the heat transfer is assumed to be substantially constant along the length of the tubing; and

estimate a rate at which fluid flows into the annulus from the reservoir at a first inflow location on the basis of the identified change in temperature between the points and the estimated heat transfer.

47. The system of claim 46, wherein the processor is arranged to use the model to determine a specific heat capacity of the fluid and thence estimating a composition of the fluid flowing from the reservoir into the annulus at the first inflow location.

48. The system of claim 46, wherein the processor is arranged to use the model to estimate a rate at which the fluid flows along the longitudinal axis of the annulus, whereby to estimate a rate at which fluid flows into the annulus at the first inflow location.

49. The system of claim 46, wherein the processor is arranged to:

identify a change in temperature of fluid within the annulus between a point upstream of the first inflow location and a point downstream of the first inflow location;

execute a further model to estimate a change in temperature of the fluid in the annulus caused by fluid entering the annulus from the reservoir at the first inflow location; and

estimate a rate at which fluid flows into the annulus at the first inflow location on the basis of the identified change in temperature and the estimated change in temperature,

the processor being further arranged to;

identify a geothermal temperature at a depth corresponding to the first inflow location, whereby to estimate a temperature of fluid flowing into the annulus at the first inflow location, wherein the further model is configured to estimate the change in temperature of the fluid in the annulus based on the temperature of the fluid entering the annulus at the inflow location.

50. The system of claim 49, wherein the further model is configured such that fluid flowing within the annulus is assumed to mix with fluid entering the annulus at the first inflow location, and to associate the change in temperature of the fluid within the annulus with a rate of flow and a temperature of fluid flowing within the annulus upstream of the first inflow location and a rate of flow and a temperature of fluid flowing into the annulus at the first inflow location.