Patent Description:
In particular, the present invention relates to a history matching technique. This kind of techniques consists in adjusting a model of the hydrocarbon reservoir by manipulating the physical properties attributed to cells representing the model. The physical properties are for example porosity, permeability, relative permeability, etc. The objective is to match the model with actual production data such as fluid flow rate (oil, water and gas) or bottom hole pressures over time and then predict any physical properties of the hydrocarbon reservoir such as future oil and gas fluid flow rates, fluid flow properties, pressure, temperature, etc., and also 3D time lapse seismic data (4D).

This process may be carried out manually for coarse hydrocarbon reservoirs with a few production/injection wells and a limited number of cells. For larger hydrocarbon reservoirs with many production/injection wells, manual history matching is not adapted. Assisted History matching (AHM) techniques allow automating such process. These techniques usually rely upon an iterative process of minimization of a cost function.

Assisted history matching techniques involve the manipulation of large set of data, generally in four dimensions (three-dimension space and variations of the properties over time). This amount of data cannot be numerically handled easily and requires a high memory and processing power.

<NPL>, discloses the use of a 4D distance to the fluid front called the Hausdorff distance. The distance is computed for each cell of the model. Although the use of said distance allows the convergence of the minimization process, it still implies working with a large number of data.

Other methods are known from document <NPL>, document <CIT>, and document <NPL>.

An object of the invention is to provide a fast and efficient method for obtaining at least one physical property of a subsurface volume of a hydrocarbon reservoir over time through assisted history matching.

To this aim, the subject-matter of the invention relates to a computer implemented method, a system and a computer program product according to the appended claims.

The invention will be better understood, upon reading of the following description, taken solely as an example, and made in reference to the following drawings, in which:.

<FIG> shows a system <NUM> for obtaining at least one physical property of a subsurface volume of a hydrocarbon reservoir over time.

The subsurface volume comprises a porous medium containing at least one fluid.

Typically, the subsurface volume comprises a mix of three phases: water, oil and gas.

Fluid saturation corresponds to the relative quantity of said fluid in the porous medium. It is generally expressed in percentage of the total volume of the porous medium.

The system <NUM> comprises a calculator <NUM> for obtaining at least one physical property of a subsurface volume of a hydrocarbon reservoir over time, a display unit <NUM> connected to the calculator <NUM> to display the results provided by the calculator <NUM> and a man-machine interface <NUM>.

The calculator <NUM> comprises a database <NUM>.

The database <NUM> is able to store the results provided by the calculator <NUM>.

In the example of <FIG>, the database <NUM> is a local database comprised in the calculator. In a variant, the database <NUM> is a remote database connected to the calculator <NUM> by a network.

The calculator <NUM> comprises a processor <NUM> and a memory <NUM> receiving software modules. The processor <NUM> is able to execute the software modules received in the memory <NUM> to carry out the method according to the invention.

The memory <NUM> contains an observed data obtaining module <NUM> configured for obtaining observed data representative of a fluid saturation in the subsurface volume over time. Typically, the observed data are stored in the database <NUM>.

The data representative of the fluid saturation is for example a pressure, directly a fluid saturation, a seismic attribute or any parameter allowing reflecting variations of fluid saturation in the porous medium.

The memory <NUM> also comprises an observed fluid front mapping module <NUM> for mapping a location of at least one observed fluid front <NUM> (<FIG>) over time from the observed data.

The memory <NUM> contains a simulated data obtaining module <NUM> for obtaining simulated data representative of the fluid saturation in the subsurface volume over time using at least one reservoir model <NUM>.

The memory <NUM> comprises a simulated fluid front mapping module <NUM> for mapping a location of at least one simulated fluid front <NUM> (<FIG>) over time from simulated data.

The memory <NUM> comprises a simulated fluid flow streamlines <NUM> (<FIG>) obtaining module <NUM> for obtaining simulated fluid flow streamlines <NUM> in the subsurface volume over time using the at least one reservoir model <NUM> and a flow simulator <NUM>.

Preferably, each observed fluid front mapping module <NUM> and simulated fluid front mapping module <NUM> comprises a calculating submodule <NUM>, <NUM> for calculating data changes over time respectively on the observed data representative of the fluid saturation and/or on the simulated data representative of the fluid saturation in the subsurface volume and applying a data change threshold.

Moreover, according to the invention, the memory <NUM> comprises a computing module <NUM> for computing a cost function representing a mismatch between the observed data and the simulated data by calculating <NUM> at least a shortest distance d among a plurality of distances d along a corresponding plurality of simulated fluid flow streamlines <NUM>, each of said simulated fluid flow streamlines <NUM> connecting a same first location of the observed fluid front <NUM> to a same second location of the simulated fluid front <NUM>.

The memory <NUM> also contains a minimizing module <NUM> for minimizing said cost function.

Finally, the memory <NUM> comprises a physical property obtaining module <NUM> for obtaining the at least one physical property of the subsurface model over time.

The display unit <NUM> is for example able to display the observed data, the simulated data, the observed fluid front <NUM>, the simulated fluid front <NUM>, the simulated streamlines <NUM> and/or the physical property of a subsurface volume of a hydrocarbon reservoir over time. Moreover, the display unit <NUM> may display information relative to the progress of the method, such as the number of iterations, the lapsed time, etc..

Typically, the display unit <NUM> is a standard computer screen.

The man-machine interface <NUM> typically comprises a keyboard, a mouse and/or a touch screen to allow the user to activate the calculator <NUM> and the various software modules contained in the memory <NUM> to be processed by the processor <NUM>.

A flow chart of a method for obtaining at least one physical property of a subsurface volume of a hydrocarbon reservoir over time, according to an embodiment of the invention, carried out with the system <NUM> as described above is shown in <FIG>.

The subsurface volume is generally discretized into a plurality of cells. At least one physical value, such as observed data representative of the fluid saturation, simulated data representative of the fluid saturation, is associated to at least a part of the plurality of cells.

The method comprises obtaining <NUM> observed data representative of the fluid saturation in the subsurface volume over time.

Preferably, the observed data are obtained from 4D seismic data inversion computed for the subsurface volume over time. For example, three-dimensional seismic data and/or borehole seismic data are acquired at different times over the subsurface volume and processed using a method known from the prior art. Typically, the different times are separated by a non-constant predetermined period of time comprised between months to several years. The observed data is for example a fluid saturation and associated fluid saturation changes over time, or a seismic attribute and associated seismic attribute changes over time reflecting respectively the fluid saturation in the medium and its change over time.

<NPL>, describe how to infer changes in fluid saturation (and to a lower extent of fluid pressure) from the repeated acquisition of 3D seismic cubes. Other examples of such methodologies may be found in the article of <NPL>, the article of <NPL>, or the article of <NPL>.

Advantageously, this step <NUM> allows obtaining observed data representative of the fluid saturation for each fluid present in the porous medium, i.e. for water, oil and gas, at different times.

Preferably, the method comprises also obtaining <NUM> additional observation data such as flow rates at the production and injections wells, bottom-hole pressures, temperatures, etc. Typically, said additional observations are function of time.

Then, the method comprises mapping <NUM> a location of at least one observed fluid front <NUM> (<FIG>) over time from the observed data.

The mapping <NUM> is carried out on each 3D block of data representative of the fluid saturation for each phase contained in the medium.

The step <NUM> of mapping the location of the observed fluid front <NUM> comprises calculating <NUM> data changes over time on the observed data representative of the fluid saturation and applying a data change threshold.

For example, in case the observed data representative of the fluid saturation is a seismic attribute, the threshold is carefully determined using a petroelastic model, that is a group of equations expressing the seismic wave impedances (velocity and density) as a function of the rock characteristics (grains, porosity, fluids, etc). Changes in fluid saturation are translated into changes of seismic impedances and the threshold is determined as the minimum saturation changed causing an impedance change detectable by the interpretation instruments and techniques.

Therefore, preferably, the threshold is different for each considered fluid and it depends on the hydrocarbon reservoir.

More particularly, the step <NUM> for mapping the location of the observed fluid front <NUM> comprises determining a binary parameter for each cell of the subsurface model chosen among a downstream of the front state and an upstream of the front state. The fluid front is then formed by a plurality of cells located at the interface between the cells having a downstream of the front state and the cells having an upstream of the front state using the flow simulator <NUM>.

The binary parameter of the cell is a downstream of the front state if the observed data value representative of the fluid saturation of said cell is above a threshold or if a data change over time of said cell is above a data change threshold. Otherwise, the binary parameter of the cell is upstream of the front state.

<FIG> shows an example of a horizontal layer <NUM> extracted from a 3D block of observed data representative of the water saturation. The data changes between a reference time t<NUM> and a first time t<NUM> allow mapping two fronts <NUM>. It has to be kept in mind that, although <FIG> shows the fronts <NUM> as lines, the observed fluid fronts and the simulated fluid fronts, as described later, are three-dimension surfaces.

The method according to the invention comprises obtaining <NUM> simulated data representative of the fluid saturation in the subsurface volume over time using at least one reservoir model <NUM> and then mapping <NUM> a location of at least one simulated fluid front <NUM> (<FIG>) over time from simulated data.

Preferably, the method comprises obtaining a plurality of simulated data representative of the fluid saturation in the subsurface volume over time using a plurality of reservoir models <NUM>.

The reservoir model <NUM> incorporates all the geological characteristics of the reservoir such as the structural shape and thicknesses of the geological formations, the lithologies, the porosity and permeability distributions, etc. This model <NUM> is then used as an input into a reservoir simulation using the flow simulator <NUM> to obtain dynamic reservoir simulations.

A general introduction to the reservoir engineering discipline is provided by <NPL>". A focus on the reservoir simulation principles can be found in the publication of <NPL>, and in the article of <NPL>.

The mapping <NUM> of the simulated fluid front <NUM> is carried out similarly to the mapping of the observed fluid front <NUM>, in particular said step <NUM> comprises calculating <NUM> data changes over time on the simulated data representative of the fluid saturation and applying a data change threshold.

<FIG> shows a horizontal layer extracted <NUM> from a 3D block of simulated data representative of the water saturation. This layer is located at the same location as that of <FIG>. The computation of the change of the data representative of the fluid saturation is carried out between the same reference time t<NUM> and first time t<NUM>. Two corresponding simulated fluid fronts <NUM> can be identified in the layer <NUM> of <FIG>.

<FIG> shows a superposition of the observed fluid fronts <NUM> of <FIG> and the simulated fluid fronts <NUM> of <FIG>. This figure allows a visual evaluation of the mismatch between the locations of the observed and simulated fronts <NUM>, <NUM>.

The method according to the invention comprises obtaining <NUM> simulated fluid flow streamlines <NUM> in the subsurface volume over time using the at least one reservoir model <NUM>, typically using the flow simulator <NUM>.

In particular, the fluid flow streamlines <NUM> are computed from the flow simulation results by taking into account the locations of the wells in the corresponding surface area of the subsurface volume over time.

<FIG> shows a projection of the streamlines <NUM> in the layer of <FIG> and <FIG>. The streamlines <NUM> are computed in three-dimensions in the subsurface volume.

For the sake of clarity, only a limited number of streamlines <NUM> are shown on the figure.

The method then comprises computing <NUM> a cost function comprising a mismatch representing a mismatch between the observed data and the simulated data by calculating <NUM> at least one shortest distance d among a plurality of distances d along a corresponding plurality of simulated fluid flow streamlines <NUM>, each of said simulated fluid flow streamlines <NUM> connecting a same first location of the observed fluid front <NUM> to a same second location of the simulated fluid front <NUM>.

The calculated distance d is made in the three-dimension space and is then a curvilinear distance along the streamline <NUM>.

The location of any point of the simulated fluid front <NUM> is connected to the location of a point of the observed fluid front <NUM> by a plurality of streamlines <NUM> of the simulated fluid flow streamlines <NUM>, as shown in <FIG>. For the sake of clarity, only one streamline between each cell of the observed fluid front and each cell of the simulated fluid front is shown in <FIG>.

In particular, a plurality of distances d along the corresponding plurality of streamlines <NUM> connecting the same first cell of the simulated fluid front <NUM> to the same second cell of the observed fluid front <NUM> is calculated.

Then, the method comprises computing the shortest distance d among said plurality of distances d (<FIG>).

The output is a three-dimension surface for each couple of observed front/simulated front <NUM>, <NUM> made of a plurality of cells, each cell of the surface having a value corresponding to the shortest distance d measured along the streamlines. According to the invention, the method comprises minimizing <NUM> the cost function.

In the embodiment wherein a plurality of simulated data are calculated using a plurality of reservoir models <NUM>, the shortest distance d is computed for each couple of observed fluid front <NUM> and simulated fluid front <NUM> corresponding to each reservoir model <NUM>. In that respect, the first location of the observed fluid front <NUM> and the second location of the simulated fluid front <NUM> may be specific to the considered couple of observed fluid front <NUM> and simulated fluid front <NUM>, i.e. specific to the corresponding reservoir model <NUM>.

Preferably, the method comprises applying <NUM> an ensemble-based method, such as an ensemble Kalman filter, for carrying out said step. Ensemble-based methods involve starting with an ensemble of initial models <NUM> of the subsurface volume.

Simulated data, in particular simulated fluid saturation data, and additional simulated data <NUM> such as flow rates, etc. are calculated for each initial model <NUM>, for a plurality of times. The covariance between observed data (saturation data, production rates, bottom-hole-pressure) and simulated data is computed. The resultant correlation data is combined with the mismatch to produce an ensemble of updated models <NUM> which should be in greater conformity with the observed data representative of the fluid saturation. The updated models <NUM> are then used as new inputs for further simulations in the flow simulator <NUM>. The process is then iterated several times to obtain models in agreement with observed data <NUM>, <NUM>.

Details regarding the implementation of the ensemble-based methods may be found for example in <NPL>.

The invention also relates to computer program product comprising software instructions which, when executed by a computer, carry out the method as described above.

Claim 1:
A computer implemented method for obtaining at least one physical property of a subsurface volume of a hydrocarbon reservoir over time, the subsurface volume comprising a porous medium containing at least one fluid, the method being carried out by a system (<NUM>) for obtaining at least one physical property of a subsurface volume of a hydrocarbon reservoir over time, said method comprising the following steps:
- obtaining (<NUM>) observed data representative of a fluid saturation in the subsurface volume over time,
- mapping (<NUM>) a location of at least one observed fluid front (<NUM>) over time from the observed data,
- obtaining (<NUM>) simulated data representative of the fluid saturation in the subsurface volume over time using at least one reservoir model (<NUM>),
- mapping (<NUM>) a location of at least one simulated fluid front (<NUM>) over time from the simulated data,
- obtaining (<NUM>) simulated fluid flow streamlines (<NUM>) in the subsurface volume over time from a flow simulator (<NUM>), characterized by
- computing (<NUM>) a cost function representing a mismatch between the observed data and the simulated data by calculating (<NUM>) at least one shortest distance (d) among a plurality of distances (d) along a corresponding plurality of simulated fluid flow streamlines (<NUM>), each of said simulated fluid flow streamlines (<NUM>) connecting a same first location of the observed fluid front (<NUM>) to a same second location of the simulated fluid front (<NUM>),
- minimizing (<NUM>) said cost function,
- obtaining (<NUM>) the at least one physical property of the subsurface model over time.