Patent Application
20250198901
The present invention relates to the study of fluid flow through fractured rocks. More specifically, the present invention relates to a system for studying the influence of natural fractures, which are found in pre-salt reservoirs, on the fluid flow within the porous medium and for understanding the fluid flow in multi-fractured wells.
Every oil reservoir contains fractures, whether natural or induced, and on different scales. In general, natural fractures can be the result of two geological processes that occur after sedimentary deposition: tectonic efforts in the subsurface and/or dissolution by percolation of acidic fluid. On the other hand, so-called induced fractures are the result of activities in which human action changes the balance of tensions in which the rocky environment was initially found, such as drilling, hydraulic fracturing or the development of the field itself. While the first two are restricted to the region neighboring the wells, the last one can occur in any location of the reservoir, depending on the pore pressure, the compartmentalization of the reservoir or the environment heterogeneities.
Regardless of the fracture nature, whether natural or induced, they exert an important influence on the hydrocarbon flow in the porous medium (i.e. in oil reservoirs), and their behavior must be represented in the fluid flow simulator in the reservoir. This representation allows the model to be adjusted to production data, which gives greater robustness to the prediction of reservoir production.
The representation of fractures in the reservoir model requires parameters that describe their contribution to the fluid flow in the porous medium, such as the permeability of the fractures and the transfer function, which, as the name suggests, quantifies the transfer of fluids between the domains of the fracture and the porous medium. For a better representation of the physical phenomenon, i.e. the contribution of fractures to the fluid flow in the fractured porous medium, parameter values representative of the medium in question should be used. To this end, one possibility is to obtain experimental results from laboratory tests on samples of fractured rock, subjected to flow.
A second application of laboratory tests, in addition to obtaining parameters to represent the contribution of fractures to the flow in the fractured medium (which may be natural or induced fractures) in reservoir simulation, is their contribution to understanding the path taken by the fluid within the fractured medium. An example of the use of laboratory-scale observation at the field scale is the best positioning of production and injection wells based on the characteristics of the fractures, including quantity, dimensions, geometry and direction. For this, it is necessary that the flow experiment in a fractured porous medium be carried out inside the microtomograph, since the image with the distribution of the fluid in the sample allows such understanding. For an image acquisition, it is important that the percolating fluid be visible to the microtomograph, while the equipment used to wrap the sample is transparent. Therefore, the test must consist of different steps of fluid injection into the fractured rock sample; at the end of each one, an image will be obtained that will highlight the distribution of the fluids.
Publication WO0150819A1 A reveals measurements of variations in fracture porosity and permeability with increasing effective stress of cylindrical rock core plugs of various types (carbonate, silicoclastic, shale, for example) and dimensions. The test can be implemented for natural and induced fractures propagating axially in the rock core. Testing begins with initial testing, sample preparation and obtaining measurements on an intact plug to define the matrix properties in the rock core plug. A rock core plug with defined matrix properties is then, after further preparation, subjected to an axial shear fracture (natural or induced) that propagates through its body. Measurements are then obtained from the plug with an axial shear fracture (natural or induced) propagating through its body to determine fracture properties.
More specifically, this prior art discloses, among others, a method for laboratory measurement of dynamic variations in the petrophysical properties of an underground formation as a result of changes in the stress applied to a core rock sample obtained from a location of interest in the underground formation. Computed tomography is performed on the core rock sample to determine the homogeneous density distribution in the rock sample. A measurement of a relationship between the sensitivity to matrix porosity and the sensitivity to matrix permeability of the rock sample is then determined. An axially extending shear fracture is propagated through the rock sample to form a split core plug composed of fracture halves of the rock sample. The fracture halves of the split core plug are axially displaced relative to each other to simulate displacement during in situ fracturing of the formation rock. The fracture-displaced halves of the split core plug are then joined to form a bonded split plug. A measure is then determined of the stress sensitivity of the fracture porosity and fracture permeability of the core rock sample (paragraphs 5 to 7).
In general terms, the method of this reference consists of selecting 108 a cylindrical plug representative of an area of interest and perform computed tomography (CT) tests on it to analyze the internal structure of the plug matrix and check whether discontinuities or high/low density inclusions are detected. Examples of CT include medical computed tomography and micro-CT. Conventional core analysis (CCA) 112 is also performed to determine plug characteristics (paragraphs 27-70).
Then the plug is subjected to intact plug stress sensitivity test 106 and pore volume compressibility (PVC) test 114. During the PVC test, a volume of water expelled by the sample under increasing confining pressure is measured. See paragraph 46. Other tests are also performed (116, 118). After this, the plug is fractured 122 by applying a load at a constant rate until an axial tensile fracture is created. In the next step 124, the two resulting fracture halves (faces) 220a and 220b (
Finally, tests similar to those performed for the intact plug are repeated for the fractured plug, namely: Computed tomography analysis 126, fracture porosity and permeability measurement 128, fracture stress sensitivity 130, and PVC+SDk testing 132 (paragraphs 70-82).
Patent application CN113029910A discloses a rock core holder used in cooperation with a rock seepage real-time imaging system and a rock core holder method, and relates to the field of rock seepage mechanics. The rock core holder is characterized in that an inlet plug, a pressure chamber and an outlet plug are connected sequentially from left to right to form an external structure; and in the external structure, the left end, the left infiltration joint, the rock sample, the right infiltration joint and the right end are connected sequentially from left to right to form an internal structure. The test method comprises the following steps: (1) sample preparation; (2) sample loading; (3) testing; and (4) recycling. The device can be matched with a rock seepage real-time imaging system, the confining pressure condition in the actual rock stratum is simulated by using the pressure of the confining pressure medium in the pressure chamber, and the permeability test of the rock sample under different stress conditions is carried out by using a steady state method or a transient state method to obtain the permeability stress sensitivity rule of the rock sample. The method is uniform standard, can realize multiple industrial replications, and is suitable for in-situ real-time permeability testing and imaging of various medium porous rocks or fractured rocks.
In other words, this reference is to use existing imaging technology and permeability testing technology to provide a core support and a method used in conjunction with a rock seepage real-time imaging system, so as to realize real-time imaging of rock samples in the process of rock permeability testing. Real-time acquisition of parameters such as infiltration channel, water saturation, water distribution or pore structure.
Core support includes rock samples, infiltration joints, ends, heat shrinkable tubes, elastics, inlet plugs, outlet plugs, pressure chambers, threads, infiltration inlet valves, infiltration outlet valves, booster valves, discharge pressure valve, exhaust valve, confining pressure medium and infiltration medium.
The reference can cooperate with the rock seepage real-time imaging system, use the pressure of the confining pressure medium in the pressure chamber to simulate the confining pressure conditions in the actual rock formation, and use the steady-state method or the transient method to realize the penetration of rock samples under different stress conditions. Rate test to obtain the permeability stress sensitivity law of rock sample. At the same time, the real-time imaging system can perform real-time imaging of the sample during the test, and realize dynamic acquisition of parameters such as infiltration channel, water saturation, water distribution or pore structure. D2 has uniform standards, can realize multiple industrial replications, and is suitable for permeability testing and real-time in-situ imaging of various porous media rocks or rocks containing fractures.
Rock sample 1 is a standard cylindrical sample of porous media or fractured rock with flat ends. The diameter and height of sample 1 meet the permeability test requirements (
The present invention discloses a system and method of using the same device for testing rock samples with fractures subjected to single-phase flow, using tracer fluid and equipment invisible to a microtomograph. A porous plug is artificially fractured and wrapped with a liner comprising holes. The plug and liner are received in a receptacle in fluid communication with a pump. The pump flows the tracer fluid through the receptacle, forcing the fluid through the porous plug, fractures, and finally through the liner ports. The flow is recorded by a microtomograph. The flow data thus obtained allow (i) the quantification of parameters that represent the flow in a fractured medium in a flow simulator and (ii) images that show the distribution of fluids in the medium, at different injection steps.
The present invention will now be described below with reference to the typical embodiments thereof and also with reference to the attached drawings, in which:
Specific embodiments of this disclosure are described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any actual implementation, as in any engineering project or design, numerous implementation-specific decisions must be made to achieve developers' specific goals, such as compliance with system- and business-related constraints, which can vary from one implementation to another. Furthermore, it should be appreciated that such a development effort may be complex and time-consuming, but would nevertheless be a routine design and manufacturing undertaking for those of ordinary skill having the benefit of this disclosure.
In order to facilitate understanding of the result application to be obtained from the laboratory tests to be performed with the system of the present invention, some related definitions are presented below.
Below are highlighted some of the main geological factors related to the formation of naturally fractured reservoirs:
In order for the impact of fractures on fluid flow in the reservoir to be effectively considered during field development, they must be represented in the flow simulation model. To this end, it is important that the fractured environment is properly characterized, from its description based on the geological events that led to its formation, to the behavior of the fluids inside it during the exploitation of the reservoir, which can be modeled both numerically and experimentally in the laboratory, the latter being the object of this description.
Naturally fractured reservoirs can be classified based on the contribution of the rock matrix and fractures to the storage and fluid flow in the reservoir, considering their petrophysical properties (porosity and permeability). Nelson (2001) presents four main types of naturally fractured reservoirs:
Nelson's (2001) classification is illustrated in
For each type of naturally fractured reservoir represented in
Hydrocarbon recovery in naturally fractured reservoirs depends mainly on the magnitude of fracture permeability and how it varies spatially within the reservoir, in addition to the communication between matrix and fracture (represented in reservoir simulation by the transfer function). Good communication between matrix and fracture is essential for the productivity of the fractured reservoir, contributing to the achievement of high recovery factors. This communication between the media depends on the characteristics of both the fractures (aperture, permeability, spacing and direction of the fractures) and the matrix (porosity and permeability).
Thus, the complexity of representing the contribution of fractures to the production of the fractured reservoir in the numerical flow simulation can be seen, depending on the characterization of the geological structure and its impact on the recovery of hydrocarbons from the fractured medium, which methods are described below.
Every oil reservoir presents, in its initial condition, prior to production, a primary energy resulting from the characteristics of the rock and the fluids present therein, as well as the geometry and dimensions of the reservoir and its initial pressure. Associated with such characteristics and primary energy, primary recovery mechanisms can be indicated. However, the exploitation resulting from the action of such mechanisms makes it possible to produce a small part of the original volume of HC contained in the reservoirs. Therefore, it is common practice to supplement the reservoir's energy with the use of supplementary recovery mechanisms, which can be of two types, conventional and improved, described below. Attention is drawn to the specific issues of fractured reservoirs, with their particularities due to the discontinuity of the porous medium, as well as the hydraulic and capillary conductivity characteristics of the fractures:
Primary recovery is closely related to the compressibility of the fluids and the formation. In the presence of free gas, the compressibility of connate and formation water can be disregarded. On the other hand, in under-saturated reservoirs, that is, where the reservoir pressure is higher than the oil saturation pressure, the latter must be taken into account, as it may influence recovery.
This production mechanism begins when the internal pressure of the reservoir decreases and reaches the bubble point of the fluid. This occurs first in the highest regions of the reservoir, where pressures are lower, and in the vicinity of producing wells. Initially, gas bubbles are formed within the rock matrix and, without forming a continuous phase, expand and contribute to the repressurization of the reservoir. When the gas bubbles reach critical gas saturation, they form a mobile phase, which is moved to the producing well. Firoozabadi (2000) draws attention to the importance of knowing this critical gas saturation to estimate the recovery of reservoirs under the influence of this process. Bourbiaux (2010) mentions that in the literature this parameter varies from 2 to 27% and that, for fractured reservoirs, high values of this parameter result in high recovery rates. Also according to Bourbiaux (2010), this mechanism, in general, results in low recovery rates.
The expansion of the gas cap is conditioned by the displacement of gas from the cap towards the oil zone, as a result of the depressurization of the reservoir. The effectiveness of this mechanism in production depends on the size of the layer, the volume of which must be greater than that of the oil zone itself.
Similar to the gas cap mechanism, the influx mechanism involves the displacement of water from the aquifer underlying the reservoir towards the oil zone. This process occurs as the reduction in pressure at the oil-water contact propagates through the aquifer. The effectiveness of this mechanism depends on the relative size of the aquifer in relation to the oil zone, and can result in the highest levels of recovery among natural mechanisms.
The combined mechanism occurs in oil reservoirs that rely on the action of the gas cap and the aquifer simultaneously. In this mechanism, production flows and the depth of the perforations must be controlled in order to avoid water and gas conification. The formation of such cones is a function of the difference in viscosity of the fluids and the anisotropy of permeability of the reservoir rock, including its fractures.
Related to the hydrostatic equilibrium between the fluid columns in the matrix and the fracture. After the formation of cones in the producing well and the disorderly distribution of fluids in the reservoir resulting from production, the closure of the producing well allows the natural reorganization of fluids in the reservoir according to density and gravity. By slowly reopening the wells, productivity is positively affected.
As cited by Legrand et al. (2011) depending on the structure and type of the fractured reservoir, more than one production mechanism can act in oil recovery. However, the gas-in-solution mechanism in fractured reservoirs generally does not promote significant oil recovery values in wells completed at the top of the reservoir. This is because, as soon as the gas reaches its critical saturation, it becomes mobile and moves to the highest parts of the reservoir, causing an increase in gas production combined with a rapid drop in reservoir pressure, since the reservoir's own energy (gas in solution) is being produced. However, this effect can be mitigated with enhanced supplemental recovery methods (also called EOR-Enhanced Oil Recovery), with the injection of additives that promote the reduction of the mobility ratio, increasing the recovery factor.
Water injection is the most widely used supplementary recovery process worldwide and has proven to be very efficient in some fractured reservoirs. The three main mechanisms acting on the displacement of oil by injected water are the spontaneous capillary soaking of the wettable rock matrix preferentially by water, the viscous displacement due to the pressure gradient generated by the flow in the fractures and the gravitational effect due to the difference in density between water and oil.
Attention in water injection is focused on the wettability of the fractured medium in question. For wettable media preferably with water and with high fracture intensity, due to capillary force, water will invade the matrix in a spontaneous soaking process and promote the concurrent and countercurrent displacement of the oil that was stored and, consequently, the sweeping efficiency will be greater, resulting in a better oil recovery. For wettability media ranging from intermediate to oil-wettable, recovery efficiency will not depend on spontaneous soaking of the matrix, but rather on other mechanisms such as forced soaking, viscous displacement and the gravitational effect.
Firoozabadi (2000) explains that although laboratory tests indicate low recovery by soaking for some media, the response shown in the field can be controversial. This is because the laboratory test consists of immersing a sample saturated with oil in water, forcing the soaking to occur in the opposite direction to the oil flow. Therefore, for non-wettable media preferentially to water, this test estimates low recovery rates. However, in a real situation, the injection of water into the field promotes soaking contrary to and/or concurrent with the oil flow, so that the increase in oil recovery is the result of the increase in the acting capillary pressure (suction), as illustrated in
Examples include the Ekofisk field in the North Sea and the Midale field in Canada, which, although not being preferentially wettable with water, have shown good results with water injection. On the other hand, after water injection into the reservoir, a large amount of oil may remain either trapped in the matrix pores or in unswept regions of the reservoir. In these cases, the application of an advanced supplementary recovery process can be studied, as in the Midale field where miscible CO2 injection was introduced, obtaining good recovery estimates.
Fractured gas reservoirs with connected aquifers are also subject to the water displacement mechanism. Significant quantities of gas are produced from low permeability carbonate reservoirs or fractured shales, and sometimes these reservoirs are overtaken by breakthroughs anticipated due to fractures that connect with active aquifers. The foothills of Alberta and northeastern British Columbia have reservoirs of this type. Initially, these reservoirs produce through the gas expansion mechanism and, after this period, when the adjacent aquifer starts to act, the soaking process occurs, which is generally quite slow. Lemonnier and Bourbiaux (2010), upon studying samples from Alberta reservoirs, concluded that, in some cases, the best production strategy would be to produce these reservoirs at the highest possible production rate until the wells began producing water, and then to use gravitational segregation by closing the wells, allowing the gas to “reorganize” in the porous medium. In fact, there are few published works on soaking in gas/water systems.
Similar to water injection, gas injection can be a conventional supplementary recovery method in which the injected gas has the function of replacing the produced fluid, repressurizing the reservoir, and displacing the oil, thus contributing to sweep efficiency and the recovery factor. The necessary condition for this behavior is the immiscibility between the injected fluids and the one originally contained in the reservoir.
As in a gas-liquid system the liquid phase will always be the wetting phase of the rock, the capillary force in this case acts to retain the oil inside the matrix. On the other hand, the magnitude of the capillary force is closely related to the reservoir pressure, becoming zero near the gas/oil miscibility pressure. The effect of viscous flow in fractures is less important than in water injection, due to the low viscosity of the gas, and is generally disregarded, except in cases of poorly fractured reservoirs.
The injected gas can come from an external source or from the reservoir itself, which may be the case for CO2 and Nitrogen injection, in which the gas produced is reinjected.
Gas injection into reservoirs is most often a compositional recovery process, since the injected gas will rarely be in full equilibrium with the in situ oil. Depending on the composition of both the injected gas and the oil and the thermodynamic conditions in the reservoir, miscibility of the two fluids can be achieved. However, these ideal displacement conditions in fractured reservoirs require the injected gas to penetrate the matrix due to gravitational forces and molecular diffusion between the two phases.
Two mechanisms can affect the efficiency of this type of recovery: reinfiltration and capillary continuity. Reinfiltration can direct oil flow into the low permeability matrix rather than direct oil flow into the high permeability fractures. Capillary continuity in the matrix can significantly increase final recovery. However, as per presented by Firoozabadi (2000), due to the difference in capillary pressure between matrix and fracture, the drainage rate in the fractured medium may be lower than in homogeneous matrices with low permeability.
It is worth noting that a conventional porous media flow simulator, the so-called black oil, does not allow the correct representation of the injection of miscible gas into reservoirs. In this case, so-called compositional simulators must be used.
A simulation model that best represents the behavior of fluids in the porous medium allows, based on the adjustment of the production history (such as records of the volumes of fluids produced and bottom-of-well pressures), a better predictability of its behavior. The more reliable the model, the better the reservoir management will be, resulting in its conscious, responsible and safe development.
A robust simulation model is based on a good representation of the reservoir rock, the fluids present therein and the interaction between these elements. In the case of naturally fractured reservoirs, this is the multiphase flow that occurs both in the matrix and in the fractures and even between both, and depends on properties such as capillary pressure and relative permeability, in addition to the transfer function.
One way of obtaining the parameters necessary for the representation in the reservoir numerical simulation of the fluids behavior in a naturally fractured environment is through laboratory tests, where one seeks to imitate, in the laboratory, the behavior that should occur in the subsurface, but under controlled conditions and on a much smaller scale.
Due to its complexity, it requires a multidisciplinary study based on the integration of the geoscientists work and reservoir engineers. The former use information such as seismic data, reservoirs or similar outcrops, as well as the description of core samples and analyses of well profiles, in order to obtain parameters that describe the fractured medium, such as properties of the matrix (porosity and permeability) and fractures (direction and dip, frequency and opening, in addition to permeability). These parameters, among others, are used to construct the geological model, which is the basis for the simulation model, which must be worked on by engineers in order to represent the formation or production test records.
Oil reservoirs contain three fluids in the porous medium: water, gas and oil. Once a pressure differential resulting from the opening of a producing well is imposed, these fluids move towards the lower pressure, competing with each other for space. The rock-fluid interaction properties that dictate this behavior are saturation, capillary pressure, and relative permeability. Such properties can be obtained in the laboratory, using rock samples (matrix and fractures that represent the fractured environment) and fluids similar to those contained in the reservoir.
Phelps and Strauss (2002) relate the main constituent components of naturally fractured reservoirs and classify them as fault-related and matrix-related. Those related to the fault are the faults themselves, the fracture corridors and the diffuse fractures, that is, small-scale fractures that can also be called background fractures. As for those related to the matrix, there is the matrix itself and the super-permeability layers. These components are illustrated in
The study of the development of naturally fractured reservoirs follows four fundamental steps for the description, modeling and simulation of the environment, as described below:
These steps are correlated in
3D seismic data are the most reliable sources for building a fracture model. First, it is necessary to locate the position of the faults, identified as deterministic objects. Then, the fault system is extrapolated to the subseismic scale through a stochastic modeling process that honors the statistical parameters of the deterministic fault map (orientation, length, among others) and the fractal properties of the distribution of faults in space. The next constraints of this model are the maps of the presence of subseismic faults constructed based on the analysis of seismic morphology and various 3D seismic attributes. Large-scale fractures are considered to be the so-called fracture corridors (or fracture swarms), which are small aligned and grouped fractures, promoting a large-scale localized discontinuity.
Firstly, work is carried out to analyze and identify the families of fractures observed in the testimonies and image profiles. Different families are defined by average orientations, which are the result of structural characteristics and/or tectonic events. The nature of the geological facies also constitutes another classification parameter, because the expression of the fracturing event in a given facies is closely related to its mechanical properties. Once the fracture families and relevant facies have been identified, a fracture geomodel, describing the distribution of fracture parameters (orientation and density) for each family and each facies, can be constructed using a matrix geomodel. Finally, a stochastic model of the small-scale (diffuse) fracture systems can be generated for any position within the reservoir based on the parameters of this fracture geomodel.
Based on these analyses, a multiscale fracture model is constructed using stochastic methods limited by deterministic observations and genesis rules.
The construction of this fracture model has recently been carried out using discrete fracture network modeling software, also known by its acronym in English DFN—Discrete Fracture Network. For illustrative purposes,
Another alternative methodology deals with discrete fracture and matrix modeling, with the acronym in English DFM—Discrete Fracture and Matrix. In this case, both the fractures and the rock matrix are discretized and it is possible to directly perform the flow simulation in a fractured medium. However, this method has certain particularities/limitations that do not currently allow its application on a field scale.
The importance of carrying out increasingly realistic characterization and modeling reflects the objective of providing more precise equivalent structural and hydrodynamic parameters for the simulation step and, thus, estimating, with the greatest possible accuracy, the future behavior of oil field production. Although the DFN model is capable of providing this more realistic modeling of the fractured medium, it cannot be directly used for field-scale flow simulation using current technologies. Therefore, even with limitations, the traditional dual-porosity, dual-permeability approach is used for field-scale simulation of flow in naturally fractured reservoirs. Therefore, it is necessary to perform a conversion (upscaling) of DFN model parameters to a predefined grid of a dual-porosity model. The main parameters required for the simulation of naturally fractured reservoirs are:
It is worth highlighting the large number of uncertainties that guide studies of naturally fractured reservoirs and the simplifications imposed throughout the process. Therefore, after constructing a fracture model, it is necessary to validate this model and calibrate its hydraulic characteristics, in order to provide adequate equivalent parameters for the flow simulation step.
In the search to identify the impact of the presence of fractures in the reservoir, some indications, flow information in the field, are considered and correspond to a “dynamic” expression of the fractures. These indications, described below, come from both drilling information, flow behavior near wells or between wells, and historical production data from the field. However, it is worth highlighting that these indicators alone are not sufficient to describe the fracture system, and thus, they need to be compared with information from geology.
A.1. Mud loss data: due to the presence of conductive fractures at a given depth in the well, it is possible to determine the hydraulic width of the fracture by the parallel plate equation, considering the appropriate fluid rheology (Bourbiaux, 2010). Only wide fractures are determined, with a hydraulic width of around 0.2 mm.
A.2. Increased penetration rate: An increase in penetration rate may indicate drilling into a zone with levels of fracturing, combined with the recovery of poor cuttings samples.
A.3. Well flow behavior:
A.3.1. Well Tests: Transient flow tests can provide information on the contrast in fluid storage capacity between matrix and fracture in a dual-porosity reservoir, as well as on the exchange factor between these media. They can also indicate faults and their distances from the well and are good for identifying high permeability contrasts between layers, such as high permeability layers, also known as ‘super-k layers’, which can sometimes be treated as horizontal fractures within the reservoir.
A.3.2. Well productivity: valuable information when compared with other well data such as distribution of faults and fractures along the well, petrophysical data measured from cores and flow data such as production logs (PLT—production logging tool, flowmeters).
The Productivity Index (PI) of the wells can also be evaluated. However, it is worth highlighting that this data does not only reflect the permeability in the region around the well, but also indicates possible changes in the rock (assessed by the effect Skin such as damage or stimulation to the well). Thus, as a preliminary attempt to identify the impact of fractures on flow, one can analyze the normalized IP (IP divided by the completion length) correlating it with the density of fractures along the completed section or another possible indicator of fracture such as the distance to the nearest fault.
A.3.3. Production Profile: the production profile of the entire completed section of the well allows specifying the contribution of each face to the permeability test, which can be compared with the permeability of the faces derived from the cores, in order to obtain the contribution of the fractures to the permeability of the reservoir for each facies (or interval). These contributions can then be compared with the fracture densities measured in the samples or in the image profiles of the respective facies, in order to qualify the conductivity of the fracture set defined by the geologist.
Distribution maps of well productivity and/or injectivity and accumulated fluid production, pressure maps, evolution of contact between fluids over time, breakthrough times, trends in water cut and in the evolution of the gas/oil ratio, RGO, over time, are examples of information obtained from the production history of a field. Although there is a need to anticipate these impacts, as there is little data prior to field production, this historical data is very important for confirming or comparing estimates made.
For already developed fields, multiphase production data is very important for future production optimizations or re-development of the field itself.
For compartmentalized reservoirs, data on the evolution of pressure and fluid composition (PVT properties of the oil, salinity of the water) during production are of interest to assess possible communication between the reservoir compartments in the presence of conductive faults.
Some of the elements and concepts described below may be generally known in the prior art. Therefore, certain details may be omitted from the description that follows with the understanding that the person skilled in the art has prior knowledge to fill these gaps. For example, the specific types of devices used, or underlying physical principles may be omitted without detracting from the description of the present invention.
The present invention describes a laboratory system for testing rock samples with fractures subjected to single-phase flow, using visible fluid and equipment invisible to a microtomography machine, allowing (i) the quantification of parameters that represent the flow in a fractured medium in the flow simulator; as well as (ii) images that portray the distribution of fluids in the medium, in different injection steps. It should be noted that the success of the experiment depends on the use of a fractured rock sample, whether natural or artificial, the obtaining of which is not part of this description.
The technology can be fully applied in the area of reservoir management and modeling in order to improve both the predictability and historical adjustment of the behavior of the naturally fractured reservoir, in addition to optimizing its management. As a consequence, more robust production curves will be obtained by reducing the degree of uncertainty regarding fluid flow in naturally fractured media.
A porous plug like the one in
The fractures illustrated in the plug in
The fractured plug is surrounded by a Liner with holes as illustrated without limitation in
The fractured plug is positioned within a receptacle 5 specially designed to receive the plug 13 and allow the inlet and outlet of fluid through at least two, but preferably four channels. Each channel receives a duct for fluid flow, each fluid having a pressure gauge to measure the pressure of the fluid passing through the respective duct and a valve to allow or block the flow of the fluid through the respective fluid. At least one of the ducts is also coupled to a pump 1, for example, a peristaltic pump, for fluid pumping. The receptacle 5, ducts, pressure gauges, valves and pump form the flow measurement system according to the present invention, being illustrated without limitation in
According to the present invention, the fluid to be pumped into the receptacle 5 is a tracer fluid. Preferably, the tracer fluid is a non-ionic iodinated scintillating fluid.
According to the present invention, the receptacle 5 and the covers 2 and 10 must be made of material invisible to the microtomograph so as not to interfere with the analysis of the fluid flow. Such materials include materials made from organic polymers, for example, the plastic known as “PEEK”, which withstands extreme temperatures and high pressure.
As seen in
Adapters 15 have an outer diameter that allows a fit in receptacle 5 and an inner diameter that allows a fit with liner 14 and plug 13. Thus, plug 13 is centered in relation to receptacle 5 and defining an annular space between receptacle 5 and plug 13. This annular space allows the fluid flow to be directed to the upper channel or the lower channel. The adapters 15 are also made of material that is not very sensitive to the microtomograph, for example, PEEK plastic.
Once the invention system is positioned inside a microtomograph, as in
The system of the invention makes it possible to evaluate the influence of fractures on the behavior of fluid flow within plug 13, by measuring the flow displaced to the fractures and, subsequently, to the annulus around plug 13 through the holes in liner 14. In the figures, these holes are represented by longitudinal cuts, however, the invention is not limited in this way.
The invention allows plugs to be tested with different amounts of fractures, from one to the maximum possible number of fractures that can be created, without weakening the structure of the plug. Fracture configurations can be varied to observe and measure the interference of the quantity and type of fractures on the flow through plug 13.
Experiments with the system of the invention are carried out inside a microtomograph so that it is possible to visualize the flow of the tracer fluid through the fractures and holes in the liner 14, providing monitoring of the behavior of the fluid flow inside the plug 13.
This entire procedure is carried out with the microtomograph activated to record the fluid flow. The data obtained in this way will allow the creation of more precise mathematical models of the flow of underwater fluids and muds in soils and fractured layers. This advancement will also allow the creation of more accurate simulations, aiding and improving the planning of future submarine operations.
A method of using the system described by the present invention is also provided, comprising the steps of:
Although the aspects of the present disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. But it should be understood that the invention is not intended to be limited to the particular forms disclosed. Instead, the invention must cover all modifications, equivalents and alternatives that fall within the scope of the invention as defined by the following appended claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 1020230262716 | Dec 2023 | BR | national |
