BACK ALLOCATION METHOD

Description

1. TECHNICAL FIELD

The present disclosure relates to improved methods and a system for determining at least one hydrocarbon fluid flow rate of at least one of a plurality of wells connected to a common pipeline, a computer program for performing said methods and a non-transitory computer readable medium for performing said methods. Further, the present invention relates to a control unit for determining at least one hydrocarbon fluid flow rate of at least one of a plurality of wells connected to a common pipeline and an oilfield comprising said control unit being operated according to said methods.

2. PRIOR ART

When operating wells of a hydrocarbon reservoir, e.g. an oilfield or gasfield, several wells are regularly connected to a common pipeline such that they have a combined, i.e. comingled, output which is measured. One of the reasons for this is that hydrocarbon reservoirs are often located in remote regions and the wells share one pipeline for transferring the output, which includes hydrocarbon fluid, to a location of further processing. Another reason is that the wells of a hydrocarbon reservoir often share the same local processing infrastructure which requires the output of the wells to be merged.

Since several wells are regularly connected, such that they have a combined output, it is difficult to precisely define the output rates of the individual wells. This applies particularly, since most existing wells are not equipped with measuring equipment which would allow for a continuous monitoring of the output of the single wells. Even further, individual wells often simply cannot be continuously measured, e.g. due to their configuration and/or interdependencies with other wells.

However, it is of high importance to precisely and/or constantly define the output rates of the individual wells. This is as based on these output rates, which, besides hydrocarbon fluid flow rates, may include gas flow rates and/or water flow rates, the operating parameters of the individual wells are adjusted if necessary. This may serve to sustain efficiency and/or avoid stress on components of the wells. Further, the precise output rates of the individual wells may be of interest from an economic point of view. Exemplarily, if wells of an oilfield being connected to a common pipeline have different shareholders.

Presently, it is regularly practiced conducting tests at the individual wells in regular or irregular time intervals. Based on this historic test data and the often continuously measured combined output of the wells, it is concluded on the output of the individual wells. Thereby interdependencies between different output rates, such as hydrocarbon fluid flow rates, gas flow rates and water flow rates, are regularly not considered. Thereby significant inaccuracies for the output rates of the individual wells are generated.

Moreover, it has shown that the use of artificial intelligence to define the output rates of the individual wells based on historic individual well test data and the measured combined output of the wells is limited therein that machine learning solutions mostly rely on accurate training data which often cannot be provided, particularly not in sufficient quantity and/or quality.

Thus, it is an object of the present disclosure to provide at least one method and a system that overcome the aforementioned drawbacks at least partially. It is also an object underlying the present invention to provide a computer program for performing said method(s) and a non-transitory computer readable medium for performing said method(s). Further, it is also an object underlying the present invention to provide a respective control unit and an oilfield comprising said control unit being operated according to said method(s).

3. SUMMARY OF THE INVENTION

This object is achieved, at least partly, by methods, particularly computer-implemented methods, a system, a computer program, a non-transitory computer readable medium and an oilfield as defined in the independent claims. Further aspects of the present disclosure are defined in the dependent claims. Since the methods and the system relate to determining at least one hydrocarbon fluid flow rate of at least one of a plurality of wells connected to a common pipeline with a comingled fluid flow from the plurality of wells, it will be understood that advantages and/or features of the methods may also apply to the system and vice versa.

In particular, the object of the present disclosure is at least partly achieved by a first method, which may be a computer implemented method, for determining at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of a plurality of wells connected to a common pipeline with a comingled hydrocarbon fluid flow from the plurality of wells to adapt at least one operating parameter of at least one well of the plurality of wells.

The wells of the plurality of wells may be oil wells and/or natural gas wells. The plurality of wells may form part of an oilfield and/or a natural gas field. The common pipeline may comprise a pipe, a tube, a channel, and/or any other flow guiding means.

Further, it is understood that the common pipeline may comprise multiple parallel pipes and/or any other flow guiding means. This may be required if a single pipeline has not enough capacity for the comingled hydrocarbon flow.

Throughout the present disclosure an “i” within any formula and/or formula symbol represents an integer value which corresponds to one well of the plurality of wells.

Exemplarily, the hydrocarbon fluid flow rate, Q_i^HC, of the fourth well (i=4) of a plurality of wells may be expressed as Q₄^HC. Moreover, in the present disclosure “n_w” represents the total number of wells of the plurality of wells.

Hydrocarbon fluids according to the present disclosure are fluids which comprise at least one type of hydrocarbon. Thereby the hydrocarbon fluids may be in a liquid state. Exemplary hydrocarbon fluids according to the present disclosure may comprise oil, e.g. crude oil, and/or liquid natural gas. Further exemplary hydrocarbon fluids according to the present disclosure may comprise co-produced non-hydrocarbons, such as water.

The first method comprises the step of receiving commingled-flow measurement data from at least one sensor, wherein the commingled-flow measurement data are representative of a comingled hydrocarbon fluid flow rate, Q_field^HC. The at least one sensor may be a flow sensor. Thereby the at least one sensor may be attached to the common pipeline. Optionally, the at least one sensor may be configured to determine when a reservoir with a specified volume is filled up to a predefined volume.

The term wherein “data are representative of” particular values according to the present disclosure describes that from the data the respective values can be determined. Hence, the commingled-flow measurement data may exemplarily comprise a volume of a hydrocarbon fluid and a time interval during which this volume passed through a portion of the common pipeline. Thus, these data are representative of the comingled hydrocarbon fluid flow rate, Q_field^HC.

Flow rates according to the present disclosure may by described in volume per time unit. Further, flow rates according to the present disclosure may by described in mass per time unit. Exemplary time units for flow rates are a year, a month, a week, a day, an hour, a minute, and/or a second.

The commingled-flow measurement data are optionally further representative of at least one of the following: a comingled gas flow rate, Q_field^Gas, and a comingled water flow rate, Q_field^Water. Gas according to the present invention is gaseous. Exemplary, gas according to the present disclosure may be natural gas. Particularly, gas according to the present disclosure may comprise methane, ethane, propane, butane, pentane, carbon dioxide, and/or nitrogen. Water according to the present disclosure may comprise sediments, sand, sludge, and/or any other soil components.

Further, the first method comprises the step of accessing historical well test data, wherein the well test data are representative of test hydrocarbon fluid flow rates, Q_i^{test HC}, of the ones of the plurality of wells, wherein the well test data are optionally further representative of at least one of the following: test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells, wherein the well test data are derived from past well tests at the ones of the plurality of wells.

The historical well test data may be derived from a historical test data storage means, such as a test database. Further, the past well tests may be experiments which were conducted at the individual wells. Moreover, the past well tests at the ones of the plurality of wells may be at least partially based on well simulations. Preferably, the historical well test data comprise test hydrocarbon fluid flow rates, Q_i^{test HC}, test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and test water-to-hydrocarbon-fluid ratios, WOR_i^test, for each well of the plurality of wells.

The test hydrocarbon fluid flow rate, Q_i^{test HC}, may describe a volume of hydrocarbon fluid, e.g. oil, which is derived from one of the plurality of wells per time unit. The time unit underlying the test hydrocarbon fluid flow rate, Q_i^{test HC}, may be the duration of a past well test.

The test gas-to-hydrocarbon-fluid ratio, GOR_i^test, may be represented by a test gas flow rate, Q_i^{test Gas}, and the test hydrocarbon fluid flow rate, Q_i^{test HC}. Hence, the test gas-to-hydrocarbon-fluid ratio, GOR_i^test, may be obtained by dividing the test gas flow rate, Q_i^{test Gas}, by the test hydrocarbon fluid flow rate, Q_i^{test HC} However, the test gas-to-hydrocarbon-fluid ratio, GOR_i^test, may be also directly measured.

The test water-to-hydrocarbon-fluid ratios, WOR_i^test, may be exemplarily represented by a test water flow rate, Q_i^{test Water}, and the test hydrocarbon fluid flow rate, Q_i^{test HC} Hence, the test water-to-hydrocarbon-fluid ratio, WOR_i^test, may be obtained by dividing the test water flow rate, Q_i^{test Water}, by the test hydrocarbon fluid flow rate, Q_i^{test HC}. However, the test water-to-hydrocarbon-fluid ratio, GOR_i^test, may also be directly measured.

The data representative of the test hydrocarbon fluid flow rates, Q_i^{test HC}, the test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and/or the test water-to-hydrocarbon-fluid ratios, WOR_i^test, may be obtained from one well test. This allows for an accurate relationship between said values.

Moreover, the first method comprises the step of determining, based on Lagrange multipliers, at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of the plurality of wells using the received commingled-flow measurement data and the accessed historical well test data.

Typically, the hydrocarbon fluid flow rates, Q_i^HC, of each well of the plurality of wells are determined. However, also the hydrocarbon fluid flow rates, Q_i^HC, of a part of the plurality of wells may be determined. Moreover, the step of determining may be conducted using an optimizer unit adapted to run an optimization program based on Lagrange multipliers.

The use of Lagrange multipliers is a strategy for finding the local maxima and/or minima of at least one function, i.e. an objective function, subject to at least one equality constraint, i.e. a constraint function. Hence, the use of Lagrange multipliers may serve to minimize the difference between the at least one hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}. Thereby, the use of Lagrange multipliers allows to take into account relations between hydrocarbon fluid flow rates, Q_i^HC, gas-to-hydrocarbon-fluid ratios, GOR_i, and/or water-to-hydrocarbon-fluid ratios, WOR_i. Accordingly, the at least one hydrocarbon fluid flow rate, Q_i^HC, may be determined with improved accuracy.

In summary, the use of Lagrange multipliers allows to link hydrocarbon fluid flow data with secondary well-test data, such as gas-to-hydrocarbon-fluid ratios and/or water-to-hydrocarbon-fluid ratios. Hence, more accurate values may be obtained. Further, values being more consistent with the test values may be obtained.

Furthermore, the first method comprises the step of adapting at least one operating parameter of at least one well of the plurality of wells, wherein adapting is at least partially based on the at least one determined hydrocarbon fluid flow rate, Q_i^HC, of the at least one of the plurality of wells.

Adapting at least one operating parameter of at least one well means that the at least one well is controlled. For example, based on the at least one determined hydrocarbon fluid flow rate, Q_i^HC, a pumping rate of the at least one well may be adjusted to increase efficiency and/or to reduce stress on components of the well. Moreover, a gas injection rate for a gas lift well may be adapted to improve efficiency of the utilized gas.

Furthermore, the wellhead pressure may be adjusted to reduce stress on components of the well. Hence, since the at least one hydrocarbon fluid flow rate, Q_i^HC, can be determined with improved accuracy, also the efficiency may be improved more accurately. Moreover, the stress on the components of the well may be precisely reduced. This allows resources to be used more efficiently and/or repairs to be avoided.

Further particular, the object of the present disclosure is at least partly achieved by a second a method, which may be a computer-implemented method, for determining at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of a plurality of wells connected to a common pipeline with a comingled hydrocarbon fluid flow from the plurality of wells. It will be understood that the details described in reference to the first method may also apply for the second method.

The second method comprises the step of receiving commingled-flow measurement data from at least one sensor, wherein the commingled-flow measurement data are representative of a comingled hydrocarbon fluid flow rate, Q_field^HC, wherein the commingled-flow measurement data are further representative of at least one of the following: a comingled gas flow rate, Q_field^Gas, and a comingled water flow rate, Q_field^Water. Further, the second method comprises the step of accessing historical well test data, wherein the well test data are representative of test hydrocarbon fluid flow rates, Q_i^{test HC}, of the ones of the plurality of wells, wherein the well test data are further representative of at least one of the following: test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells, wherein the well test data are derived from past well tests at the ones of the plurality of wells. Furthermore, the second method comprises the step of determining, based on Lagrange multipliers, at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of the plurality of wells using the received commingled-flow measurement data and the accessed historical well test data.

It is to be understood, that individual method steps of the first and the second method can be combined. For example, a method step described with respect to the first method can be part of the second method, or vice versa. The following description refers to the first and the second method.

The methods described above may further comprise the step of identifying the ones of the plurality of wells for which the difference between the at least one determined hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}, exceeds a predefined threshold value. Thus, it is possible to identify wells which exhibit significant deviations between the at least one determined hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}. This allows for improved monitoring of the plurality of wells. Exemplarily, the identified wells may be selected for further investigation and/or operating parameter adaption.

Further, determining the at least one hydrocarbon fluid flow rate, Q_i^HC, may comprise using at least one uncertainty value for at least one of the plurality of wells, wherein preferably the at least one uncertainty value is at least partially based on a measurement error of the well test data. The use of uncertainty values allows a weighing of test data in dependence of an increased uncertainty. Hence, accuracy may be increased. The increased uncertainty may exemplarily arise from test data whose acquisition already lies longer in the past. Further, the at least one uncertainty value, w_i, may be defined as

1 σ 2 ,

wherein σ² represents a measurement error. Further, at least one uncertainty value, w_i^HC, may relate to a test hydrocarbon fluid flow rate, Q_i^{test HC}. Moreover, at least one uncertainty value, w_i^Gas, may relate to a test gas-to-hydrocarbon-fluid ratio, GOR_i^test. Furthermore, at least one uncertainty value, w_i^Water, may relate to a test water-to-hydrocarbon-fluid ratio, WOR_i^test. Thereby differences in uncertainties for the different test values may be considered which allows to further increase the accuracy of determining the at least one hydrocarbon fluid flow rate, Q_i^HC. Hence, also the adaption of at least one operating parameter of the at least one well may be conducted more precisely.

Moreover, determining the at least one hydrocarbon fluid flow rate, Q_i^HC, of the at least one of the plurality of wells may be based on a Lagrangian function that comprises at least one objective function and at least one constraint function, wherein the Lagrangian function optionally comprises two objective functions and at least two constraint functions, wherein the Lagrangian function further optionally comprises at least three objective functions and at least three constraint functions, wherein the Lagrangian function even further optionally comprises exactly three objective functions and exactly three constraint functions.

By means of at least two objective functions and at least two constraint functions the relation between at least one hydrocarbon fluid flow rate, Q_i^HC, and at least one gas-to-hydrocarbon-fluid ratio, GOR_i, or at least one water-to-hydrocarbon-fluid ratio, WOR_i, may be taken into account. Hence, the at least one hydrocarbon fluid flow rate, Q_i^HC, may be determined more accurately. Further, by means of at least three or exactly three objective functions and at least three or exactly three constraint functions the relation between at least one hydrocarbon fluid flow rate, Q_i^HC, and at least one gas-to-hydrocarbon-fluid ratio, GOR_i, and/or at least one water-to-hydrocarbon-fluid ratio, WOR_i, may be considered. Hence, the at least one hydrocarbon fluid flow rate, Q_i^HC, may be determined even more accurately. As above, an accurate determination of the at least one hydrocarbon fluid flow rate, Q_i^HC, may also allow for a more accurate adaption of at least one operating parameter of the at least one well.

The Lagrangian function may comprise a hydrocarbon fluid flow rate objective function. The hydrocarbon fluid flow rate objective function may be referred to as HCOF. Thereby the hydrocarbon fluid flow rate objective function may be configured to minimize the difference between a well specific hydrocarbon fluid flow rate, Q_i^HC, and a respective well specific test hydrocarbon fluid flow rate, Q_i^{test HC}. Said difference may be minimized for each well. Further the hydrocarbon fluid flow rate objective function optionally comprises the sum of the squared differences of each well's hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}. Moreover, each squared difference may be multiplied with a respective uncertainty value, w_i^HC. An exemplary hydrocarbon fluid flow rate objective function, HCOF, may be

HCOF = ∑ i = 1 n w w i HC 2 ⁢ ( Q i HC - Q i test ⁢ HC ) 2 .

It will be understood that other hydrocarbon fluid flow rate objective functions, HCOF, being configured to minimize the difference between a well specific hydrocarbon fluid flow rate, Q_i^HC, and a respective well specific test hydrocarbon fluid flow rate, Q_i^{test HC}, may be used. Further it will be understood that the well specific hydrocarbon fluid flow rate, Q_i^HC, of the hydrocarbon fluid flow rate objective function, HCOF, may be the at least one hydrocarbon fluid flow rate, Q_i^HC, to be determined by the methods according to the present disclosure.

By reducing the difference between the well specific hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}, it is ensured that the well specific hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC} are interrelated. Thereby the uncertainty value, w_i^HC, may allow for considering the uncertainty associated with the respective test hydrocarbon fluid flow rate, Q_i^{test HC}. Thus, inaccuracies may be avoided or at least reduced.

The Lagrangian function may comprise a gas-to-hydrocarbon-fluid ratio objective function. The gas-to-hydrocarbon-fluid ratio objective function may be referred to as GOF. Thereby the gas-to-hydrocarbon-fluid ratio objective function may be configured to minimize the difference between a well specific gas-to-hydrocarbon-fluid ratio, GOR_i, and a respective well specific test gas-to-hydrocarbon-fluid ratio, GOR_i^test. Said difference may be minimized for each well. Further the gas-to-hydrocarbon-fluid ratio objective function optionally comprises the sum of the squared differences of each well's gas-to-hydrocarbon-fluid ratio, GOR_i, and the respective test gas-to-hydrocarbon-fluid ratio, GOR_i^test. Moreover, each squared difference may be multiplied with a respective uncertainty value, w_i^Gas. An exemplary gas-to-hydrocarbon-fluid ratio objective function, GOF, may be

GOF = ∑ i = 1 n w w i G ⁢ a ⁢ s 2 ⁢ ( GOR i - GOR i test ) 2 .

It will be understood that other gas-to-hydrocarbon-fluid ratio objective functions, GOF, being configured to minimize the difference between a well specific gas-to-hydrocarbon-fluid ratio, GOR_i, and a respective well specific test gas-to-hydrocarbon-fluid ratio, GOR_i^test, may be used.

By reducing the difference between the well specific gas-to-hydrocarbon-fluid ratio, GOR_i, and the respective test gas-to-hydrocarbon-fluid ratio, GOR_i^test, it is ensured that said ratios are interrelated. Thereby the uncertainty value, w_i^Gas, may allow for considering the uncertainty associated with the respective test gas-to-hydrocarbon-fluid ratio, GOR_i^test. Thereby, inaccuracies may be avoided or at least reduced.

The Lagrangian function may comprise a water-to-hydrocarbon-fluid ratio objective function. The water-to-hydrocarbon-fluid ratio objective function may be referred to as WOF. Thereby the water-to-hydrocarbon-fluid ratio objective function may be configured to minimize the difference between a well specific water-to-hydrocarbon-fluid ratio, WOR_i, and a respective well specific test water-to-hydrocarbon-fluid ratio, WOR_i^test. Said difference may be minimized for each well. Further the water-to-hydrocarbon-fluid ratio objective function optionally comprises the sum of the squared differences of each well's water-to-hydrocarbon-fluid ratio, WOR_i, and the respective test water-to-hydrocarbon-fluid ratio, WOR_i^test. Moreover, each squared difference may be multiplied with a respective uncertainty value, w_i^Water. An exemplary water-to-hydrocarbon-fluid ratio objective function, WOF, may be

WOF = ∑ i = 1 n w w i Water 2 ⁢ ( WOR i - WOR i test ) 2 .

It will be understood that other water-to-hydrocarbon-fluid ratio objective functions, WOF, being configured to minimize the difference between a well specific water-to-hydrocarbon-fluid ratio, WOR_i, and a respective well specific test water-to-hydrocarbon-fluid ratio, WOR_i^test, may be used.

By reducing the difference between the well specific water-to-hydrocarbon-fluid ratio, WOR_i, and the respective test water-to-hydrocarbon-fluid ratio, WOR_i^test, it is ensured that said ratios are interrelated. Thereby the uncertainty value, w_i^Water, may allow for considering the uncertainty associated with the respective test water-to-hydrocarbon-fluid ratio, WOR_i^test. Thus, inaccuracies may be avoided or at least reduced.

The Lagrangian function may comprise a hydrocarbon fluid flow constraint function being multiplied with a hydrocarbon fluid flow Lagrange multiplier. The hydrocarbon fluid flow constraint function may be referred to as HCCF. Thereby the hydrocarbon fluid flow constraint function optionally comprises the difference between the comingled hydrocarbon fluid flow rate, Q_field^HC, and the sum of hydrocarbon fluid flow rates, Q_i^HC, of the ones of the plurality of wells.

Since the individual wells of the plurality of wells may be flowing only during a fraction of the time during which the comingled flow rates, Q_field^HC, Q_field^Gas, Q_field^Water, are determined, i.e. measured, the respective flow rates of the individual wells may be multiplied with a factor, L_i. Exemplarily, if the comingled flow rates, Q_field^HC, Q_field^Gas, Q_field^Water, were determined during one week and an individual well was flowing only one day, the factor L_i would be 1/7.

An exemplary hydrocarbon fluid flow constraint function, HCCF, may be

HCCF = Q field HC - ∑ i = 1 n w ( L i ⁢ Q i HC ) .

Thus, by means of the above exemplary hydrocarbon fluid flow constraint function, HCCF, it is ensured that the objective functions described above are optimized under the constraint that the sum of hydrocarbon fluid flow rates, Q_i^HC, of the ones of the plurality of wells equals the comingled hydrocarbon fluid flow rate, Q_field^HC. Hence, it may be ensured that the sum of hydrocarbon fluid flow rates, Q_i^HC, is accurate. This improves the accuracy of the step of determining of the methods described above.

The Lagrangian function may comprise a gas flow rate constraint function being multiplied with a gas flow rate Lagrange multiplier. The gas flow rate constraint function may be referred to as GCF. Thereby the gas flow rate constraint function optionally comprises the difference between the comingled gas flow rate, Q_field^HC, and the sum of hydrocarbon fluid flow rates, Q_i^HC, of the ones of the plurality of wells, wherein each hydrocarbon fluid flow rate, Q_i^HC, of the ones of the plurality of wells is multiplied with a respective gas-to-hydrocarbon-fluid ratio, GOR_i.

An exemplary gas flow rate constraint function, GCF, may be

GCF = Q field Gas ( - ∑ i = 1 n w ( L i ⁢ Q i HC ⁢ GOR i ) .

Thus, by means of the above exemplary gas flow rate constraint function, GCF, it is ensured that the objective functions described above are optimized under the constraint that the sum of gas flow rates, Q_i^Gas=Q_i^HCGOR_i, of the ones of the plurality of wells equals the comingled gas flow rate, Q_field^Gas. Hence, it may be ensured that the sum of gas flow rates, Q_i^Gas, is accurate. This further improves the accuracy of the step of determining of the methods described above. Further, accuracy may be improved by taking the relation between hydrocarbon fluid flow to gas flow into account by Q_i^Gas=Q_i^HCGOR_i.

The Lagrangian function may comprise a water flow rate constraint function being multiplied with a water flow rate Lagrange multiplier. The water flow rate constraint function may be referred to as WCF. Thereby the water flow rate constraint function optionally comprises the difference between the comingled water flow rate, Q_field^Water, and the sum of hydrocarbon fluid flow rates, Q_i^HC, of the ones of the plurality of wells, wherein each hydrocarbon fluid flow rate, Q_i^HC, of the ones of the plurality of wells is multiplied with a respective water-to-hydrocarbon-fluid ratio, WOR_i.

An exemplary water flow rate constraint function, WCF, may be

WCF = Q field Water - ∑ i = 1 n w ( L i ⁢ Q i HC ⁢ WOR i ) .

Thus, by means of the above exemplary water flow rate constraint function, WCF, it is ensured that the objective functions described above are optimized under the constraint that the sum of water flow rates, Q_i^Water=Q_i^HCWOR_i, of the ones of the plurality of wells equals the comingled water flow rate, Q_field^Water. Hence, it may be ensured that the sum of water flow rates, Q_i^Water, is accurate. This improves the accuracy of the step of determining of the methods described above. Further, accuracy may be improved by taking the relation between hydrocarbon fluid flow to water flow into account by Q_i^Water=Q_i^HCWOR_i.

The Lagrangian function with the above objective functions and constraint functions may be formulated as

F = HCOF + GOF + WOF + λ HC ⁢ HCCF + λ G ⁢ GCF + λ W ⁢ WCF .

Thereby the Lagrange multipliers are represented by X. In more detail, the Lagrangian function with the above objective functions and constraint functions may be formulated as

F = ∑ i = 1 n w w i HC 2 ⁢ ( Q i HC - Q i test ⁢ HC ) 2 + ∑ i = 1 n w w i Gas 2 ⁢ ( GOR i - GOR i test ) 2 + 
 ∑ i = 1 n w w i Water 2 ⁢ ( WOR i - WOR i test ) 2 + λ H ⁢ C [ Q field HC - ∑ i = 1 n w ( L i ⁢ Q i HC ) ] + λ G [ Q field Gas - 
 ∑ i = 1 n w L i ⁢ Q i HC ⁢ GOR i ] + λ W [ Q field Water - ∑ i = 1 n w ( L i ⁢ Q i HC ⁢ WOR i ) ]

The Lagrangian function may be minimized by solving

∇ F = 0 = ( ∂ F ∂ Q i HC , ∂ F ∂ GOR i , ∂ F ∂ WOR i , ∂ F ∂ λ HC , ∂ F ∂ λ G , ∂ F ∂ λ W ) .

In detail,

∂ F ∂ Q i HC = w i HC ( Q i HC - Q i test ⁢ HC ) - λ HC ⁢ L i - λ G ⁢ L i ⁢ G ⁢ O ⁢ R i - λ W ⁢ L i ⁢ WOR i , ∂ F ∂ GOR i = w i Gas ( GOR i - GOR i test ) - λ G ⁢ L i ⁢ Q i HC , ∂ F ∂ WOR i = w i Water ( WOR i - WOR i test ) - λ W ⁢ L i ⁢ Q i HC , ∂ F ∂ λ H ⁢ C = [ Q field HC - ∑ i = 1 n w ( L i ⁢ Q i HC ) ] , ∂ F ∂ λ G = [ Q field Gas - ∑ i = 1 n w ( L i ⁢ Q i HC ⁢ GOR i ) ] , ∂ F ∂ λ W = [ Q field Water - ∑ i = 1 n w ( L i ⁢ Q i HC ⁢ WOR i ) ] .

The above equations assume that Q_i^HC, GOR_i and WOR_i are constant over time. For even further increased accuracy, a decline rate may be included. Exemplarily, Q_i^HC may be replaced by Q_ij^HC=Q_i1^HCe^−c, wherein Q_i1^HC is a single rate and c is a decline constant for all time periods j.

The commingled-flow measurement data may be representative of the comingled hydrocarbon fluid flow rate, Q_field^HC, the comingled gas flow rate, Q_field^HC, and the comingled water flow rate, Q_field^Water. Thus, interdependencies between all three rates may be taken into account which serves to further increase the accuracy of the at least one determined hydrocarbon fluid flow rate, Q_i^HC.

The well test data may be representative of test hydrocarbon fluid flow rates, Q_i^{test HC}, test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells. By taking the test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and the test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells into account, interdependencies between the hydrocarbon fluid flow, the gas flow, and the water flow may be taken into account which serves to further increase the accuracy of the at least one determined hydrocarbon fluid flow rate, Q_i^HC.

The step of determining may further comprise determining gas-to-hydrocarbon-fluid ratios, GOR_i, and/or water-to-hydrocarbon-fluid ratios, WOR_i, of individual ones of the plurality of wells. Thus, further information may be provided which may be used to adapt at least one operating parameter of at least one well of the plurality of wells. Hence, accuracy may be further improved.

It is to be understood, that the method described above, can be a computer implemented method. The entire method may be computer implemented or only some of the method steps. The method may be carried out on a single data processing means, such as a computer, or may be distributed in a computing environment, including multiple (at least two) data processing means. Further, additional devices and/or specific data processing means, particularly specific control units, may be utilized to carry out the above-described method/method steps.

Further, the object of the present disclosure is at least partly achieved by a system for determining at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of a plurality of wells connected to a common pipeline with a comingled hydrocarbon fluid flow from the plurality of wells.

As mentioned above, since the methods and the system relate to determining at least one hydrocarbon fluid flow rate of at least one of a plurality of wells connected to a common pipeline with a comingled hydrocarbon fluid flow from the plurality of wells, it will be understood that advantages and/or features of the methods may also apply to the system and vice versa. Further, the system according to the present disclosure may serve to perform one of the methods as described above.

The system comprises a data storing means, such as a database, configured to store historical well test data, wherein the well test data are representative of test hydrocarbon fluid flow rates, Q_i^{test HC}, of the ones of the plurality of wells, wherein the well test data are optionally further representative of at least one of test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells, wherein the well test data are derived from past well tests at the ones of the plurality of wells.

Moreover, the system comprises a data acquisition unit configured to receive commingled-flow measurement data, wherein the commingled-flow measurement data are representative of a comingled hydrocarbon fluid flow rate, Q_field^HC, wherein the commingled-flow measurement data are optionally further representative of at least one of the following: a comingled gas flow rate, Q_field^Gas, and a comingled water flow rate, Q_field^Water.

The data acquisition unit is further configured to access historical well test data from the data storing means.

Even further, the system comprises an optimizer unit being able to receive data from the data acquisition unit. The optimizer unit is configured to determine, based on Lagrange multipliers, at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of the plurality of wells using the received commingled-flow measurement data and the accessed historical well test data.

Furthermore, the system may comprise at least one sensor disposed on the pipeline with the comingled hydrocarbon fluid flow from a plurality of wells. Thereby the data acquisition unit may be configured to receive commingled-flow measurement data from the sensor.

The system may further comprise a signal transmission unit being configured for adapting at least one operating parameter of at least one well of the plurality of wells. Thereby adapting is optionally at least partially based on the at least one determined hydrocarbon fluid flow rate, Q_i^HC, of the at least one of the plurality of wells.

The system may further comprise means for identifying the ones of the plurality of wells for which the difference between the at least one determined hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}, exceeds a predefined threshold value.

Thus, it is possible to identify wells which exhibit significant deviations between the at least one determined hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}. This allows for improved monitoring of the plurality of wells. The identified wells may be selected for further investigation and/or operating parameter adaption.

Determining the at least one hydrocarbon fluid flow rate, Q_i^HC, may comprise using at least one uncertainty value for at least one of the plurality of wells, wherein preferably the at least one uncertainty value of the ones of the plurality of wells is at least partially based on a measurement error of the well test data of the ones of the plurality of wells.

The use of uncertainty values allows a weighing of test data in dependence of an increased uncertainty. Hence, accuracy may be increased. The increased uncertainty may exemplarily arise from test data whose acquisition already lies longer in the past. Further, the at least one uncertainty value, w_i, may be defined as

1 σ 2 ,

wherein σ² represents a measurement error. Further, at least one uncertainty value, w_i^HC, may relate to a test hydrocarbon fluid flow rate, Q_i^{test HC}. Moreover, at least one uncertainty value, w_i^Gas, may relate to a test gas-to-hydrocarbon-fluid ratio, GOR_i^test. Furthermore, at least one uncertainty value, w_i^Water, may relate to a test water-to-hydrocarbon-fluid ratio, WOR_i^test.

The commingled-flow measurement data may be representative of the comingled hydrocarbon fluid flow rate, Q_field^HC, the comingled gas flow rate, Q_field^Gas, and the comingled water flow rate, Q_field^water. Thus, interdependencies between all three rates may be taken into account which may serve to further increase the accuracy of the at least one determined hydrocarbon fluid flow rate, Q_i^HC.

The well test data may be representative of test hydrocarbon fluid flow rates, Q_i^{test HC}, test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells. By taking the test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and the test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells into account, interdependencies between the hydrocarbon fluid flow, the gas flow, and the water flow may be taken into account which serves to further increase the accuracy of the at least one determined hydrocarbon fluid flow rate, Q_i^HC.

Furthermore, the object of the present disclosure is at least partly achieved by a computer program, comprising instructions that when carried out by at least one processor, cause the at least one processor to perform for performing a method as described above.

Further, the object of the present disclosure is at least partly achieved by a non-transitory computer readable medium having stored thereon software instructions that, when carried out by at least one processor, cause the processor to perform for performing a method as described above.

Moreover, the object of the present disclosure is at least partly achieved by a control unit for determining at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of a plurality of wells connected to a common pipeline with a comingled hydrocarbon fluid flow from the plurality of wells, the control unit comprising at least one processor and a memory coupled with the at least one processor; the at least one processor and memory configured to perform a method as described above.

Even further, the object of the present disclosure is at least partly achieved by an oilfield comprising a plurality of wells connected to a common pipeline and a control unit as described above, operated to perform a method as also described above.

4. BRIEF DESCRIPTION OF THE ACCOMPANYING FIGURES

In the following, the accompanying figures are briefly described:

FIG. 1 shows an exemplary method according to the present invention,

FIG. 2 shows an exemplary system according to the present invention, and

FIG. 3 shows an exemplary oilfield according to the present invention.

5. DETAILED DESCRIPTION OF THE FIGURES

According to the present invention, FIG. 1 shows a method 100 for determining at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of a plurality of wells 2a, 2b, 2c connected to a common pipeline 3 with a comingled hydrocarbon fluid flow from the plurality of wells 2a, 2b, 2c to adapt at least one operating parameter of at least one well of the plurality of wells 2a, 2b, 2c.

The depicted method comprises the step of receiving 110 commingled-flow measurement data from at least one sensor 5, wherein the commingled-flow measurement data are representative of a comingled hydrocarbon fluid flow rate, Q_field^HC. Further, the commingled-flow measurement data are representative of at least one of the following: a comingled gas flow rate, Q_field^HC, and a comingled water flow rate, Q_field^Water.

The method of FIG. 1 further comprises the step of accessing 120 historical well test data, exemplarily from a historical test data storing means, such as a database. Thereby the well test data are representative of test hydrocarbon fluid flow rates, Q_i^{test HC}, of the ones of the plurality of wells 2a, 2b, 2c. Moreover, the well test data are representative of at least one of the following: test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells 2a, 2b, 2c. The well test data are derived from past well tests at the ones of the plurality of wells 2a, 2b, 2c.

The depicted method further comprises determining 130, based on Lagrange multipliers, at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of the plurality of wells 2a, 2b, 2c using the received commingled-flow measurement data and the accessed historical well test data. Determining 130 may be conducted by using an optimizer unit adapted to run an optimization program.

The illustrated exemplary method further comprises identifying 140 the ones of the plurality of wells 2a, 2b, 2c for which the difference between the at least one determined hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}, exceeds a predefined threshold value.

The depicted exemplary method further comprises adapting 150 at least one operating parameter of at least one well of the plurality of wells 2a, 2b, 2c. Said adapting 150 is at least partially based on the at least one determined hydrocarbon fluid flow rate, Q_i^HC, of the at least one of the plurality of wells 2a, 2b, 2c.

Further according to the present invention, FIG. 2 shows a system 50 for determining at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of a plurality of wells 2a, 2b, 2c connected to a common pipeline 3 with a comingled hydrocarbon fluid flow from the plurality of wells 2a, 2b, 2c.

The exemplary system 50 comprises a data storing means 10 being configured to store historical well test data. Said well test data are representative of test hydrocarbon fluid flow rates, Q_i^{test HC}, of the ones of the plurality of wells 2a, 2b, 2c. Further, the well test data are representative of at least one of test gas-to-hydrocarbon-fluid ratios, GOR_i^test, and test water-to-hydrocarbon-fluid ratios, WOR_i^test, of the ones of the plurality of wells 2a, 2b, 2c. The well test data are derived from past well tests at the ones of the plurality of wells 2a, 2b, 2c.

The exemplary system 50 of FIG. 2 further comprises a data acquisition unit 15 which is configured to receive commingled-flow measurement data. Said commingled-flow measurement data are representative of a comingled hydrocarbon fluid flow rate, Q_field^HC. Further, the commingled-flow measurement data are representative of at least one of the following: a comingled gas flow rate, Q_field^HC, and a comingled water flow rate, Q_field^Water.

The data acquisition unit 15 is further configured to access historical well test data from the data storing means 10.

Moreover, the system illustrated in FIG. 2 comprises an optimizer unit 20 being able to receive data from the data acquisition unit 15. Said optimizer unit 20 is configured to determine, based on Lagrange multipliers, at least one hydrocarbon fluid flow rate, Q_i^HC, of at least one of the plurality of wells 2a, 2b, 2c, using the received commingled-flow measurement data and the accessed historical well test data.

The system 50 of FIG. 2 further comprises a signal transmission unit 30 being configured for adapting at least one operating parameter of at least one well of the plurality of wells 2a, 2b, 2c. Thereby adapting is at least partially based on the at least one determined hydrocarbon fluid flow rate, Q_i^HC, of the at least one of the plurality of wells 2a, 2b, 2c.

Even further the exemplary system 50 comprises means for identifying 25 the ones of the plurality of wells 2a, 2b, 2c for which the difference between the at least one determined hydrocarbon fluid flow rate, Q_i^HC, and the respective test hydrocarbon fluid flow rate, Q_i^{test HC}, exceeds a predefined threshold value.

FIG. 3 of shows an oilfield 1 according to the present disclosure. The oilfield 1 comprises a plurality of wells 2a, 2b, 2c connected to a common pipeline 3 and a control unit 1000. The control unit 1000 is operated to perform a method as described within the present disclosure.

LIST OF REFERENCE SIGNS

• • 1 oilfield
  • 2a, 2b, 2c plurality of wells
  • 3 common pipeline
  • 5 sensor
  • 10 data storing means
  • 15 data acquisition unit
  • 20 optimizer unit
  • 25 means for identifying
  • 30 signal transmission unit
  • 50 system
  • 100 method
  • 110 receiving
  • 120 accessing
  • 130 determining
  • 140 identifying
  • 150 adapting
  • 1000 control unit