APPLIED PETROLEUM RESERVOIR ENGINEERING 3RD EDITION PDF

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Applied Petroleum Reservoir Engineering 3rd Edition Pdf

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Original edition published: Applied petroleum reservoir engineering / . neering, Third Edition, the purpose of the book has been and continues to be to prepare engineering beijuaganette.gq Craft - Applied Petroleum Reservoir Engineering - Free ebook download as PDF File .pdf), Text SECOND EDITION j Be Call:ยป Me rlawkins noe ae Hie Ronald E ee Applied Petroleum Reservoir Petroleum Production System 2nd beijuaganette.gq Applied Petroleum Reservoir Engineering. Third Edition. This page intentionally left blank. Applied Petroleum Reservoir Engineering Third Edition Ronald E.

The lower Blue line is the oil decline curve, which is an exponential decline curve. Oil is measured in BBL Oil barrels. Data is from actual sales, not pumped production. The dips to zero indicate there were no sales that month, likely because the oil well did not produce a full tank, and thus was not worth a visit from a tank truck. The upper right legend map displays CUM, which is the cumulative gas or oil produced. ULT is the ultimate recovery projected for the well.

The decline curve method uses production data to fit a decline curve and estimate future oil production. The three most common forms of decline curves are exponential, hyperbolic, and harmonic.

It is assumed that the production will decline on a reasonably smooth curve, and so allowances must be made for wells shut in and production restrictions. The curve can be expressed mathematically or plotted on a graph to estimate future production.

It has the advantage of implicitly including all reservoir characteristics. It requires a sufficient history to establish a statistically significant trend, ideally when production is not curtailed by regulatory or other artificial conditions.

As years pass, successive estimates of the ultimate recovery of fields tend to increase. The term reserve growth refers to the typical increases in estimated ultimate recovery that occur as oil fields are developed and produced. Relevant discussion may be found on the talk page.

Please do not remove this message until conditions to do so are met. May This section may require cleanup to meet Wikipedia's quality standards. The specific problem is: The table in this section presently presents resources rather than reserves, according to SPE definition Please help improve this section if you can. February Applied petroleum reservoir engineering 3rd edition [pdf] download 1.

Book Details Author: Ronald E. Terry ,J. Brandon Rogers Pages: Prentice Hall Brand: English ISBN: Publication Date: Terry and project engineer J. Brandon Rogers review the history of reservoir engineering, define key terms, carefully introduce the material balance approach, and show how to apply it with many types of reservoirs. Next, they introduce key principles of fluid flow, water influx, and advanced recovery including hydrofracturing.

Throughout, they present field examples demonstrating the use of material balance and history matching to predict reservoir performance. For the first time, this edition relies on Microsoft Excel with VBA to make calculations easier and more intuitive. This edition features Extensive updates to reflect modern practices and technologies, including gas condensate reservoirs, 4. You just clipped your first slide! Prospective resources are those quantities of petroleum estimated. Reserves must further satisfy four criteria: Prospective resources have both an associated chance of discovery and a chance of development.

Discovered petroleum initially-in-place is that quantity of petroleum that is estimated. Total recoverable or EUR may be termed basin potential. Early progress in oil recovery methods made it obvious that computations made from wellhead or surface data were generally misleading.

The precise knowledge of the behavior of crude oil. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur.

Even where solid materials are used. The separation of well or reservoir fluid into liquid and gas vapor phases depends mainly on temperature. Although these substances can occur as solids or semisolids such as paraffin. Sclater and Ste- phenson described the first recording bottom-hole pressure gauge and a mechanism for sampling fluids under pressure in wells. In many cases. When such terms are used.

In specialized areas.

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The sum of reserves. As early as The state or phase of a fluid in the reservoir usually changes with decreasing pressure as the reservoir fluid is being produced. The temperature in the reservoir stays relatively constant during the production.

These data enabled the development of certain useful equations. The study of the properties of rocks and their relationship to the fluids they contain in both the static and flowing states is called petrophysics.

Millikan pointed out the significance of temperature data in applications to reservoir and well studies. Schilthuis was able to derive a useful equation. Although temperature and geothermal gradients had been of interest to geologists for many years. The measurement of water saturation provided another important correction to the volumetric equation by consider- ing the hydrocarbon pore space as a fraction of the total pore volume. The next significant development was the recognition and measurement of connate water saturation.

The need for accurate bottom-hole pressures was further emphasized when Millikan and Sidwell described the first precision pressure gauge and pointed out the fundamental importance of bottom-hole pressures to reservoir engineers in determining the most efficient oil recovery methods and lifting procedures. Odeh and.

Schilthuis described a bot- tom-hole sampler and a method of measuring the physical properties of the samples obtained. Although Schilthuis proposed a method of calculating water encroachment using the material-balance equation.

Muskat21 pre- sented methods for calculating recovery by the internal or solution gas drive mechanism. Tarner and Buckley and Leverett laid the basis for calculating the oil recovery to be expected for particular rock and fluid characteristics.

Reservoir simulation was aided by the development of large-scale. Clark and Wessely urged a joint application of geological and engineering data to arrive at sound field development programs. This discovery in turn pointed the way to improved recoveries by taking advan- tage of the natural forces and energies. With the development of these techniques. Sophisticated numerical methods were also developed to allow the solution of a large number of equations by finite-difference or finite- element techniques.

In reservoirs under water drive. During the s.

These methods not only provided means for estimating recov- eries for economic studies. Reservoir engineering may be defined as the application of scientific principles to the drainage problems arising during the development and production of oil and gas reservoirs. Because reservoir engineering is the science of pro- ducing oil and gas. A reservoir is not an open underground cavern full of oil and gas. Usually the interface between two reservoir fluid phases is horizontal and is called a contact.

Between gas and oil is a gas-oil contact. That oil and gas. A small volume of water called con- nate or interstitial water remains in the oil and gas zones of the reservoir.

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As the density of gas is less than that of oil and both are less than water. Before defining these terms. Reservoir fluids are segregated into phases according to the density of the fluid. When the hydrocarbon reservoir is in contact with an aquifer. To account for all the reservoir fluid as pressure changes. Produced gases are measured in standard cubic feet SCF. Oil volume at these atmospheric conditions is measured in STBs one barrel is equal to 42 gallons.

As long as only liquid phases are in the reservoir. The total reservoir volume is fixed and dependent on the rock formations of the area. As reser- voir fluid is produced and the reservoir pressure drops. In practice. The liquid from the primary separator is then flashed into the stock tank. Once the saturation pressure is reached and gas starts evolving from solution. The well fluid is introduced into the primary separator where most of the produced gas is obtained.

G and W are initial reservoir gas and water. The change in volume factor for a measured change in the reservoir pressure allows for simple estimation of the initial gas or oil volume.

At this point. When the well fluid reaches the surface. As these fluids are produced. Figure 1. Gas Bg volume factors will increase considerably fold or more as the reservoir pressure drops.

The liquid accumulated in the stock tank is Np. Thus the gas produced at the surface will have a lower liquid content. Here the fluid is also initially in the one- phase gas state. Since this point lies outside the two-phase region and to the right of the critical point. The term retrograde is used because generally vaporization.

Of course. The condensed liquid remains immobile at low concentrations. This type of reservoir is commonly called a dew-point or a gas-condensate reservoir. Although the fluid left in the reservoir remains in one phase. This accounts for the production of condensate liquid at the surface from a single-phase gas phase in the reservoir.

This process of retrograde condensation continues until a point of maximum liquid volume is reached. Consider a reservoir containing the fluid of Fig.

The curves within the two-phase envelope show the percentage of the total hydrocarbon volume that is liquid for any temperature and pressure.

The area enclosed by the bubble-point and dew-point curves represents pressure and temperature combinations for which both gas and liquid phases exist.

The critical point. This is true for any accumulation with this hydrocarbon composition where the reservoir temperature exceeds the cricondentherm. As pressure declines due to production.

Below this pressure. This condensation leaves the gas phase with a lower liquid content. At pressure and temperature points located above the bubble-point curve. At pressure and temperature points located above or to the right of the dew-point curve.

After the dew point is reached. The overall retro- grade loss will evidently be greater 1 for lower reservoir temperatures. The retrograde liquid in the reservoir at any time is composed of mostly methane and ethane by volume. This revaporization aids liquid recovery and may be evidenced by decreasing gas-oil ratios on the surface.

The phase diagram of Fig. Neglecting for the moment this shift in the phase diagram. The gas cap will be at the dew point and may be either retrograde. Because surface facilities limit the gas production rate. This is called a bubble-point or black-oil or solution-gas reservoir.

Table 1.

When the free gas saturation is sufficiently large. As pressure de- clines during production. Because the composition of the gas and oil zones are entirely different from each other.

The liquid or oil zone will be at its bubble point and will be produced as a bubble-point reservoir modified by the presence of the gas cap. These reservoir types are discussed in detail in Chapters 4.

Oil reserves

From this technical point of view. Gas Single phase: Oil Two phase: Produced Primarily gas Gas and Oil and gas Oil and gas hydrocarbons condensate. The volatile oil is intermediate between the gas condensate and the black, or heavy, oil types.

The term wet gas is sometimes used interchangeably with gas condensate. In the gas-oil ratios, general trends are noticeable in the methane and heptanes-plus content of the fluids and the color of the tank liquids. The gas-oil ratios are a good indication of the overall composition of the fluid, high gas-oil ratios being associated with low concentrations of pentanes and heavier and vice versa. The gas-oil ratios given in Table 1. The gas-oil ratios and consequently the API gravity of the produced liquid vary with the number, pressures, and tem- peratures of the separators so that one operator may report a somewhat different gas-oil ratio from another, although both produce the same reservoir fluid.

Also, as pressure declines in the black oil, volatile oil, and some gas-condensate reservoirs, there is generally a considerable increase in the gas-oil ratio owing to the reservoir mechanisms that control the relative flow of oil and gas to the wellbores. The separator efficiencies also generally decline as flowing wellhead pressures decline, which also contributes to increased gas-oil ratios.

What has been said previously applies to reservoirs initially in a single phase. The initial gas- oil ratio of production from wells completed either in the gas cap or in the oil zone of two-phase reservoirs depends, as discussed previously, on the compositions of the gas cap hydrocarbons and the oil zone hydrocarbons, as well as the reservoir temperature and pressure.

The gas cap may con- tain gas condensate or dry gas, whereas the oil zone may contain black oil or volatile oil. Sometimes this is unavoidable, as when the gas and oil zones columns are only a few feet in thickness. Even when a well is completed in the oil zone only, the downward coning of gas from the overlying gas cap may occur to increase the gas-oil ratio of the production.

This means that when hydrocarbon is produced from a reservoir, the space that it occupied must be replaced with something. That something could be the swelling of the remaining hydrocarbon due to a drop in reservoir pressure, the encroachment of water from a neighboring aquifer, or the expansion of formation.

The initial production of hydrocarbons from an underground reservoir is accomplished by the use of natural reservoir energy. Sources of natural reservoir energy that lead to primary production include the swelling of reservoir fluids, the release of solution gas as the reservoir pressure declines, nearby communicating aquifers, grav- ity drainage, and formation expansion. When there is no communicating aquifer, the hydrocarbon recovery is brought about mainly by the swelling or expansion of reservoir fluids as the pressure in the formation drops.

However, in the case of oil, it may be materially aided by gravitational drain- age. When there is water influx from the aquifer and the reservoir pressure remains near the initial reservoir pressure, recovery is accomplished by a displacement mechanism, which again may be aided by gravitational drainage. When the natural reservoir energy has been depleted, it becomes necessary to augment the nat- ural energy with an external source.

The use of an injection scheme is called a secondary recovery operation. When water injection is the secondary recovery process, the process is referred to as waterflooding. The main purpose of either a natural gas or water injection process is to repressurize the reservoir and then maintain the reservoir at a high pressure. Hence the term pressure maintenance is sometimes used to describe a secondary recovery process. Often injected fluids also displace oil toward production wells, thus providing an additional recovery mechanism.

When gas is used as the pressure maintenance agent, it is usually injected into a zone of free gas i. The injected gas is usually produced natural gas from the reservoir in question. This, of course, defers the sale of that gas until the second- ary operation is completed and the gas can be recovered by depletion. Other gases, such as nitrogen, can be injected to maintain reservoir pressure.

This allows the natural gas to be sold as it is produced. The recovery efficiency of a waterflood is largely a function of the mac- roscopic sweep efficiency of the flood and the microscopic pore scale displacement behavior that is largely governed by the ratio of the oil and water viscosities. These concepts will be discussed in detail in Chapters 9, 10, and In many reservoirs, several recovery mechanisms may be operating simultaneously, but gen- erally one or two predominate.

During the producing life of a reservoir, the predominance may shift from one mechanism to another either naturally or because of operations planned by engineers.

For example, initial production in a volumetric reservoir may occur through the mechanism of fluid ex- pansion. When its pressure is largely depleted, the dominant mechanism may change to gravitational drainage, the fluid being lifted to the surface by pumps. Still later, water may be injected in some wells to drive additional oil to other wells.

Applied Petroleum Reservoir Engineering (2nd Edition)

In this case, the cycle of the mechanisms is expansion, gravitational drainage, displacement. There are many alternatives in these cycles, and it is the object of the reservoir engineer to plan these cycles for maximum recovery, usually in minimum time. Other displacement processes called tertiary recovery processes have been developed for application in situations in which secondary processes have become ineffective.

However, the same processes have also been considered for reservoir applications when secondary recovery techniques are not used because of low recovery potential. In this latter case, the word tertiary is a misnomer.

For most reservoirs, it is advantageous to begin a secondary or a tertiary process before primary production is completed. For these reservoirs, the term enhanced oil recovery was introduced and has become popular in reference to any recovery process that, in general, improves the recovery over what the natural reservoir energy would be expected to yield.

Enhanced oil recovery processes are presented in detail in Chapter Many of these factors carry with them debates concerning future predictions. King Hubbert took this concept and developed the term peak oil to describe not the decline of oil pro- duction but the point at which a reservoir reaches a maximum oil production rate. These factors include proven re- serves.

As a result. It would appear that Hubbert was fairly accurate with his model but a little off on the timing. There are many factors that go into building such a model.

Once all the wells that are going to be drilled for a given reservoir have been brought into production. Hubbert said this would occur at the midpoint of reservoir depletion or when one-half of the initial hydrocarbon in place had been produced.

It is not the purpose of this text to discuss this argument in detail but simply to point out some of the projections and suggest that the reader go to the literature for further information.. Just as there are several factors that affect the time of peak oil. Hubbert predicted the total world crude oil production would reach the peak around the year As one can see.

The report states the following: This method makes. These technologies are a large reason for the increase in US reserves from Hydraulic fracturing or fracking refers to the process of injecting a high-pressure fluid into a well in order to fracture the reservoir formation to release oil and natural gas. What are the issues that are involved in the debate? Write a short report that contains a description of both sides of the argument.Hence the term pressure maintenance is sometimes used to describe a secondary recovery process.

At this point. Neglecting for the moment this shift in the phase diagram. Full Name Comment goes here. You just clipped your first slide! See Tertiary oil Reserves. It gets even better: The solutions manual is in digital downloadable format and can be accessed instantly after download! The injected gas is usually produced natural gas from the reservoir in question.