книги / Разработка нефтяных и газовых месторождений. Ч. 2

Федеральное агентство по образованию

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

В.А. Мордвинов, В.В. Поплыгин, Б.В. Косков, М.С. Турбаков

V.A. Mordvinov, V.V. Poplygin,

B.V. Koskov, M.S. Turbakov

РАЗРАБОТКА НЕФТЯНЫХ И ГАЗОВЫХ МЕСТОРОЖДЕНИЙ

OIL AND GAS FIELD

DEVELOPMENT AND OPERATION

Часть 2 Part 2

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 А.А.Кукьян (Пермский государственный технический университет)

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

Разработка нефтяных и газовых месторождений. Ч. 2: учеб. пособие / Р17 В.А. Мордвинов, В.В. Поплыгин, Б.В. Косков, М.С. Турбаков. – Пермь: Изд-во Перм. гос. техн. ун-та, 2008. – (На англ. языке). – 79 с.

ISBN 978-5-88151-929-2

В пособии излагаются следующие темы: разработка и эксплуатация нефтяных и газовых месторождений, исследование пластов и скважин при разработке нефтяных и газовых залежей, гидродинамические исследования скважин в ООО «ЛУКОЙЛ-ПЕРМЬ». Кроме этого, приведены описания трех практических занятий по разработке и эксплуатации нефтяных и газовых месторождений.

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

OIL AND GAS WELL OPERATION. Oil and Gas Field Development Formation and Well Testing. OOO «LUKOIL-PERM» WELL HYDRODYNAMIC STUDYING. Practical Exercises

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

Course of lectures in

OIL AND GAS WELL OPERATION

1. OIL AND GAS FIELD DEVELOPMENT AND OPERATION

FUNDAMENTAL NOTIONS

1.1. Natural Oil and Gas Reservoirs

Oil is a combustible liquid mineral. It is an oleaginous fluid containing carbon (82–87 %), hydrogen (11.5–14.5 %), and other components (oxygen, sulfur, nitrogen compounds and other). It is a complex blend of paraffinic (methane), naphtenic and aromatic hydrocarbons.

Petroleum (associated) gases are hydrocarbon gases dissolved in oil (under reservoir conditions), gas cap gases formed in the dome part of oil reservoirs, and gases formed in oil treatment. Petroleum (associated) gases can contain non-hydrocarbon components (nitrogen, hydrogen sulfide, carbon dioxide and inert gases).

Oil production is oil and associated petroleum gas extraction from the interior of the Earth, and gathering and treatment under field conditions.

Natural gas is hydrocarbon gas produced from gas, gas hydrate, gas condensate, gas condensate-and-oil or gas-and-oil pools. Natural gas can contain non-hydrocarbon components.

Natural reservoir is an oil, gas or water container in reservoir rocks surrounded by low permeable (impermeable) rocks in the Earth’s crust. The upper part of such reservoir, in which oil and gas are accumulated, is termed a trap.

Pool is a considerable (feasible for commercial development) accumulation of oil and gas in any form of trap.

A number of oil and gas pools of the same type present over a limited area in the Earth’s crust is termed an oil and gas field.

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Oil field (pool) contains oil with various dissolved gas content. The oil field with gas cap is termed an oil-and-gas field. The field with areally widespread gas cap and oil leg is termed a gas-and-oil field.

Field is termed a gas field if all its pools are pure gas pools containing natural gas that is not condensed under pressure decrease up to atmospheric pressure. If, under pressure decrease, produced gas is partially condensed and, thus, a fluid phase is formed, such field is termed a gas condensate field. Under original reservoir conditions such fields contain light hydrocarbon gas in which some volume of heavier hydrocarbon components are dissolved. If in the pool there is a leg contained gas with dissolved condensate, such pool (field) is termed a gas condensate-and-oil pool (field).

Natural gas can occur in natural reservoir in solid (hydrate) state – gas hydrate pool (field).

1.2. Oil and Gas Field (Pool) Development Systems

Development system is a totality of operations aimed at making oil (gas) migrating in productive formations to the bottomholes of production wells. It includes reservoir drilling priority and rate; number and ratio of injection, production and special (monitor) wells; productive formation stimulation operations (methods) aimed at reaching the target hydrocarbon recovery rate; and reservoir development monitoring and control measures. Well pattern, number of wells and productive formation stimulation methods are the basic factors which characterize the development system.

Well is a mine opening of cylindrical form constructed using the special equipment. It is characterized by large length (depth) and small diameter. There can be vertical, directional, horizontal (in the interval of productive formation) and multibranch wells.

Productive formation drilling-in in the process of well drilling (construction) is termed primary drilling-in. Connection of the drilled and cased well with the productive formation is termed secondary drilling-in (completion).

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Production well development includes preparatory work, perforation operations and oil (gas) inflow stimulation operations.

Production well productivity characterizes the productive capacities of wells. Well productivity index is a ratio of amount of product produced by well for the unit of time per the unit of underbalance (difference between formation pressure and bottomhole pressure): for oil well – t/d . MPa,

and for gas well – thousand m3/d . MPa.

Injection wells are characterized by indicator that is termed a specific-injectivity index. It is a volume (m3) of water injected per the unit of overbalance (difference between bottomhole pressure and formation pressure); i.e. m3/d . MPa.

Well operating practice is a set of indices and parameters which characterize well operation. For production well: productivity, oil rate (t/d) and fluid rate (usually, m3/d), gas-oil ratio, bottomhole pressure and wellhead pressure (surface squeeze, annulus and line pressure), dynamic and static levels, underbalance, water cut, well equipment assembly, nominal size, dry-up job parameters, well pump duty, pump setting depth and other. For injection well: specific-injectivity, bottomhole pressure and wellhead pressure, overbalance and well equipment assembly.

Well operating practice should be set for a specified period of time and adjusted (changed) with changing in well operation conditions (water cut, gas-oil factor and formation pressure).

Oil (gas) reservoir drive is a dominant form of energy that dictates oil and gas encroachment (influx). Sources (types) of reservoir energy are as follows: energy of edgeor bottom-water drive; energy of compressed gas of gas cap; energy of expanding gas that transforms from oil-dissolved state to free state; energy of elastic expansion of compressed rocks and fluids; gravity energy; and energy of compressed natural gas (gas reservoirs). Various kinds of energy can act simultaneously, but one of them is dominant at this or that stage of reservoir development.

If oil and gas migrate to the bottomholes under edgeor bottom water drive it is termed a water drive, and, if water completely displaces withdrawn fluid, and there is a balance between withdrawal of fluid and encroaching water, such drive is termed an elastic water drive. Water and elastic water drives can be both natural, if

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maintained by active catchment area (natural energy), and artificial, if maintained by water injection. Under such drives, oil is displaced in one-phase state (without gas bleeding).

Gas cap drive acts and dominates in areally widespread gas caps. If gas is injected to gas cap and constant gas cap pressure is maintained, the gas cap drive is inelastic, and if gas cap pressure is decreased – elastic.

In case of simultaneous and approximately equal action of several kinds of energy, reservoir drive is termed a combination drive.

Head drives are more active and efficient in oil displacement. Depletion drives (elastic, dissolved gas and gravity drives) are characterized by low oil recovery factors.

Development target (production zone) is a formation (reservoir) or several formations (reservoirs) combined for development by separate well pattern (production and injection wells). If two or more formations are developed by one well pattern, it is said to be a combined development of multizone reservoir, if each formation is developed by separate well patterns – separate development. And if two or more formations are developed by one well (one well pattern) with special equipment without hydrodynamic combination of zones in borehole, such production is termed a commingled production. In terms of time, formations can be developed simultaneously (simultaneous combined and simultaneous separate development) or consecutively.

Well pattern spacing for this or that reservoir (development target) is a ratio of oil productive area to the number of production wells (m2/well or hectare/well, 1 hectare = 104m2). For instance, if a distance between well rows is 500 m, and a distance between wells in the row is 400 m, well spacing is 20=104·m2/well. (20 hectare/well).

Reservoir flooding for reservoir pressure maintaining can be out-contour (perimeter) water flooding (bottomholes of injection wells are outside the outer oil-pool outline at a distance 100…1000 from it), marginal water flooding (bottomholes of injection wells are within the oil-water zone closer to the outer oil-pool outline)

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and contour (boundary) water flooding. In the latter case, there are various flooding patterns: block contour water flooding (rows of injection wells, usually transverse rows) dividing a reservoir into two or more blocks), center-to-edge water flooding, localized water flooding, selective water flooding, pattern water flooding and combined water flooding. In Russia, block contour water flooding is mainly used for petroleum reservoir development.

1.3. Oil and Gas Field Development Indicators.

Stages of Development

The main production data and engineering parameters of field development, which characterize the oil field (reservoir) development, are as follows: annual and accumulated oil and fluid production; water cut; production and injection well stock; percent of oil recovery from the reservoir (annual oil production versus initial recoverable oil reserves); and oil recovery factor. Reservoir performance is also characterized by the current and accumulated balance between water injection and fluid withdrawal, by ratio of the current water cut to the share of recovered oil in the initial recoverable oil reserves, and by reservoir pressure decrease and other.

Oil field (reservoir) development is staged as follows: 1) the first stage – production zone development; it is characterized by growth of current oil production to maximum level; by increase of producing well stock (to 0.6…0.8 of maximum); by reservoir pressure decrease, and low water cut. Duration of the first stage is up to 4-5 years; the sudden flattening of drawdown curve indicates the end of the first stage; recovery factor can reach 10 % at the first stage; 2) the second stage corresponds to the highest current oil production which is retained for some time (from 1–2 to 5–7 years, sometimes longer); well stock is increased to maximum at the second stage (mainly, due to standby wells); water cut is also increased on from 2–3 to 5–7 % per year and reaches 55–65 %; the major part of flowing wells is transferred to artificial lift; a minor part of wells is put out of operation because of high water cut; oil recovery rate reaches 10…20 %, and 25-30 % for reservoirs with long oil rate-plateau. Fluid withdrawal is increased as water cut grows, but the current oil production begins gradually scaling down from some time; 3) the beginning of the third stage corresponds to the significant production drawdown at

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water cut reaching 75…85 % by the end of the stage; well stock is reduced because of flooding or poor technical state; practically all wells are artificial lift operated; the duration of the third stage is 10…15 years and over; oil recovery factors increases to 10…20 % for high-viscosity oil, and 40…50 % for low-viscosity oil; 4) the fourth (final) stage is characterized by low rate of production drawdown (annual withdrawal rate is about 1 % of initial recoverable reserves ), high water cut (higher than 80 %) and slow growth of it, and substantial decrease of producing well stock; the duration of the fourth stage is relatively long and comparable with the total duration of the first three stages, and it can be 20 years and over. Production wells are shut-in if water cut is 98–99 %; oil recovery under efficient reservoir development reaches the design oil recovery or is about it (usually adjusted at the final stage by amount of initial recoverable reserves and oil recovery factor); up to 15…25 % of the recoverable oil reserves are produced within the fourth stage.

The above indicators (oil rates, oil recovery rates and other) can significantly vary if fractured-cavernous and fractured-porous reservoirs are under development.

Oil recovery factor is efficiency of oil recovery from reservoir. Oil recovery factor is equal to the ratio of the amount of recovered oil to the amount of original in-place oil reserves. Relationship between oil recovery factor and production factors can be determined by the mathematical expression put forward by academician A.P. Krylov:

where η oil recovery factor; ηd is oil displacement efficiency; ηs is areal sweep efficiency; ηws – well spacing efficiency (it considers the fact that there is no displacement process in a part of volume of oil-saturated rocks); ηwf is water flooding efficiency or movable oil reserves efficiency (it considers withdrawal of movable reserves). Product ηd · ηs shows a share in the total (in-place) reserves of movable oil; ηr shows the part of such movable oil reserves that can be withdrawn during reservoir development (due to irregular water-front advancing, watering out reaches 100 % gradually, not instantaneously; based on economic consideration, production well operation is ceased if 100 % watering out is reached; and because of water breakthrough, a part of movable reserves is non-recovered).

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There are three stages or three periods in gas and gas condensate field development: 1) period of rising production (development, construction of surface field facilities and bringing the field into stable gas production); 2) period of stable production (further development for maintaining stable production level, booster station construction or expansion); and 3) period of declining production (decrease of producing well stock, decrease of well flow rates, increase of water cut and considerable decrease of reservoir pressure). Duration of the first stage can be 7…10 year, gas recovery reaches 20…25 % of initial reserves; within the second period, up to 50 % of the initial gas reserves are recovered, and gas recovery factor is 60…70 %. The period of stable production (the second stage) depends on the achieved rate of gas withdrawal: the higher the rate, the shorter the duration of the period.

Gas recovery factor is equal to the ratio of the recovered gas reserves to the initial gas reserves. It can be 0.8…0.85 under water drive and 0.9…0.95 under gas drive. Initial recoverable reserves of oil (gas) - original in-place reserves multiplied by the design oil (gas) recovery factor.

1.4. Oil and Gas Lift to Surface

Fluid (oil) rises to the surface due to reservoir energy. Such energy manifests itself by reservoir pressure and bottomhole pressure. Three cases are possible:

1)reservoir energy is sufficient for oil travel (migration) to bottomholes of producing wells, and for fluid lift to the surface;

2)bottomhole pressure is sufficient for fluid lift to the surface, but such pressure slightly differ from reservoir pressure, so, in case of low productivity factors, oil influx is low. Under reservoir drive, oil influx can be increased by reducing bottomhole pressure, but, in such case, such pressure will be insufficient for fluid lift; and

3)reservoir pressure is lower than pressure required for fluid lift.

In the first case, producing wells are operated under natural flow production, which is the most efficient and requires the lowest costs.

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In the second case, wells can be operated by natural flow production or by well pumps. Application of well pumps makes it possible to provide additional energy in well from the surface, reduce bottomhole pressure, increase underbalance and fluid influx, i.e. increase well flow rates. But application of pumps increases well operation costs, that is why well operation method – by natural flow or by pumps - should be selected based on technical and economic assessment.

In the third case, well operation without additional energy is impossible, and that is why well pumps or gas lift production (additional energy is provided in the form of compressed agent – gas) is applied.

Producing well operation by pumps (sucker rod, electric centrifugal, screw, diaphragm, jet, hydraulic piston and other pumps) or by gas lift is termed artificial lift well operation.

Gas wells are operated by natural flow production: due to much lower gas density against oil density, gas well wellhead pressure can be significantly lower than that of oil well.

1.5. Wellhead Stream Gathering and Treatment in Field

Oil production process flow diagram is shown in fig. 1.

Oil (oil with water) produced from well 1 should be metered, i.e. well oil flow rate and well fluid flow rate must be determined. It is also necessary to determine gas-oil ratio of well – this is amount of associated gas produced from 1 t or 1m3 of oil. All measurements are made automatically in satellite. In the satellite (2), at this or that period of time, one well flow is measured, if no flow meter is installed on its flow lines, while flows from other wells come to the working line without flow measuring. After the satellite, the combined flow of the given group of wells goes to the 1st stage separator (3) for associated gas separation. Separator pressure is slightly lower than wellhead pressure, and usually it is 0.4…0.6 MPa. Separated gas flows through gas line to the gas compressor station (5), which pumps gas to gas main pipeline (МГ).

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