Method and Apparatus for Predicting the Fluid Characteristics in a Well Hole

1. Field of the Invention

The present invention relates to oil and gas wells. More particularly, the present invention relates to a method and apparatus for predicting the state properties of a multi-phase fluid at any point within the fluid conduit of an oil and gas well.

2. Description of the Related Art

Oil and gas have been extracted from the subsurface of the earth for many decades. Well holes are drilled into the earth until a reservoir of fluid is reached. The underground fluid is then extracted and refined for various purposes. As with most oil and gas wells, the extracted fluid is a multi-phase mixture of oil, water, and gas. The gas itself is in two forms, free gas and gas that is in solution either with the oil or with the water.

The monitoring of the production of fluid from oil and gas wells continues to be an important activity. Not only is monitoring necessary for obvious economic reasons, but also as an indicator of serious problems, such as leaks in the piping making up the well.

Currently, oilfield service companies physically insert a measuring tool into the flow conduit of a well to measure fluid characteristics such as temperature, pressure, and total flow rate. The process of physically measuring and recording the flow in a well hole is called production logging. At best, a production log may provide an accurate snapshot of production information at the particular time that the measurements are made. However, this information can change relatively quickly, especially in a well with multi-zone production where the production from one zone can affect the production in another. There are several other problems involved with prior art production logging methods. First, the measuring device that is used has a finite size, so it disturbs the flow that it is trying to measure and introduces error into the measurement and subsequent calculations. Second, the measuring device must be calibrated in the well. Unfortunately, the well cannot be producing while the measuring device is being calibrated so the calibration period results in a loss of revenue for the oil well owner. Consequently, current production logging methods are not entirely satisfactory.

There is, therefore, a need, therefore, of a method and/or a device for production logging that can measure accurately the production capacity of an oil and gas well without disturbing the fluid flow during measurement. There is also a need in the art for a method that does not require the well to be shut down during calibration of the measuring instruments. It is an object of the present invention to solve the problems inherent in the prior art methods. It is a further object of the present invention to utilize existing equipment on the wellhead to enable remote monitoring of well production.

The present invention solves the problems inherent in the prior art. First, the present invention eliminates the need to insert tools or measuring devices into the oil well. Omission of the measuring device eliminates calibration shut-down time and also eliminates the probe-introduced disturbance to the fluid flow within the well that was inherent in prior art methods. The present invention utilizes a personal computer having a display device, an entry device, a storage device, and a processor for executing an evaluation program. The evaluation program is capable of reading a geometric profile, including a starting point and an ending point that makes up a predefined geometric volume of the well hole. Along with a geometric profile the evaluation program is also input with stabilized surface test data and fluid property data.

The evaluation program of the present invention is capable of performing a series of functions necessary to calculate the characteristics of the multi-phase fluid flow along the predefined geometry of the well hole. First, the evaluation program divides the geometric profile into a series of discrete segments of a predefined thickness, starting at the wellhead and ending at the last reservoir. Starting at the wellhead, the evaluation program marches, segment by segment, until the end point is reached. At the starting point, the wellhead temperature and pressure, the wellhead geometric profile, the wellhead gas production rate, and the oil, condensate and water production rates are provided. To determine the conditions at the segment just below the wellhead, the evaluation program interpolates the temperature profile to estimate the temperature at that particular segment location. Similarly, the geometric profile is interpolated to determine the geometric configuration of the segment at that particular location in the fluid conduit. Using the total flow rate at the previous step (in this case, at the wellhead), an estimated pressure is calculated for that particular segment. The estimated pressure, estimated temperature, estimated geometry are used to calculate an estimated total flow rate of the fluid in the well hole at that particular location. These estimated values are used first to correlate the phase segregation of the fluid at that segment, and secondly as the initial values for the next segment farther down the well hole. These steps are repeated until the end point of the well hole is reached.

This method is also useful for estimating the phase segregation of the fluid in the well. Once the phase segregation can be determined at each step within the well geometry, the constituent flow rates of the gas, water, and oil can also be calculated. These velocity rates are useful in determining if apparent flow rate losses are due to liquid drop-out (retrograde condensation) of the gas. Furthermore, apparent fluid flow losses or gains at particular steps can be attributed accurately to thief zones or production zones, respectively.

FIG. 1 shows a computer system of the present invention;

FIG. 2 shows a conventional well hole;

FIG. 3 shows a flowchart of the method of the present invention;

FIG. 4 shows a conventional well hole that is divided into segments; and

FIG. 5 shows a segment of a fluid conduit.

The method of the present invention utilizes stabilized surface test data and determines fluid properties at the points of influx or efflux in the flow conduit (well hole). The fluid in question can be from any well through which gas and at least one other liquid phase is being commingled and produced. Such a fluid is called a multi-phase fluid. The method of the present invention applies to any well producing either of the following combinations of fluids:

a) gas, oil, and water;

b) gas and oil,

c) gas and water,

d) gas, condensate, and water, or

e) gas and condensate.

This method does not apply to either dry gas well or dead oil wells. In addition, the method of the present invention does not apply to wells on rod pumps where the fluids are separated and the wellhead pressure is near atmospheric pressure.

The method of the present invention determines the flow properties and information such as the depth of production zones (influx) and the depth of thief zones (efflux). The present invention also determines the productivity indexes (PI) or injectivity index (II) of the zones. Points of influx are normally attributed to the following: productive zone, points of liquid channeling into the flow conduit, liquid "drop out" in a gas well, gas injection in a continuous flow gas lifted well, and lift points for a well with an electric submersible pump or hydraulic pump. Points of efflux are normally attributed to the following: thief zones and leaks in the flow conduit.

To perform the method of the present invention, three categories of data are needed:

1) stabilized surface production test data,

2) fluid property data, and

3) the flow conduits geometric profile data.

The stabilized surface test data required by the present invention is taken regularly on a producing well, typically at the wellhead. The stabilized surface test data that is needed for the present invention includes:

a) the wellhead pressure,

b) the gas production rate, and

c) the oil, condensate, and water production rates.

The use of stabilized surface test data (wellhead data) is preferred because the data are much less expensive to obtain than inserting probes into the fluid conduit. Furthermore, unlike the prior art probe insertion method, no well down-time is required for the method of the present invention.

The required fluid property data for the method of the present invention comprises:

a) the API gravity of oil or condensate,

b) the specific gravity of water (if any),

c) the specific gravity of the gas produced,

d) the wellhead temperature, and

e) the bottomhole temperature.

The method of the present invention divides the flow conduit into a series of segments. Geometric profile data are needed at each segment. The data needed for each segment includes:

a) the true vertical depth,

b) the measured depth, and

c) the internal diameter (used to calculate the cross-sectional area).

Generally, these data are provided at specific points along the fluid conduit. Data for points in between are interpolated using common algorithms.

The method of the present invention is best accomplished with the use of a digital computer. A software program that embodies the steps proscribed herein is executed on the digital computer to achieve the desired results. As shown in FIG. 1, the computer system comprises a personal computer 30. The average personal computer produced today is sufficient for these purposes. Connected to the computer 30 is a display monitor 32 that is capable of displaying the results from the software program. A keyboard 34 and/or mouse 38 are used to input the data about the well. Optionally, a printer 36 is also connected to the computer 30 so that hard copies of the results from the software program can be produced. In the preferred embodiment of the present invention, a sufficient amount of storage capacity is included with the computer 30 to store all of the fluid information at each segment along the well. The stored information about each segment, along with the input data, can then be presented on display 32 or printed on printer 36.

FIG. 2 shows a typical oil and gas well. The well 10 is composed of a reservoir 28 that contains the desired fluid (usually oil and/or natural gas). Pipe 26 is drilled into the ground until it reaches reservoir 28. Once drilled, pipe 26 acts as a conduit to remove the fluid from the reservoir 28. There may be multiple reservoirs along the well 10.

As shown in FIGS. 3 and 4, the extracted fluid flows from the reservoir 28 to the wellhead 20. An out-take pipe 24 takes the fluid from the wellhead 20 to the separator 22 where the multi-phase fluid is separated into its constituent elements, namely oil, water, and gas. The geometric profile of a typical segment is shown in FIG. 5. Referring to FIG. 5, the geometric profile for each segment comprises the internal diameter 43, the measured depth 42, and the true vertical depth 40. As shown in FIG. 4, the wellhead is defined by the cross sectional area of the well along the hole running from the starting point 21 (typically at the wellhead 20) and the ending point 23 (typically at the last reservoir 28). This cross-sectional area at any given point along the well is designated by the symbol "A." The set of areas along the well hole is designated by the symbol "G." The cross-sectional area usually known at several points along the well. The geometric profile is considered to be predefined for purposes of the present invention and constitutes one set of the input data values. An estimated value of A at any point along the well can be estimated by using standard straight-line or curve interpolation algorithms with G as input to the interpolation algorithm.

As with the geometric profile, the temperature profile of the well from the starting point 21 to the ending point 23 is usually well known. For purposes of this disclosure, the temperature at any given point along the well is designated by the symbol "T." The set of temperature data along the well hole is designated by the symbol "H." The temperature profile H is considered to be predefined for purposes of the present invention and constitutes one set of the input data values. An estimated value of T at any point along the well can be estimated by using standard straight-line or curve interpolation algorithms with H as input to the interpolation algorithm.

Two other parameters, in addition to the temperature T and area A, define the characteristics of the fluid at any given point in the well. Those two parameters are the pressure (designated by the symbol "P") and the total fluid flow rate (designated by the symbol "W.sub.t "). The total fluid flow rate W.sub.t is defined by the following formula:

where W.sub.o is the flow rate of oil, W.sub.w is the flow rate of water, W.sub.gf is the flow rate of free gas, and W.sub.gs is the flow rate of the gas that is in solution. Typically, the pressure and total flow rate are known only at the wellhead. The total flow rate, W.sub.ti, may itself have been calculated knowing the specific gravity of the fluid at the wellhead. The wellhead pressure and the wellhead total flow rate constitute the final two input data values for the present invention.

As shown in FIG. 3, the program is started and the input data values are read in step 102. The input values consist of the temperature profile H, the geometric profile G, the wellhead pressure P.sub.i, and the wellhead total flow rate W.sub.ti. The input data is calibrated in step 104. In the preferred embodiment of the present invention, a user-friendly software program, called a front-end, performs steps 102 and 104 of FIG. 3 and is used to format the input data for the evaluation program.

The technique for the multi-phase flow correlation is defined by Beggs and Brill. See Beggs, H. D. and Brill, J. P., "A Study of Two-Phase Flow in Inclined Pipes," Journal of Petroleum Technology (Many 1973), pp. 607-619, included herein by reference for all purposes. While there are many multi-phase flow correlations in use today, the Beggs and Brill technique was the simplest to program on a digital computer. It will be understood by those of ordinary skill in the art to use other techniques for multi-phase flow correlation without departing from the scope of this invention.

In order to avoid unnecessary calculation of bad data the calibrated data is checked in step 106. If the input data is bad, the program is terminated immediately in step 130. However, if the data is valid, step 108 is executed.

In step 108, the length of the well hole is divided into equal-length sections. Each section is called a segment and each segment is separated, in the preferred embodiment, by 0.01 feet. Shorter segment lengths increase the accuracy of the results. However, segment lengths less than 0.01 feet do not significantly increase the accuracy. Segment lengths much greater than 0.01 feet generally yield inaccurate results. Longer wells require more segments. Consequently, the computer must have sufficient memory to retain data at each segment if such data are requested by the user. According to step 108 of FIG. 3, each segment is assigned a number. As shown in FIG. 4, the first segment (i) is at the wellhead and the last segment (j) is at the last reservoir. The segments are in sequential order, i.e., i, i+1, i+2, . . . , j-2, j-1, j. Segments at any given point along the well hole are designated by the letter "k," e.g., T.sub.k or P.sub.k. Correspondingly, the next segment down-hole after segment k would be segment k+1.

As mentioned previously, the only place where the fluid characteristics are well known is at the wellhead. Thus, T.sub.i, A.sub.i, P.sub.i, and W.sub.ti are used as the initial values and are loaded into the k registers of the evaluation program, T.sub.k, A.sub.k, P.sub.k, and W.sub.tk, respectively (i.e., setting k=i), as shown in step 110 of FIG. 3. The value of k indicates the current segment number.

Given the two surface production tests and other well data PPPM initially calibrates the data to fit the actual well data to the multiphase flow correlation used, which is in the PPPM program the Beggs and Brill correlation, and the various black oil models used. The black oil models used are the more popular ones used and are chosen because of its programming ease. Once calibration is completed the pressure profiles are computed for the surface production tests in the flow conduit. The profiles are computed beginning at the wellhead and moving in an increasing measured depth sequence. The changes in the profiles give indications of points of influx or efflux. Once the last section of flow conduit is reached then PPPM calculations are completed.

Once step 118 is complete, or if W.sub.t(k+1) and W.sub.tk were found to be equivalent in step 116, then step 120 is performed. In step 120, the phase segregation is determined by the multi-phase flow correlation techniques mentioned above. Once the phase segregation is determined, differences between the phases as segment k+1 can be compared to the phase segregation in segment k. These phase segregation differences are used to calculate flow velocities of the various phases, i.e., oil velocity V.sub.o(k+1), gas velocity V.sub.g(k+1), water velocity V.sub.w(k+1) and, finally, the total (average) velocity of the fluid V.sub.t(k+1).

In step 122, a check is made to see whether or not all of the segments have been addressed. If so, the results are output in step 126 either to display 32 and or to the printer 36 and the program is terminated. Otherwise, k is incremented in step 124 and the program is continued at step 112. Execution continues until all segments have been addressed (e.g., k=j).

For standard oil and gas wells, the method of the present invention determines the mid-depth of production or injection for each productive or thief zone. This mid-depth of production or injection should correspond to the mid-perforation depth. If it does not, then formation damage and/or plugging of the fluid conduit perforation is indicated. The method of the present invention also determines the depths of liquid "drop-out" of either condensate or water for a gas well producing water and/or condensate. The latter information is necessary for determining the depth at which artificial lift equipment should be set to prevent liquid loading problems in a gas well that is producing water and/or condensate. It should be noted that the method of the present invention can also distinguish between the "drop-out" of condensate or water, and a productive or thief zone. While the absolute value of the PI or II for each zone is itself meaningless, comparison from zone to zone in the same well, or for the same zone in the same well from time to time, can provide accurate results.

For a well on continuous flow gas lift, the method of the present invention determines the gas injection depth. In addition, the as with the well described previously, the method of the present invention can also distinguish between the "drop-out" of condensate or water and productive or thief zone. This index at each depth of gas injection provides a measure of valve performance as the valve sits in the wellbore. For a well using an electric submersible pump (ESP) or hydraulic jet pump or hydraulic piston pump, this index at pump depth provides a measure of pump performance as the pump sits in the wellbore. Finally, this index for the well at each of its productive zones provides a measure of well productivity which, in the prior art, could be obtained only by pulling the pump to test the productive zones.