RU2143064C1 - Method of research of internal structure of gas- oil pools - Google Patents

Abstract

FIELD: thermohydrodynamic researches of gas-oil pools; applicable in identification of internal structure of gas-oil pools and determination of their characteristics especially in study of massive fractured pools where determination of their internal structure by the existing methods is impossible. SUBSTANCE: method includes drilling- in with subsequent withdrawal of fluid from well; measurement in course of fluid withdrawal under different conditions of well operation of temperature, pressure and flow rate of fluid over well bore; determination on basis of research results of geothermal gradient, value of calorimetric effect of mixing of interval inflows with flow ascending over wellbore and actual value of Joule-Thompson factor. On the basis of obtained data, standard thermogram is calculated for conditions of fluid horizontal flow and its standard thermogram is compared with actual thermogram. EFFECT: provision of identification of factured pools and detection of fractures crossing wellbore with simultaneous obtained information on filtration direction over fractures from supply region to wellbore, geometric shape of fractures and depth of location of supply regions. 5 dwg, 1 tbl

Description

 The invention relates to the field of research of gas and oil deposits and can be used to recognize the internal structure of gas and oil deposits and determine their characteristics.

The term internal structure of gas and oil deposits is commonly understood as:
- for granular deposits it is a combination of permeable and impermeable layers (interlayers), their spatial, geometric and filtration-capacitive parameters, the nature of heterogeneity;
- for massive fracture deposits, this is a set of blocks of impermeable (undestructed) rock and areas of permeable (decompressed, destroyed) rock, fracture faults connecting these areas, their spatial, geometric and filtration-capacitive parameters, the nature of heterogeneity.

 There is a method of studying the internal structure of deposits by conducting seismic studies [Areshev EG, Gavrilov VP, Dong Ch.L., N. Zao, Popov OK and others. Geology and oil and gas potential of the Sund shelf foundation, Moscow, Oil and gas , 1997, pp. 54-56, 75, 201]. Seismic exploration quite clearly discourages the roof and bottom of the strata, traces their thickness, shows the location of water and gas-oil contacts and the presence of inhomogeneities in granular reservoirs.

 However, in massive fracture deposits, the density difference between solid and oil-saturated rocks does not exceed 3%, therefore, the known method allows to beat off only the roof of the deposit, and inside it, although it reveals some areas, it is impossible to accurately relate them to areas of decompression or to zones of increased fracturing.

 Also known are methods of geophysical studies of well walls, by which productive and non-productive formations are separated in granular reservoirs and their reservoir properties are determined [Areshev EG, Gavrilov VP, Dong Ch.L., N. Zao, Popov O.K. et al. Geology and oil and gas potential of the Sund shelf foundation, Moscow, Oil and gas, 1997, pp. 218-250]. In Russia and abroad, various GIS processing programs are used for complex granular sedimentary complex reservoirs and carbonate sections. These are programs such as GLOBAL, FACIOLOG, CYBERLOG, etc. But they require either preliminary stratification of the section (GLOBAL) or separation of the section according to facial features (FACIOLOG), which makes them unsuitable for studying massive fracture deposits.

 These methods make it possible to determine the parameters of the near-wellbore zone only within a few centimeters only in sedimentary (granular) reservoirs and do not provide for the identification and determination of parameters of fractured reservoirs with large faults of large length and large cavities. On the other hand, the well data obtained as a result of the use of well logging data characterize on the scale of the reservoir only the places of their point sections. For granular reservoir deposits, such information on point sections allows one to successfully apply various interpolation methods between wells and to accurately determine the structure of the reservoir. But in massive fractured deposits, where the inflow intervals in neighboring wells in the same reservoir can vary in height up to 1000 meters, the well-known interpolation methods between wells become unacceptable, which makes it difficult to use well log data to study the internal structure of deposits in such cases.

 Of the known methods, the closest to the proposed one is the method of thermohydrodynamic studies, including measuring the temperature, pressure, and interval flow rate along the wellbore of a working well, determining the geothermal gradient, the actual value of the Joule-Thompson coefficient, as well as the values of the calorimetric effects of mixing the interval flows with the upward flow along the wellbore [Chekalyuk EB Thermodynamics of the oil reservoir, Moscow, Nedra, 1965, pp. 184-187]. According to these data, in accordance with the known method, a reference temperature profile is constructed by calculating temperature jumps at the identified inflow points for the conditions of horizontal fluid flow. The calculated temperature profile and the measured along the wellbore in granular reservoirs with flat radial horizontal filtration, as a rule, coincide with a field accuracy of 10-15%. This confirms that, in fact, under these conditions, fluid filtration proceeds along a horizontal formation with temperatures corresponding to the geothermal gradient and standard values of the Joule-Thompson coefficient. Also, for various types of research (barometry, thermometry and flow metering), permeable (working) and impermeable (non-working) formations, their working capacities, heterogeneities and other parameters of the internal structure of granular deposits are uniquely identified.

 However, the known method as applied to massive fracture deposits does not provide an investigation of their internal structure and does not allow to identify fracture faults and determine their parameters, since the calculated and measured temperature profiles in these deposits do not coincide and their difference is beyond the permissible production error. That is, the method of interpreting thermohydrodynamic studies is suitable only for granular collectors.

 The objective of the invention is to provide a method for studying the internal structure of gas and oil deposits, providing recognition of fractured deposits and detection of fractured faults while obtaining information about the direction of filtration by fracture fractures from the supply area to the wellbore, determining the geometric shape of these fracture fractures and depths of the location of supply areas.

 The problem is achieved in that in a method for studying the internal structure of gas and oil deposits, including opening the reservoir by drilling with subsequent selection of fluid from the well, measuring its temperature, pressure and flow rate from the well in different modes of the well’s operation, determining the geothermal gradient, calorimetric values the effects of mixing the interval inflows with the flow upward along the borehole and the actual Joule-Thompson coefficient, according to the invention, according to the geothermal values The gradient, Joule-Thompson coefficient, interval flow rates and the corresponding values of the calorimetric mixing effects determine the reference thermogram for the conditions of horizontal fluid flow, compare it with the actual thermogram and determine the presence of fracture faults crossing the borehole by the anomalies of the actual temperature jumps in the places of flow from the reference , then, by the signs of anomalies, the direction of filtration is determined by fracture cracks from the supply area to the wellbore, and by No other anomalies determine the depth of the location of the supply areas and the geometric shape of the fracture cracks.

 The essence of the method is illustrated by drawings, which show the main cases of fluid flow through fractures of fractures in the well.

 Figure 1 shows the case of inflow into the well along a fracture fracture during oil filtration in the bottom-up direction and the actual and reference thermograms corresponding to this case.

 In FIG. Figure 2 shows the case of inflow into the well along only one fracture fracture during oil filtration in the top-down direction and the actual and reference thermograms corresponding to this case.

 Figure 3 shows the case of inflow into the well from bottom to top along the fracture of a fracture of complex geometric shape and the actual and reference thermograms corresponding to this case.

 Figure 4 shows the case of inflow into the well from top to bottom along the fracture of a fracture of the same complex geometric shape and the actual and reference thermograms corresponding to this case.

 In practice, in massive fissure deposits with a thickness of up to 2.0 km, various intermediate variants in the most various combinations may take place (extreme variants are shown in the drawings).

 The method is as follows.

After opening the oil reservoir by drilling it is put into operation with the selection of oil. They begin to carry out the mandatory complex of thermohydrodynamic studies, which also includes the so-called operational logging. During production logging, the temperature, pressure and / or flow rate are measured along the wellbore in the process of oil extraction at different modes of operation of the well. According to the results of these studies, the values of oil consumption at the points of inflows, bar and thermograms are determined. The value of the geothermal gradient α [ ^o C / m], the calorimetric effects of mixing the interval inflows with the flow upstream along the wellbore, and the actual value of the Joule-Thompson coefficient are also determined.

 Then proceed to the analysis of the obtained actual thermograms. It was established that information from such an analysis about the presence of fracture faults, the direction of filtration by fracture faults from the supply area to the wellbore, the depths of the supply areas and the geometric shape of the fracture fractures can be obtained by examining the well in 3-4 modes of operation with the corresponding thermograms .

 Below is an algorithm for interpreting the obtained thermograms.

 The first step is the analysis of actual and reference thermograms.

 Based on the obtained values of the geothermal gradient, the Joule-Thompson coefficient, the interval (or total) flow rates and the corresponding values of the calorimetric mixing effects, the reference thermogram is determined, which should be with a horizontal oil flow. By combining the reference thermogram is compared with the actual. And if anomalies of temperature jumps in the places of inflow from the reference ones are established on the actual thermogram, then the presence of fracture faults crossing the wellbore is recorded by this sign (Fig. 1-4). In this case, we can confidently assume that the wellbore has crossed a strongly inclined fracture fault or faults along which oil flows to the well. That is, at the first step of the analysis, it is possible to reliably determine the type of collector - homogeneous granular (when the reference and actual thermograms coincide) or heterogeneous fracture with the presence of large fracture cracks (when the reference and actual thermograms are different).

In the second step of the analysis of the actual and reference thermograms, the direction of oil filtration to the wellbore is determined by the detected fracture cracks. When measuring temperature along the wellbore of a working well in the place of oil inflow, either a positive (Fig. 1) or negative (Fig. 2) temperature jump can be obtained. Moreover, in Figs. 1-4, there are cases of oil entering the well through only one fracture fault, although in reality much more inflow points can be detected. It should be noted that, above each inflow point, oil rises up the wellbore, cooling as it moves due to the colder walls of the well, and then this flow is mixed with a new inflow from the well and so on. With a positive temperature jump (Fig. 1), the inequality Δt _fact > Δt can be _calculated only for one reason - a hotter oil appeared at the inflow point with a temperature exceeding the temperature due to the existing Joule-Thompson coefficient, i.e., from deeper reservoir marks. Therefore, an unambiguous conclusion is drawn about the inflow of oil to the well along the bottom-up fault. An additional confirmation of this is the increase in the values of positive temperature jumps with an increase in oil withdrawal from the well (Fig. 1). With a negative temperature jump (Fig. 2), the inequality Δt _fact <Δt _calculation can be for only one reason - a cooler oil appeared at the inflow point with a temperature different from the temperature due to the existing Joule-Thompson coefficient, i.e., from higher elevation . Consequently, an unambiguous conclusion is drawn about the inflow of oil to the well along the top-down fault fracture. The same additional confirmation of this is the increase in the values of negative temperature jumps with an increase in oil withdrawal from the well (Fig. 2).

 The third step in the analysis of actual and reference thermograms is to determine the depth of the location of the nutrition areas.

здесь ε_факт - фактический коэффициент Джоуля-Томпсона, определяемый по результатам термогидродинамических исследований;
ΔP_факт - депрессия при данном исследовании;
Δt_расч - расчетный (эталонный) скачок температуры в точках притока;
Q_n - дебит очередной точки притока;
Δt_{восх.потока} - приращение температуры восходящего потока;
ΣQ - сумма дебитов (снизу-вверх до рассчитываемой точки притока).The values of the obtained anomalies are determined:
δ = Δt _fact -Δt _calculation , (1)
where for the inflow - 1 (the lowest):
Δt _calc = ε _fact • ΔP _fact , (2)
and for the inflow - 2 and the rest (when counting from the bottom up):

here ε _fact is the actual Joule-Thompson coefficient determined by the results of thermohydrodynamic studies;
ΔP _fact - depression in this study;
Δt _calculation - calculated (reference) temperature jump at the inflow points;
Q _n - flow rate of the next inflow point;
Δt _{asc. Flow} - increment of the temperature of the upward flow;
ΣQ - the sum of flow rates (from bottom to top to the calculated inflow point).

где T_k, T_o, T_m - температура породы на высоте притока, температура флюида в области питания, температура флюида, поступающего из микротрещин в стенках трещины;
Q_k и Q_o - расход флюида в точке притока и в области питания;
c_k, c_o, c_m - теплоемкость породы на высоте притока, теплоемкость флюида в области питания, теплоемкость флюида, поступающего из микротрещин;

удельный приток флюидов из стенок трещины;

удельный поток тепла на стенках трещины;
ΔH - разность высот точки притока и области питания;
β(x) - угол наклона трещины в точке x;
l - длина трещины.And further, by the values of the anomalies for each inflow point, from the relations (4) and (5) determine the depth of the feeding area:

where T _k , T _o , T _m - rock temperature at the inflow height, fluid temperature in the feeding area, temperature of the fluid coming from microcracks in the walls of the crack;
Q _k and Q _o - fluid flow rate at the inflow point and in the supply area;
c _k , c _o , c _m — heat capacity of the rock at the inflow height, heat capacity of the fluid in the feeding area, heat capacity of the fluid coming from microcracks;

specific influx of fluids from the walls of the fracture;

specific heat flux on the walls of the crack;
ΔH is the height difference between the inflow point and the feeding area;
β (x) is the angle of inclination of the crack at point x;
l is the length of the crack.

 In these ratios, the specific heat flux depends on the geometry of the crack, its roughness, the temperature of the oil and the walls of the crack, thermal properties, and flow rate. Therefore, in practice, a solution is found only by numerical methods using electronic computer technology. If necessary, to narrow the range of possible solutions, it is possible to use well-known equations of fluid flow in crevices and pore media.

 The fourth step of the analysis of the actual and reference thermograms is carried out to clarify the geometry of the fracture faults and identify cases of sharp bending of the conductive paths (Fig. 3 and 4).

 For example, two fracture faults intersected in zone A, which may be higher (Fig. 3) or lower (Fig. 4) the inflow point into the well. Accordingly, the supply area can be either lower (Fig. 3) or higher (Fig. 4) of the inflow point. In this case, the temperature jumps are not higher than the reference ones (Fig. 1), as they should be in the case of rectilinear fractures, and lower (Fig. 3). Or vice versa, temperature jumps are not lower than the reference ones (Fig. 2), as in the case of rectilinear fractures of faults, but higher (Fig. 4). On this basis, that is, by the nature of changes in temperature anomalies in thermograms at different well operation modes, the geometrical shape of the fracture fault is determined and, based on relations (4) and (5), the depth of the location of the supply area is specified.

 The method is implemented in the field of Southeast Asia, where a large oil field (White Tiger) was discovered on the shelf of the South China Sea in fractured crystalline granites (foundation). This method was applied at 6 wells, where the crystalline foundation was opened by drilling to a depth of 2000 meters from the roof. The production string went down to the roof of the foundation, and in the foundation itself, the wellbore remained open. After putting these wells into operation, a set of thermohydrodynamic studies was performed, including production logging (i.e., measurements along the wellbore of a working well over the entire open interval of the foundation of temperature, pressure and / or flow). For all these wells, the lower boundaries of the tributaries were clearly and unequivocally determined using thermograms, and the geothermal gradients of the space surrounding each well were determined using idle sumps with a stationary thermal field. For identified inflow points, reference thermograms were calculated. After analyzing the differences between the reference and actual thermograms, the direction of oil filtration along each fault crack was revealed, the geometric shape of the fault cracks, the location of the supply areas were determined. So, the length of the cracks ranged from 40 to 620 meters, and the boundaries of the supply areas (i.e., areas of crushed permeable rock) were at a distance from the axis of the well to 300 meters.

In FIG. Figure 5 shows the actual thermograms in three operating modes and fragments of 3-reference thermograms for one of the wells of the White Tiger field (due to the confidentiality of the field data of Fig. 5, it was done rather conditionally - that is, the depths of the inflows and the absolute temperature values of the oil entering the well are not indicated). The table shows the results of operational logging and calculation results. The geothermal gradient according to the results of actual thermograms is 0.03 ^o C / m. The actual Joule-Thompson coefficient according to the results of thermohydrodynamic studies is 0.4 ^o C / MPa. According to the values of the actual temperature jumps at different well operating modes, significantly exceeding the reference ones, it can be seen that the well crossed two fracture faults, and the increment sign indicates the direction of oil movement from the supply area to the wellbore. Consequently, inflow 1 flows from the bottom up, and inflow 2 flows from the top down. Since the values of increments of anomalies at different operating modes increase with increasing sampling, the geometric shape of these cracks is straight faults, at the end of which there are feeding areas. Average distances from supply points to feeding areas:
- 237 m below inflow point 1 and
- 125 m above tributary point 2.

Claims (1)

 A method for studying the internal structure of gas-oil deposits, including opening a reservoir by drilling with subsequent selection of fluid from the well, measuring its temperature, pressure and flow rate along the wellbore during different modes of the well’s operation, and determining the geothermal gradient, the calorimetric effects of mixing the interval inflows with ascending wellbore flow and the actual value of the Joule-Thompson coefficient, characterized in that according to the values of the geothermal gradient, the coefficient J oul-Thompson, the interval flow rates and the corresponding values of the calorimetric mixing effects determine the reference thermogram for the conditions of horizontal fluid flow, compare it with the actual thermogram, and the anomalies of the actual temperature jumps in the places of inflow from the reference record the presence of fracture faults crossing the wellbore, then anomalies determine the direction of filtration by fracture cracks from the supply area to the wellbore, and the depths p are determined by the magnitude of the anomalies memory location of nutrition and the geometric shape of the fault fissures.

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