книги / Разработка нефтяных и газовых месторождений
..pdfThe highest oil recovery factor is under water-oil displacement. Usually, it is associated with large energy margin of edge waters that can be unrestrictedly large in comparison with energy margin of free gas compressed in gas cap and dissolved in oil. It is also due to high efficiency of water displacement because the ratio of oil viscosity to water viscosity is more favorable for oil displacement by water than by gas. And, finally, physicochemical interaction of water with rock and oil can also be conductive to oil recovery enhancing under water drive. Washing out and displacement properties of water are better than those of gas.
Efficiency of dissolved gas drive is lower than efficiency of any other source of reservoir energy. It is due to limited volume of gas in reservoir and low gas-oil viscosity ratio that promotes fast gas breakthrough because of higher mobility. Moreover, gas phase does not wet reservoir rock, and this causes increasing residual oil content.
Gas cap drive is much more efficient. When expanding, gas migrates to bottomhole, and effective frontal drive is created under comparatively low gas saturation of reservoir. That is why, depending on the reservoir structure, oil recovery factors can be high in gas-cap reservoirs. But, in case of high heterogeneity of reservoir, oil recovery factor reduces under such conditions. Reduction of efficiency of gas cap expansion is mainly caused by gas non-wettability of solid phase or its low viscosity, and, as a result, gas breaks through large channels and more permeable zones of reservoir.
Gas-cap reservoir oil recovery factor is substantially impacted by angle of bedding. At steep dipping, conditions of gravitational separation of gas from oil are improved and gas drive efficiency is enhanced.
High oil viscosity against water viscosity causes oil recovery factor decrease. Studies show that, with oil viscosity growing, various local non-uniformities of physical properties of rocks appear and promote formation of small but numerous areas bypassed by water front and poorly encroached.
Reservoir oil recovery is significantly impacted by high specific surface of rocks. Oil hydrophobes the surface of solid phase, and part of film oil can be recovered only by applying a stimulation method.
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According to experimental and statistic field data, oil recovery factors under different reservoir drives can reach the below values:
Water drive .......................................... |
0.5—0.8 |
Gas cap drive ....................................... |
0.4—0.7 |
Dissolved gas drive.............................. |
0.15—0.3 |
Gas recovery factor of gas and gas condensate reservoirs is, as a rule, higher than oil recovery factor. Unlike oil, gases weakly interact with porous rock medium surface, their viscosity is low (hundred and more times less than light oil viscosity); due to high elasticity compressed gas always has energy margin required for filtration in porous rock medium; and reservoir pressure can decrease up to approximately atmospheric pressure. So, gas recovery factor of gas reservoirs can reach 0.90–0.95 under gas drive, and 0.6–0.85 under water drive. Gas recovery factor under water drive is lower because a part of gas volume is arrested due to faster movement of injected or edge water.
The highest gas recovery factor of gas reservoir can be reached by minimizing reservoir pressure to value at which bottomhole pressure is near atmospheric pressure or even lower than atmospheric pressure (gas vacuum suction). But under such conditions, well flow rate become low due to low pressure difference (Рr—Рbh). That is why, based on technical and engineering considerations, gas reservoir development is stopped if bottomhole pressure becomes higher than atmospheric pressure.
5. FLUID AND GAS INFLUX
Under oil or gas reservoir development, oil or gas inflow is radial.
Inflowing fluid or gas passes in succession a kind of number of concentrically located cylindrical surfaces between impermeable roof and bottom of reservoir, and areas of these surfaces are continuously reduced as the bottomhole is approached. If reservoir thickness is uniform and structure is homogenous, fluid (gas) filtration rate is continuously increasing, provided that flow rate is not changed, and reaches maximum on borehole walls.
If flow rate increases, hydraulic resistance becomes higher. Therefore, under migration of volumetric unit of fluid (or gas) to well, energy consumption per unit of travel path is continuously increasing, or pressure difference (pressure gradient) per unit of travel is increasing.
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Relationship between well flow rate and pressure difference (Pr–Pbh) is determined by Dupuis formula for radial steady-state flow of homogeneous fluid:
Q = 2πkh(Pпл − Pзаб) .
µln Rk rc
6. PETROLEUM RESERVOIR DEVELOPMENT
BY RESERVOIR PRESSURE MAINTAINING METHODS
6.1. Purpose of Reservoir Pressure Maintaining Methods
In the majority of cases, natural reservoir energy is not sufficient for high rate of oil withdrawal. Even under effective water drive, reservoir pressure is decreased during reservoir development, and this is indicative of reservoir pressure depletion. It is explained by the fact that volume of inflowing reservoir water is, as a rule, less than volume of recovered fluids.
If reservoir pressure becomes lower than bubble point pressure, gas bleeding begins, gas-oil ratio increases, water drive is converted to dissolved gas drive and well production rate significantly decreases, and, as a result, reservoir development is delayed for years.
In gas cap drive reservoirs, natural reservoir energy margin is comparatively low and reservoir pressure flashes down.
Dissolved gas drive can be characterized by reservoir pressure flashing down, low well flow rate and low oil recovery rate. The most effective measure for enhancing oil withdrawal rate and oil recovery factor is artificial maintenance of reservoir energy by water or gas (air) injection.
Reservoir energy maintenance prevent gas bleeding as reservoir pressure is maintained to be higher than bubble point pressure; under high pressure oil is better displaced from low permeable layers; reservoir life decreases; and oil production economics improves.
Methods of maintaining reservoir pressure by water or gas injection have received wide recognition in petroleum reservoir development. Gas should be injected to gas cap for maintaining reservoir gas cap drive, or it is necessary to create gas cap artificially in reservoirs if dip angle exceeds 10–15°. Water may be injected beyond oil drainage boundary, in zones adjacent to oil drainage boundary or within
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oil drainage boundary. In some cases, it is advisable to apply simultaneously a combined injection: gas and water injection.
Working agent can be injected at the initial stage of reservoir development. If reservoir is characterized by high elastic energy margin, injection can be applied at later stage.
In case of marginal flooding, water is injected through the special injection wells located along the perimeter of reservoir beyond oil drainage boundary. Production wells should be located within oil drainage boundary in rows parallel to outline.
Homogeneous sand or sandstone reservoirs with high permeability and not complicated with disturbances are most productive for perimeter water flooding. Perimeter water flooding of limestone reservoirs can not always respond favorably as some parts of such reservoirs are not interconnected with the rest area of conjugated channels and fractures.
Water injection can be also inefficient in high viscous oil production, because water viscosity is less than oil viscosity, and water will overdrive oil and breakthrough to wells, and premature flooding can take place.
In case of boundary water flooding, reservoir pressure balance is maintained or restored by water injection directly to the oil-saturated part of reservoir.
The below given types of boundary water flooding are applied in Russia:
•dividing by injection well rows into separate areas;
•barrier water flooding;
•dividing into separate blocks for independent development;
•center to edge water flooding;
•localized water flooding; and
•pattern water flooding.
6. PETROLEUM RESERVOIR ENGINEERING
ANALYSIS AND CONTROL
Drilling out, development and facilities construction, and, properly speaking, oil and gas production can be started when a reservoir management program is approved and accepted for implementation. From bringing reservoir into develop-
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ment and right to the end of reservoir development, various studies are performed for specifying geological-and-physical reservoir characteristics and reservoir performance indicators.
1.Standard geophysical measurements of apparent resistivity of rocks and spontaneous potential in penetrated geological column in all step-out wells.
2.Formation testing by formation tester tools in exploration wells, and core sampling in the majority of wells.
3.Flow-after-flow testing for building-up inflow performance relationship curves for all production and injection wells. Practically all wells shall be tested by bottomhole pressure build-up method. Such test shall be repeated in 1–2 years or more frequently, if effective drainage area is impacted. Bottomhole pressure and reservoir pressure should be measured, in the average, one time per six months.
For petroleum reservoir analysis and control, it is very important to measure fluid movement profile and intake rate of well by flow meters and flow rate meters. Frequency of such measurements in each well should be from six months up to twelve months, and, if necessary, such measurements may be made more frequent.
It is required to measure oil and water flow rates in all wells.
Oil-water and gas-oil contact position is determined by neutron and neutron lifetime logging with frequency about one time per six months.
Based on the analysis of petroleum reservoir engineering and identification of deviations between design and actual performance indicators, various work and actions should be performed for bringing the actual drift of development with designed one. A set of such arrangements is termed petroleum reservoir engineering control.
The process methods of petroleum reservoir engineering control shall include:
1.Change of production and injection well operation conditions by decreasing or increasing well flow rates and repressuring medium flow rate up to ceasing (shutting-in) well operation;
2.Interval bottomhole formation zone treatment for increasing fluid inflow from separate layers, or increasing flow rate of injected fluids;
3.Increase of injection pressure up to fracture opening pressure;
4.Isolation of particular interlayer; and
5.Cyclic formation stimulation and controlled change of filtration flows.
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The control methods associated with partial change of field development system shall include:
1)Localized and selective treatment of development targets by agent injection through the special injection wells or pattern of wells used for selective stimulation of regions of reservoir; and
2)Well workover operations or packer equipment setting for partial enlarging or downsizing, i.e. changing development targets.
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Course of lectures in
OIL AND GAS FIELD DEVELOPMENT GUIDING DOCUMENTS AND PROJECT CONTROL
1. ALL SUBSURFACE RESOURCES IN THE RUSSIAN FEDERATION BELONG TO THE STATE
The Constitution of the Russian Federation is the basis of the subsurface resources legislation of the Russian Federation which includes the Underground Resources Law and other federal laws and regulatory legal acts, as well as laws and other regulatory legal acts of the constituent entities of the Russian Federation, adopted under the Underground Resources Law.
Article 1–2 of the Underground Resources Law is dedicated to establishing the definition of subsurface resources property and contains the following wording: «Underground resources within the territory of the Russian Federation, including underground space, mineral and energy resources, and other resources, are state property.»
Being a property owner, the state maintains accounting of underground resources it owns.
For the purpose of accounting the mineral resources base status, the national balance of mineral reserves is maintained. It must contain information and data about quantity, quality and level of knowledge of each type of minerals in each field, about the extent of commercial development, production and economic life of proved reserves.
The state may give the right to use subsoil. The rights and responsibilities of a subsoil user are created on the date of subsoil license. Subsoil use is under constant control of the state.
Control over oil and gas field engineering and development is maintained through developing the production engineering documentation (PTD).
2. THE PRINCIPLE GUIDING DOCUMENTS
Oil and gas field engineering and development shall be in strict adherence to the laws of the Russian Federation, guiding documents (RD), guidelines and other regulatory documents acting in oil industry. The below three documents are the most important.
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Underground Resources Law establishes legal and economic framework of integrated rational subsoil use and protection, and provides protection of interests of state and citizens of the Russian Federation, as well as the rights of subsoil users.
Regulations for Oil and Gas-and-Oil Field Development is practical guidance for reservoir engineering, exploration, drilling, research and design enterprises and organizations, and control authorities of the Russian Federation. It provides the present-day requirements for exploration, reserves estimation and oil and gas-and-oil field development, construction and operation of wells and other oil and gas field production facilities, subsurface resources and environment protection.
Rules of Developing Project and Engineering Documentation on Oil and Gas Field Development (RD 153-39-007-96) establishes the structure and content of project documents on commercial development.
The Rules provides the general requirements and recommendations on Technical Design Assignment (Terms of Reference) content, development of project documents and content of all parts and sections of project documentation.
3. SUBSOIL USE LICENSING
Under Underground Resources Law and Regulations for Subsoil Use Licensing Procedure, oil and gas field exploration and development can be commenced only after granting the license for the right to use subsurface mineral resources.
License is a document that certifies the right of the license holder to use a portion of subsurface within the established boundaries for the purpose specified in the license within the established period of time, provided that the user complies with all stipulated requirements, terms and conditions.
4. MINING ALLOTMENT FOR FIELD DEVELOPMENT
Under the license for mineral resources production, the license holder is granted a portion of subsurface in the form of mining allotment.
Mining allotment is a sealed subsoil plot given to the subsoil user for oil and gas field development.
The subsoil user, who received a mining allotment, has an exclusive right to use subsurface resources under the granted license within the boundaries of such mining allotment. All activities related to subsoil use within the boundaries of
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the mining allotment may be carried out only upon consent of the subsoil use whom the mining allotment was given.
5. ALLOWABLE OIL AND GAS PRODUCTION
For the purpose of regular control over subsoil user’s activity, allowable oil and gas production is specified annually.
Allowable oil and gas production from the development target means amount of oil and gas production established by the approved production engineering documents and achieved by implementing all engineering solutions considering subsoil and environment protection requirements.
Allowable oil and gas production shall be established for each target under development annually for each quarter and calendar month. They shall be determined by Geological Department of the company, agreed with the engineering organization that developed the reservoir engineering plan for the target under development, and approved by the regional Geological Survey of the Ministry of Natural Resources and local body of Rostekhnadzor.
6. FIELD DEVELOPMENT ENGINEERING STAGES
Both engineering and field development are phased. Such approach is dictated by the fact that a development target is not accessible to full-scale investigation. All characteristics of the development target become known by indirect indicators. At the initial stage, the reservoir data are obtained by exploration wells and seismic operations, and, then, with drilling-out and putting of operating well stock into operation, volume of information is increased, and, in the majority of cases, reservoir data are significantly updated. Such updating the development target data is reflected in the engineering solutions.
Engineering project (design) documents are: 1 – exploration well testing plan;
2 – pilot operation project design;
3 – pilot commercial development process flow diagrams;
4 – reservoir engineering plan;
5 – development project design;
6 – specified development project designs (further development); and
7 – development analysis.
In case if new geological data are obtained, and they significantly changes the earlier estimation of the field reserves, basic development targets, as well as due
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to development economics changes or application of new production technologies, the below intermediate engineering documents may be developed, as an exceptional case:
–Supplements to pilot operation project design;
–Supplements to pilot commercial development process flow diagrams; and
–supplements to reservoir engineering plans.
Such supplements can introduce amendments or modifications or revisions of some engineering solutions, but they do not change the approved fundamentals of engineering project (design) documents.
The same tasks can be solved by field development follow-on.
6.1. Exploration Well Testing Plan
In the majority of cases, the first project document for the field is exploration well testing plan.
The main objective of production test is, in addition to oil production, to obtain data about production capacities of wells, composition and physicochemical properties of fluids and producing characteristics, and, in this connection, a research program shall be focused in such document.
6.2. Pilot Operation Project Design
Pilot operation project design is the first stage of oil and gas-and-oil field development project design. Pilot field or a part of field operation means a temporary (for the time period not longer than 3 years) operation of group of wells, either exploration, or, if necessary, specially drilled guide production and injection wells.
The objective and tasks is to specify the available data and obtain additional data for calculating hydrocarbon reserves, their valuable component content, build- ing-up geological model, Selection of reservoir drives, singling out pay zones and assessing oil, gas and gas condensate production prospects.
The special attention in Pilot Operation Project Plan should be paid, as it is in Exploration Well Testing Plan, to research program.
6.3. Reservoir Engineering Plan
Reservoir engineering plan is a project document that establishes the principles of formation stimulation and preliminary system of commercial field development, considering cost efficiency.
It is the first engineering document that envisages development of all reserves.
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