HK1017075B - Automatic well test system and method of operating the same - Google Patents

Description

Automatic logging system and operation method thereof

Technical Field

The present invention relates to an automated oilfield separator system for measuring the production of a mixture of components including oil, steam, and water components. More specifically, the separator system utilizes a complementary flow meter, density meter, and water output (water content) probe to measure the production of the respective individual components or phases of the component mixture of the product.

Background

Oil and gas wells reach below the surface of the earth to evacuate the formations that have had recoverable amounts of oil and gas trapped therein. Oil, gas, and water may flow simultaneously from a single producing formation into the well. This multiphase flow of oil, gas and water produces a mixture of components of a product that can be separated into its respective components. It is desirable to separate the component mixture comprising oil and gas water into its individual components because there is typically only oil and gas market and no water market, as this water is typically brine which can cause disposal problems. Oil and gas production is often accompanied by the production of significant amounts of water, as it is commercially feasible to run these wells without the sum of the cost of operating the pump plus the cost of brine treatment exceeding the income of oil and gas sales.

The field is typically spread over a series of well sites which have the right to recover the mineral products. Each well site or group of well sites typically has an operator who manages a given group of wells to produce oil. The operator must obtain well log data to properly manage the wellsite. The well log data includes wellhead pressure data and the corresponding volumetric flow rates of the oil, gas and water components of the component mixtures produced from a single well. The wellsite operator needs logging information to reasonably distribute the total revenue received from each producing well among the various proprietary interests in that well. In addition, the wellsite operator also needs logging information in order to conduct technical research in an attempt to optimize the production performance of the wellsite as a whole. For example, an engineer may choose to shut down an oil well with too high a water production (water content) and convert this well to a water injection well to assist in the ongoing water injection.

Production wells in an oil field or part of an oil field often share a production unit that includes a main production separator, a logging separator, tubing, brine disposal wells and safety control devices. The use of a common or shared production means prevents the operator from spending additional money on the excess equipment.

Logging separators are used to help measure volumetric flow rate information of production material produced from a single well. The measurements include the volumetric flow rates of the respective hydrocarbon water phases, e.g., 95 barrels of water per day, 5 barrels of oil per day, and 6MCF gas per day. Another useful measurement is the 'water yield (water content)' measurement. The term 'water yield (water content)' is defined herein to mean any ratio between the volume of oil and the volume of water in an oil-water mixture. According to the most common use of the word 'water yield (water content)', the well production fluid yield (water content) in the above example is 95% since water makes up 95 barrels of the total amount of 100 barrels of oil water liquid. The term 'water yield (water content)' is sometimes also used to denote the ratio of the total volume of oil produced to the total volume of water produced. The term 'oil output' is meant to denote the volume of oil divided by the sum of the volumes of oil and water. As defined herein, the term 'water yield (water content)' encompasses both of these possible meanings.

The main production separator and the logging separator are each used to separate the respective oil, gas and water components that arrive at the production facility in the form of a mixture of these phases or components. The main production separator receives mixed products from a plurality of wells and separates the products for sale. Logging separators have a low production capacity compared to the main production separator and are used to determine single well productivity. As used herein, the term "phase" refers to the type of fluid that may be present in contact with other fluids, i.e., an oil-water mixture comprising a separate oil phase and a separate water phase. Likewise, the mixture of oil and water comprises a separate gas phase and a separate liquid phase comprising an oil phase and a water phase. The industry term treats a 'two-phase' separator as a separator for separating a gas phase from a liquid phase comprising oil and water. A 'three-phase' separator is used to separate a gas phase from a liquid phase and also to separate said liquid phase into an oil phase and a water phase.

Three-phase separators also require additional valve weir devices compared to two-phase separators and generally have a larger volume to facilitate longer residence times of the product for gravity separation into the corresponding oil, vapor and water components. The use of a three-phase logging separator allows for direct measurement of the separated components. Even in such direct measurements, errors are present, since the water is hardly able to be completely separated from the separated oil component in the production plant. Typically, after most of the water is removed from the oil component using a separator, up to ten percent of residual water is still present in the separated oil component.

Compared to a three-phase separator, a two-phase separator is low cost, much simpler in construction and requires little maintenance. The use of a two-phase separator generally does not allow volume measurements to be obtained directly from the separated liquid (oil and water) components under production conditions. The use of a coriolis flowmeter in combination with a two-phase separator provides a good measure of the volume of oil and water in the liquid phase flowing from the logging separator.

It is known in the industry to measure the amount of water produced (water content) in a produced fluid using a capacitive or resistive probe. The operation of these water yield (water content) monitors is based on the principle that the dielectric constants of oil and water are very different. Thus, the water yield (water content) probe can measure the volume percent of water in the mixed oil water fluid stream. However, the accuracy of the water yield (water content) measurements provided by these monitors is only acceptable if the volume of water is less than 20% to 30% of the volume of the total fluid flow. The accuracy limit of up to 30% is well below the level observed from many wells. For example, a well may have a total fluid production of 99% water. Thus, a water yield (water content) monitor is used to determine the water yield (water content) in the low water content oil component. Water yield (water content) monitors often fail to determine the water content of the material flowing from a two-phase separator because the water content of the total liquid component exceeds the upper accuracy limit of 30%.

Coriolis based mass flow rates must be converted to volume because oilfield products are conventionally sold by volume rather than by mass. Conventional coriolis meters have a variety of capabilities in addition to making mass flow rate measurements. Conventional coriolis mass flowmeters can also be used as a vibrating tube densitometer because the mass flowmeter operates on the principle of a vibrating tube and mass system acting as a spring. These density values are used to convert the total mass flow rate measurement to a volume value. However, this volumetric measurement relates to the total mixed fluid flow.

There are many difficulties in determining the respective mass percentages of oil, gas and water in the total mass fluid flow using a coriolis flowmeter. A coriolis flowmeter may be used to determine a total mass flow rate and assign the total mass flow rate to a corresponding component or phase in the mixed fluid flow. This computational technique is particularly useful in determining the mass distribution of two-phase (e.g., water and oil) fluids. Even so, the technology currently requires laboratory analysis of manually obtained samples in order to provide density data values for volumetric flow rate and water output (water content) calculations.

Us patent 5,029,482 teaches the use of an empirically derived relationship obtained by flowing a mixed gas-liquid fluid stream having known mass percentages of respective gas and liquid components through a coriolis flowmeter. This empirically derived relationship is then used to calculate the percentage of gas and the percentage of liquid in the mixed gas-liquid fluid stream for known gas-liquid percentages as a direct coriolis measurement of the total mass flow rate.

Us patent 4,773,482 teaches that the water fraction of the total oil-water fluid flow can be calculated according to the following equation (1):

(1)X_W＝(D_e-D_o，T)/(D_w，T-D_o，T)，

in which X is_WIs the mass fraction of water in the total mixed oil-water fluid stream; d_eIs the density of the total mixed oil-water fluid flow at the measured temperature T; d_o，TIs the known density of the pure oil component in the total mixed oil-water fluid stream at the measured temperature T; and D_w，TIs the known density of water in the total mixed oil water fluid stream at the measured temperature T. Value D_o，TAnd D_w，TThe temperature effect can be corrected according to equations (2) and (3):

(2)D_o，T＝D_o ^*-C_o(T-Tr)

(3)D_w，T＝D_W ^*-C_W(T-Tr)

in which D is_o ^*Is the oil density at a reference temperature Tr (typically selected to be 60 ° F); d_W ^*Is the density of water at a reference temperature Tr; c_oIs the coefficient of thermal expansion of the oil; c_WIs the coefficient of thermal expansion of water, the remaining variables being as defined above. The coefficient of thermal expansion C will be understood by those of ordinary skill in the art_oAnd C_WAnd other temperature-corrected density relationships can be obtained from a variety of sources, including the american petroleum institute publication.

The total volumetric flow rate is calculated according to equation (4):

(4)Q_e＝M_e/D_e，

in which Q is_eIs the coriolis based mass flow rate resulting from the total mixed oil-water fluid flow; the remaining variables are as defined above.

The volumetric flow rate of oil is calculated according to equation (5):

(5)Q_o＝Q_e(1-X_W)，

in which Q is_oIs the volumetric flow rate of the oil, the remaining variables being as defined above.

Calculating the volumetric flow rate of water according to equation (5):

(6)Q_W＝Q_e ^*X_W，

in which Q is_WIs the volumetric flow rate of water, the remaining variables being as defined above.

Volume flow rate value Q_oAnd Q_WCan be corrected to the standard reference temperature Tr by multiplying the volume flow rate value by the density at the measured temperature and dividing by the density at the reference temperature, as in equation (7):

(7)Q_o ^*＝Q_o，T ^*D_o，T/D_o ^*，

in which Q is_OIs the volumetric flow rate of the oil at a standard reference temperature Tr, Q_o，TIs the volumetric flow rate of oil at temperature T and is calculated according to equation (5); the remaining variables are as defined above.

Due to density value D_o，TAnd D_W，TMust be determined by manually taking a sample from a given production well so there are significant problems in using equations (1) - (7). In the absence of laboratory measurements, it is still not possible to convert the phase mediated mass flow rate information into oil and water volumes, since the coriolis meter cannot generate oil density and water density by direct measurement of the mixed fluid flow. The environment in which the samples are frequently sampled creates a source of error in making laboratory measurements due to the exposure of the samples to atmospheric pressure. Exposure to atmospheric pressure dissipates the gas and the resulting sample has a relatively higher density than the previous sample. Furthermore, it is almost impossible to provide laboratory measurements that reproduce the conditions of the field. The density values of the produced fluids often vary within the life of an oil well. Thus, periodic sampling of the product fluid is required. Thus, performing laboratory measurements can suppress errors and changes in conditions that cannot be reproduced at the production site in the laboratory due to lack of timeliness for fluid sampling.

Direct density measurements from a coriolis meter cannot be used for volume calculations because satisfactory direct density measurements are often not obtained from the oil component alone. Even if a separator is used to separate the oil component from the water component, the separated oil phase still contains up to about 10% water (by volume). Residual water causes errors in direct density measurements.

Another source of inaccuracy in log volumes involves the release of solution gas at reduced pressure. The pressure-volume-temperature behavior of the produced fluids can cause significant differences in the measured amounts of the separated oil and gas obtained from the component mixtures. The reduction in gas pressure will release gas from the oil phase. The gas pressure is increased to drive the gas back into solution. Therefore, it is desirable that the test separator adjust the main production separator to the appropriate condition.

The pressure in the test separator may be different from the pressure in the main production separator. Two-phase logging separators often flash the production fluid by releasing gas from the fluid at a pressure drop created by the liquid being discharged from the separator. There is no effort to control the pressure of the test separator as the liquid is being discharged, since it is generally believed that the separated product components will remix in the main production separator for eventual sale. Failure to control the test pressure will result in erroneous volume measurements because the reduced gas pressure causes the dissolved gas to be released from the oil phase. Therefore, the liquid volume is reduced and the liquid density is greater.

There is a real need for a coriolis based flowmeter that can measure the volumetric flow rate of a corresponding phase or component in a total product stream without the need for laboratory measurements on a manual sample of the product stream in order to provide density values for the corresponding component. Further, there is a need for a test separator system that utilizes either the sales line or the main production separator conditions during the measurement process in order to preserve the integrity of the volumetric measurement data.

Disclosure of Invention

The present invention overcomes the above-identified problems by providing a fully automated coriolis logging system that does not require manual sampling or laboratory analysis of the production fluid to determine the density of the hydrocarbon components. In addition, the test system also eliminates volumetric measurement errors caused by the release of dissolved gas under reduced pressure conditions.

The logging system of the present invention has two modes of operation. The logging system operates as a normal logging system to measure the volume of the respective component separated from the mixture of components (i.e., the wellhead production including the oil, gas, and water components). The logging system also has a specialized density measurement mode that does not require manual collection of a product fluid sample for density measurement. The in situ density measurements obtained by this system are more accurate than laboratory measurements because the fluid measurements are made on-line.

The system includes a test separator that receives the wellhead production and separates the mixture into its individual components. A valve tube is used to selectively fill the logging separator with product from a single well. The logging separator is used to retain a mixture of oil, gas and water phases or constituents while gravity separates the constituents from the component mixture. Opening the drain valve at least partially drains the liquid component of the product component mixture from the logging separator after separation of those respective components. Coriolis flowmeters (including a mass flowmeter and a densitometer) are used to measure the mass flow rate of respective oil and water components as they exit the logging separator. A densitometer is used to obtain a density reading of the separated oil component in the logging separator. An effluent (water content) monitor is used to obtain an effluent (water content) reading of the separated oil phase. In summary, fluid density, temperature, mass flow rate, and water output (water content) measurements are used to calculate the volumetric flow rate of the oil-water component in the product fluid. This correction allows a more accurate calculation of the oil volume flow rate.

In the preferred embodiment, volumetric measurement errors are also minimized by coupling a pressurized gas source to the logging separator. The separator pressure may be maintained substantially constant even when the separator drain valve allows liquid to flow from the logging separator.

According to the above aspect of the present invention, there is provided an automatic well logging system for determining respective components separated from a wellhead production forming a mixture of components: volumes of water, oily emulsion, oil, gas, the system comprising: separation means responsive to receipt of wellhead production and separating said component mixture into its respective components; filling means for filling said separation means with said component mixture to a fill level at which said separation means can separate said component mixture of said wellhead production into their respective components, and discharging means for discharging liquid components of said component mixture of said production from said separation means to a discharge level, said liquid components including an oil component and a water component; the automatic logging system is characterized in that: measuring means for measuring a liquid density value and a mass flow rate value for each of said oil component and said water component as said discharge means discharges said liquid component from said separation means to said discharge level; correcting means for correcting the measured liquid density value of the oil component by adjusting a fluid density value of the water yield of the oil component to provide a corrected oil component fluid density value, wherein the correcting means corrects the measured fluid density value of the oil component using the fluid density value of the water component; and calculating means for calculating a volumetric flow rate corresponding to said oil component using said corrected oil component fluid density.

In the above system, the measuring means comprises a mass flow meter and densitometer for providing the mass flow rate value and the fluid density value.

The discharge means comprises an electronically controllable discharge valve connected to the separator and a controller.

The filling device includes a fluid level indicator coupled to the separator and the controller for indicating the fluid level of the separator to the controller. The charging device may further comprise an electronically controllable valve connected to a source of wellhead production fluid and the separation device.

The measuring device includes a coriolis mass flowmeter, a densitometer, and a water output monitor.

Said filling means and said discharging means include means for repeatedly filling said separating means and discharging said liquid component from said separating means by adding said component mixture to said predetermined fill level.

In accordance with another aspect of the present invention, there is provided an automated logging system operable to measure respective components separated from a mixture of components of a wellhead production: a process for the volume and density of water, oily emulsions, oil, gas, the process comprising the steps of: filling a test separation device with said component mixture to a fill level required to separate said component mixture with said separation device, said component mixture including a water component and an oil component; discharging the liquid component of said component mixture from said separation device to a discharge level; measuring a fluid density value, a mass flow rate value, and a water output value of the respective liquid component after the discharge device discharges the liquid component from the separation device to the discharge level; correcting the fluid density value measured for the oil component by adjusting a fluid density value of an amount of water produced in the oil component to provide a corrected oil component fluid density value; and calculating a volumetric flow rate corresponding to the oil component using the corrected oil component fluid density value and the mass flow rate, wherein the correcting step corrects the measured fluid density value for the oil component using the equation

ρ_O，T＝(ρ_t-ρ_W，TWC)/(1-WC)，

Where ρ is_O，TIs the corrected oil component fluid density at temperature T; rho_tIs the total density of the oil component containing residual water, measured with a densitometer at a temperature T; rho_W，TIs the density of the water component as measured from the separated aqueous phase at temperature T with a densitometer; also WC is the water yield of the separated oil component containing residual water expressed as parts by volume of water in the separated oil component.

In the method of operating an automatic logging system described above, the discharging step is characterized by providing a pressurized gas jacket over the material within the separator to prevent flashing of the material as the liquid component is discharged from the separator.

The method further includes refilling the separator apparatus with the mixture of components after the discharging apparatus discharges the separator apparatus to the discharge level, and repeating the discharging step until a sufficient amount of oil component is obtained to allow the measuring step to be performed.

Other significant features, objects, and advantages will be apparent to those skilled in the art in view of the following discussion in conjunction with the accompanying drawings.

Drawings

FIG. 1 depicts a schematic diagram of an automatic logging system according to the present invention; and

FIG. 2 depicts a flow chart that controls the operation of the system shown in FIG. 1.

Detailed Description

FIG. 1 illustrates an automatic logging system 20. The main components of the system 20 include valve tubing 22 for selectively flowing individual wells, a logging separator 24, a discharge line 26 of a flow rate measurement device for measuring the volumetric flow rate of the product components from the logging separator 24, a housing system 28 for maintaining a constant pressure in the logging separator 24, and an automated system 30. The various components of the logging system 20 may be purchased from different commercial units and assembled together as shown in FIG. 1.

Valve conduit 22 includes a series of valves, such as valve 23. Each valve is connected to a wellhead supply line (e.g., supply line 34) leading to a separate production well (not shown). Each valve is connected to a logging separator supply line, such as line 36 leading to a logging separator input line 38. Each valve is associated with a main process separator input line 40 leading to a conventional main process separator 42. These valves, such as valve 32, are preferably electrically actuated three-way valves with compressed air operated valves that control the inlet to the logging separator line 38 and the main production separator input line 40. Valve 32 is used to direct the production of a single well to either main production separator 42 or logging separator 24. The most preferred three-way valve for this purpose is the Xomox TUFFLINE 037 AXWCB/316 well on-off valve with a MATRYX MX200 actuator. The valves are preferably constructed so that each receives production fluid from a respective individual well. These valves can selectively switch the product fluid to the main production separator input line 40 where it is mixed with fluid from other valves for delivery to the main production separator 42. A single valve may be selected to switch production from its associated well to the logging separator input line 38 for delivery to the logging separator 24.

Logging separator 24 is a conventional logging gravity separator having an oval housing 44 of sufficient strength to withstand logging pressures. The logging separator 24 is provided with an electronic level indicator 46 for indicating the level of all liquids of the automated system 30, including water 48, oil-in-water emulsion 50 and oil 52. Gas 54 resides within the logging separator 24 above the total liquid level. One exemplary type of level indicator 46 is a Fisher Model 249B-2309 Model analog float system level transmitter with a sight glass. Logging separator 24 is connected to a pipeline gas discharge line 56, which preferably includes a draft pressure transmitter 58, such as model 2088 manufactured by Rosemount of EdenPririe, Minnesota. The pipeline gas exhaust line 56 also preferably includes a gas flow meter 60, such as the 8800 sensitive vortex meter stage manufactured by Rosemount of Eden Prairie, Minnesota, or an orifice differential pressure transmitter, such as the 3051 differential pressure transmitter manufactured by Rosemount of Eden Prairie, Minnesota. An electronically controlled gas flow control shut-off valve 62 controls the flow of gas through the gas discharge line 56. For example, valve 62 may be purchased as a V2001066-ASCO type valve manufactured by Fisher of Mashall Town, Iowa. The gas discharge line 56 terminates at the main production separator 42.

The discharge line 26 of the flow measurement device is connected to a discharge point 64 on the logging separator 24. The discharge line 26 of the flow rate measurement device includes a water output (water content) monitor 66 that uses electrical measurements to quantify the water output (water content) of the fluid flowing through the discharge line 26 of the flow rate measurement device. Water and oil have different dielectric constants, which makes it possible to quantify the water yield (water content) using electrical measurements. Other commercially available devices include devices that measure water output (water content) using microwave radiation. A typical water output (water content) monitor 66 is a Drexelbrook Model CM-2 capacitance monitor. The discharge line 26 of the apparatus continues from a water yield (water content) monitor 66 to a liquid flow meter 68. The fluid flow meter 68 preferably comprises a coriolis flow meter (including a mass flow meter, a density meter and a temperature meter) such that mass flow, density and temperature measurements of the material passing through the discharge line 26 of the measuring device are obtained. Exemplary flow meters 68 include ELITE Models CMF300356NU and Models CMF300H551NU, which are commercially available from Micro Motion of boulder, Colorado. The temperature sensor 69 is used to measure the temperature of the fluid within the discharge line 26 of the device. A typical temperature sensor 69 is a Model 68 sensor manufactured by Rosemount of Eden Prairie, Minnesota. The sampling port 70 is a manual valve provided for obtaining a sample within the line 26. An in-line electrostatic mixer 71 is used to ensure that a well-mixed sample is taken from line 26 through port 70.

The discharge valve 72 is preferably electronically controlled and operated by compressed air. The drain valve 72 may be opened to drain the logging separator 24 through the measurement device drain line 26, and the drain valve 72 may be closed to fill the logging separator 24 with product from the valve line 22. A typical discharge valve 72 is a Fisher level control valve Model EZ-667-ASCO valve. The discharge line 26 of the measuring device terminates in a main production separator 42.

The gas jacket system 28 includes a compressed gas source 74, which may be gas from an air compressor or fuel gas from a compressed gas source used to operate the production facility. The gas source 74 may also be the main production separator 42. The gas source 74 flows into a gas supply line 76 that leads to a gas sleeve valve 80. An exemplary valve 80 is a Fisher Model 357-546. Valve 80 preferably operates to maintain a constant pressure within logging separator 24, and if desired, may be in the form of a shut-off for flow through supply line 76. Line 76 terminates at an upper entry point 82 of logging separator 24.

An automated system 30 is used to control the operation of the system 20. The system 30 includes a computer 84 (e.g., an IBM 486-compatible machine) programmed with data acquisition and programming software. A preferred brand of such software is Intellution software DMACS, which is commercially available from Intellution (a subsidiary of Fisher Industries). Such software is particularly desirable because it can issue alarms indicating abnormal logging conditions that represent potentially dangerous mechanical failures. The computer 84 controls the programming of a remote operator controller 86 that includes a series of drivers and interfaces that allow the computer to interact with remote portions of the system 20. A preferred brand for remotely operating the controller 86 is the Fisher Model ROC 364. The controller 86 may also be programmed with software to facilitate the completion of instructions from the computer 84. Valve control leads 88, 90, 92 and 94 connect the controller 86 to the respective electronically controlled valves 32, 80, 72 and 62 for selectively controlling these valves. Leads 96 connect the controller 86 with the pressure transmitter 58. A lead 98 connects the controller 86 with the gas meter 60. A lead 100 connects the controller 86 to the water output (water content) meter 66. Leads 102 connect the controller 86 to a transmitter 104, which in turn is connected to the fluid level gauge 46, the fluid flow meter 68, and the temperature sensor 69 to communicate information to the controller 86. A typical brand of transmitter 104 is the ELITE Model RFT9739 available from MicroMotion of Boulder, Colorado.

FIG. 2 depicts a graphical process control diagram for manipulating the operation of the logging system 20. The process of fig. 2 is controlled by control software in computer 84 or controller 86. Step P200 represents a standard testing mode that may optionally include testing a selected well in two ways, one by adjusting conduit 22 to flow the well's production through test separator 24, and the other by-passing test separator 24 by using valve line 22 to flow all of the production into main production separator 42 without requiring testing.

In step P200, the manager of the well needs to know the oil volume flow rate Q defined by equation (5) above accurately and precisely_OAnd the volumetric flow rate Q of water defined above by equation (6)_W. Calculating these values requires calculating the moisture content, e.g., X as defined above by equation (1)_W. In equation (1), the flow meter 68 can only provide a mixed density reading D_eAlthough a given well is in a test state. Thus, equation (1) relies on laboratory measurements to provide D_O，TAnd D_W，T. As noted above in the background section of the invention, laboratory measurements sometimes lack accuracy and precision because the conditions in the laboratory are inconsistent with the conditions in the test system 20 (e.g., pressure, temperature, and dissolved gas content).

According to the invention, D of formula (1)_O，TAnd D_W，TUsing p of equation (8)_O，TAnd ρ_W，TInstead of:

(8)X_W＝(D_e-ρ_O，T)/(ρ_W，T-ρ_O，T)，

where ρ is_O，TIs the density of the neat oil phase (excluding any residual moisture in the separated oil component), ρ_W，TIs the pure water phase density, with the remaining variables defined above. Variable ρ of equation (8)_{O， T}And ρ_W，TVariable D different from equation (1)_O，TAnd D_W，TThis is because of the variable D_O，TAnd D_W，TIs derived from laboratory measurements made in a flow laboratory based on manually taken samples, i.e., samples taken from system 20 through socket 70. In contrast, the variable ρ_O，TAnd ρ_W，TIt is derived from an on-line measurement, i.e., a measurement of the material in the test system 20 with a flow meter.

The following discussion of step 201-214 describes how ρ is obtained_O，TAnd ρ_W，TOn-line measurement of (a). These values are important because each of the equations (1) to (7) is calculated by using ρ_{O， T}In place of D_O，TAnd by rho_W，TIn place of D_W，TGiving an excellent (more accurate) calculation as is done for equation (1) in the case of equation (8). This replacement improves the accuracy of the calculation since no error prone laboratory measurements need be made for on-line density measurements. In contrast, equation (1) depends on error prone laboratory measurements that do not reflect online status.

The flow meter 68 is preferably programmed to operate by respectively using p_O，TAnd ρ_W，TAlternative D_O，TAnd D_W，TThe calculations according to equations (2) - (8) are completed. These calculations may also be performed using the computer 84 or the controller 86.

These variables ρ must be updated periodically_O，TAnd ρ_W，TSince these values vary over the lifetime of the production well. Thus, the process of fig. 2 includes a temperature measurement mode starting at step P201. In step P201, the computer 84 causes the controller 86 to activate a valve (e.g., valve 32) in the line 22. The actuation of the valve will be from a selected oneThrough which the well material fluid is transferred to the test separator 24. If the well is already in communication with the test separator 24, there is no need to activate the valve, however, it is often advantageous to enter the density measurement mode before entering the actual logging.

In step P202, the controller 86 opens the discharge valve 72 and the material fluid from valve 32 flows through the test separator 24 and the measurement device discharge line 26 into the main production separator 42. Controller 86 uses liquid flow meter 68 to measure the total volume of liquid sufficient to fill the portion of collection line 38, test separator 24, and measurement device drain line 26 prior to flow meter 68. This volume of fluid flows through test separator 24 but cannot fill test separator 24 because discharge valve 72 is in an open state. This multiple of volume may optionally be used to ensure that the test separator 24 can be adequately replaced with fluid from another well that cannot flow through the valve 32. The emptying operation of such volumetric test separators is significantly better than conventional separator emptying cycles which rely on the flow time to empty the separator. A time-dependent drain cycle may result in the separator not being drained sufficiently and the experimental measurements are ultimately made on the fluid from that wrong well. The volume drainage ensures that the experimental measurements are ultimately made on the fluid from that correct well.

In step P204, the controller 86 closes the drain valve 72 to fill the test separator 24 with liquid. At the same time, valve 32 is allowed to continue to flow material into test separator 24 until the level indicator provides controller 86 with a fill level that has been reached by the liquid in test separator 24. The fill level is preferably predetermined by the well manager and the controller 86 or computer 84 may be programmed to fill the test separator 24 to a different level for each producing well. The optimal fill level for each well is determined empirically in the field. The fill level is preferably referenced to the total level, but may also be referenced to the oil or water level if a weighted float is used in the level indicator 46. The gas flow meter 60 measures the volumetric flow of gas exiting the test separator 24 during filling while the gas flow control shut-off valve 62 is adjusted by the controller 86 if necessary to maintain the material in the test separator at a substantially constant pressure. The gas flow meter 60 provides a signal to the controller 86 indicative of the volume of gas flowing through the gas discharge line 56.

When the controller 86 receives a signal indicating that the test separator 24 is full, the controller 86 causes the valve 32 to divert its product to the main production separator 42. The controller 86 also closes the air sleeve valve 80 and the air flow control shut-off valve 62, sealing the material in the test separator 24. The material in the test separator 24 can settle while gravity separates the oil, gas, and water, respectively, of the material in the test separator. The waiting period for gravity separation may be based on a sufficiently long time, for example 30 minutes, as indicated by experience in the art. During an initial installation phase of the system 20, an operator may observe the separation within the test separator 24 through a window in the level indicator 46. The time required for the separation is supplied as programmed control data to the computer 84. The material in the test separator 24 is allowed sufficient time for gravity to cause the different materials to stratify. This stratification phenomenon need not occur in a two-phase separator because the separator is only designed to measure two-phase (gas and total liquid) fluids.

The fill level in the test separator 24 during gravity separation is preferably distributed in the range of about 60% to about 80% of the internal volume of the separator. The discharge level preferably drops to about half the internal volume of the separator. The respective fill and drain levels of the test separator 24 are preferably different for each well and may be programmed into the computer 84. For example, a well producing at high water production (water content) and low production rates with minimal associated gas is preferably accompanied by high fill levels and low drain levels in order to optimize the oil production volume within the separator. In comparison, wells producing at high gas-to-oil ratios and high oil volume rates preferably have low fill levels and drain volumes down to a drain level to allow separation of the gas phase while eliminating the need for a large drain volume to remove the separated water phase below the reservoir.

At step P206, after controller 86 determines that the material inside test separator 24 is sufficiently separated, controller 86 opens discharge valve 72 to discharge the material in test separator 24 into main production separator 42 through measurement device discharge line 26. Valves 32 and 62 remain closed. The volume of material discharged from the test separator 24 preferably remains small, e.g., less than about 5% of the total volume of the separator (5 barrels in a 100 barrel volume separator). This small drain volume allows for rapid refill of the test separator 24 if it is desired to obtain accurate logs of the daily rate of the well.

Step P208 includes obtaining a measurement of the material discharged through line 26. The controller 66 receives a signal from a water yield (water content) monitor 66 indicative of the water yield (water content) of the liquid flowing through the discharge line. Likewise, the controller 86 receives mass flow rate and density signals from the liquid flow meter 68. These signals may be converted to volumetric flow rates on the flow meter 68 or computer 84. The controller 86 receives a temperature signal from the temperature sensor 69. When controller 86 receives a minimum level from level indicator 46 indicating that the liquid component is being discharged from test separator 24 to avoid introducing gas into measurement apparatus discharge line 26, controller 86 closes discharge valve 72. The flow meter 68 measures the density of the separated material flowing from the test separator 24. Water density (. rho.)_W，T) Is measured from the water layer 48 and is at its maximum density compared to the other components. This measurement is made for substantially pure water because the water component is substantially free of oil. The oil-in-water emulsion 50 typically causes large deviations in the density measurements, and these values are ignored. The omitted oil-in-water emulsion is also characterized by a density less than that of water and greater than that of oil. The density measurement of the oil-in-water emulsion 50 is omitted. The oil layer 52 has the lowest density. Density measurement (ρ) of the oil layer 52_t) A correction for residual water content must be made because it usually contains up to about ten percent water.

The measured oil density is corrected for the water content according to the following equation (9):

(9)ρ_O，T＝(ρ_t-ρ_W，TWC)/(1-WC)，

where ρ is_O，TIs the water corrected oil density at temperature T; rho_tIs the density of the oil component from which water was extracted as measured by flow meter 68 at temperature T; rho_W，TIs the density of the water component as measured from the separated aqueous phase at temperature T using flow meter 68; also WC is the water yield (water content) of the oil component as expressed in volume fraction of water in the gravity separated oil component that escapes test separator 24. WC is measured by a water yield (water content) monitor 66. It should be noted that an accurate water yield (water content) reading can be obtained by means of the water yield (water content) monitor 66, since the water yield (water content) in the separated oil component typically does not exceed 10%. The value rho_O，TX used in formula (8), and X in formula (8)_WThe values are used in combination with equations (2) - (7) to make the volumetric flow rate calculations.

During step P208, it is desirable to maintain a constant pressure in the test separator 24, since excessive or insufficient pressure can cause errors in the volumetric flow rate and density measurements due to gas being released or absorbed by the separator liquid in response to abnormal changes in pressure. Controller 86 monitors the signals from pressure transmitter 58 and uses these signals to maintain a constant pressure inside test separator 24. The controller 86 adjusts the valve 80 to supply additional gas as needed to compensate for the pressure drop created by the expansion of the gas that occurs as compensation liquid is removed from the test separator 24. The pressure inside the test separator 24 is preferably maintained at or slightly above the pressure of the main production separator 42. A small amount of additional pressure (e.g., +10psi) facilitates the flow of liquid through the discharge line 26 and into the main production separator 42 without causing significant volumetric errors. The pressure inside the test separator 24 is typically distributed in a range from 200 + -20 psi to 1500 + -20 psi, but can be any pressure required by the environment.

At step P210, computer 84 determines whether the amount of oil measured by liquid flow meter 68 is an amount sufficient to obtain an accurate reading therefrom. It is preferable to close the valve 32 for a very short period of time so as not to interrupt the stand-by flow characteristics of the production well with significant pressure drop and rise cycles. Therefore, the emission test separator 24 that appears in step P208 is preferably limited to a relatively small volume for a total production of 1 to 3 barrels. Preferably, the controller 86 generates a threshold volume, such as 100 barrels, before the test is completed. The volumetric measurement is made during the entire time that the well actually discharges crude oil. If the cumulative amount of well test fluid is not sufficient, control transfers to step P212, which repeats the flushing and draining cycle until a sufficient amount of oil is available for measurement. In this case, a signal is received from the level indicator 46 to indicate that the water discharge has reached a minimum level at which oil is not drained from the test separator until steps P202 and P208 are repeated a sufficient number of times to obtain a measurable amount of oil. This feature of the process avoids the need for a manager to purchase an oversized test separator simply to get a sufficient amount of oil for measurement. Once a sufficient amount of oil is available for measurement, step P210 transfers control to step P214.

Step P214 includes returning control to the density measurement mode of step P201. The cycle is preferably repeated until density measurements are obtained from all of the production wells connected to the pipeline 22. In addition, step P214 may return control to step P200 for logging.

The logging information obtained from the above process includes water production (water content) data, gas volumetric flow rate, oil volumetric flow rate, water volumetric flow rate, oil density, water density, separator temperature, and separator pressure. The computer 84 stores the data for transmission to the manager. In addition, the data can be transmitted to the manager by radio connected to a computer. Advantageously, the system may be more frequent and accurate than logging manually by pump operators in the field. Coriolis flowmeter (including a flowmeter and densitometer) is particularly preferred for use as the flowmeter 68 due to its inherent accuracy and reliability.

Of course, there are many sources of the market for the corresponding materials listed above. For example, there are several potential sources for electronically controlled three-way valves (e.g., valve 32), water production (water content) monitors (e.g., monitor 66), and liquid level indicators (e.g., indicator 46). The fact that the applicant has identified the most desirable market sources does not limit the practice of the invention to items obtained solely from these sources, since one of ordinary skill in the art can readily find substantially equivalent materials from other sources and replace them with one of ordinary skill in the art. Further, the test separator 24 may be a conventional three-phase separator having a series of internal floats and discharge ports for discharging the respective phases. In this case, a separate liquid flow meter is required for each discharge line. In this application, the term 'oil' includes gas well condensate. The oil well does not have to produce oil, water and gas, it is only necessary that the wellhead product comprises a mixture of these different phases.

Claims (10)

1. An automatic well logging system (20) for determining the volume of respective component water (48), oil emulsion (50), oil (52), gas (54) separated by a wellhead production that forms a mixture of components, the system comprising:

a separation device (24) responsive to receipt of wellhead production and separating said component mixture into its respective components;

filling means for filling said separation means with said component mixture to a fill level at which said separation means can separate said component mixture of said wellhead production into their respective components (48, 50, 52, 54), and discharging means for discharging liquid components (48, 50, 52) of said component mixture of production from said separation means to a discharge level, said liquid components including an oil component (52) and a water component (48);

the automatic logging system is characterized in that:

measuring means for measuring a liquid density value and a mass flow rate value for each of said oil component and said water component as said discharge means discharges said liquid component from said separation means to said discharge level;

correcting means for correcting the measured liquid density value of the oil component by adjusting a fluid density value of the water yield of the oil component to provide a corrected oil component fluid density value, wherein the correcting means corrects the measured fluid density value of the oil component using the fluid density value of the water component; and

calculating means for calculating a volumetric flow rate corresponding to said oil component using said corrected oil component fluid density.

2. The system of claim 1 wherein said measuring means comprises a mass flow meter and densitometer for providing said mass flow rate value and said fluid density value.

3. The system of claim 1, wherein said discharge means includes an electronically controllable discharge valve (72) connected to said separator and a controller (86).

4. The system of claim 3, wherein said filling device includes a fluid level indicator (46) connected to said separator and said controller (86) for indicating said fluid level of said separator to said controller (86).

5. The system of claim 1, wherein said charging means includes an electronically controllable valve (32) connected to a source of wellhead production fluid and said separation means.

6. The system of claim 1, wherein said measuring means comprises a coriolis mass flowmeter, a densitometer, and a water output monitor (66).

7. A system according to claim 1, wherein said filling means and said discharging means include means for repeatedly filling said separating means and discharging said liquid component from said separating means by adding said component mixture to said predetermined fill level.

8. A method of operating an automatic logging system to measure the volume and density of respective components water (48), oily emulsion (50), oil (52), gas (54) separated from a mixture of components of a wellhead production, the method comprising the steps of:

filling a test separation device (24) with the component mixture (48, 50, 52, 54) to a fill level required for separation of the component mixture with the separation device, the component mixture including a water component (48) and an oil component (52) (P204);

discharging a liquid component (48, 50, 52) of said mixture of components from said separation device to a discharge level (P206);

measuring a fluid density value, a mass flow rate value and a water output value (P208) of the respective liquid component after the discharge device discharges the liquid component from the separation device to the discharge level;

correcting said fluid density value measured for said oil component by adjusting a fluid density value of water yield in said oil component to provide a corrected oil component fluid density value (P210); and

calculating a volumetric flow rate (P200) corresponding to the oil component using the corrected oil component fluid density value and said mass flow rate,

characterized in that said correction step corrects the fluid density value measured for said oil component using the following formula

ρ_O，T＝(ρ_t-ρ_W，TWC)/(1-WC)，

Where ρ is_O，TIs the corrected oil component fluid density at temperature T; rho_tIs the total density of the oil component containing residual water, measured with a densitometer at a temperature T; rho_W，TIs the density of the water component as measured from the separated aqueous phase at temperature T with a densitometer; also WC is the water yield of the separated oil component containing residual water expressed as parts by volume of water in the separated oil component.

9. The method of operating an automatic well logging system according to claim 8, wherein said discharging step is characterized by providing a pressurized gas jacket (28) over the material within said separator to prevent flashing of said material as said liquid component is discharged from said separator.

10. A method of operating an automatic well logging system according to claim 9, further comprising step P212, which comprises refilling said separator means with said mixture of components after said discharging means discharges said separator means to said discharge level, and repeating said discharging step until a sufficient amount of oil component is available to allow said measuring step.