RU2185642C1 - Process of improvement of measurement of acceleration gradient of gravity ( variants ) - Google Patents

Abstract

FIELD: control over anomalies of gravitational field in process of secondary extraction of oil. SUBSTANCE: measurement of acceleration gradient of gravity conducted with the aid of gradiometer of the type of accelerometer is optimized by way of inclination of plane of instrument used in measurement through chosen angle above or below horizon to generate data from which systematic errors of instrument can be excepted by means of subtraction or by any other processing and by way of data reading in direction of first azimuth and then in direction of second orthogonal azimuth to obtain absolutely independent measurement of gradient. EFFECT: optimization of production of hydrocarbons by secondary extraction. 6 cl, 11 dwg

Description

 The invention relates to a method and system for optimizing measurements made using a gravity acceleration gradiometer for secondary oil production, and more specifically, a method for improving the measurement of gravity acceleration gradients for secondary oil production, in which an underground boundary is detected and controlled to optimize production or the interface between the produced oil and the fluid displacing the oil from the reservoir, and even more specifically, relates to a method for optimizing the measurements of grains iometrom acceleration of gravity, wherein the gradiometer via gravity acceleration monitored anomalies gravitational field caused by changes in density and contrast caused by displacement with time underground interface between the crude oil and fluid displacing oil from the reservoir or reducing reservoir pressure.

 Hydrocarbon reservoirs, oil and gas, are formed as a result of the conversion of organic matter into various types of hydrocarbon materials, including coal, tar, oil and natural gas. Oil and gas reservoirs are thought to form when lighter hydrocarbon molecules leak to the surface of the earth until they are trapped in a relatively permeable formation under a relatively impermeable formation that “plugs” the permeable formation. Lighter hydrocarbon molecules continue to accumulate in relatively large underground reservoirs, often accompanied by water molecules. Because reservoirs exist at various depths in the earth's interior, they are often under significant geostatic pressure.

 Hydrocarbon resources are extracted from surface and underground deposits by developing deposits of solid resources (coal, tar) and by pumping or using other methods to extract natural gas and liquid oil from naturally occurring underground deposits.

 In the last century, natural gas and oil were extracted by drilling into underground reservoirs. In general, most reservoirs in their natural state were pressurized due to the presence of free natural gas that accumulated above the liquid oil reservoir, and often due to the presence of water that accumulated below the liquid oil reservoir. Since naturally occurring crude oil has a density lower than the density of water (ie, in the range of 0.7 in the case of “light” crude oil to 0.9 in the case of “heavy” crude oil), crude oil accumulates above the permeable reservoir and below the gas-permeable reservoir. Consequently, a well drilled in an oil-permeable formation will produce oil, which receives energy to ensure its displacement from the gas-permeable layer lying above and / or from the water-permeable layer lying below.

 In general, “primary” crude oil production occurs during a time period when natural reservoir pressure causes the crude oil to be squeezed up through the borehole. At some point in the reservoir’s operating life, the naturally occurring reservoir pressure is actually exhausted. Several different methods, generally known as secondary production methods, are designed to recover crude oil after the natural reservoir pressure has lowered. Typically, secondary production involves restoring reservoir pressure using a fluid (i.e., liquid or gas) to lower the viscosity of the oil and / or to displace the remaining crude oil in the oil-permeable layer to the surface through one or more wells. The displacing fluid is introduced into the reservoir using injection wells, through which the displacing fluid is pumped into the reservoir under pressure in order to displace and thereby displace the oil in the direction of the producing wells and towards the wells.

 Various schemes have been developed to accommodate injection wells. For example, the line along which injection wells are located may be at or near the known boundary of the reservoir in order to displace crude oil in the direction of the producing wells and toward the wells. When the boundary between the pressurized fluid is advanced forward through the production wells, these production wells may be plugged or, if required, converted to injection wells. In another design, injection wells are interspersed between production wells to displace oil from the oil-permeable formation from the injection site in the direction of production wells and directly to production wells.

 Various fluids, including water at different temperatures, steam, carbon dioxide and nitrogen, are used to effect reservoir pressure recovery and displacement of the required crude oil from the main rock or oil-bearing sand formation towards production wells.

 In the technology with water injection, water at ambient temperature is pumped into the reservoir to displace oil in the direction of the producing wells and to the wells. Injected water accumulates underneath the crude oil and actually pushes the lower density crude oil up in the direction of the wellbore and toward it. In cases where the oil-permeable formation is relatively thin, from a geological perspective, and is also limited between two relatively less permeable formations (i.e., an impermeable reservoir lying above the reservoir and a more permeable reservoir lying below the reservoir), water is pumped at relatively high pressure and in such a volume that the regime of "marginal displacement" is realized, due to which crude oil is pushed to oil producing wells. Sometimes injected water is heated to lower the viscosity of the oil and, thereby, the movement of crude oil from the pores of a permeable sand formation or base rock. The water injection technology is also well suited for displacing natural gas trapped in the pores of relatively low-permeability rock to a production well.

 In steam injection technology, steam is used to move or displace oil from oil sand or oil rock in the direction of production wells and to wells. Steam, which may be superheated in the initial state, is injected into the oil-permeable formation to cause formation pressure to recover. As the steam moves from the starting point of discharge, its temperature drops, and the quality of the steam deteriorates, and the steam eventually condenses in the form of a layer of hot water. In addition, some of the lightest hydrocarbons can be distilled from crude oil when they are moved at the interface between steam / hot water and crude oil. The steam injection can be continuous or based on a periodic injection-stop mode.

 In addition to using water and steam to restore reservoir pressure and displace crude oil to production wells, carbon dioxide and nitrogen are also used for the same purpose.

 One of the problems associated with water, steam, or gas displacement technology is determining the interface or interface between the displacing fluid and the crude oil. In an optimal embodiment, the boundary between the displacing fluid and the transported crude oil would be predictably shifted through the reservoir from the injection points to the producing wells in order to maximize the production of crude oil. The geology of the reservoir is usually complex and heterogeneous and often contains areas or zones with relatively higher permeability sand or rock; these higher permeability zones can function as low resistance paths for pressurized displacing fluid. A pressurized displacing fluid sometimes forms low resistance channels, known as thieves zones (absorption zones), through which a pressurized fluid “breaks” to a production well, thereby significantly reducing production efficiency.

 Having the ability to determine the position of the interface or contour and often unclear between the displaced crude oil and the displacing fluid under pressure in order to track the displacement rate and morphology of this border and to control it would significantly increase secondary oil production.

 Various technologies have been developed to improve understanding of the underground geology configuration of an oil permeable reservoir. The most widely used method includes seismic echocontrol, in which a compression wave is directed down into the underground strata. The initial energy of the “interrogating” wave is usually created by detonating explosives or using special machines that hit the ground. An “interrogating” wave is emitted from the source location with a propagation velocity that depends on the elastic modulus and density of the material through which it passes. Like any wave energy, the “interrogating” wave undergoes reflection, refraction, scattering, absorption and attenuating effects caused by the material through which it passes and from which it is reflected. The energy of the reflected wave is detected by geophones spatially spaced from the location of the seismic source, and the data is processed to obtain a reservoir model. This method is well developed and is suitable for identifying underground structures that may be favorable for the accumulation of oil or gas.

 Other methods of research in underground geology include the use of gravimeters to detect minor changes in the magnitude of the acceleration vector of gravity in order to identify underground structures that may be favorable for the accumulation of oil or gas.

 Various devices and methods used to "interrogate" underground formations have led to significant progress in the possibility of creating a 3D model or simulation of a reservoir. However, existing sounding technologies do not allow to identify the location and morphology of the boundary or interface between the pressurized displacing fluid and oil or natural gas in those reservoirs from which secondary mining is carried out. Information on the position, morphology, and speed of border movement would be of considerable value in optimizing the production of hydrocarbons that are produced by secondary methods, especially in the matter of the efficient use of displacing fluid.

 Based on the foregoing, the purpose of the present invention, among others, is to provide a method for improving the measurements of the acceleration gradient of gravity, performed using a gradiometer in the case of production of fluid hydrocarbons, such as oil and natural gas, from an oil and / or gas reservoir, in which recovery reservoir pressure.

 Another objective of the present invention is to provide a method for improving the measurement of the acceleration gradient of gravity, performed using a gradiometer in the case of secondary hydrocarbon production, in which a pressurized fluid is used to displace oil and / or natural gas from the reservoir to the production well.

 Another objective of the present invention is to provide a method for secondary oil production, in which the boundary or interface between the produced oil and the pressurized fluid displacing the produced oil can be determined.

 A further object of the present invention is to provide a method for improving the accuracy of measurements performed using a gravity acceleration gradiometer in the case of secondary hydrocarbon production, in which the interface or interface between the produced hydrocarbon and the pressurized hydrocarbon displacing fluid can be determined and subsequently it can be controlled to maximize production.

These goals are achieved by the fact that the method of improving the measurement of the acceleration gradient of gravity when using a gradiometer such as an accelerometer having at least one pair of accelerometers rotating in orbit around the axis of rotation in a common plane, perceiving changes in the acceleration gradient of gravity when they move along their corresponding orbits and based on them providing the formation of the corresponding output electrical signals, contains the following operations:
placement of the gravity acceleration gradiometer at the observation point;
the implementation of the inclination of the common plane by a first angle below the local horizon and orienting the axis in the direction with the first azimuth;
data acquisition during the selected time interval in the direction with the first azimuth;
the implementation of the inclination of the common plane by a first angle above the local horizon;
data acquisition during the selected time interval in the direction with the first azimuth;
reorienting the axis to a direction with a second azimuth offset 90 degrees from the direction with the first azimuth;
data acquisition during the selected time interval at the first angle above the local horizon and in the direction with the second azimuth;
the implementation of the inclination of the common plane by a first angle below the local horizon;
data acquisition during the selected time interval at the first angle below the local horizon in the direction with the second azimuth;
averaging the differences between the series of measurements in the directions with the first azimuth and with the second azimuth to compensate for the systematic errors of a particular measuring device and gradients caused by a specific measuring device.

 The first angle may be less than 1 degree. The first angle may be 0.9 degrees.

These goals are achieved by the fact that the method of improving the measurement of the acceleration gradient of gravity when using a gradiometer such as an accelerometer having at least one pair of accelerometers rotating in orbit around the axis of rotation in a common plane, perceiving changes in the acceleration gradient of gravity as they move along its corresponding orbits and based on them providing the formation of the corresponding output electrical signals, contains the following operations:
placement of the gravity acceleration gradiometer at the observation point;
the implementation of the inclination of the common plane by a first angle above the local horizon and orienting the axis in the direction with the first azimuth;
data acquisition during the selected time interval in the direction with the first azimuth;
the implementation of the inclination of the common plane by a first angle below the local horizon;
data acquisition during the selected time interval in the direction with the first azimuth;
reorienting the axis to a direction with a second azimuth offset 90 degrees from the direction with the first azimuth;
data acquisition during the selected time interval at the first angle below the local horizon and in the direction with the second azimuth;
the implementation of the inclination of the common plane by a first angle above the local horizon;
data acquisition during the selected time interval at the first angle above the local horizon in the direction with the second azimuth;
averaging the differences between the series of measurements in the directions with the first and second azimuth to compensate for the systematic errors of a particular measuring device and gradients caused by a specific measuring device.

 The first angle may be less than 1 degree. The first angle may be 0.9 degrees.

 Other objects and advantages of the present invention will become apparent from the following detailed descriptions in conjunction with the accompanying drawings, in which like parts are denoted by the same reference numerals.

The present invention is described below by way of example with reference to the accompanying drawings, in which:
FIG. 1 is a cross-sectional view of an oil trap or reservoir from which oil is extracted by secondary methods, showing in idealized form the interface between the displacing fluid and the displaced oil;
FIG. 1A is an idealized schematic representation of an interface between a displacing fluid and displaced oil;
figv - an idealized representation of the contrast in density at the interface shown in figa;
FIG. 2 is a plan view of the reservoir of FIG. 1, showing an oil boundary in the form of a strip of dotted lines in the case of a rectilinear displacement configuration;
FIG. 3 is a view of FIG. 2 showing the oil boundary offset from the position shown in FIG. 2;
4 is an example of a five-point production configuration;
FIG. 5 illustrates how a uniform gravitational field is perturbed with the introduction of any mass;
figa is a top view of the field shown in figure 5;
FIG. 6 is an isometric view of a preferred gravity acceleration gradiometer with cutout of selected portions for greater clarity;
FIG. 7 is a functional block diagram showing how the output signal of an accelerometer included in the gravity acceleration gradiometer shown in FIG. 6 is processed;
Fig.8 is a mathematical conclusion for a protocol depending on a particular device, to eliminate systematic errors of the measuring device and its own gradients;
Fig.9 represents the mathematical conclusion for the protocol, depending on the specific device, in order to exclude horizontal gradients from the estimates of the gradient of curvature and evaluate horizontal gradients, both operations are combined with the compensation of the systematic error of the measuring device and its own gradients;
FIG. 10A and 10B are a flow chart of a test protocol for obtaining a plurality of data series; and
FIG. 11 is a graphical representation of the values of the gradient at the interface.

Preferred Embodiment
In FIG. 1 shows an idealized and exemplary geological formation having oily formations. As shown, the oil permeable formation 10 is bounded above by a relatively impermeable overlying formation 12 (known as “clogging”) and below by a relatively permeable formation 14. Oil permeable formation 10 is typically fine grained or coarse sand impregnated with crude oil, which typically accumulates between particles. In a conventional formation, formations can form a shallow dome or anticlinal fold under which oil accumulates; oil is often accompanied by natural gas and water. In those reservoirs that include natural gas, oil, and water, natural gas tends to form a layer or region above the oil, and water tends to form a layer or region below the oil. Depending on the geostatic pressure in the oil-containing formation, part of the gas may pass into the solution with oil. In general, interphase boundaries are usually indistinct, although in some cases the boundaries can be geologically distinct.

 As shown on the left in FIG. 1, the formations are displaced vertically along the discharge line 16, so that the displaced rock formation 14 creates a wedge 18 that defines the lateral boundary of the oil-permeable formation 10. Similarly, the side wall of the salt dome 20, which is often found along with oil reservoirs, defines another lateral boundary of the oil-permeable reservoir 10. Generally having a lateral boundary of the oil-permeable reservoir 10, bounded by the underlying and overlying rocks, is defined as a reservoir and can occur at depths from several tens to several thousand feet (from several meters to several thousand meters) below the surface of the earth. The image in FIG. 1 illustrates a reservoir at a depth of several hundred feet (several hundred meters) and is only an example of the vast variety of geological configurations in which oil reservoirs are found.

 Figure 1 shows four tower towers, each with a borehole, which passes through several layers into an oil-permeable layer 10. When a naturally-pressurized oil reservoir is initially opened by a well, oil is displaced through the well to the surface. However, over time, the pressure in the reservoir decreases to the point where mass transfer to the surface stops or drops to an unacceptably low flow rate. At this point, it is possible to induce oil flow using surface pumps to pump oil, or by restoring reservoir pressure by injecting water, steam or gas (i.e. carbon dioxide or nitrogen) into the reservoir through injection wells. In the example shown in FIG. 1, the two wells on the left are injection wells that inject reservoir pressure recovery fluid into the oil-permeable formation 10, and the two wells on the right are production wells through which crude oil is discharged. The completely black portion of the oil-permeable formation on the right represents the available crude oil, and the part of the formation with a dotted line on the left represents that part of the formation 10 where the oil is displaced and replaced by an injected displacing fluid.

 In Fig. 1, the transition from the dotted-dotted region to the black region represents the interphase or “front” between the displacing fluid under pressure from the left and the crude oil, which thereby shifts to the right in the direction of the producing wells. FIG. 1A is an idealized representation of the transition between a displacing fluid and a displaced oil, and it illustrates a physical phenomenon that is not fully understood and which may include parameters or features not shown. Assuming that the oil-permeable formation is completely saturated with oil, and in the case where the displacing fluid is steam, the temperature of the steam, which may be initially superheated, decreases as it moves away from the discharge point, and the steam is a source of latent heat. At some point, the quality of the steam deteriorates (i.e., the water content increases), and the heat of vaporization is transferred to the surrounding oil. At this point, steam and / or heated condensed water may be forced to mix with the oil and steam-induced fractional distillation may occur, during which some light hydrocarbons in the transported oil evaporate to mix with the steam. At some point in this process, the quality of the steam drops to zero or close to zero (i.e., the steam condenses into hot water). On figa a gradual increase in the density of the dotted line from left to right represents the movement of oil from the pores. In general, approximately 90% of the oil is displaced from any arbitrarily defined volume element, and 10% of the oil remains as residual oil; the remaining volume is usually replaced by 30% steam and 60% water. On figa steam is shown as cutting oil, since the vapor tends to rise within the oil-permeable reservoir. The boundary is often not clear and its morphology can change as a result of mixing with water in the lower parts of the oil-permeable layer and with natural gas in the upper parts of the oil-permeable layer.

 Although FIG. 1 illustrates secondary production of crude oil, the same configuration exists for secondary production of natural gas remaining in the pores of a gas-permeable formation. In the case where the manifold shown in FIG. 1 is a gas trap, an injected fluid (usually water) will cause the trapped natural gas to move towards the producing wells and towards these wells.

 Figure 2 is a plan view of the field shown in Figure 1, showing a rectangular grid of sixteen wells located in the center of the established sections of the field, identified by the numbers of rows and columns. The symbol 22 at the bottom of FIG. 2 represents the location of the below-surface discharge line 16 shown in FIG. 1, and the curvilinear designation 24 at the top of FIG. 2 represents the outline of the perimeter of the salt dome 20 shown in FIG. In figure 2, the wells in sections 11, 12, 13, 14 of the field are injection wells pumping the displacing fluid into the oil-permeable formation 10, and the remaining wells are conventional producing oil wells. The dotted line zone, partially passing through the oilfield sections 21, 11 and all the way through the oilfield sections 12, 13, 14 from left to right in FIG. 2, represents the position of the under-surface boundary between the oil and the displacing pressurized fluid. As you can see, the boundary or “front” is obscure and heterogeneous, reflecting the variation in the permeability of the oil-permeable layer 10. In general, the boundary will move over time from the injection wells to the producing wells through the field.

 The configuration shown in FIG. 2 is known as a straight-line displacement configuration because the line-forming injection wells in the field sections 11, 12, 13, 14 pump the displacing fluid into the oil-permeable formation. In alternative configurations, injection wells are located between production wells, as shown, for example, in a five-point configuration in FIG. 4. With a five-point configuration, an injection well is located at the center of a group of four production wells. A displacement fluid is injected through a centrally located injection well to create a boundary below the surface that extends around the injection well to propel, move, or displace oil in the direction of the producing wells and toward the wells. Variations of the five-point configuration include a seven-point and nine-point configurations (not shown) in which a centrally located injection well is surrounded by seven or nine production wells, respectively.

 FIG. 3 represents the field of FIG. 2, offset over time, to show the displacement of the boundary between the displacing fluid and the oil being transported over a period of time. In general, the time difference between FIGS. 2 and 3 can be measured in weeks, months, or years depending on the size of the reservoir in question, as well as the flow rate of the wells and the flow rate of the fluid when injected into the well. As shown, the boundary moved farther from the injection wells, and different sections of the front moved at different speeds so that the morphology of the boundary essentially changed. More specifically, the border on the left passed the wells in sections 21, 31 of the field, and the border on the right only passed the wells in section 24 of the field. In addition, part of the boundary between wells in sections 22, 23 of the field advanced to section 33 of the field and in the direction of the well in section 33. The specific morphology of the boundary shown in section 33 of the field between wells in sections 22, 23 of the field convincingly suggests a zone absorption, i.e. the volume occupied by the material with relatively high permeability, which allows the displacing fluid under pressure to form a channel through it, which can make its way to the production well and significantly reduce production efficiency.

 Information on the position, extent, morphology, and speed of the border over time would provide valuable information when managing injection wells to optimize the area advanced by moving the border and, therefore, optimizing production. Information regarding changes in the oil reservoir over time is useful for predicting trends of its depletion, indicating the location and extent of the remaining resources, and provides information on the location of new injection and production wells to optimally increase the flow rate.

In relation to the conditions shown in FIG. 1A, the density of an arbitrary volume element is a function of the density of liquid and gas fluids, saturation with liquid and gas fluids, density of the base rock and porosity of the base rock. The density change Δ _ρ for the reservoir volume element ΔV can be represented as Δ _ρ = P (ρ _f Δ _f + ρ _g Δg ^), where ρ _f is the fluid density, Δ _f is the change in fluid saturation, ρ _g is the gas density, and Δ _g is the change in gas saturation.

In general, the rock has a usual density between about 1.9 and 3.0 g / cm ³ and the oil has a density between 0.7 g / cm ³ in the case of light oil and 0.9 g / cm ³ in the case of heavier oil; thus, an oil-permeable material can be considered as a material having a composite density. When the displacing fluid displaces and replaces the trapped oil, the composite density changes due to the movement of the oil and the occupation of the pores with the residual oil and the displacing material. For an arbitrary volume element at point A in FIG. 1A, the density is a function of the main rock, residual oil (about 10%), as well as newly introduced steam (about 30%) and water (about 60%). Therefore, the difference in density for the volume element at point A and point B shown in FIG. 1A represents the contrast in sweat, which will affect the local gradient of gravity acceleration so that changes in this gradient can be established on the surface. In general, the contrast in density will be less than a few tenths of a g / cm ³ ; it is assumed that the horizontal size of the transfer zone, in which the contrast in density occurs, is a range between tens and hundreds of feet (meters).

The Earth’s gravitational field varies between a lower magnitude of about 978 Gal (9.78 m / s ² ) at the equator to about 983 Gal (9.83 m / s ² ) at the poles with gradients, characterized in units of Etvash, where one is Etvesh "is equal to 10 ^-9 s ^-2 . For an idealized homogeneous sphere, the equipotential surfaces outside the sphere are also spherical. However, density inhomogeneities in the sphere make the equipotential surface non-spherical; for such a surface, the curvature at any point is different in different directions. Two directions in which the curvature is maximum and minimum are called the main directions; the difference in curvature in these two directions is called differential curvature, which is explained in more detail below. In the case of the Earth, local changes in the acceleration of gravity are caused by deviations of the Earth’s surface from the geometric sphere, surface geology, tides of water, atmospheric tides, as well as a change in the relative position of the Earth, the Moon and the Sun. For any relatively small volume element in free space, an idealized gravitational field can be considered as a set of unidirectional field lines oriented along the local vertical and having zero amplitude in the x, y directions. If some mass is placed within this volume element, the gravitational field will be disturbed. For example, and as shown in Fig. 5, a dense mass M of cylindrical shape, having hemispherical ends and a finite length along the main axis, located in the center of an arbitrary volume element, will perturb the local gravitational field within this volume element, leading to force the lines closest to the mass M will bend in the direction of the mass M, and the lines of force farther from the nearest lines of force will bend in the direction of the mass M to a lesser extent.

 For any observation point within an arbitrary volume element, the gravitational field at this observation point can be decomposed into components x, y, z, of which the vector z will have the largest value, and the vectors x, y will have corresponding values, which are a function of location observation points relative to the disturbing mass M. For observation points in a plane above or below the mass M shown in FIG. 5, information about the vectors at this observation point will give information about the deviation or angle of inclination as long as field disturbance. In the conditions of the example shown in FIG. 5A, a sufficient number of observations in the plane above the mass M (or the plane below the mass M) will create a set of data from which one or more isopotential surfaces can be obtained that graphically determine the perturbation of the gravitational field caused by the introduction of the mass M.

 In general, the gravitational field along the z axis can be measured using uniaxial gravimeters, the usual types of which use lasers and high-precision clocks to measure the time of the fall of the mass between two vertically spaced points in a vacuum space. Gradiometers, unlike gravimeters, measure curvature gradients (or differential curvature, or ellipticity of equipotential surfaces of the gravitational field), horizontal gradients (or the rate of change of the acceleration of gravity in the horizontal direction) or vertical gradients (or the rate of increase of the acceleration of gravity in the vertical direction). Various methods and devices have been developed to measure the acceleration gradient of gravity. These methods and measuring instruments include measuring the deviation in the horizontal plane of the mass suspended from the string (Booger method) and the torsional rotation occurring on a horizontally suspended rocker with unequal masses at its ends (rocker arms Cavendish and Etves). Modern gravity acceleration gradiometers use accelerometer accelerators with restoring force to measure the horizontal components of x, the gravity acceleration gradient. Generally and in the simplest form, the mass used in the accelerator is suspended from the end of the adjustable balancer. Any deviation of the mass position from the zero position due to the acceleration experienced by the mass is detected, and the mass returns to its zero position using a magnetic field applied by the returning magnetic coil. The current flowing through the return coil is proportional to the acceleration experienced by the mass.

 Some modern gravity acceleration gradiometers use several pairs of accelerometers that move at a constant speed along an orbital path around an axis. Information from each accelerometer at any angular position in orbit gives information about the horizontal acceleration experienced by the accelerometer. Under the conditions shown in Fig. 5A, an accelerometer moving at a constant angular velocity along the orbital path in the observation plane above the mass M will experience positive and negative accelerations in the x, y directions and generate an output sinusoidal waveform that is modulated by acceleration anomaly information gravity in this plane of observation. When the observation plane is normal to the local vertical, then the output of the accelerometer does not contain a component representing the z axis. Conversely, as explained below, as applied to the preferred test protocol, if the accelerometer is in the observation plane, which is inclined relative to the field lines, then the output signal of the accelerometer will also be modulated with information related to the z axis.

 A gravity acceleration gradiometer suitable for the present invention includes a gravity acceleration gradient meter (ISU) sold by Lockheed Martin Corporation (Buffalo, NY, USA); Lockheed Martin IGU, the basic design of which is shown in Fig.6, is preferred in relation to the present invention. The basic design and operation of Lockheed Martin ISU are described in US Pat. No. 5,357,802, issued October 25, 1994 to Hofmeyer and Affleck, entitled "Rotating Accelerometer Gradiometer," the disclosure of which is incorporated herein. by reference.

As shown in Fig.6 and 7, the ISU includes eight accelerometers 100 mounted at the same radius and equally spaced from each other along the perimeter of the rotor assembly 102, which rotates with a constant and adjustable angular velocity relative to the axis of rotation _x . The rotor assembly 102 includes a rotor 104 configured to rotate with the support shaft 106. The rotor assembly 102 is rotatably mounted in bearings 108 and, in turn, in a flexibly mounted vibration protecting assembly 110. Processing electronic circuits 112 are located on the rotor 104 near each accelerometer 100 to process their output signals, as explained below in connection with FIG. The inner casing 114 includes a rotor assembly 102 and is rotatably rotatable with the rotor assembly 102. The outer casing 116 includes internal components and includes one or more heaters 118 designed to provide operation of the measuring device at a certain controlled temperature above the environment (i.e. e., about 115 ^o F (46.1 ^o C)) and also includes a screen 120 for protection against magnetic field. The node 122 current-collecting contact rings on the upper end of the support shaft 106 provides an electrical / signal interface with the rotor node 102 and the devices operating on it. A shaft position sensor 124 at the lower end of the support shaft 106 interacts with a strain gauge 126 to provide rotational position information. The output of the strain gauge 126 is supplied to a computer and a speed controller, which, in turn, controls the motor 128 at the upper end of the device to provide an adjustable speed of rotation.

 Each accelerometer 100 generates a sinusoidally varying analog output signal, which is a function of the acceleration that each accelerometer experiences when this accelerometer makes orbital motion relative to the axis of rotation. For a gradiometer with a rotation axis oriented along the lines of force in a perfectly uniform and undisturbed gravitational field, each accelerometer experiences the same forces under the action of acceleration as they move along the orbital path. However, if the local gravitational field is disturbed due to the presence of one or more masses and / or the axis of rotation is inclined relative to the local vertical lines of force, then each accelerometer will experience various accelerations, passing in orbit. The quantitative value of the output signal of each accelerometer in combination with its rotational position gives information on the local gravity acceleration gradients.

Компоненты Г_x,z и Г_y,z приблизительно равны изменению силы тяжести вдоль направлений х и у, соответственно, и известны как составляющие горизонтального градиента, a Г_z,z известен как вертикальный градиент силы тяжести. Дифференциальная кривизна связана с Г_x,x, Г_y,y и Г_x,y следующим образом:
[(Г_x,x-Г_y,y)² + 4(Г_x,y)²]^1/2/F, (2)
где F - сила тяжести.At any point of observation, the acceleration gradient of gravity is a second-order derivative of the scalar quantity Г of the gravitational potential and is represented by a symmetric tensor Г _ij of nine second-order components as follows:

The components Г _{x, z} and Г _{y, z are} approximately equal to the change in gravity along the x and y directions, respectively, and are known as components of a horizontal gradient, and Г _{z, z} is known as a vertical gradient of gravity. The differential curvature is associated with G _{x, x} , G _{y, y} and G _{x, y} as follows:
[(D _{x, x-} D _{y, y} ) ² + 4 (D _{x, y} ) ² ] ^1/2 / F, (2)
where F is gravity.

In addition to the differential curvature, formula (2), the curvature vector, whose modulus is equal to the differential curvature, is also determined by the value of λ as follows:
λ = -1 / 2tan ^-1 [2Г _{x, y} / (Г _{y, y} -Г _{x, x} )], (3)
where λ is the angle of the differential curvature vector with respect to the x axis.

As is known, diagonal elements are scalar invariants and satisfy the Laplace relation
0 = Г _{x, x} + Г _{y, y} + Г _{z, z} , (4)
which implies
_{Z z, z} = - (, _{x, x} + _{y y, y} ). (5)
In addition, three pairs of nine elements are symmetrically equal, i.e., Г _{x, z} = Г _{z, x} , Г _{y, z} = Г _{z, y} and, finally, Г _{x, y} = Г _{y, x} so that the tensor is characterized by five independent components.

Gradients Г _{y, y} - Г _{x, x} and 2 Г _{x, y} in the formula (1) are two components of the curvature gradient, and Г _{x, z} and Г _{y, z} are two components of the horizontal gradient; Г _{z, z} - component of the vertical gradient.

 The output of the accelerometers is processed in accordance with the flowchart shown in FIG. 7; processing can be carried out using separate semiconductor functional devices, using software or hardware-based software controlled by microprocessors or computers, using a specialized integrated circuit (SIS), or by combining them.

 As shown, the pre-processed output signals of eight accelerometers 100 of the gravity acceleration gradient meter, ISU, shown in Fig.6, are divided into two groups A and B of four signals, each group is divided into two subgroups, i.e., (A1 , A2), (A3, A4), (B1, B2) and (B3, B4).

 The output signals A1, A2 of the accelerometers are fed to the inputs of the summing device SUM (A1 + A2), and the output signals A3, A4 are similarly fed to the summing device SUM (A3 + A4). The summed output signals of the SUM (A1 + A2) and SUM (A3 + A4) devices are fed to the SUB-A subtractor. Similarly, the output signals B1, B2 of the accelerators are supplied to the inputs of the summing device SUM (B1 + B2), and the output signals B3, B4 are similarly fed to the input of the summing device SUM (B3 + B4). The summed output signals of the SUM (B1 + B2) and SUM (B3 + B4) devices are fed to the SUM-B subtractor. The summation of the diametrically opposite accelerometers 100 signals actually destroys the acceleration component due to any displacement of the rotor assembly in the XY plane. The operation for determining the difference in the subtraction circuits SUB-A and SUB-B eliminates the influence of any angular acceleration of the rotor assembly, which may occur during the reaction to the angular velocity correction signals sent to the engine by the speed controller.

A group of four demodulators demodulates the subtraction device output signals SUB-A and SUB-B when responding to in-phase and quadrature reference signals with a frequency twice the rotational speed of the rotor assembly, which are generated by the reference signal source. The reference signal source can include a generator with a phase synchronization circuit, which is automatically phase-locked with the rotation of the rotor assembly 102 when it responds to the output signal of the strain gauge 126. The in-phase reference signal sin 2ΩT is supplied to the demodulators DEMOD-SA and DEMOD-SB, connected, respectively, with outputs of subtraction circuits SUB-A and SUB-B. Similarly, the quadrature reference signal cos 2ΩT is supplied to the demodulators DEMOD-CA and DEMOD-CB, also connected, respectively, to the outputs of the subtraction circuits SUB-A and SUB-B. The output signals of the four demodulators DEMOD-SA, DEMOD-SB, DEMOD-CA and DEMOD-CB are in the form of squared sine and cosine signals. More specifically, at the output, DEMOD-SA generates a value of 2R (Г _{x, x-} Г _{y, y} ) sin ² 2Ωt and components associated with 4Ωt, a demodulator DEMOD-CA generates a value of 4RГ _xy cos ² 2Ωt and components with 4Ωt, a demodulator DEMOD-SB generates the output value minus 4RG _xy sin ² 2Ωt and components with 4Ωt and finally demodulator DEMOD-CB outputs a value 2R (T -T _{xx yy)} cos ² 2Ωt and components with 4Ωt. The 2R factor is the distance between opposing accelerometers, i.e. distance between a pair of accelerometers A1 and A2.

 The summing circuit SUM-A receives the output signal from the demodulators DEMOD-SA and DEMOD-CB and supplies the total output signal to the low-pass filter LP-A. Similarly, the summing circuit SUM-B receives the output signal from the demodulators DEMOD-SB and DEMOD-CA and supplies the total output signal to the low-pass filter LP-B.

The output signals of the demodulators DEMOD-SA, DEMOD-SB, DEMOD-CA and DEMOD-CB include high-frequency components in the sense of frequencies equal to four times the rotational frequency of the rotor assembly. The gradient data, not counting the scalar coefficient, are determined by the squared sinusoidal and squared cosine components of the demodulated signals. These components are summed together in the summing circuits SUM-A and SUM-B to obtain a constant current value of the gradient data along with high frequency components. The function of the low-pass filters LP-A and LP-B, respectively, is to filter the output signals of the summing circuits SUN-A and SUM-B and attenuate the high-frequency components so as to obtain the required DC components that represent the gradient data. The gradient data is output from the low-pass filter LP-A in the form of an expression that includes the term 2R (G _xx- G _yy ), and from the low-pass filter LP-B in the form of the expression 4R (G _xy ).

Dividing the output signals 2R (Г _xx- Г _yy ) and 4R (Г _xy ) by 2R gives two results, (Г _xx- Г _yy ) and 2R (Г _xy ), which determine the curvature vector; the curvature vector module is known as "differential curvature" or "horizontal pointing tendency" and is equal to the square root of the sum of (G _xx -G _yy ) ² and (2G _xy ) ² .

The direction λ of the curvature vector with respect to the X axis is represented as follows:
λ = -1 / 2tan ^-1 (2g _xy / (Г _yy -Г _xx ).

The above description, in connection with FIG. 7, represents the function of the ISU when the sensitive axes of the accelerometers are in a plane normal to the vertical. With this orientation, the measuring device is optimized to detect x, the components of the acceleration gradient of gravity. However, due to the design of the measuring device itself, a number of errors can be introduced into the output signal. When constructing the ISU, an attempt is made to ensure that the mass is uniformly and symmetrically distributed around the axis of rotation _x Since separate disparate devices are used in the ISU, there is some mass asymmetry about the axis of rotation. In addition, the ISU is asymmetric in mass above and below the plane of the rotor 104. If the mass asymmetry is small, then the asymmetry is physically close to the accelerometers and it is assumed that it
affects in the form of a component of the measurement error.

 In accordance with the present invention and, as explained below in connection with the test protocol shown in FIG. 10, the ISU operates in at least two orthogonally spaced directions (i.e., at an angle of 90 degrees). Since errors associated with the systematic error of a particular measuring device and errors due to the gradient caused by a specific measuring device are “constant” for the measuring device itself and related structures, the rotation of the ISU around its axis of rotation for two orthogonal directions will not change the values of the systematic error of a particular measuring device and errors in gradient measurements associated with a specific measuring device, although at the same time the sign of the measured oyannyh gradients of the Earth reversed. By averaging the differences between the series of data obtained in two orthogonal directions, the absolute values of the Earth's curvature gradients can be obtained, since the systematic error of a particular measuring device and the gradients caused by a specific measuring device will be mutually compensated.

As explained in the mathematical representation shown in Fig. 8, the primary output signal of the ISU can be characterized as a "linear (in line)" I / L component, and the secondary output signal can be characterized as a "cross" CR component. As applied to the functional block diagram shown in FIG. 7, the linear and cross components can be defined as shown in formula (1) and formula (2) in FIG. 8. The X axis of the ISU can be oriented, for example, to the north, and using a sequence of Euler angles, the curvature gradients measured with a measuring device in the x, y coordinate system can be expressed as a function of the constant curvature gradients of the Earth in the north and east coordinate system as shown in formula (3) and formula (4) in FIG. The linear output signals of the ISU in the direction with the azimuth to the north (0 degrees) are presented in Fig. 8 as I / L (H = 0 ^o ), and for orthogonal measurement, as I / L (H = 90 ^o ). Similarly, the cross-output signals of the ISU when directed to the north and east are represented as CR (H = 0 ^o ), and for orthogonal measurements, as CR (H = 90 ^o ), so that the values of the curvature gradient without systematic error can be obtained from the formulas (5) to (9) shown in FIG.

 As explained below in connection with FIGS. 10A and 10B, the ISU operates when the test protocol is executed with the axis of rotation “tilted” at a small positive angle and a small negative angle relative to the horizontal plane to create a horizontal component of gravity acceleration to excite control loops in the ISU compensation with feedback and provide the ability to calibrate the scalar coefficients of accelerometers. However, when the axis of rotation is tilted, in the curvature measurements made using the ISU, horizontal gradients of acceleration of the Earth's gravity arise. Performing measurements using a measuring instrument inclined at a small angle above the horizontal and at a small angle below the horizontal, in combination with measurements taken in directions with two azimuths that differ by 90 degrees, will lead to measurements that duplicate the required gradients of curvature and of which unwanted horizontal gradients are excluded.

ISU includes orthogonal axis of rotation and inclination, of which the axis of rotation is horizontal in local x, near the plane, when the measuring device is rotated around its axis of rotation to tilt the measuring device up or down relative to the local horizontal plane. The I / L component indicates a line that is in the x-plane of the ISU, which can be oriented in a direction with some azimuth, when the x-plane of the measuring device is inclined at a slight angle relative to the local x-plane. The secondary output of the gradiometer is a “cross” CR component, as explained above in connection with formulas (1) and (2) in FIG. In terms of the mathematical representation shown in Fig. 9, the I / L and CR gradients measured by the ISU in its x, y coordinate system can be expressed as a function of the components of the Earth's gradient tensor in the geodetic reference frame: north, east, and down. The cosine direction matrix (KMN), which converts the geodetic coordinate system, north, east, and down to the coordinate system of the measuring device, x, y, z, with a direction with an angle H and an inclination angle P, is presented in formula (1) in Fig. 9 . The ISU I / L and CR output signals are associated with geodesic gradients, as shown in formulas (2) and (3) in FIG. 9, where the terms “error (I / L)” and “error (CR)” include their own systematic error measuring device and all errors in the measurement of the gradient due to a specific measuring device. As shown in formulas (4) and (5), the sums of the measurement results are indicated for the slope up and down, where the superscript “U” indicates the slope “up” and the superscript “D” indicates the slope “down”, and formulas (6 ) and (7) show the relationship with geodesic gradients. Having performed the measurements at Н = 0 degrees and Н = 90 degrees and calculating the sum of the linear and cross values, the result is formulas (8) and (9) for estimating the curvature gradients, Г _ee -Г _nn and 2Г _ne without relating them to horizontal gradients Г _nd and Г _ed and a vertical gradient Г _dd , and these values do not contain systematic errors and errors caused by the intrinsic gradients of a particular measuring device. Formulas (10) and (11) represent the difference between the I / L and CR measurements at the tilts “up” and “down”, and formulas (12) and (13) give an estimate of the horizontal gradients based on the measurement data performed, in addition, at 180 degrees.

 In accordance with the test protocol of the present invention and, as shown in FIGS. 10A and 10B, a number of measuring points n are installed in an oil field. Each measuring point may be in the form of a plot of cleared land or, more preferably, in the form of an asphalt or cement pad. It is important that the location of the measuring point is constant during the first and subsequent tests. The measurement points may preferably be in the form of a rectangular periodic structure formed from observation points, a polar structure from observation points or mixed, including observation points that are not related to a predetermined pattern and can be considered as randomly placed within the surveyed field. For example, as applied to FIGS. 2 and 3, the locations at which measurements are taken may correspond to the location of the numbers, rows, and columns of the field sites shown.

 The ISU is preferably mounted on a small wheeled trolley that can move from point to point, as provided for by the test. Depending on the distance between the observation points, the ISU can be transported, for example, by a wheeled or other vehicle. If required, the ISU can be mounted on a wheeled vehicle and switched on from point to point, and measurements can be made from the vehicle. However, a mobile carriage is preferred since the use of the carriage eliminates the gravity anomalies introduced by the wheeled vehicle from the data set. At each measurement point, the trolley rises on supports with adjustable height.

 As shown in the flowchart of FIG. 10A, the system is reset and parameters m and n are set to 1; wherein n represents the number of predetermined measurement points, where the maximum number of measurement points is N (max), and m represents the number of series of data that must be obtained for all time, where the maximum number M (max).

 The ISU is located in the first measurement point and, prior to the start of data acquisition, all objects having a mass large enough to affect the measurements (vehicle (s), power sources, local computer control, personnel, etc.) are moved to a sufficiently remote distance from the measuring device to minimize any adverse effects on the measuring device from these objects. In general, it is preferable that each measurement point is not located close to fixed, fixed in place structures made by man in order to minimize the appearance of large signals that are not related to the location of the interface.

 Then, the ISU is set to its initial position, and the rotation axis is tilted by some pre-selected angle of inclination (i.e., plus about 0.9 degrees in the case of the present invention), sufficient to obtain a response along the z axis in accelerometers, and the measuring device orient in the direction with an azimuth of zero degrees. As explained above in connection with Fig. 9, the "inclination" of the rotor assembly by a certain angle sufficient for eight accelerometers to receive the gravity acceleration vector allows the measuring device to receive the output signals of each accelerometer to determine the magnitude of the gravity acceleration, to determine the scalar coefficient each accelerometer, the differences between the scalar coefficients of the accelerometers, and determining the matching value so that all the accelerometers give identical, easily distinguishable output signals. As shown in the flowchart of FIG. 10A, the meter is further inclined at an angle opposite to the first angle so that cross-linking with horizontal gradients can be eliminated. Therefore, the measurement data obtained at the first angle of inclination include the systematic error of the measuring device and, similarly, the measurement data obtained at the opposite angle of inclination similarly include the systematic errors of the measuring device; then the measurement data for both tilt angles can be averaged to compensate for the bias.

 The ISU then takes the data at the observation point for a period of time sufficient to ensure that the sources of errors are minimized; in the case of a preferred ISU, a time interval of the order of several minutes (i.e., approximately five minutes) in each direction is considered suitable for data acquisition.

 Then, the measuring device is deflected at the opposite angle (i.e. minus about 0.9 degrees in the case of the present invention) and the data acquisition step is repeated at the initial azimuth. When the data acquisition is completed in the direction with the initial azimuth for both orientations, with an upward inclination and a downward inclination, the measuring device is turned to an azimuth increased by 90 degrees, and the data acquisition step is repeated with an upward inclination and an inclination downward. Data acquisition for tilting up and tilting down should be carried out in directions with only two azimuths; however, if required, in order to increase the accuracy of data acquisition, the step of data acquisition during tilt up and tilt down can be repeated in directions with a large number of azimuths. Turning the measuring device in a new direction includes turning the measuring device itself, its trolley and any associated structures, including any surrounding enclosure. The rotation of the structures associated with the operation of the measuring device itself helps to minimize the sources of errors. As explained above in connection with Fig. 8, the azimuth rotation is performed to provide the information necessary to eliminate the sources of errors associated with the mass asymmetry of the measuring device itself and its immediate environment. This sequence continues until the data is taken at least in directions with three orthogonal azimuths; however, in the case of the preferred embodiment, the data is taken at 0, 90, 180, 270 degrees and then again at 0 degrees. If additional information is required, the data acquisition steps may be repeated in different directions.

 As explained in more detail above, data acquisition for directions with different azimuths and different tilt angles is carried out to minimize the sources of errors and, in fact, to increase the sensitivity of the measuring device.

 Then n increases by one, the ISU is moved to the next next measuring point and the sequence of actions at this point is repeated.

 When the data are taken at each of n measuring points (i.e., n = N (max)), the first series of data is completely received. In accordance with the present invention, a period of time (measured in weeks, months, or years) passes such that the oil field is subjected to a continuous or non-continuous increase in pressure using an injected displacing fluid to cause a displacement of the interface between the displacing fluid and produced hydrocarbons . After the test period has passed, the test sequence shown in FIG. 10A is repeated to obtain another series of data, called a second series of data. As you can see, the third, fourth and subsequent tests can be performed after suitable inter-test time intervals have passed to obtain the third, fourth and subsequent series of data. In practice, the presence of two consecutive series of data (i.e., M (max) = 2) is sufficient to obtain acceptable data.

 Each data series includes information about the acceleration gradient of gravity over the field, including the influence of underground geology, changes due to the terrain and man-made fixed structures in place, including tower towers, pipelines, pumps, engines, etc., which are usually located in the oil field. In addition, this series of data will include information regarding the effect of the interface between the displacing fluid and displaced hydrocarbons on the acceleration gradient of gravity. However, there is no method that is not presumptive that could accurately determine the location of the interface based on a single series of data. As in the case of the first series of data, the second and subsequent series of data similarly include information regarding the effect on the acceleration gradient of gravity of geology, terrain and man-made structures, as well as the interface at a new location. Consequently, information regarding geology, terrain, and man-made structures will represent relatively invariant (unchanging) common data or signaling information of the same type for each data series, and information regarding the interface moving with time will not be common for different data series .

 Sources of errors that could adversely affect accuracy may include geological displacements, such as oil reservoir compaction and groundwater level displacement.

 To process the first and second (and / or subsequent series of data) and as an initial step, a theoretical model is developed for the relationship of the gradient of the acceleration of gravity with the formations below the hydrocarbon reservoir of interest. For any hydrocarbon reservoir from which the secondary production is conducted, it is likely that the set of geophysical data, including the reservoir model, can be obtained from preliminary acoustic surveying, well logging, core, product analysis of test wells and knowledge about the presence or absence (and changes) displacing fluid in the product of producing wells. If required, well-known geophysical data can be combined with available data on the acceleration gradient of gravity. More specifically, gradient data can be “best fitted” to geophysical data to obtain a predictive reservoir model and / or gradient data can likewise be “best fitted” to geophysical data using inverse transform methods to obtain the best model the reservoir and the model boundary between the displacing fluid and the produced hydrocarbon.

 To obtain information about the underground density, either forward modeling methods (also known as the indirect method) or direct methods can be used. Forward modeling methods begin with the use of existing knowledge of reservoir reservoirs into which injection is performed, and assumptions are made about changes in the levels of saturation of various fluids, and knowledge derived from other geological measurements (e.g., seismic) and other observations of the oil field is included such as changes in pressure and temperature in observed wells. Calculations of gradients over time can be made from this initial model. For this, the Talwani forward modeling method described in Computation with the help of a digital computer of magnetic anomalies caused by bodies of arbitrary shape, disclosed in the work “Digital Computer Calculation of Magnetic Anomalies,” can be used. Geophysics, vol. 30, 5, pps. 797-817 (1965)) The calculated values are compared with the observed gradient values over time and the initial model using the iteration method is modified so that the calculated values correspond to the values obtained from the observations. in The saturation values in the final model are given by the position of the front between the displacing fluid and displaced hydrocarbons.

 Direct methods use existing knowledge about the reservoir as boundary conditions and the observation data are inverted to obtain changes in underground density, which, as in forward modeling methods, are associated with changes in fluid saturation.

 When gradient data are obtained over time (i.e., 4D), there are numerous machine-based calculation methods for determining changes in the distribution of subsurface density (formation morphology) over a time interval. Direct methods for using gradient data to estimate the density distribution fall into the category of linear problems, and direct methods that determine boundary perturbations for bodies with constant density fall into the category of nonlinear problems, as described by D.U. Vasco, in the article "Resolution and Variation Operators of Gravity Acceleration and Gravity Acceleration Gradiometry", published in Geophysics (DW Vasco, Resolution and Variance Operators of Gravity and Gravity Gradiometry, Geophysics, vol. 54, no. 7 (July 1989), pps . 889-899). Vasco's solution linearizes the relationships between prisms (mass density or density changes) and the associated gravity acceleration gradients and solves the inverse transformation by iterating using generalized inversions. Direct methods also include methods described by S.K. Rimer and J.F. By Ferguson in his article, “The ordered two-dimensional inverse Fourier acceleration method of gravity acceleration as applied to the Silent Canyon caldera in Nevada,” published in Geophysics (S.K. Reamer, LF Ferguson, Regularized two-dimensional Fourier gravity inversion method with application to the Silent Canyon caldera, Nevada, Geophysics, vol. 54, 4 (April 1989), pps. 486-496) and methods with Galerkin pulses described in the provisional application US 60 / 099,937, filed September 11, 1998. In general, for the Vasco method, restrictive conditions such as formation thickness greater than or equal to zero or all gr Anitsa lie below the surface; other limiting conditions include reasonable density ranges according to M. Kuer and R. Bayer, as described in the article “Fortran Programs for Solving Linear Inverse Problems” published in Geophysics (M. Cuer, R. Bayer, Fortran Routines for Linear Inverse Problems , Geophysics, vol. 45, 11 (November 1980), pps. 1706-1719).

 The initial model will be improved as the data increases and the only best known estimate at that point in time can be obtained. The model, front or back, is then analytically outraged to determine the relationship between changes in the acceleration gradient of gravity and changes in the morphology of the formations. Indirect methods for perturbing the starting or initial model forward include the “Directional Monte Carlo methods of the model quenching algorithm and the genetic algorithm [General Optimization Method in Geophysical Inverse Transformation,” M. Sen and PL Stoff (“Global Optimization Method in Geophysical Inversion, M. Sen, PL Stoffa, Elsevler, Amsterdam, 1995)].

Then, the actual gravity acceleration gradient (a graphical representation of which for Г _xz and Г _{xx is} shown in Fig. 11) is compared with that predicted by the theoretical model to generate successive iterations of the model, so that there is a tendency for the gradients to converge, with successively decreasing differences in comparisons. As additional measurement data is obtained, as shown in the test sequence of FIGS. 10A and 10B, the model is progressively improved. Before each refinement of the model, measurement data are processed to eliminate known and statistically estimated sources of errors, including the effects of geological “noise”.

 With a sufficient amount of measurement data, it is possible, using a computer processor to process the data, to create an animation of the displacement and morphology of the interface with time displayed on the computer for display on a computer monitor or similar display device. The processed data obtained during the display provides information on the boundary between the displacing fluid and the produced hydrocarbon. Then, the boundary movement and movement speeds can be graphically printed or plotted for use by the oilfield manager, which can control injection wells with respect to pressure and quantity parameters to use the border morphology in such a way as to obtain maximum production at the lowest cost of secondary production. The illustration of hydrocarbon boundaries and their changes can also be used by the manager of the oil field to identify possible absorption zones, as suggested in the sections 22, 23 of the field shown in FIG. 3. Providing the manager of the oil field with such a visual representation of the developing situation allows him to use this analysis to evaluate, adjust and compensate for changing conditions and maintaining or increasing production at the field.

 Although an accelerometer-type gradiometer is shown as a preferred measuring instrument for detecting a gravity acceleration gradient, other devices capable of measuring or otherwise establishing a local gravity acceleration gradient are also suitable. Other devices include paired gravimeters of this type, which use incident masses in evacuated space, while the acceleration of the incident mass is measured using a laser beam and a high-precision clock, as well as instruments that sense gravity, in which superconducting sensors are used.

 The present invention provides an advantageous method and system for optimizing measurements carried out using a gravity acceleration gradiometer to detect underground fluid boundaries in the case of secondary oil production, by which the cost of production can be reduced and / or the amount of hydrocarbon produced can be increased. The present invention is likewise well suited for use in detecting movement of underground fluids, including, for example, fronts of contaminated and / or toxic fluids.

 As will be appreciated by those skilled in the art, various changes and modifications can be made to the method and system for the secondary production of hydrocarbons, which illustrate the present invention without departing from the spirit and scope of the invention, as defined in the attached claims and established by law its equivalents.

Claims (6)

 1. A method for improving the measurement of the acceleration gradient of gravity using an accelerometer-type gradiometer having at least one pair of accelerometers rotating in an orbit around the axis of rotation in a common plane, perceiving changes in the acceleration gradient of gravity as they move in their respective orbits and, based on them, providing the formation of the corresponding output electrical signals, containing the following operations: placing the gradiometer of acceleration of gravity at the observation point; the implementation of the inclination of the common plane by a first angle below the local horizon and orienting the axis in the direction with the first azimuth; data acquisition during the selected time interval in the direction with the first azimuth; the implementation of the inclination of the common plane by a first angle above the local horizon; data acquisition during the selected time interval in the direction with the first azimuth; reorienting the axis to a direction with a second azimuth offset 90 degrees from the direction with the first azimuth; data acquisition during the selected time interval at the first angle above the local horizon and in the direction with the second azimuth; the implementation of the inclination of the common plane by a first angle below the local horizon; data acquisition during the selected time interval at the first angle below the local horizon in the direction with the second azimuth; averaging the differences between the series of measurements in the directions with the first azimuth and with the second azimuth to compensate for the systematic errors of a particular measuring device and gradients caused by a specific measuring device.  2. The method of claim 1, wherein the first angle is less than 1 degree.  3. The method according to p. 2, in which the first angle is 0.9 degrees.  4. A method for improving the measurement of the acceleration gradient of gravity using an accelerometer-type gradiometer having at least one pair of accelerometers rotating in an orbit around the axis of rotation in a common plane, perceiving changes in the acceleration gradient of gravity as they move in their respective orbits and, based on them, providing the formation of the corresponding output electrical signals, containing the following operations: placing the gradiometer of acceleration of gravity at the observation point; the implementation of the inclination of the common plane by a first angle above the local horizon and orienting the axis in the direction with the first azimuth; data acquisition during the selected time interval in the direction with the first azimuth; the implementation of the inclination of the common plane by a first angle below the local horizon; data acquisition during the selected time interval in the direction with the first azimuth; reorienting the axis to a direction with a second azimuth offset 90 degrees from the direction with the first azimuth; data acquisition during the selected time interval at the first angle below the local horizon and in the direction with the second azimuth; the implementation of the inclination of the common plane by a first angle above the local horizon; data acquisition during the selected time interval at the first angle above the local horizon in the direction with the second azimuth; averaging the differences between the series of measurements in directions with the first and second azimuths to compensate for the systematic errors of a particular measuring device and gradients due to a specific measuring device.  5. The method of claim 4, wherein the first angle is less than 1 degree.  6. The method of claim 5, wherein the first angle is 0.9 degrees. Priority on points:
November 6, 1998 1 and 4;
05/11/1999 on pp. 2, 3 and 6.

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