Geological basis for designing the development of oil and gas fields. Lectures on oil field development
Development design and development process is stage-based. The technological design documents are the following:
1. project for trial operation of deposits and wells.
2. technological schemes of pilot industrial development (for gas - operation).
3. technological development schemes.
4. development projects.
5. updated development projects (before development).
6. development analysis.
Oil and gas fields are put into development on the basis of the above documents. The conditions and procedure for putting fields into development are determined by the “Rules for the development of oil, gas and gas condensate fields.”
The first project document for the development of hydrocarbon deposits is a trial operation project (PE). Trial operation is carried out to obtain initial data for drawing up a technological scheme for pilot industrial development (for oil deposits) and pilot industrial operation (for gas deposits). They are compiled for 10-15 years. They substantiate the technological and technical-economic indicators of deposit development.
After obtaining additional information about the deposit and reservoir, a reservoir development project is drawn up based on the recalculation of reserves.
The project justifies all indicators for the development of the deposit until the end of the field's life.
When actual development indicators deviate significantly from the design ones, an updated development project is drawn up.
At the last stage of field development, a pre-development project is drawn up. Its main goal: justification of measures to increase oil recovery.
There are 4 stages (see Fig. 40), and in gas mode there are 3 stages.
1. Development of an object (deposit) - is characterized by an increase in oil production, an increase in the number of wells and ends when the design oil production is achieved.
2. Main stage - characterized by a high, stable level of oil production. By the end of the stage, there is an increase in the water cut of the product, while 40-60% of the recoverable reserves are recovered.
3. A sharp decrease in oil production - the number of production wells decreases (due to their watering), flow rates fall, and the amount of produced water increases. At the end of the stage, 80-90% of recoverable reserves are produced.
4. The final stage - characterized by low well flow rates and high water cut of wells and production in general.
Rice. 40.
Geological and field control over the process of developing hydrocarbon deposits
Purpose of control: necessary to obtain sufficient quantity information to make a decision on the need to regulate development.
The following control methods are distinguished:
1. Hydrodynamic methods - allow you to study the productivity of layers and other geological and physical parameters using deep equipment.
2. Geophysical methods - allow you to control the position of contacts and the nature of the current fluid saturation of the formation.
3. Physico-chemical methods that allow you to control the chemical composition and physical properties of oil, gas and water.
In the process of development control, initial information is obtained for development analysis. The main purpose of the analysis is to compare design and actual development indicators. Development analysis is carried out by oil and gas production departments (OGPD) and gas production departments (GPU). Large and medium-sized deposits are analyzed once every 5 years with the involvement of research institutes (SRI). In this case, the change over time of the following indicators is studied:
Oil production
Liquid extraction
Gas production
Injection of water and gas
Well stock (various purposes)
Reservoir pressure
Contact position.
When conducting a development analysis, the following graphic documents are compiled:
Development map (total production map) - compiled on the basis of a structural map, which shows the positions of oil and gas content contours, the positions of wells various categories. For each well, a pie chart of the total (cumulative) production of oil, gas, and water is compiled.
Map of the current state of development (current production) - in the form of pie charts, the current production rate of wells is shown on the date of compilation of the map. Otherwise it is similar to the development map.
Development schedule - changes in development indicators over time.
Operation schedules - the dynamics of the main indicators of the development of an individual well.
Isobar map - monitoring pressure changes within the reservoir.
Product water-cut map - the study of reservoir water-cut and movement of OWC, is compiled in isolines of the percentage of water in the produced fluid.
Gas factor map - when the reservoir operates in dissolved gas mode or gas pressure mode. They allow you to control the development process. An increase in the gas factor is observed in zones of sharp decrease in reservoir pressure.
When deviations of actual indicators from the design ones are identified, the process of deposit development is regulated.
A borehole is a cylindrical mine opening, constructed without human access and having a diameter many times smaller than the length. The beginning of the well is called the mouth, the cylindrical surface is called the wall or trunk, and the bottom is called the bottom. The distance from the mouth to the bottom along the axis of the well determines the length of the well, and according to the projection of the axis onto the vertical, its depth. The maximum initial diameter of oil and gas wells usually do not exceed 900 mm, and the final one is rarely less than 165 mm.
Well drilling is a complex technological process of building a shaft drilling wells, consisting of the following main operations:
Deepening wells by destroying rocks with a drilling tool;
Removing drilled rock from a well;
Fastening the wellbore during its deepening with casing columns;
Carrying out a complex of geological and geophysical work to study rocks and identify productive horizons;
Lowering to the design depth and cementing the last (production) casing.
Based on the nature of rock destruction, mechanical and non-mechanical methods are distinguished. drilling. Mechanical methods include rotational methods (rotary, turbine, jet-turbine drilling and drilling using an electric drill and downhole motors), in which the rock is destroyed as a result of a rock-cutting tool (drill bit) pressed to the bottom, and shock methods. Non-mechanical drilling methods (thermal, electrical, explosive, hydraulic, etc.) have not yet found wide industrial application.
When drilling for oil and gas, the rock is destroyed by drill bits, and the bottom of the well is usually cleared of drilled rock by streams of continuously circulating drilling fluid ( drilling fluid), less often the face is purged with a gaseous working agent.
Wells are drilled vertically (deviation up to 2¸3°). If necessary, inclined drilling is used: directional, cluster, multi-hole, double-barreled).
Wells are deepened by destroying the bottom over the entire area (without core sampling) or the peripheral part (with core sampling). In the latter case, a rock column (core) remains in the center of the well, which is periodically raised to the surface to study the rock section passed through.
Wells are drilled on land and offshore using drilling rigs.
The purposes and purposes of boreholes are different. Production wells are laid in a field that has been fully explored and prepared for development. The production category includes not only wells with which oil and gas are extracted (production wells), but also wells that allow for the effective development of a field (appraisal, injection, observation wells).
Appraisal wells are designed to clarify the operating mode of the reservoir and the degree of depletion of sections of the field, and to clarify the scheme for its development.
Injection wells are used to organize peripheral and intracircuit injection of water, gas or air into the production formation in order to maintain reservoir pressure.
Observation wells are constructed to systematically monitor the field development regime.
The design of a production well is determined by the number of rows of pipes lowered into the well and cemented during the drilling process for successful drilling of wells, as well as equipment her slaughter.
The following rows of pipes are lowered into the well:
2. Conductor - for fastening the upper unstable intervals of the cut, isolating horizons from groundwater, installation at the mouth of the blowout preventer equipment.
3. Intermediate casing string (one or more) - to prevent possible complications when drilling deeper intervals (when drilling the same type of section of strong rocks, the casing string may be absent).
4. Production string - for isolating horizons and extracting oil and gas from the reservoir to the surface. Operational the column is equipped with elements of column and casing equipment (packers, shoe, check valve, centralizer, thrust ring, etc.).
A well design is called single-string if it consists only of operational column, two-column - in the presence of one intermediate and production column, etc.
The wellhead is equipped with a casing head (column piping). The column head is designed to isolate the intercolumn spaces and control the pressure in them. It is installed on a thread or by welding on the jig. Intermediate and operational the columns are suspended on wedges or a coupling.
At the fields Western Siberia Cluster drilling is common. Cluster drilling is the construction of groups of wells from a common base of a limited area on which a drilling rig and equipment. It is produced in the absence of convenient sites for drilling rigs and to reduce the time and cost of drilling. The distance between wellheads is at least 3 m.
Reservoir energy is the totality of those types of mechanical and thermal energy of fluid (oil, gas and water in rocks, characterized by fluidity) and rock that can be practically used in the selection oil and gas. The main ones:
1. Pressure energy of the edge waters of oil deposits and gas.
2. Energy of elastic compression of rock and fluid, including gas, released into the free phase from the dissolved state when the pressure decreases.
3. Part of the gravitational energy of the overlying strata, spent on plastic deformations of the reservoir caused by a decrease in reservoir pressure in the reservoir as a result of fluid withdrawal from it.
4. The heat of the fluid carried to the surface during well operation. Not all the energy of the formation is practically significant, but only that part of it that can be used with sufficient efficiency during the operation of wells.
Development of mineral deposits - a system of organizational and technical measures for production minerals from the subsoil. Development oil And gas deposits are carried out using boreholes. Sometimes a mine is used oil production(Yaregskoe oil deposit, Komi Republic).
Introduction ..................................................... ........................................................ ...................................3
1. Basics of development of oil and gas fields ........................................................... .......5
1.1. Distribution of hydrocarbons along the height of the deposit ...........................................................5
1.2. The concept of the contours of oil-bearing capacity and water-oil zone of the deposit..................................... 7
1.3. Oil field development modes .................................................................... .....8
1.4. Technologies for influencing oil deposits .................................................................... ..............eleven
1.5. Displacement of oil from reservoirs by various agents....................................14
2. Debitometry and flow metering .................................................... ...........................................17
2.1. Barometry ........................................................... ........................................................ ..........19
2.2. Thermometry ..................................................... ........................................................ ........20
3. Definition performance characteristics productive formations .......................22
3.1. Determination of flow rate and injectivity of wells .................................................... .......22
3.2. Determination of the working thickness of the formation ...................................................... ......23
3.3. Determination of productivity coefficient and reservoir pressure................24
4. Studying the technical condition of wells ...................................................... ........................26
Bibliography …............................................... ........................................................ ................27
Introduction
Successful development of oil and gas fields is determined by the choice of development system. During the development process, there is a need to monitor and clarify the state of deposits, taking into account new information about the geological structure obtained during their drilling and operation. The high efficiency of waterflooding systems is due to the fact that by injecting water they increase reservoir pressure, as a result of which oil is more efficiently squeezed out of the pore space to production wells. The main advantage of such systems is that during waterflooding the intensity of oil extraction from the reservoir increases. On the other hand, such methods of maintaining reservoir pressure pose a danger of waterflooding of productive formations. A situation may arise when the injected water “gets ahead” of the oil, moving through the most permeable areas. In this case, part of the oil in the reservoir is isolated in so-called “pillars”, which in turn will complicate its extraction. It is very important to be able to regulate waterflooding processes. Control methods based on changes in water injection and oil withdrawal rates require information about current changes in the reservoir. Waterflood control is one of the most important and most difficult development problems oil fields. Currently, more than 70% of oil is produced from fields that are operated while maintaining reservoir pressure through waterflooding. One of the main issues in the rational development of oil fields with a natural elastic-water-pressure regime, as well as with the use of contour and intra-circuit flooding, is the control and regulation of the advancement of oil-bearing contours.
The purpose of geophysical control is to obtain information about the state and changes occurring in productive formations during their operation. At the same time, geophysical methods mean all methods ever carried out on the territory of the field. Currently, development control has developed into a separate direction with its own methodology, methods and equipment. Using these methods allows you to solve the following problems:
1. Determine the position and monitor the progress of OWC and GOC in the process of displacing oil from the reservoir;
2. Control the movement of the injection water front across the formation;
3. Assess the coefficients of current and final oil saturation and oil recovery of formations;
4. Study the recovery and injectivity (the ability of the formation to accept injected water) of wells;
5. Establish the state of fluids in the wellbore;
6. Identify places where water enters the well and flows of oil and water in the annulus;
7. Evaluate technical condition production and injection wells;
8. Study the operating mode of technological equipment of production wells;
9. Clarify the geological structure and oil reserves.
Until the end of the 40s of the 20th century, OWC was studied mainly using electrical logging data. This, naturally, imposed its limitations: research was carried out only in open wells, therefore, geologists received information about the initial position of the water-oil contact, the initial oil-bearing contour, oil saturation, and perforation intervals. The movement of the internal oil-bearing contour could only be traced by the appearance of water in production wells.
In the 50s of the 20th century, with the introduction of radioactive logging, a real opportunity arose to create methods for separating oil-bearing and aquifer reservoirs in cased wells. However, the results of these methods are reliable only if it is established that water does not enter the well from other formations due to a violation of the column or well plugging. When monitoring development, the main thing is the difference in the neutron properties of mineralized formation water. The most favorable conditions exist in places with mineralization of formation water of more than 100 g/l (Devonian and Carboniferous layers of the Volga-Ural oil and gas province ~300 g/l). The situation is worse with a mineralization of 20-30 g/l (Western Siberia). In this case, they resort to pulsed neutron methods (PNN), which significantly increase sensitivity to the neutron properties of the formation. Along with stationary and pulsed methods, methods of radio-, thermometry, acoustic logging, debitometry, as well as special interpretation techniques have become widespread when monitoring development.
Astrakhan State Technical University
Department of Geology of Oil and Gas
LECTURE COURSE
by discipline:
Geological basis for the development of oil, gas and gas condensate fields
Introduction
The lecture course “Geological foundations of the development of oil, gas and gas condensate fields” consists of three interrelated parts:
1.Fundamentals of oil and gas field geology 2.Calculation of reserves and assessment of hydrocarbon resources .Geological basis for the development of oil and gas fields. the main objective studying this discipline is geological support effective development oil and gas. The first part shows that oil and gas field geology is a science that studies oil and gas deposits in a static and dynamic state as sources of hydrocarbon raw materials. Oil and gas field geology as a science originated at the beginning of the last century (1900) and has gone through a long path of development. This path is divided into several stages, differing in the range of issues to be resolved, methods and means of solving them. The modern stage, which began in the late 40s of the twentieth century, is characterized by the widespread use of methods of influencing productive formations in the development of oil deposits. The results of oil and gas field geology studies serve as the geological basis for the design and regulation of hydrocarbon deposits. Oil and gas field geology considers an oil and gas reservoir before development as a static geological system consisting of interconnected elements: a natural reservoir of a certain shape with a specific void volume; formation fluids; thermobaric conditions. The developed hydrocarbon deposit is considered as a complex dynamic system that changes its state over time. The second part of the manual provides definitions of groups and categories of reserves and resources of oil, gas and condensate. Methods for calculating reserves and assessing resources of oil, gas, condensate and associated components are discussed in detail. To calculate oil and gas reserves, a comprehensive geological study of the field with which oil and gas deposits are associated and knowledge of the specific conditions of their occurrence is necessary. The third part provides the basic concepts of geological and field support for the development of oil and gas deposits. Systems for developing multi-layer oil and gas fields and a separate production facility are considered, systems for developing oil fields with maintaining reservoir pressure are also given, methods of geological and field control over the process of developing hydrocarbon deposits and methods for enhancing oil recovery are discussed in detail. The course ends with the topic: “Protection of subsoil and the environment in the process of drilling wells and developing hydrocarbon deposits.” Thus, the main objectives of this discipline are as follows: detailed study of hydrocarbon deposits geological justification for the choice of development systems control over the development of oil and gas deposits in order to justify and select measures to manage development processes generalization of experience in developing oil and gas fields planning of oil, gas, condensate production; calculation of reserves of oil, gas, condensate and associated components; protection of subsoil and the environment during the drilling of wells and exploitation of hydrocarbon deposits. Each oil, gas and condensate field is put into development in accordance with a project document drawn up by a specialized research organization and providing for the development system that, from a national standpoint, is the most rational for a given field. Development of an oil (gas) deposit is a set of works carried out to control the process of movement of formation fluids through the formation to the bottoms of production wells. Development of an oil (gas) deposit includes the following elements: Ø number of wells per deposit; Ø placement of wells on deposits; Ø procedure (sequence) for putting wells into operation; Ø well operating mode; Ø reservoir energy balance; The system for developing an oil (gas) deposit is the drilling of the deposit with production wells according to a specific scheme and an accepted plan, taking into account measures to influence the formation. A development system is called rational when, with the fullest use of reservoir energy and the application of measures to influence the reservoir, it ensures maximum extraction of oil and gas from the subsoil in the shortest possible time at minimal cost, taking into account the specific geological and economic conditions of the region. The development of the oil and gas industry in Russia has a history of more than a century. Until the mid-40s of the 19th century, the development of oil fields was carried out only using the natural energy of the deposits. This was due to insufficient high level development techniques and technologies, as well as the lack of objective prerequisites for a radical change in this approach to development. Since the mid-40s, as a result of the discovery of new oil and gas bearing areas, the development of the oil industry has been associated with the development of platform-type fields with large sizes oil-bearing areas, significant depth of productive strata and ineffective natural regime - elastic water pressure, quickly turning into the dissolved gas regime. Russian scientists and industrial workers in short term substantiated theoretically and proved in practice the need and possibility of using fundamentally new development systems with the artificial introduction of additional energy into productive oil reservoirs by injecting water into them. The next step in scientific and technological progress was the search for processes that would further increase the efficiency of developing oil deposits. IN last years Scientific and engineering thought is working to create ways to increase the efficiency of waterflooding. At the same time, new methods of influencing oil reservoirs, which are based on fundamentally new physical and chemical processes of displacing oil from reservoir rocks, are being sought and tested, industrially tested and introduced. The development of gas deposits, taking into account the high efficiency of their natural regimes, has so far been carried out using natural energy without artificial influence on the formation. In the last period, gas condensate fields play a major role in the balance of hydrocarbon deposits. And here, one of the most pressing tasks is the search for economically feasible methods for developing gas condensate fields that prevent loss of condensate in the formation. Section 1: “Methods for studying the geological structure of the subsoil and hydrocarbon deposits in field areas”
Chapter 1. Geological observations and research when drilling wells
Hydrocarbon deposits are always isolated from the surface and are located at different depths - from several hundred meters to several kilometers - 5.0-7.0 km. The main goal of geological observations of the well drilling process is to study the geological structure of deposits and individual productive horizons and the fluids saturating these horizons. The more complete and better this information is, the better the field development project will be. The process of drilling wells must be carefully controlled geologically. Upon completion of drilling a well, the geologist should receive the following information about it: geological section of the well, lithology of the work completed; position in the section of reservoir rock wells; nature of saturation of reservoir rocks, what they are saturated with, what formation fluid technical condition of wells (well design, pressure and temperature distribution along the wellbore) Particularly careful geological control should be carried out when drilling exploration wells, on the information of which the drilling of production wells for oil and gas will be based. Methods for studying sections of drilled wells are divided into 2 groups: 1.direct methods 2.indirect methods Direct methods allow us to directly obtain information about the passed section of rock lithology, material composition, position of reservoirs and their saturation. Indirect methods provide information about the section of wells based on indirect signs, namely the relationship of their physical properties with the same characteristics as resistance to the passage of electric current, magnetic, elastic. Direct methods are based on studying: rock samples taken from the well during the drilling process (core, cuttings, side soil carrier) sampling of fluids during incidental and stationary testing. sampling of formation fluid when testing in a production casing gas logging monitoring complications during the drilling process (collapses of the well walls, loss of drilling fluid, manifestations of formation fluid) Indirect methods make it possible to judge the material composition of a well section, reservoir properties, the nature of saturation of reservoir rocks with formation fluid based on indirect signs: natural or artificial radioactivity, the ability of a rock to conduct electric current, acoustic properties, magnetic, thermal. Core study Core material is the main information about a well. The choice of drilling interval with core selection depends on the geological objectives. In new, still poorly studied fields, when drilling the first wells, it is recommended to carry out continuous core sampling in conjunction with complexes of geophysical research. For deposits where the upper part of the section has been studied, and the lower part is still subject to study, in the studied interval, core should be taken only at the contacts of formations, and in the unstudied interval, continuous core sampling should be carried out (see Fig. 1) No core is taken from production wells and all observations are based on logging information and observations of the drilling process. In this case, a core is taken from the productive horizon for its detailed study. When studying the core, it is necessary to obtain the following information about the well: presence of signs of oil and gas material composition of the rocks and their stratigraphic affiliation reservoir properties of rocks structural features of rocks and possible conditions of their occurrence Rock samples that are sent to the laboratory to study the hydrocarbon content are paraffinized (wrapped in gauze and immersed in molten paraffin several times, each time allowing the paraffin soaked in the gauze to harden). The waxed samples are then placed in metal jars with flat lids. The samples are covered with cotton wool or soft paper and sent to the laboratory for testing. The remaining part of the core is delivered to the core storage facility. Signs of oil and gas in cores must first be studied at the drilling site using fresh samples and fractures and then in more detail in the field management laboratory. Fig.1 - a - drilling without core sampling; b - drilling with core sampling The intervals for drilling a well with core sampling are determined by the purpose of drilling and the degree of study of the section. All deep wells are divided into 5 categories: - reference, parametric, search, exploration, operational. Reference wells are drilled to study the general geological structure in new territories that have not been explored by deep drilling. Core sampling is carried out evenly throughout the entire wellbore. In this case, drilling with core sampling ranges from 50 to 100% of the total depth of the wells. Parametric wells are drilled to study the geological structure and oil and gas potential of new territories, as well as to link geological and geophysical materials. Drilling with core sampling is at least 20% of the total depth of the well. Exploration wells are drilled to search for oil and gas deposits. Core sampling here is carried out in the intervals of occurrence of productive horizons and contacts of various stratigraphic units. With core sampling, no more than 10-12% of the well depth is covered. Exploration wells are drilled within areas with established oil and gas potential in order to prepare deposits for development. Core is taken only in intervals of productive horizons within 6-8% of the well depth. Development wells are drilled to develop oil and gas deposits. Core, as a rule, is not selected. However, in some cases, to study a productive formation, core sampling is practiced in 10% of wells evenly spaced over the area. Intervals with core sampling are carried out with special bits - core bits, which leave undrilled rock, called core, in the center of the bit and lift it to the surface. The drilled part of the rock is called cuttings, which is carried to the surface by a stream of drilling fluid during the drilling process. Selection of rock samples using lateral soil carriers This method is used when it was not possible to select a core in the planned interval. In addition, even when, as a result of geophysical research after completion of drilling, horizons of interest from the point of view of oil and gas content have been identified, but this interval is not illuminated by core. Using a side soil carrier, a rock sample is taken from the borehole wall. Currently, 2 types of partings are used: 1.shooting side soil carriers 2.drilling side soil carriers The principle of operation of a shooting ground carrier: a garland of cartridges descends on pipes against the interval of interest to us. When an explosion occurs, the shell casings crash into the walls of the well. When lifting the tool, the sleeves on steel leads with captured rock from the borehole wall rise upward. Disadvantages of this method: we get crushed rock small sample The striker does not penetrate into hard rock loose rock spills out Drilling side soil carriers - imitation of horizontal drilling, we obtain small volume samples. Sludge selection During the drilling process, bits destroy rock and a stream of drilling fluid carries rock fragments to the surface. These fragments, rock particles are called slurry. On the surface they are selected, washed from the drilling fluid and carefully studied, i.e. determine the material composition of these fragments. The research results are plotted in accordance with the depth of sludge sampling. Such a diagram is called a slurry diagram (see Fig. 2). During the drilling process, cuttings are sampled in all categories of wells. Rice. 2 Sludge chart Geophysical methods for well explorationare studied independently when studying the GIS course. Geochemical research methods Gas logging During the process of drilling wells, the drilling fluid washes the productive formation. Oil and gas particles enter the solution and are carried along with it to the surface, where a special sampler degasses the drilling fluid, studying the content of light hydrocarbons and the total content hydrocarbon gases. The research results are plotted on a special gas logging diagram (see Fig. 3). Fig.3 Gas logging diagram If the presence of a productive formation is determined during the drilling process, the gas sample is examined using a chromatograph for the content of individual components directly at the borehole. Mechanical logging The rate of penetration is studied, the time spent on drilling 1 m is recorded and the results are plotted on a special form (see Fig. 4). Rice. 4. mechanical logging form Calipermetry Calipermetry -continuous determination of the well diameter using a caliper. During the drilling process, the diameter of the hole differs from the diameter of the bit and varies depending on the lithological type of rock. For example, in the interval of occurrence of permeable sandy rocks, a narrowing occurs, a decrease in the diameter of the well, as a result of the formation of a clay cake on the walls of the well. In the interval of occurrence of clayey rocks, on the contrary, there is an increase in the diameter of the well compared to the diameter of the bit as a result of saturation of the clayey rocks with drilling fluid filtrate and further collapse of the well walls (see Fig. 5). In the interval of carbonate rocks, the diameter of the well corresponds to the diameter of the bit. Rice. 5. Increasing and decreasing the diameter of the well depending on the lithology of the rocks Observations of drilling fluid parameters, oil, gas and water shows During the process of drilling a well, the following complications may occur: collapse of well walls, which leads to stuck drilling tools; absorption of drilling fluid, up to its catastrophic loss - when opening zones of discontinuous faults; liquefaction of the drilling fluid, reducing its density, which can lead to the release of oil or gas. Incidental and stationary testing of the productive formation There are incidental and stationary testing of the productive formation. Incidental testing of a productive formation involves taking samples of oil, gas and water from productive formations during the drilling process using special instruments: formation tester on logging cable OPK formation tester on drill pipes - KII (set of testing tools) Stationary testing is carried out upon completion of drilling the well. As a result of formation testing, the following information is obtained: Character of formation fluid; Information about reservoir pressure; Position of VNK, GVK, GNK; Information about the permeability of the reservoir rock. Design documentation for well construction The main document for the construction of wells is the geological and technical work order. It consists of 3 parts: geological part technical part The geological part contains the following information about the well: design well section rock age, burial depth, dip angles, strength intervals of possible complications, core sampling intervals. The technical part provides: drilling mode (load on bit, mud pump performance, rotor speed) depth of descent of columns and their number, diameter height of cement lifting behind the column, etc. Chapter 2 Methods of geological processing of well drilling materials and study of the geological structure of the field Geological processing of well drilling materials makes it possible to construct a field profile and structural maps of the top of the productive formation, allowing to obtain a complete picture of the structure of the field. For a detailed study of all issues of the field structure, it is necessary to conduct a thorough correlation (comparison of well sections). Correlation of well sections consists of identifying supporting layers and determining the depth of their occurrence in order to establish the sequence of occurrence of rocks, identifying layers of the same name to track changes in their thickness and lithological composition. In the oilfield industry, a distinction is made between general correlation of well sections and zonal (detailed) correlation. With general correlation, well sections are compared as a whole from the wellhead to the bottom along one or more horizons (benchmarks) See Figure 6. Detailed (zonal) correlation is carried out for a detailed study of individual layers and units. The correlation results are presented in the form of a correlation diagram. A reference point (marking horizon) is a layer in a well section that differs sharply in its characteristics (material composition, radioactivity, electrical properties, etc.) from the overlying and underlying layers. He must: easy to find in the well section; be present in all wells; have a small but constant value. Rice. 6. Reference surface In case of zonal correlation, the roof of the productive formation is taken as the reference surface. If it is blurry, use the sole. If it is also washed out, then choose any layer maintained within the area, an interlayer within the layer. Drawing up sections of the field - typical, average normal, summary When performing a general correlation, we obtain information about the bedding of rocks and their thickness. This information is necessary to construct a section of the field. This section shows the average characteristics of rocks, their age and thickness. If the vertical thickness of the layers is used, the section is called a standard section. Such sections are made in fishing areas. In exploration areas, average normal sections are compiled, where true (normal) formation thicknesses are used. In the case when the field section changes significantly in area, summary sections are built. When compiling a lithological column on a summary section, the maximum thickness of each layer is used, and its maximum and minimum values are given in the “thickness” column. Drawing up a geological profile section of the field Geological profile section - graphic image subsoil structure along a certain line in projection onto a vertical plane. Depending on the position on the structure, profile (1-1), transverse (2-4) and diagonal (5-5) cuts are distinguished. Exist certain rules orientation of the profile line in the drawing. On the right is north, east, northeast, southeast. From left - south, west, southwest, northwest. To construct a profile section of a field, the most commonly used scales are 1:5000, 1:10000, 1:25000, 1:50000, 1:100000. To avoid distortion of rock dip angles, the vertical and horizontal scales are assumed to be the same. But for clarity of the image, the vertical and horizontal scales are taken to be different. For example, the vertical scale is 1:1000, and the horizontal scale is 1:10000. If the wells are curved, we first build horizontal and vertical projections of the curved wellbores, put vertical projections on the drawing and build a profile. Sequence of constructing a profile section of the field A sea level line is drawn - 0-0 and the position of the well is plotted on it. The position of the 1st well is chosen arbitrarily. Through the obtained points we draw vertical lines, on which we plot the altitudes of the wellheads on the profile scale. We connect the wellheads with a smooth line - we get the terrain. Rice. 9. Profile section of the deposit From the wellhead we build well shafts to the bottom. We cut the projections of the curved trunks into a drawing. Along the wellbore we plot the depths of stratigraphic horizons, occurrence elements, and depths of faults, which are given first. Construction of a structural map A structural map is a geological drawing that displays in horizontal lines the underground relief of the roof or base of any one horizon, in contrast to topographic map, showing the relief in horizontal lines Earth's surface, the structure of which may involve horizons of different ages. The structural map gives a clear idea of the structure of the subsoil, ensures accurate design of production and exploration wells, facilitates the study of oil and gas deposits, and the distribution of reservoir pressures over the deposit area. An example of constructing a structural map is shown in Figure 10. Rice. 10. Example of constructing a structural map When constructing a structural map, the base plane is usually taken to be sea level, from which the horizontal contours (isohypses) of the underground relief are measured. Elevations below sea level are taken with a minus sign, above with a plus sign. Equal-height spaces between isohypses are called isohypsum cross section.
In fishing practice they usually use following methods constructing structural maps: the triangle method is for undisturbed structures. profile method - for heavily damaged structures. combined. Constructing a structural map using the triangle method involves connecting wells with lines, forming a system of triangles, preferably equilateral. Then we interpolate between the formation opening points. We connect the marks of the same name and get a structural map. The absolute elevation of the formation opening point is determined by the formula: + A.O.=+Al-,
A.O.-The absolute elevation of the formation opening point is the vertical distance from sea level to the formation opening point, m. Al- altitude of the wellhead - vertical distance from sea level to the wellhead, m. l- formation opening depth - distance from the wellhead to the point of formation opening, m. ΣΔ
l- correction for well curvature, m. Figure 11 shows various options for opening the formation: Rice. 11. Various options for opening up the formation Conditions for occurrence of oil, gas and water in the subsoil To implement a rational system for the development and organization of effective exploitation of oil and gas bearing formations, it is necessary to know their physical and reservoir properties, physicochemical characteristics formation fluids contained in them, conditions of their distribution in the formation, hydrogeological features of the formation. Physical properties of reservoir rocks Productive formations of oil fields containing hydrocarbons are characterized by the following basic properties: porosity; permeability; saturation of rocks with oil, gas, water in various conditions of their occurrence; granulometric composition; molecular-surface properties when interacting with oil, gas, water. Porosity The porosity of a rock means the presence of voids (pores, caverns, cracks) in it. Porosity determines the rock's ability to accommodate reservoir fluid. Porosity is the ratio of the pore volume of a sample to its volume, expressed as a percentage. n=VP/VO *100%
Porosity is quantitatively characterized by the porosity coefficient - the ratio of the pore volume of the sample to the volume of the sample in fractions of a unit. kP=VP/VO
Different rocks have different porosity values, for example: clay shales - 0.54 - 1.4% clay - 6.0 - 50% sands - 6.0 - 52% sandstones - 3.5 - 29% limestones, dolomites - 0.65 - 33% In fishing practice there are the following types porosity: total (absolute, physical, total) is the difference between the volume of the sample and the volume of its constituent grains. open (saturation porosity) - the volume of all interconnected pores and cracks into which liquid or gas penetrates; effective - the volume of pores saturated with oil or gas minus the content of bound water in the pores; The porosity efficiency coefficient is the product of the open porosity coefficient and the oil and gas saturation coefficient. Carbonate rocks are productive with a porosity of 6-10% and above. The porosity of sand rocks ranges from 3 to 40%, mostly 16-25%. Porosity is determined by laboratory analysis of samples or by GIS results. Rock permeability Rock permeability [To]- its ability to pass formation fluid. Some rocks, such as clays, have high porosity but low permeability. Other limestones - on the contrary - have low porosity, but high permeability. In oilfield practice, the following types of permeability are distinguished: absolute; effective (phase); relative; Absolute permeability is the permeability of a porous medium when one phase (oil, gas or water) moves through it. The absolute permeability is considered to be the permeability of rocks determined by gas (nitrogen) - after extraction and drying of the rock to a constant weight. Absolute permeability characterizes the nature of the medium itself. Phase permeability (effective) is the permeability of a rock for a given fluid in the presence and movement in the pores of multiphase systems. Relative permeability is the ratio of phase permeability to absolute permeability. When studying the permeability of rocks, the formula of Darcy's linear filtration law is used, according to which the filtration rate of a liquid in a porous medium is proportional to the pressure drop and inversely proportional to the viscosity of the liquid. V=Q/ F =kΔP/
μL ,
Q- volumetric flow rate of fluid through the rock in 1 second. - m 3
V-linear filtration speed - m/s μ
- dynamic viscosity of the liquid, n s/m2
F- filtration area - m2
ΔP- pressure drop along the length of the sample L,MPa
k- proportionality coefficient (permeability coefficient), determined by the formula: K=QML/FΔP
The units of measurement are as follows: [L]th [F]th2
[Q]-m3
/s [P]-n/m2
[
μ
]-ns/m2
For all coefficient values equal to unity, the dimension k is m2
Physical meaning of dimension kthis is the area. Permeability characterizes the cross-sectional area of the channels of the porous medium through which formation fluid is filtered. In fishing, a practical unit is used to assess permeability - Darcy- which is at 10 12times less than k=1 m2
.
Per unit in 1dtake the permeability of such a porous medium, when filtered through a sample of which with an area 1 cm2
length 1 cmwith pressure drop 1 kg/cm2
fluid flow viscosity 1sp(centi-poise) is 1 cm3
/With. Magnitude 0.001 d- called millidarcy.
Oil and gas bearing formations have a permeability of the order of 10-20 md to 200 md. Rice. 12. Relative permeability of water and kerosene From Fig. 12, it is clear that the relative permeability for kerosene Cook- decreases quickly with increasing water saturation of the formation. When water saturation is reached Kv- up to 50% relative permeability coefficient for kerosene Cookreduced to 25%. When increasing Kvup to 80%, Cookdecreases to 0 and is filtered through a porous medium pure water. The change in relative permeability to water occurs in the opposite direction. Conditions for occurrence of oil, gas and water in deposits Oil and gas deposits are located in upper parts structures formed by porous and overlying impermeable rocks (tires).These structures are called traps.
Depending on the conditions of occurrence and the quantitative ratio of oil and gas, deposits are divided into: pure gas gas condensate gas-oil (with gas cap) oil with gas dissolved in oil. Oil and gas are located in the reservoir according to their densities: gas lies in the upper part, oil lies below, and water lies even lower (see Figure 13). In addition to oil and gas, the oil and gas parts of the formations also contain water in the form thin layers on the walls of pores and subcapillary cracks held in place by capillary pressure forces. This water is called "associated" or "residual".The content of “bound” water is 10-30% of the total volume of pore space. Fig. 13. Distribution of oil, gas and water in reservoirs Deposit elements oil and gas:
oil-water contact (OWC) - the boundary between the oil and water parts of the deposit. gas-oil contact (GOC) - the boundary between the gas and oil parts of the deposit. gas-water contact (GWC) - the boundary between the gas-saturated and water-saturated parts of the deposit. the outer contour of oil-bearing capacity is the intersection of the water-oil contact with the roof of the productive formation. the internal oil-bearing contour is the intersection of the OWC with the base of the productive formation; the marginal zone is the part of the oil deposit between the external and internal oil-bearing contours; Wells drilled within the internal oil-bearing contour reveal the entire thickness of the oil reservoir. Wells drilled within the boundary zone reveal the oil-saturated layer in the upper part, and the water-saturated part below the OWC. Wells drilled behind the profiles of the outer oil-bearing contour reveal the water-saturated part of the formation. Water saturation coefficient is the ratio of the volume of water in the sample to the pore volume of the sample. KV=Vwater/Vsince then
Oil saturation coefficient is the ratio of the volume of oil in the sample to the pore volume of the sample. TOn=Vnave/Vpore
There is the following relationship between these coefficients: TOn+KV=1
Reservoir thickness In oilfield practice, the following types of productive formation thicknesses are distinguished (see Fig. 14): total formation thickness hgenerally- the total thickness of all interlayers - permeable and impermeable - the distance from the roof to the bottom of the formation. effective thickness hef- the total thickness of porous and permeable layers through which fluid movement is possible. effective oil or gas saturated thickness hefn-us- the total thickness of interlayers saturated with oil or gas. hgenerally-(total thickness) ef= h1
+h2efn-nose= h1
+h3
Rice. 14 Change of thickness of productive layers To study the pattern of thickness changes, a map is compiled - total, effective, and effective oil and gas-saturated thicknesses. Lines of equal thickness values are called isopachs, and the map is an isopach map. The construction technique is similar to constructing a structural map using the triangle method. Thermobaric conditions of the subsoil of oil and gas fields Knowing the temperature and pressure in the depths of oil and gas fields is necessary in order to correctly approach the solution of issues of both scientific and national economic importance: 1.formation and placement of oil and gas deposits. 2.determination of the phase state of hydrocarbon accumulations at great depths. .issues of technology for drilling and pumping deep and ultra-deep wells. .well development. Temperature in the bowels Numerous temperature measurements in idle wells have noted that the temperature increases with depth and this increase can be characterized by a geothermal step and a geothermal gradient. As the depth of productive formations increases, the temperature also increases. The change in temperature per unit depth is called. geothermal gradient. Its value ranges from 2.5 - 4.0%/100 m. Geothermal gradient is the increase in temperature per unit length (depth). grad t= t2
-t1
/H2
-H1
[
0
Cm]
Geothermal step [G] is the distance to which you need to go deeper for the temperature to increase by 10 WITH. G=H2
-H1
/ t2
-t1
[m/0
WITH]
Rice. 15. Temperature change with depth These parameters are determined from temperature measurements in idle wells. Measurements of temperature with depth are carried out either with an electric thermometer along the entire wellbore, or with a maximum thermometer for scientific purposes. The maximum thermometer shows maximum temperature at the depth to which it is lowered. An electric thermometer records a continuous record of temperature along the wellbore as the device is lifted. To obtain the true temperature of the rocks, the well must be at rest for a long time, at least 25-30 days, so that the natural thermal regime disturbed by drilling is established in it. Based on the results of temperature measurements, thermograms are constructed - curves of temperature versus depth. Using thermogram data, the geothermal gradient and step can be determined. On average across the globe, the geothermal gradient has a value of 2.5-3.0 0S/100m. Reservoir pressure in the depths of oil and gas fields Each underground reservoir is filled with oil, water or gas and has the energy of a reservoir water system. Reservoir energy is the potential energy of the formation fluid in the Earth's gravity field. After a well is drilled, an imbalance occurs in the natural water-pressure system: potential energy turns into kinetic energy and is spent on moving fluids in the formation to the bottoms of production wells and raising them to the surface. A measure of reservoir energy is reservoir pressure - this is the pressure of liquid or gas located in reservoir layers under natural conditions. In oil and gas fields, reservoir pressure (P pl ) increases with depth for every 100 m of depth by 0.8 - 1.2 MPa, i.e. by approximately 1.0 MPa/100m. The pressure that is balanced by a column of mineralized water with a density ρ = 1.05 - 1.25 g/cm 3 (103kg/m 3) is called normal hydrostatic pressure. It is calculated like this: Rn.g.= Hρ
V/ 100 [MPa]
H - depth, m. ρ
V- water density, g/cm3
, kg/m3
.
If ρ V taken equal to 1.0, then this pressure is called conditional hydrostatic Conditional hydrostatic pressure is the pressure created by the column fresh water density 1.0 g/cm 3height from the wellhead to the bottom. Ru.g.= N / 100 [MPa]
The pressure that is balanced by the flushing fluid with a density ρ and =1.3 g/cm 3and more, the height from the wellhead to the bottom of the well is called superhydrostatic (SGPD) or anomalously high formation pressure (AHRP). This pressure is 30% or more higher than the conditional hydrostatic pressure and 20-25% higher than the normal hydrostatic pressure. The ratio of the high pressure pressure to the normal hydrostatic pressure is called the reservoir pressure anomaly coefficient. TOA=(PAVPD/Rn.g..) >1,3
Pressure below hydrostatic is abnormally low reservoir pressure (ANPR) - this is pressure that is balanced by a column of drilling fluid with a density of less than 0.8 g/cm 3. If Ka< 0,8 - это АНПД.
One of the most important characteristics formation is rock pressure - this is the pressure that is a consequence of the total influence on the formation of geostatic and geotectonic pressures. Geostatic pressure is the pressure exerted on a formation by the mass of the overlying rock mass. Rg.e.=
HρP/100 [MPa]
Where, ρ P = 2.3 g/cm 3 - average density rocks. Geotectonic pressure (stress pressure) is the pressure that is formed in layers as a result of continuously intermittent tectonic movements. Rock pressure is transmitted by the rocks themselves, and within the rocks by their skeleton (the grains that make up the layer). Under natural conditions, rock pressure is counteracted by reservoir pressure. The difference between geostatic and reservoir pressure is called compaction pressure. Rupl=Pg.e- Rpl
In field practice, reservoir pressure is understood as the pressure at a certain point in the reservoir that is not influenced by the depression funnels of neighboring wells (see Fig. 16) Depression on the reservoir Δ
Pcalculated using the following formula: Δ
P=Ppl-Pzab ,
Where, Ppl-reservoir pressure Forget-pressure at the bottom of an active well. Rice. 16 Reservoir pressure distribution during operating wells Initial reservoir pressure P0
- this is the pressure measured in the first well that penetrated the formation, before any noticeable amount of liquid or gas was withdrawn from the formation. Current reservoir pressure is the pressure measured at a certain date in a well in which relative statistical equilibrium has been established. To eliminate the influence geological structure(measurement depth) by the value of reservoir pressure, the pressure measured in the well is recalculated to the middle of the oil or gas content level, to the midpoint of the deposit volume or to the plane coinciding with the OWC. During the development of oil or gas deposits, the pressure continuously changes; when monitoring development, the pressure is periodically measured in each well. To study the nature of pressure changes within the deposit area, pressure maps are constructed. Lines of equal pressure are called isobars, and the maps are called isobar maps. Rice. 17. Graph of pressure changes over time by wells Systematic monitoring of changes in reservoir pressure makes it possible to judge the processes occurring in the reservoir and regulate the development of the field as a whole. Reservoir pressure is determined using downhole pressure gauges lowered into the well on a wire. Liquids and gas in the formation are under pressure, which is called plastovy.From the reservoir pressure value Ppl- the reserve of reservoir energy and the properties of liquids and gases in reservoir conditions depend. Ppldetermines gas reserves, well flow rates and operating conditions of the deposits. Experience shows that P0
(initial reservoir pressure) measured in the first drilled well depends on the depth of the deposit and can be approximately determined by the following formula: P= Hρg [MPa] H - deposit depth, m ρ- liquid density, kg/m 3
g- free fall acceleration If the well flows (overflows), P pl determined by the formula: P pl =Hρg +P (wellhead pressure) If the liquid level in the well does not reach the mouth P pl =H 1ρg H 1- height of the liquid column in well, m. Rice. 18. Determination of reduced reservoir pressure In a gas deposit or gas part of an oil reservoir, the reservoir pressure is almost the same throughout the entire volume. In oil deposits, reservoir pressure is different in different parts: on the wings - maximum, in the roof - minimum. Therefore, the analysis of changes in reservoir pressure during reservoir operation is difficult. It is more convenient to relate reservoir pressure values to one plane, for example, to the plane of the oil-water contact (WOC). The pressure referred to this plane is called reduced (see Fig. 18) and is determined by the formulas: P1pr=P1
+ x1
ρg P2pr=P2
- X2
ρg
Physical properties of oil, gas and water Gases from gas fields are called natural gases, and gases produced along with oil are called petroleum or associated gases. Natural and petroleum gases consist mainly of saturated hydrocarbons of the C series n N 2n+2 : methane, ethane, propane, butane. Starting with pentane (C 5H 12) and above are liquids. Hydrocarbon gases often contain hydrocarbon (CO 2, hydrogen sulfide H 2S, nitrogen N, helium He, argon, Ar, mercury vapor and mercaptans. CO content 2 and H 2S sometimes reaches tens of percent, and other impurities - fractions of percent, for example, in the AGCM reservoir mixture the content carbon dioxide is 12-15%, and hydrogen sulfide is 24-30%. Molecular mass (M) of hydrocarbon gases is determined by the formula: M= ∑MiYi
Mi- molecular weight of the i-th component Yi- the share of the i-th component in the mixture by volume. Density is the ratio of the mass of a substance to its occupied volume. ρ
=m/V [kg/m3
].
Density is in the range of 0.73-1.0 kg/m 3. In practice, they use the relative density of a gas - the ratio of the mass of a given gas to the mass of air of the same volume. The relative densities of various gases are given below: Air - 1.0CH 4 - 0,553N 2- 0.9673C 8H 6 - 1,038CO 2- 1.5291C 3H 8 - 1,523H 2S - 1.1906C 4H 10 - 2,007
To transition from the volume under normal conditions to the volume occupied by the same amount in reservoir conditions, the volumetric coefficient of reservoir gas V is used - the volume that would occupy 1 m 3 gas in reservoir conditions. V=V0
Z (TP0
/T0
*P)
Where, V0
- volume of gas under normal conditions at initial pressure P 0
, and temperature T0
.
V is the volume of gas at the current pressure P and temperature T. is the coefficient above the compressibility of the gas. Volumetric coefficient of reservoir gas V is within 0.01-0.0075
Gas viscosity is the property of a gas to resist the movement of some particles relative to others. In the SI system, dynamic viscosity is measured in mPa*s (miles-pascals per second), for example, the dynamic viscosity of water at t 0 200C is µ=1 mPa*s. The viscosity of gas from gas fields ranges from 0.0131 to 0.0172 mPa*s. The viscosity of the AGCM reservoir mixture is 0.05 - 0.09 mPa*s. Solubility of gases in oil The volume of a one-component gas dissolving in a unit volume of liquid is directly proportional to pressure VG/Vand =
αP
Where, V G - volume of dissolving gas V and - volume of liquid
The book “Fundamentals of Oil and Gas Field Development,” which has gone through twenty reprints, was created on the basis of lecture courses given by the author at the training center of Shell Internationale Petroleum Maatschappij B.V. (SIPM).
The publication covers a wide range of issues related to the development of oil and gas fields. Characteristic feature The book is its practical orientation. The physical foundations of field development are presented using simple and convenient mathematical methods for practical use. In addition to theoretical materials, almost every chapter contains tasks for developing practical skills of oil and gas industry specialists. For specialists, a valuable addition will be the method presented in the book for recalculating numerical coefficients in formulas when moving from one system of units of measurement to other systems.
Recommended for a wide range of oil and gas industry specialists, teachers and university students.
DEVELOPMENT OF GAS FIELDS UNDER GAS REGIME.
The development of gas fields under gas conditions is discussed at the beginning of the book due to relative simplicity subject. Below we will show how the gas recovery factor is determined and the duration of the development period is calculated.
The simplicity of the subject is explained by the fact that gas is one of the few substances whose state, determined by pressure, volume and temperature (PVT), can be described by a simple relationship that includes these three parameters. Another such substance is saturated steam. But, for example, for oil containing dissolved gas, such a dependence does not exist. As shown in Chapter 2, the PVT parameters that determine the condition of such mixtures must be obtained empirically.
CONTENT
Preface
Acknowledgments In memory of Lawrence P. Dyke Nomenclature
1. Some basic concepts underlying oil and gas development
1.1. Introduction
1.2. Calculation of initial hydrocarbon reserves
1.3. Change in reservoir pressure by depth
1.4. Oil recovery: oil recovery factor
1.5. Development of gas fields under gas conditions
1.6. Application of the equation of state of real gas
1.7. Material balance for gas reservoir: gas recovery factor
1.8. Phase states of hydrocarbons References
2. Analysis of PVT properties of formation fluids
2.1. Introduction
2.2. Definition of basic parameters
2.3. Reservoir fluid sampling
2.4. Obtaining basic PVT data in the laboratory and converting it for field use
2.5. Another method of expressing laboratory results PVT
2.6. Full range of PVT studies References
3. Application of the material balance method in the development of oil fields
3.1. Introduction
3.2. Material balance equation for oil and gas deposits in general form
3.3. Linear material balance equation
3.4. Deposit operating modes
3.5. Elastic regime transforming into dissolved gas regime
3.6. Gas pressure mode
3.7. Natural water pressure regime
3.8. Elastic-plastic regime References
4. Darcy's Law and its Application
4.1. Introduction
4.2. Darcy's law. Potential energy of fluids
4.3. Assignment of characters
4.4. Units. Transition from one system of units to another
4.5. Potential energy of real gas
4.6. Reduced pressure
4.7. Steady-state radial filtration. Intensification of oil flow into a well
4.8. Two-phase flow. Phase and relative permeability
4.9. Methods for enhanced oil recovery References
5. Basic differential equation of radial filtration
5.1. Introduction
5.2. Derivation of the basic differential equation of radial filtration
5.3. Initial and boundary conditions
5.4. Linearization of the main differential equation of radial filtration of fluids with low and constant compressibility
Bibliography
6. Equations of quasi-steady and steady inflows into a well
6.1. Introduction
6.2. Solution for quasi-steady flow
6.3. Steady Flow Solution
6.4. Example of using quasi-steady and steady-state inflow equations
6.5. Generalized form of the quasi-steady inflow equation
Bibliography
7. Solving the piezoelectric conductivity equation at constant flow rate and using it to study oil wells
7.1. Introduction
7.2. Solution for constant flow
7.3. Solution at constant flow rate for conditions of unsteady and quasi-steady filtration
7.4. Dimensionless parameters 209
7.5. Superposition principle. General theory well testing
7.6. Analysis of Well Testing Results by the Pressure Recovery Method Proposed by Matthews, Brons and Haizbrack
7.7. Practical analysis of well testing results using pressure recovery method_
7.8. Study using the method of multiple changes in the well operating mode
7.9. Influence of well imperfection on the degree and nature of penetration
7.10. Some practical aspects of well testing
7.11. Accounting for inflow into a well after shutting it down References
8. Real gas flow. Gas well exploration
8.1. Introduction
8.2. Linearization and solution of the basic differential equation of radial filtration of real gas
8.3. Method of Russell, Goodrich et al.
8.4. Al-Husseini, Raimi and Crawford method
8.5. Comparison of the square pressure method and the pseudo pressure method
8.6. Deviation of flow from Darcy's law
8.7. Determination of the coefficient f, taking into account the deviation from Darcy's law
8.8. Solution at constant flow rate for the case of filtration of real gas
8.9. General theory of gas well exploration
8.10. Study of gas wells using the method of multiple mode changes
8.11. Study of gas wells using pressure recovery method
8.12. Analysis of the results of a study using the method of pressure recovery in oil deposits operating in dissolved gas mode
8.13. Brief overview of results analysis methods
well testing
Bibliography
9. Water influx into the reservoir
9.1. Introduction
9.2. Hirst and van Everdingen's unsteady flow theory
9.3. Application of Hirst and van Everdingen's aquifer theory to reconstruct development history
9.4. Approximate Fetkovich theory of water influx into a reservoir for the case of a limited aquifer area
9.5. Inflow volume forecasting_
9.6. Application of methods for calculating water inflow to cyclic steam and thermal treatments
Bibliography
10. Immiscible displacement
10.1. Introduction
10.2. Physical assumptions and their consequences
10.3. Equation for calculating the fluid fraction in a flow
10.4. Buckley-Leverett one-dimensional displacement theory
10.5. Calculation of oil production
10.6. Displacement under conditions of gravitational segregation
10.7. Taking into account the influence of the transition zone of finite height in displacement calculations
10.8. Displacement from layered heterogeneous formations
10.9. Displacement in the complete absence of vertical balance
10.10. Numerical modeling of immiscible displacement during filtration of incompressible liquids
Bibliography
EXERCISES
1.1. Gas hydrostatic pressure gradient in a reservoir
1.2. Material balance of gas reservoir
2.1. Selected volume reduced to reservoir conditions
2.2. Conversion of differential degassing data into field PVT parameters Bo, Rs and Bg
3.1. Elastic mode (undersaturated oil)
3.2. Dissolved gas mode (pressure below saturation pressure)
3.3. Water injection begins after the reservoir pressure decreases below the saturation pressure
3.4. Gas pressure mode
4.1. Transition from one system of units to another
6.1. Accounting for changes in permeability of the near-wellbore zone
7.1. Logarithmic approximation of the function Ei(x)
7.2. Well testing using a single mode change method
7.3. Dimensionless parameters
7.4. Transition from unsteady filtration to quasi-steady filtration
7.5. Obtaining dependencies for dimensionless pressure
7.6. Analysis of research results using the pressure recovery method. Endless layer
7.7. Analysis of research results using the pressure recovery method. Limited drainage volume
7.8. Analysis of the research results using the method of multiple changes in the well operating mode
7.9.Methods for analyzing additional inflow into a well after its shutdown
8.1. Analysis of the results of studying a gas well using the method of multiple mode changes with the assumption of the existence of quasi-steady filtration conditions
8.2. Analysis of the results of studying a gas well using the method of multiple mode changes with the assumption of the existence of unsteady filtration conditions
8.3. Analysis of research results using the pressure recovery method
9.1. Application of solution at constant pressure
9.2. Fitting a boundary aquifer model using the unsteady inflow theory of Hurst and van Everdingen
9.3. Calculation of water inflow into a reservoir using the Fetkovich method
10.1. Calculation of the share of water in the inflow
10.2. Forecasting production during waterflooding
10.3. Displacement under conditions of gravitational segregation
10.4. Construction of curves of averaged relative phase permeabilities for a layered heterogeneous formation (conditions of gravitational segregation)
Subject index.