книги / Разработка нефтяных и газовых месторождений. Ч. 1

Федеральное агентство по образованию

Государственное образовательное учреждение высшего профессионального образования «Пермский государственный технический университет»

А.А. Злобин, Г.П. Хижняк, И.Р. Юшков, А.В. Распопов

A.A. Zlobin, G.P. Khizhnyak, I.R. Yushkov, A.V. Raspopov

РАЗРАБОТКА НЕФТЯНЫХ И ГАЗОВЫХ МЕСТОРОЖДЕНИЙ

OIL AND GAS FIELD

DEVELOPMENT AND OPERATION

Часть 1 Part 1

Утверждено Редакционно-издательским советом университета в качестве учебного пособия

Издательство Пермского государственного технического университета

2008

УДК 622.276:532 + 622.279](075.8)

ББК 33.361 + 33.362]я73 Р17

Рецензенты:

канд. техн. наук, профессор В.А. Мордвинов (Пермский государственный технический университет);

советник генерального директора Н.И. Кобяков (ООО «ЛУКОЙЛ-Пермь»)

Разработка нефтяных и газовых месторождений. Ч. 1: учеб. пособие / Р17 А.А. Злобин, Г.П. Хижняк, И.Р. Юшков, А.В. Распопов. – Пермь: Изд-во

Перм. гос. техн. ун-та, 2008. – (На англ. языке). – 63 с.

ISBN 978-5-88151-921-6

Излагаются следующие темы: основы физики нефтяного и газового пласта, основы гидродинамики нефтяного и газового пласта, проектирование, анализ и регулирование разработки нефтяных залежей.

Рассчитано на специалистов Республики Ирак, обучающихся в Пермском государственном техническом университете по дополнительной образовательной программе профессиональной переподготовки специалистов «Руководитель нефтегазового производства».

Fundamentals of petroleum reservoir physics. fundamentals of petroleum reservoir hydrodynamics. petroleum reservoir engineering. analisis and control oil and gas field development. project and guiding documents.

The textbook is destined for the Iraq Republic specialists studying on the extra educational program of professional retraining «Oil and gas production manager» at Perm State Technical University.

УДК 622.276:532 + 622.279](075.8) ББК 33.361 + 33.362]я73

39 % are confined to carbonate deposits and I % – to weathered metamorphic and igneous rocks.

Therefore, sedimentary rocks are the main oil and gas reservoirs.

2. RESERVOIR CLASSIFICATION

Due to the fact that capacity of rock voids can widely range, the classification of reservoirs, which makes it possible to estimate the relative oil, gas and water reserves, and select methods of reserves estimation and development, is of great importance. Classification of oil and gas reservoirs is given in Table 1. The advantage of this classification is that it is applicable to reservoirs of any origin – igneous, sedimentary and metamorphic. As may be seen from Table 1, porous rocks include rocks with porosity and fracturing factors equal to zero and bound takes only a part of pore volume. But rock studies show that, strictly speaking, there are no pure porous or fractured reservoirs in nature. As a rule, fracturing and porosity are combined, and in carbonate reservoirs, as it has been already mentioned, they are added with cavern porosity. That is why the given classification is based on subdivision of reservoir into types by dominating characteristics.

Fractured rocks include rocks with cavern porosity equal to zero, and with no pores or pores filled with water. In other words, fractured rocks include rocks which contain oil and gas only in fractures.

Pure cavernous rocks include rocks with fracturing equal to zero, and the porous part of matrix is completely saturated with water, i.e. oil and gas are contained only in caverns.

Note: Sв – bound water content; mп, mк, mт – porosity, cavern porosity and fracturing factors, Qип, Qик, Qит – recoverable reserves of oil and gas, respectively, in pores, caverns and fractures.

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Rocks with commensurable recoverable oil and gas reserves in pores and fractures relate to fractured-porous and porous-fractured reservoirs. In fractured-porous reservoir, recoverable reserves are mainly accumulated in fractures, and in porousfractured reservoir recoverable reserves are mainly accumulated in pores, though, in both the cases, the capacity of pores is significantly higher than capacity of fractures. The distinguishing characteristic of such reservoirs is that if there were no fractures, confined oil and gas accumulations would have no commercial importance. The most common type is porous-fractured reservoirs.

Rocks in which oil and gas are accumulated in fractures and caverns, and matrix pores are filled with bound water, relate to cavernous-fractured reservoirs. The major part of recoverable oil and gas reserves is accumulated in caverns. Many carbonate rocks of organogenic and chemogenic origin relate to this type of reservoirs.

Rocks in which recoverable reserves are either equally distributed in all types of voids, or mainly accumulated in pores, or in caverns, or in fractures relate to, respectively, porous-cavernous-fractured, cavernous-porous-fractured and fractured- porous-cavernous types of reservoirs. Such reservoirs can be only in carbonate rocks characterized by high capacity of voids of primary and secondary origin.

3. MINERAL COMPOSITION OF TERRIGENOUS ROCKS

Principle outlines of oil and gas reservoir structure depend on their origin, but, at the same time, the origin is only the starting point that preconditions various properties of rocks. Together with the origin, the secondary processes, and mineral composition in case of terrigenous rock, play significant role in reservoir forming. Terrigenous deposit formation can be schematically represented as the process of the Earth’s crust destruction and consolidation of fragmentary material formed by such destruction. The composition of fragmentary material can include fragments of the destructed rock, particles of original minerals and substances undergone not only mechanical destruction but also chemical reformation. In the course of such disintegration, the original mineral composition of source rock is disintegrated, and composition of the newly formed sedimentary rocks is different.

It is known that lithosphere mainly consists of aluminosilicates, and the basic minerals are feldspars and quartz. In terrigenous rocks, quartz and feldspars dominate, and good reservoir properties depend on their share in sedimentation. If the share of feldspar and products of feldspar chemical transformation in sedimentation is high, the formed rock is clay-based, and, because of this, it is a bad reservoir or can not be a reservoir at all (so termed Impermeable Beds).

Therefore, the mineral composition of rocks effects the reservoir properties of rocks by grain-size distribution which, under otherwise equal conditions, is dictated by various strength of minerals.

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4. GRAIN-SIZE COMPOSITION

(MECHANICAL COMPOSITION) OF ROCKS

Sand reservoirs are composed of irregular-shaped grains of various sizes. The grain-size composition of rocks means the quantitative content of grains of various sizes. Various properties of porous rock medium, such as permeability, porosity, specific surface area, capillary properties and other, as well as quantity of oil in the form of film covering the surface of grains after completion of development, depend on the grain-size composition.

Size of rock grains widely varies. The first group – sand or psammite – is mainly composed of grains sized 1 0.1 mm; the second group – siltstone – is composed of grains sized 0.1 0.01 mm and the third group – pelite – contains grains of size less than 0.01 mm. Clay and colloid-dispersed minerals, grain size less than 0.0001 mm (0.1 mcm), widely occur together with grained minerals.

Mechanical composition of rocks is determined by sieve and sedimentary analysis. The sieve analysis of loose rocks is used for size grading of sand grains sized from 0.05 mm and over. The content of smaller grains is determined by sedimentation method.

Pelite grains are fractionated due to difference of sedimentation rate of grains of different sizes in viscous liquid. The smaller grain diameter, the lower sedimentation rate in suspended sedimentation.

The most accurate sedimentary analysis technique is balance measurement of sediment. Properly stirred suspended sedimentation is poured into a high cylindrical vessel, and a thin glass disc suspended on the arm of N.A. Figurovskiy balance is lowered into it. The precipitated particles of suspended sedimentation are deposited on the glass disc. The equilibrium of the balance is upset as sediment precipitating, and additional load is required for recovery. By registering time and current load, various size grain content data are obtained, and the grain-size analysis data are tabled.

Mechanical analysis data can be also represented in the form of the total grain-size composition and distribution curves (fig. 1). To build-up the first F curve, percentage by weight is plotted in Y-axis, and diameter of logarithm lg d is plotted in X-axis. For the second curve f, grain diameter d is plotted in X-axis, and percentage by weight of each fraction of the rock under analysis – in Y-axis. Ratio d60/d10 is termed Hasen rock heterogeneity coefficient, where d60 is grain diameter at which the sum of weights of fractions with diameter from zero to the given diameter is 60 % of weight of all fractions, and d10 is a similar value for the 10 % point of the total grain-size composition curve.

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Fig. 1. Integral (F) and differential (f) curves of grain-size distribution

5. CAPACITY OF ROCK VOIDS

Oil and gas reservoir capacity is specified by pores, caverns and fractures. By origin, pores and other voids can be primary and secondary. The primary pores are intergranular spaces, spaces between sheeting planes formed in the process of sedimentation and rock formation. The secondary pores are formed as a result of the subsequent processes of rock faulting, breaking, dissolving and fracturing (for instance, by dolomitization). Based on the above, all oil and gas reservoirs are characterized by porosity, cavern porosity and fracturing.

Rock porosity means availability of pores in the rock which are not filled with solid matter. Such porosity is termed in Petroleum Geology as total (true) porosity. Total porosity includes absolutely all pores of the rock (open and closed pores) regardless of their form and relative positions. Accordingly, together with total porosity, the term effective porosity, which characterizes capacity of pores communicating with the rock sample surface, is used.

The total porosity is characterized by total porosity factor mп, which is a ratio of the total volume of all pores Vп to the apparent volume of rock V0:

Porosity is measured by unit fraction or percent.

Table 3

Porosity Factors of Some Rocks

Total porosity factor of petroleum rocks is required for oil and gas pool and absolute oil and gas reserves estimation. The effective porosity is characterized by the effective porosity factor – ratio of the total volume of the open interconnected pores Vef.p to the rock volume:

The reservoir static pay load capacity and dynamic pay load capacity are also used for characterizing the effective porosity.

The reservoir static pay load capacity characterizes the volume of pores and voids which can be filled with oil or gas. The symbol of this magnitude is Pst, and it is determined as difference between the effective porosity and the part of pore volume filled with bound water. Depending on pressure differential in porous medium, fluid properties and rock sample surface, this or that part of fluid does not flow in pores. It includes motionless films at the rock sample surface and capillary retained fluid:

The reservoir dynamic pay load capacity Pdyn characterizes the relative volume of pores and voids through which oil and gas can filtering under the formation conditions.

6. METHODS OF ROCK POROSITY, CAVERN POROSITY AND FRACTURING MEASUREMENT

For determining the total porosity factor mp, it is necessary to determine the volume of solid phase Vs.ph., volume of rock sample Vо or density of rock sample ρо and solid phase ρs.ph.:

For determining the solid phase volume and density, the well-known picnometer (bottle) method and disintegrated rock lot are used. The rock sample volume Vо, in its turn, can be determined by several methods. If it is necessary to exclude saturation of the rock sample saturation with fluid, the volume is determined by hydrostatic weighing the rock sample in water, provided that the rock sample surface is coated with impermeable thin layer of paraffin (Melcher method). If the rock sample has regular shape, its volume can be easily determined by multiplying its section area by length.

The effective porosity is most often determined by weighing rock sample saturated with liquid (usually with kerosene) in air and in the same considering Archimedes principle (I.A. Preobrazhenskiy method):

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The static porosity considering effective porosity mо and residual (bound) water saturation factor Sb.ws is determined by the following formula:

where Sb.w is ratio of pores filled with bound water to the volume of open pores. Thus, static porosity depends upon residual (bound) water saturation determination methods.

Dynamic volume of pores means the equivalent volume of substance that displaces oil and gas from reservoir when maximum fluid displacement is reached. In doing so, dynamic porosity is calculated by formula considering initial αн and final αк water saturation factor of the rock:

where Sbw is residual (bound) water saturation factor – ratio of pores filled with residual oil to the volume of open pores. For gas displacement with water:

and Srgs is residual gas saturation factor.

According to A.A. Khanin, the total porosity in sandstone and siltstone can exceed the effective porosity on 5–6 %. Limestone and tuff are characterized by the largest volume of closed pores.

7. ROCK PERMEABILITY

Permeability is a filtration property of rock that characterizes the ability of a rock to let oil, gas and water go through to bottomhole. In the course of oil and gas resrvoir engineering, various types of fitration of fluid and gas, and their mixture in porous rock medium can occur – combined flow of oil, gas and water, or water and gas, or water and oil, or oil and gas, or only oil or gas. At the same time, permeability of one the same porous rock medium for the given phase, depending on quantitative and qualitative composition of phases, is different. That is why, oilcontaining reservoir is characterized by absolute, effective (phase) and relative permeability is used.

Absolute permeability is permeability of porous rock medium to be determined if it contains only one phase which is chemically inert to the rock. The absolute permeability is a rock property that does not depend on properties of filtrating fluid

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or gas, and pressure difference. That is why, air or inert gas (nitrogen and helium) are used for absolute permeability measuring.

Phase or effective permeability means the permeability of a porous medium for a given fluid or gas in the presence of several phases in the rock. It depends not only on physical properties of rocks but also on degree of saturation of purous space with fluidss or gases, and on their physicochemical properties.

Relative permeability of porous rock medium is ratio of the effective permeability of such porous rock medium to the absolute permeability.

As a rule, rock permeability is measured using Darcy linear law (1856), under which the fluid filtration rate in porous rock medium is proportional to the pressure gradient and inversely proportional to the dynamic viscosity:

where v is linear filtration rate; Q is volumetric flow rate of fluid per unit of time; F is filtration area; is dynamic viscosity of fluid; ∆р is pressure difference; and L is length of porous rock medium. In the above equation the ability of rock to let fluid, gas and water go through is characterized by proportionality factor K that is termed permeability factor. At L = l m; F = 1 m2; Q = 1 m3/sec; р =1 Pa and= 1 Pa·sec, we obtain the permeability factor К=1 m2.

In the International System of Units (SI), permeability factor is measured by m2; and in the CGS (centimeter-gram-second) system [kp] in cm2; and in the NPG (petroleum field geology) [kp] in D (Darcy):

In the International System of Units (SI), the unit of permeability 1 m2 is permeability of porous rock medium, during the filtration through the sample of which with area 1 m2, length 1 m and pressure difference 1 Pa, the flow rate of fluid with viscosity 1 Pa sec is 1 m3/sec.

The physical content of unit of measurement К (area) is that permeability characterizes the section area of porous medium channels through which filtration occurs.

8. PHASE AND REALTIVE PERMEABILITY OF ROCKS

Under the natural conditions, voids of oil and gas reservoir rocks are filled with water, gas or oil, i.e. two or three phases are present in them simultaneously. When flowing, permeability of rock for any phase is less than absolute permeability. Studies show that phase and relative permeability for various phases depends on oil, gas and water saturation of porous space of rock, physicochemical properties of fluids and porous media, and pressure gradient.

Saturation is an important characteristic of productive formations. There are water saturation (Sw), gas saturation (Sg) and oil saturation (So). Oil, gas and

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