Course Reservoir Engg

RESERVOIR ENGINEERING & MANAGEMENT

UNIT 1

1. Principles of Reservoir Engineering

Scope & importance of Reservoir Engineering

The technology concerned with the prediction of the optimum economic recovery of oil or gas from hydrocarbon-bearing reservoirs. It is an eclectic technology requiring coordinated application of many disciplines: physics, chemistry, mathematics, geology, and chemical engineering. Originally, the role of reservoir engineering was exclusively that of counting oil and natural gas reserves. The amount of oil or gas that can be economically recovered from the reservoir is a measure of the wealth available to the owner and operator. It is also necessary to know the reserves in order to make proper decisions concerning the viability of downstream pipeline, refining, and marketing facilities that will rely on the production as feedstock.

The scope of reservoir engineering has broadened to include the analysis of optimum ways for recovering oil and natural gas, and the study and implementation of enhanced recovery techniques for increasing the recovery above that which can be expected from the use of conventional technology.

The amount of oil in a reservoir can be estimated volumetrically or by material balance techniques. A reservoir is sampled only at the points at which wells penetrate it. By using logging techniques and core analysis, the porosity and net feet of pay (oil-saturated interval) and the average oil saturation for the interval can be estimated in the immediate vicinity of the well. The oil-saturated interval observed at one location is not identical to that at another because of the inherent heterogeneity of a sedimentary layer. It is therefore necessary to use statistical averaging techniques in order to define the average oil content of the reservoir (usually expressed in barrels per net acre-foot) and the average net pay. The aerial extent of the reservoir is inferred from the extrapolation of geology and fluid content as well as the drilling of dry holes beyond the productive limits of the reservoir. The definition of reservoir boundaries can be heightened by study of seismic surveys, particularly 3-D surveys, and analysis of pressure buildups in wells after they have been brought on production.

The overall recovery of crude oil from a reservoir is a function of the production mechanism, the reservoir and fluid parameters, and the implementation of supplementary recovery techniques. In general, recovery efficiency is not dependent upon the rate of production except for those reservoirs where gravity segregation is sufficient to permit segregation of the gas, oil, and water. Where gravity drainage is the producing mechanism, which occurs when the oil column

in the reservoir is quite thick and the vertical permeability is high and a gas cap is initially present or is developed on producing, the reservoir will also show a significant effect of rate on the production efficiency. Reservoir engineering expertise, together with geological and petrophysical engineering expertise, is being used to make very detailed studies of the production performance of crude oil reservoirs in an effort to delineate the distribution of residual oil and gas in the reservoir, and to develop the necessary technology to enhance the recovery.

The first chemical tracerTest Conducted at NCPA’s well

C-11 in January 1990.

The application of reservoir engineering begins during the exploration phase of the project with the analysis of the initial geophysical measurement data that indicate a promising geothermal system, and it continues throughout the operational life of the geothermal resource. It is the reservoir engineer’s task to test wells, monitor their output, design new wells, and predict the long-term performance of the reservoir and wells. This design and prediction is accomplished by studying field and operational measurement data and using computer models to project the field operation into the future. During operation of a geothermal field, the reservoir engineer will be able to compare the actual performance to the predicted performance. If necessary, the engineer can modify the management plan for the geothermal field to obtain more efficient operation.

Sedimentary formations suitable for hydrocarbon reserves The first requisite for hydrocarbon is a reservoir: a rock formation porous enough to contain oil or gas and permeable enough to allow their movement through it. Oil and gas occur in sedimentary rock formation laid down

in ancient riverbeds or beaches, and also occasionally in dune sands or deep-sea sands. Where the limestone is porous and permeable they also form reservoirs, as in reefs built up by corals, and in places where waves and tidal currents exist. In carbonate formation, limestone (Ca CO3) and dolomite (Mg CO3), which are more brittle and soluble than sandstones, secondary porosity is found in fractures, solution channels. The more prolific Iranian Petroleum Reservoirs are made of fractured carbonates. Hydrocarbons can occur within and around igneous rocks, sometimes in commercially significant quantities. Igneous or closely associated rocks can be hydrocarbon sources in the conventional sense (biotic) as well as possibly through abiotic processes. Maturation is extremely variable, depending on the extrusive/intrusive nature of the activity and the relative importance of a deep heat source. Igneous volatiles and hydrothermal fluids may also be important in mobilizing and moving hydrocarbons. Igneous rocks can have good reservoir qualities, and they can produce their own trapping structures as well as being part of a larger feature.

Though oil is mainly found in sedimentary rocks, all sedimentary rocks do not contain oil. An oil reservoir must have three pre-requisite conditions:

1. Porosity so as to accommodate sufficiently large amount of oil.2. Permeability to discharge oil and/or gas when well has been drilled.3. The porous sand beds, sand stone, conglomerates of fissured limestone

containing oil should be capped by impervious beds so that oil does not dissipate by percolation in the surrounding rocks.

Oil is usually found where the sedimentary rock strata are inclined and folded; in a sort of chamber or reservoir, in the highest possible situation. Normally, oils are associated with water. Being lighter than water, it collects in the anticlines or fault traps above the surface of water. Gas is still lighter and occurs above oil. Thus on drilling an oil well, one finds gas followed by oil, although gas seepage is not always a sure indicator of an oil reservoir.

Classification

Sedimentary rock types are classified in one of three categories. The clastic category forms from fragmented sediment. Portions of eroded or weathered rock bind, producing clastic subcategories of conglomerate, sandstone, siltstone, or shale. Grain size distinguishes rocks in each clastic subcategory.

A second category of sediment and sedimentary rock is termed chemical. As a result of dissolution, sediment of pre-existing rock(s) somewhat congeals and travels in a body of water. Usually evaporation settles the deposit which then completely solidifies. The product is a type of chemical sedimentary rock, commonly limestone.

The last category of sedimentary rock is known as biogenic or organic. The biogenic method, while chemical, is categorized separately because leftovers of living organisms compose the sediment. Shells and plant fragments unite in biogenic sedimentary rocks. Biogenic rocks form from evaporative and chemical processes which glue fossils into one mass. Limestone and coal are examples of biogenic sedimentary rocks.

Brief description of origin, migration & accumulation of hydrocarbon fluids

Origin of fossil fuels Fossil fuels are those energy sources that formed from the remains of once-living organisms. They include oil, natural gas, coal, and fuels derived from oil shale and tar sand. The differences in the physical properties among the various fossil fuels arise from differences between the starting materials from which the fuels formed and changes to those materials after the organisms died and were buried within the layers of the earth. Petroleum means rock-oil, and comes from the Latin Petra, meaning rock or stone, and oleum, meaning oil. Liquid petroleum, or oil, comprises a variety of liquid hydrocarbon compounds; compounds made up of different proportions of the elements carbon and hydrogen. There are also gaseous hydrocarbons (natural gas), in which methane is the most common component. Hydrocarbon mixtures usually also contain minor amounts of nitrogen, oxygen, and sulfur as impurities.

The production of a large deposit of any fossil fuel requires an even larger initial accumulation of organic matter, which is rich in carbon and hydrogen. Another requirement is that the organic debris be buried quickly to protect it from the air so that decay by biological activity or reaction with oxygen will not destroy it. Microscopic life is abundant over most of the earth’s oceans. When these organisms die, their remains can settle to the sea floor. There are also underwater areas near Shorelines, such as on many continental shelves, where sediments derived from continental erosion accumulate rapidly. In such a setting, the starting requirements for the formation of oil are satisfied; there is an abundance of organic matter rapidly buried by sediment. Oil and most natural gas are believed to form from such accumulated marine microorganisms. Some natural gas deposits that are not associated with oil may form from deposits of plant material buried in sediment. As burial continues, the organic matter begins to change. Pressures increase with the weight of the overlying sediment or rock; temperatures increase with depth in the earth; and slowly, over long periods of time, chemical reactions take place. These reactions break down the large, complex organic molecules into simpler, smaller hydrocarbon molecules. In the early stages of petroleum formation, the deposit may consist mainly of larger (heavy) hydrocarbons, which have the thick, nearly solid consistency of asphalt. As the petroleum matures, and as the breakdown of large molecules continues, successively “lighter” hydrocarbons are produced. Thick liquids give way to thinner ones, from which lubricating oils, heating oils, and gasoline are derived. In the final stages, most or all of the petroleum is broken down further into very simple, light, gaseous molecules—natural gas. Most of the maturation (cooking) process occurs in the temperature range of 50° to 100° C (approximately 120° to 210° F). Above these temperatures, the remaining hydrocarbon is almost entirely methane (natural gas); with further temperature increases, methane can also be broken down and destroyed.

Migration and accumulation

Once the solid organic matter is converted to liquids and/or gases, the hydrocarbons need to migrate out of the source rocks in which they formed in order to form a commercial deposit. The majority of petroleum source rocks are fine grained sedimentary rocks (like shale), from which it would be difficult to extract large quantities of oil or gas quickly. However, oil and gas are able to migrate out of their source rocks into more permeable rocks over the long spans of geologic time. Most people have the incorrect notion that there are underground “lakes” of oil. The oil industry has helped feed this misconception by talking about oil “pools.” The truth is that virtually all the oil is contained in tiny holes in solid rock. These holes, or pores, are filled with water, gas, or oil. But if the holes are not connected, then oil can’t flow out of the rock. The ability of liquid to flow through the pores is permeability. So, in addition to high porosity, which allows the rock to hold large amounts of oil, the rock must have good permeability, which allows oil to flow quickly out of the rock. A rock with good

porosity and permeability is a reservoir rock. Most oils and all natural gases are less dense than water, so they tend to rise as well as to migrate laterally through the water-filled pores of permeable rocks. Unless sealed by impermeable cap rocks, oil and gas may keep rising right up to the earth’s surface. These substances escape into the air, the oceans, or they flow out onto the ground at oil and gas seeps. These natural seeps, which are one of nature’s own pollution

Sources are not very efficient sources of hydrocarbons for fuel compared with present day extraction methods. Commercially, the most valuable deposits are those in which a large quantity of oil and/or gas is concentrated and confined) by geologic traps, such as folds and faults. If the reservoir rocks are not naturally permeable enough, it may be necessary to fracture (crack open) them artificially with explosives or with water or gas under high pressure to increase the rate at which oil or gas flows through them.

Porosity

Porosity or void fraction is a measure of the void spaces in a material, and is a fraction of the volume of voids over the total volume, between 0–1, or as a percentage between 0–100percent. It is defined by the ratio:

Where VV is the volume of void-space (such as fluids) and VT is the total or bulk volume of material, including the solid and void components. Both the mathematical symbols φ and n are used to denote porosity.

Two types of porosity are

a. Total &

b. Effective porosity

Total porosity

Total Porosity is the ratio: Sum of the volumes of all pores in the rock -------------------------------------------------------- Total Volume of rock

The volume of the reservoir rock which is fluid (oil, water, gas) filled, expressed as a percentage or a fraction of the gross (bulk) rock volume.

Effective porosity Effective Porosity is the ratio: Sum of the volumes of all interconnected pores in the rock ----------------------------------------------------------------- Total Volume of rock

Effective porosity excludes isolated pores and pore volume occupied by water adsorbed on clay minerals or other grains. Effective porosity is typically less than total porosity. In the original definition of core analysts, the volume of connected

pores in a unit volume of rock. Effective porosity in this sense is the total porosity less the isolated porosity. It is the porosity measured by most core analysis techniques that do not involve disaggregating the sample. In these techniques, the porosity is usually measured on totally dried core samples. Drying removes most of the clay-bound water.

In log interpretation, effective porosity means the total porosity less the clay-bound water. The definition is based on the analysis of shaly formations, in which the clay-bound water is considered immobile and hence ineffective. Isolated porosity is rare in such formations and is ignored, being included in the effective porosity.

Effective porosity on dried core samples is therefore greater than effective porosity from log analysis, and close to the total porosity from log analysis. In humidity-dried cores, part of the clay-bound water is not removed, and the difference is reduced.

In some usage, the capillary-bound water is not considered part of the effective porosity. In this case effective porosity is synonymous with free fluid. Effective porosity is measured in volume/volume, percent or porosity units.

1.5 Connate water saturation and irreducible oil saturation

The lowest water saturation, Swi, that can be achieved in a core plug by displacing the water by oil or gas. The state is usually achieved by flowing oil or gas through a water-saturated sample, or spinning it in a centrifuge to displace the water with oil or gas. The term is somewhat imprecise because the irreducible water saturation is dependent on the final drive pressure (when flowing oil or gas) or the maximum speed of rotation (in a centrifuge). The related term connate water saturation is the lowest water saturation found in situ.

1.6 Pressure transient analysis The analysis of pressure changes over time, especially those associated with small variations in the volume of fluid. In most well tests, a limited amount of fluid is allowed to flow from the formation being tested and the pressure at the formation monitored over time. Then, the well is closed and the pressure monitored while the fluid within the formation equilibrates. The analysis of these pressure changes can provide information on the size and shape of the formation as well as its ability to produce fluids.

1.7 Pressure built up test

The use of pressure buildup data has provided the reservoir engineer with one more useful tool in the determination of reservoir behavior. Pressure buildup analysis describes the build up in well bore pressure with time after a well

has been shut in. One of the principal objectives of this analysis is to determine the static reservoir pressure without waiting weeks or months for the pressure in the entire reservoir to stabilize.

Because the buildup in well bore pressure will generally follow some definite trend, it has been possible to extend the pressure buildup analysis to determine:

• Effective reservoir permeability• Extent of permeability damage around the well bore• Presence of faults and to some degree the distance to the faults• Any interference between producing wells • Limits of the reservoir where there is not a strong water drive or where the aquifer is no larger than the hydrocarbon reservoir

Certainly all of this information will probably not be available from any given analysis, and the degree of usefulness or any of this information will depend on the experience in the area and the amount of other information available for correlation purposes. The general formulas used in analyzing pressure buildup data come from a solution of the diffusivity equation. In pressure buildup and draw down analyses, the following assumptions, with regard to the reservoir,fluid and flow behavior, are usually made:

Reservoir

• Homogeneous• Isotropic• Horizontal of uniform thickness Fluid:• Single phase• Slightly compressible

Flow:

• Laminar flow• No gravity effects

Pressure buildup testing requires shutting in a producing well. The most common and the simplest analysis techniques require that the well produce at a constant rate, either from startup or long enough to establish a stabilized pressure distribution.

The pressure is measured immediately before shut-in and is recorded as a function of time during the shut-in period. The resulting pressure buildup curve is analyzed for reservoir properties and well bore condition. Stabilizing the well at a constant rate before testing is an important part of a pressure buildup test. If stabilization is overlooked or is impossible, standard data analysis techniques may provide erroneous information about the formation.

THE NEED FOR RESERVOIR LIMIT TESTSA reservoir limit test is a drawdown test to determine the pore volume connected to a well. Knowledge of the pore volume connected to a discovery well is vital in determining whether or not to develop a pool. Many such post-discovery decisions are made on the basis of core and log data. However, while such data is readily available and relatively easy to use, it only reflects the reservoir at or near the well bore, thus usually represents only a small part of the reservoir. Hence the need exists for surveying a large portion of the reservoir, and it is the reservoir limit test that has been specifically designed with this in mind.

THE NATURE OF THE TESTThe test requires that a well that has been shut in to stabilize the reservoir pressure be produced at a constant rate for a period long enough for the onset of a pseudo steady-state flow regime in the reservoir At pseudo steady state, the pressure decline throughout the reservoir becomes a linear function of time with a proportionality constant that is directly related to the reservoir volume

THE FEASIBILITY OF THE TESTSince the test must satisfy certain strict design criteria in order to be valid, and since the pressure response may render achievement of those criteria impractical, the following must be considered to determine whether or not the test would be feasible in a given reservoir. The producing time must exceed the time required for the onset of pseudo steady-state flow in the reservoir. In some cases, particularly where the reservoir is large, the permeability is low or both, the testing time would become impractically long. The production rate must be sufficient to cause a discernible pressure drop. This may be difficult to achieve in a low-productivity well. The rate should be held constant during the test. This may be difficult to achieve in a prolonged test. The test rate should not result in a pressure drawdown that would cause free-gas saturation, since this could complicate interpretation of the test results. The presence of an external drive makes it impractical to conduct a reservoir limit test.

Test-Design CalculationsTest-design calculations are made to estimate a range of pressure responses based on a range of possible reservoir properties. To have an idea about the reservoir properties, it is generally good practice to run a short transient test on the well soon after completion. Such tests would provide some of the data required for design calculations and, in addition, help to assess the potential of the well. The latter is very important especially when there is significant well bore damage. The common practice in test-design calculations has been to assume that the reservoir is a closed square except where geology in the area suggests otherwise. On the basis of this shape, and assuming an area equivalent to one or two drilling spacing units, the time for the onset of pseudo steady- state flow may be estimated

If the estimated time is so long as to result in poor economics, operational problems, or both, the reservoir limit test should be replaced by the so-called "economic limits test", which is run to estimate a minimum oil in place using the early-time pressure data. This type of test is mandatory where the reservoir is so large as to result in flaring of significant volumes of solution gas during the test.

1.8 Oil water contact

A bounding surface in a reservoir above which predominantly oil occurs and below which predominantly water occurs. Although oil and water are immiscible, the contact between oil and water is commonly a transition zone and there is usually irreducible water adsorbed by the grains in the rock and immovable oil that cannot be produced. The oil-water contact is not always a flat horizontal surface, but instead might be tilted or irregular.

1.9 Transition zone

An area in which water is too shallow for acquisition of marine seismic data with towed streamers, such as near the shoreline, marshes and lagoons. In some cases, source explosives can be rammed into the unconsolidated sediments of transition zone environments rather than drilling more costly shot holes. Likewise, hydrophones can be placed by ramming to couple the receiver to the Earth better and to save time and money during survey acquisition.

On drilling into a transition zone where pore pressure gradient is increasing, the decrease in bottom hole differential pressure results in an increase in penetration rate thus deviating from the compaction trend established in the normally pressured sequences above. In theory, the greater the overpressure/under

compaction the higher the drillability/penetration rate and this proportionality should allow the pore pressure to be quantified.

 However, any changes in drilling parameters are also likely to effect penetration rate therefore it is necessary to "normalise" penetration rate for such changes. The most widely used equation to accomplish this normalisation is the "corrected drilling exponent" or Dxc .

Where: R = penetration rate (ft/hr); N = rotation speed (rpm); W = weight on bit (klbs); B = hole diameter (ins); FBG = normal formation balance gradient and ECD = equivalent circulating density.

This dimensionless number is plotted every metre or 5 feet intervals in shale. Logarithmic or semi-logarithmic scale plots will in consolidated sediments produce a straight line compaction trend. On entering the transition zone Dxc points plotted will move to the left of the normal compaction trend as the drillability of the shale increases.

The ratio method can be used to calculate the pore pressure by dividing the Dxc value on the normal compaction trend by the observed Dxc value at the depth of interest and multiplying it by the normal formation balance gradient, which offshore is usually taken to be that of seawater (1.04 g/cc or 8.66 ppg).

It is important to remember that the Dxc was designed to be used for vertical holes drilled through transition zones of undercompacted clays using roller cone bits. In other situations, such as complex carbonate rich lithologies or where PDC bits are used, other normalizing equations have been developed.

 Unit-2 Gas liquid equilibria

2.1 Bubble point pressure

The pressure above which the fluid essentially remains in the liquid phase and all volatile

components are dissolved in the liquid.

Equations

Standing Correlation

o Pb = 18.2[(Rs/Sg) 0.83 10 a - 1.4

o a = 0.00091 (T) - 0.0125 Sapi

o Pb - Bubble Point Pressure (psi)

o Rs - gas solubility at bubble point (scf/stb)

o Sg - Specific Gravity of Gas under surface conditions

o T - Reservoir temperature (deg.F)

Assumptions

Standing correlation equation for Bubble Point pressure

2.2 Gas oil ratio

When oil is brought to surface conditions it is usual for some natural gas to come out of

solution. The gas/oil ratio (GOR) is the ratio of the volume of gas that comes out of

solution, to the volume of oil at standard conditions.

A point to check is whether the volume of oil is measured before or after the gas comes

out of solution, since the oil volume will shrink when the gas comes out.

In fact gas dissolution and oil volume shrinkage will happen at many stages during the

path of the hydrocarbon stream from reservoir through the well bore and processing plant

to export. For light oils and rich gas condensates the ultimate GOR of export streams is

strongly influenced by the efficiency with which the processing plant strips liquids from

the gas phase. Reported GORs may be calculated from export volumes which may not be

at standard conditions.

The GOR is usually measured in cubic feet of gas per barrel of oil or condensate.

If the GOR is greater than 10,000 cf/bbl, then the field is usually described as a gas well.

If less than 10,000, then the field is generally described as an oil well.

2.3 Formation volume factor of oil & gas

Oil and dissolved gas volume at reservoir conditions divided by oil volume at standard

conditions. Since most measurements of oil and gas production are made at the surface,

and since the fluid flow takes place in the formation, volume factors are needed to

convert measured surface volumes to reservoir conditions.

Oil formation volume factor

Oil formation volume factors are almost always greater than 1.0 because the oil in the

formation usually contains dissolved gas that comes out of solution in the well bore with

dropping pressure. The Oil Formation Volume Factor is a measure of the reduction in the

volume of crude oil as it is produced.

Gas formation volume factor

Gas volume at reservoir conditions divided by gas volume at standard conditions. This

factor is used to convert surface measured volumes to reservoir conditions, just as oil

formation volume factors are used to convert surface measured oil volumes to reservoir

volumes.

Equations

General Equation

o Bo = Vor/Vop

o Bo - Formation Volume Factor (rb/stb)

o Vor - Volume of oil + dissolved volatiles at reservoir conditions (rb)

o Vop - Volume of produced oil under stock tank conditions (stb)

o Standing Correlation - Below Bubble Point Pressure

o Bo = 0.972 + 0.000147 F 1.175

o F = Rso (Sg/So) 0.5+ 1.25 T

o Rso - Solution GOR (scf/stb)

o Sg - Gas Gravity

o So - Oil Gravity

o T - Temperature (deg.F)

o Correlations - Above Bubble Point Pressure

o Bo = Bob exp[co (pb - p)]

o Bob = Formation volume factor at Bubble Point (rb/stb)

o co - Oil Compressibility (1/psi)

o Pb - Bubble Point Pressure (psi)

o P - Reservoir Pressure (psi)

Assumptions

o Single Phase

2.4 Shrinkage factor of reservoir oil

The shrinkage factor of crude oil from separator conditions varies, dependant upon the

pressure and temperature of the separator and the individual fluid properties. The more

volatile the separator liquid phase, the more impact separator conditions and shrinkage

will be. Shrinkage value will be very dependant upon the separator pressure and

temperature and will change as these values vary.

Measuring the Crude Oil Shrinkage Factor

Good shrinkage measurement is best approached by collecting the primary separator

liquid and performing a separator test on it. This involves simulating shrinkage in the

laboratory at each stage of separation (pressure and temperature) from primary separator

to stock tank conditions. Different liquid streams (with different compositions), will

require laboratory analysis for each stream. The only problem with this approach is if

separator conditions change so will the shrinkage. There are a couple of ways to take this

into account.

It is done by collecting a separator liquid sample at the maximum pressure a separator

will be operated (preferably at a lowest temperature) to allow the maximum amount of

gas in solution. The sample is then compositionally analyzed and subjected to a separator

test, duplicating standard separator conditions from primary separator through stock tank

conditions. Examples are of the primary separator at 1100 psia and 100°F, second stage

separator at 750 psia and 85°F, third stage separator at 340 psia and 75°F, fourth stage

separator at 120 psia and 105°F, and stock tank at 15 psia and 85°F. Utilizing the

composition and the results from the separator test, an equation-of-state (EOS) computer

model is "tuned" to the measured shrinkage data. This tuned model can then be used to

predict shrinkage values at different separator pressure or temperature conditions with the

resulting data well within a 5% error band.

Alternatively, a series or matrix of separator tests at separator conditions covering the

anticipated spread of pressures and temperatures can be performed in the laboratory.

These tests generate a matrix of shrinkage values covering the anticipated range. The data

can establish a table or equation to yield shrinkage value as a function of separator

conditions. Typically, only primary separator conditions are varied. This approach can be

used with the equation-of-state computer model instead of physically performing the

matrix of separator tests — it is important to perform one experimentally to tune the

EOS, however.

Measuring Shrinkage Factor at the Well site

The "shrinkage tester" suggested for well site installation provides a rough shrinkage

value, one that probably isn’t is sufficient if your system is a 30°API oil and separator

conditions are not subject to significant change. Typically such equipment employ a

vessel filled with separator liquid at pressure (although not necessarily at temperature).

The volume of this vessel is known and calibrated. The vessel is then drained into a non-

pressurized graduated container while the entrained gas is allowed to escape. The

shrinkage value is simply the non-pressurized volume divided by the volume of the

pressurized vessel (dead oil divided by live oil volumes). Petroleum table values can

correct the non-pressurized volume to standard conditions (15°C or 60°F) although this is

often not done, adding yet another error.

This method does not take into account changes in shrinkage value caused by multiple

pressure/temperature changes of the liquid as produced by secondary and tertiary

separators. On an offshore platform and all the way to the shore base, typically there will

be several downstream separators in line from the primary separator. Each one of these

separators will have an impact on the shrinkage value and this is part of the reason they

are in place. Not taking temperature into account, there will be less shrinkage with more

stages of separation as the oil pressure is reduced to atmospheric pressure.

Shrinkage tester

2.5 Differential gas liberation process

In the differential liberation process, the solution gas that is liberated from an oil sample

during a decline in pressure is continuously removed from contact with the oil, and

before establishing equilibrium with the liquid phase. This type of liberation is

characterized by a varying composition of the total hydrocarbon system.

The experimental data obtained from the test include:

• Amount of gas in solution as a function of pressure

• The shrinkage in the oil volume as a function of pressure

• Properties of the evolved gas including the composition of the liberated gas, the gas

compressibility factor, and the gas specific gravity

• Density of the remaining oil as a function of pressure

The differential liberation test is considered to better describe the separation process

taking place in the reservoir and is also considered to simulate the flowing behavior of

hydrocarbon systems at conditions above the critical gas saturation. As the saturation of

the liberated gas reaches the critical gas saturation, the liberated gas begins to flow,

leaving behind the oil that originally contained it. This is attributed to the fact that gases

have, in general, higher mobility than oils. Consequently, this behavior follows the

differential liberation sequence. The test is carried out on reservoir oil samples and

involves charging a visual PVT cell with a liquid sample at the bubble-point pressure and

at reservoir temperature. As shown schematically in above Figure, the pressure is reduced

in steps, usually 10 to 15 pressure levels, and all the liberated gas is removed and its

volume is measured at standard conditions. The volume of oil remaining VL is also

measured at each pressure level. It should be noted that the remaining oil is subjected to

continual compositional changes as it becomes progressively richer in the heavier

components. The above procedure is continued to atmospheric pressure where the

volume of the residual (remaining) oil is measured and converted to a volume at 60°F,

Vsc. The differential oil formation volume factors Bod (commonly called the relative oil

volume factors) at all the various pressure levels are calculated by dividing the recorded

oil volumes VL by the volume of residual oil Vsc, or:

The differential solution gas-oil ratio Rsd is also calculated by dividing the volume of gas

in solution by the residual oil volume. Relative total volume Btd from differential

liberation as calculated from the following expression:

                Btd = Bod + (Rsdb - Rsd) Bg  

Where

Btd = relative total volume, bbl/STB

Bg = gas formation volume factor, bbl/scf

The gas deviation z-factor of the liberated (removed) solution gas at the specific pressure

and these values are calculated from the recorded gas volume measurements as follows:

Where

V = volume of the liberated gas in the PVT cell at p and T

Vsc = volume of the removed gas at standard condition

Flash gas liberation process

Flash or equilibrium separation is the condition that occurs when the fluid's pressure is

radically and suddenly changed and the whole system immediately separates into two

phases. In the laboratory, this type of liberation of gas is carried out in a mercury cell or

in a small-scale separator at surface temperature. It is felt that flash liberation most nearly

approximates the situation that occurs in field separators. In the flash gas liberation

process, all of the gas evolved from a reduction in pressure remains in contact with the

liquid phase. A typical example is the surface separator. In this the oil and gas are kept in

the vessel sufficiently long to approximate equilibrium for the pressure and temperature

in the vessel.

Another method is a lab test called a constant composition expansion or the constant

mass expansion is available. In addition it is possible to measure the volume of liquid and

gas if a windowed cell is used. This is not commonly done for oil and is used frequently

for gas condensates.

Schematic of (a) flash liberation and (b) differential liberation. The degree to which oil

volume is effected by the separation process is dependent on the composition of the oil.

In the case of low shrinkage oil (c), differential liberation provides for a larger volume of

stock tank oil. High shrinkage oil (d) is affected differently. The composition of the

reservoir fluid will determine which of the two processes results in a greater degree of oil

shrinkage. For most black oils, differential liberation results in less shrinkage.

Multistage separation is an attempt to approach differential separation at the surface in

order to achieve a larger volume of oil in the stock tank per barrel produced. There is also

an optimum set of separator conditions (pressure, temperature) for maximizing stock-

tank-oil volume.

2.6 Retrograde condensation in gas reservoir

The formation of liquid hydrocarbons in a gas reservoir as the pressure in the reservoir

decreases below dew point pressure during production. It is called retrograde because

some of the gas condenses into a liquid under isothermal conditions instead of expanding

or vaporizing when pressure is decreased.

2.7 Reservoir drive mechanisms

Producing oil and gas needs energy. Usually some of this required energy is supplied

by nature. The hydrocarbon fluids are under pressure because of their depth. The gas and

water in petroleum reservoirs under pressure are the two main sources that help move the

oil to the well bore and sometimes up to the surface. Depending on the original

characteristics of hydrocarbon reservoirs, the type of driving energy is different.

Solution Gas Drive Reservoirs

When a newly discovered reservoir is below the bubble point pressure, there will be

free gas as bubbles within the oil phase in reservoir. The reservoir pressure decreases as

Production goes on and this causes emerging and expansion of gas bubbles creating extra

Energy in the reservoir. These kinds of reservoirs are called as solution gas drive

reservoirs. Crude oil under high pressure may contain large amounts of dissolved gas.

When the reservoir pressure is reduced as fluids are withdrawn, gas comes out of the

solution and displaces oil from the reservoir to the producing wells. The efficiency of

solution gas drive depends on the amount of gas in solution, the rock and fluid properties

and the geological structure of the reservoir. Recoveries are low, on the order of 10-15 %

of the original oil in place (OOIP).

Recovery is low, because the gas phase is more mobile than the oil phase in the reservoir.

Solution gas drive reservoirs are usually good candidates fro water-flooding

Gas Cap Drive Reservoirs

Sometimes, the pressure in the reservoir is below the bubble point initially, so there is

more gas in the reservoir than the oilcan retain in solution. This extra gas, because of

density difference, accumulates at the top pf the reservoir and forms a cap. These kinds of

reservoirs are called a gas cap drive reservoir. In gas cap drive reservoirs, wells are

drilled into the crude oil producing layer of the formation. As oil production causes a

reduction in pressure, the gas in gas cap expands and pushes oil into the well bores.

Expansion the gas cap is limited by the desired pressure level in the reservoir and by gas

production after gas comes into production wells.

Schematic of a Typical Gas Cap Reservoir

Water Drive Reservoirs

Most oil or gas reservoirs have water aquifers. When this water aquifer is an active

one, continuously fed by incoming water, then this bottom water will expand as pressure

of the oil/gas zone is reduced because of production causing an extra driving energy. This

kind of reservoir is called water drive reservoirs. The expanding water also moves and

displaces oil or gas in an upward direction from lower parts of the reservoir, so the pore

spaces vacated by oil or gas produced are filled by water. The oil and gas are

progressively pushed towards the well bore. Recovery efficiencies of 70 to 80 % of the

original oil in place (OOIP) are possible in some water drive reservoirs.

Schematic of a Typical Water Drive Reservoir

Gravity Drainage Reservoirs

Gravity drainage may be a primary producing mechanism in thick reservoirs that have

a good vertical communication or in steeply dipping reservoirs. Gravity drainage is a

slow process because gas must migrate up structure or to the top of the formation to fill

the space formerly occupied by oil. Gas migration is fast relative to oil drainage so those

oil rates are controlled by the rate of oil drainage.

Under-saturated Reservoirs

A crude oil is under-saturated when it contains less gas than is required to saturate the

oil at the pressure and temperature of the reservoir. When the oil is highly under-

saturated much of the reservoir energy is stored in the form of fluid and rock

compressibility. Pressure declines rapidly as fluids are withdrawn from the under-

saturated reservoir until the bubble point is reached. Then, solution gas drive becomes the

source of energy for fluid displacement. Reservoir fluid analysis, PVT behavior and the

pressure data will identify an under-saturated reservoir. Those reservoirs are good

candidates for water injection to maintain a high pressure to increase oil recovery.

2.8 PVT properties of reservoir fluids

Fluids exist in reservoirs as mixtures of gas, oil, and water. Some reservoirs may contain

only gas and water, only oil and water, or mixtures of gas, oil, and water. Irrespective of

the proportions of these fluids present in a reservoir, obtaining fluid samples and studying

their phase behavior in a laboratory are necessary for establishing reservoir type, devising

strategies for reservoir management, and estimating expected hydrocarbon recovery. The

importance of collecting representative reservoir fluid samples (preferably early in the

life of the reservoir) and having the samples analyzed in a reputable laboratory can not be

over emphasized. It is one of the essential functions of the engineers working on new or

existing reservoirs as an integral part of a comprehensive data collection program.

Phase Diagrams

The PVT properties of reservoir fluids are introduced by reviewing the basic concepts of

phase diagrams. Phase diagrams are graphical representations that relate the properties of

a fluid system. The properties used in the representation could be intensive or extensive

properties. Intensive properties (pressure, temperature, density) are independent of the

extent of the system. Extensive properties (mass, volume, heat) depend on the extent of

the system. Common forms of phase diagrams show pressure-temperature (P-T),

pressure-volume (P-V), and temperature-volume (T-V) relationships. The basic concepts

of phase behavior and phase diagrams are discussed in this book by the use of P-T

diagrams.

PVT STUDY:

(i) PV Diagram:

A pressure volume diagram (or P-V diagram, or volume-pressure

loop) is used to describe a thermal cycle involving the following two variables:

Volume (on the X axis)

Pressure (on the Y axis)

(ii) PT Diagram:

A common graphic used to illustrate the relationship of substances in their

phase states as a function of pressure and temperature is the P-T diagram. It is also

referred to as a phase state diagram or a phase change diagram. The asterisk in the P-T

diagram below identifies a pressure-temperature combination that is known as the triple

point. That is where the substance can exist as a solid, a liquid, or a vapor.

PT diagram for ultramafic rocks.

(iii) Bubble point:

When heating a liquid consisting of two or more components, the bubble

point is the point where first bubble of vapor is formed. Given that vapor will probably

have a different composition than the liquid, the bubble point (along with the dew point)

at different compositions are useful data when designing distillation systems. For single

component mixtures the bubble point and the dew point are the same and are referred to

as the boiling point.

(iv) Dew Point:

The dew point is the temperature at which a given parcel of

humid air must be cooled, at constant barometric pressure, for water

vapor to condense into water. The condensed water is called dew. The dew point is a

saturation temperature.

The dew point is associated with relative humidity. A high relative humidity indicates

that the dew point is closer to the current air temperature. Relative humidity of 100%

indicates the dew point is equal to the current temperature and the air is maximally

saturated with water. When the dew point remains constant and temperature increases,

relative humidity will decrease.

Unit-3

Methods of reservoir estimation

Reserves and its classification

Reserves are those quantities of petroleum claimed to be

commercially recoverable by application of development projects to known

accumulations under defined conditions.] Reserves must satisfy four criteria:

They must be:

discovered through one or more exploratory wells

recoverable using existing technology

commercially viable

remaining in the ground

All reserve estimates involve uncertainty, depending on the amount of

reliable geologic and engineering data available and the interpretation of

those data. The relative degree of uncertainty can be expressed by dividing

reserves into two principal classifications—"proven" (or "proved") and

"unproven" (or "unproved"). Unproven reserves can further be divided into

two subcategories—"probable" and "possible"—to indicate the relative

degree of uncertainty about their existence. The most commonly accepted

definitions of these are based on those approved by the Society of Petroleum

Engineers (SPE) and the World Petroleum Council (WPC) in 1997.

Proven reserves

Proven reserves are those reserves claimed to have a reasonable certainty

(normally at least 90% confidence) of being recoverable under existing

economic and political conditions, with existing technology. Industry

specialists refer to this as P90 (i.e., having a 90% certainty of being

produced). Proven reserves are also known in the industry as 1P.

Proven reserves are further subdivided into "proven developed" (PD) and

"proven undeveloped" (PUD). PD reserves are reserves that can be produced

with existing wells and perforations, or from additional reservoirs where

minimal additional investment (operating expense) is required. PUD reserves

require additional capital investment (e.g., drilling new wells) to bring the

oil to the surface.

Proved reserves are the only type the U.S. Securities and Exchange

Commission allows oil companies to report to investors. Companies listed

on U.S. stock exchanges must substantiate their claims, but many

governments and national oil companies do not disclose verifying data to

support their claims.

Unproven reserves

Unproven reserves are based on geological and/or engineering data

similar to that used in estimates of proven reserves, but technical,

contractual, or regulatory uncertainties preclude such reserves being

classified as proven. Unproven reserves may be used internally by oil

companies and government agencies for future planning purposes but are not

routinely compiled. They are sub-classified as probable and possible.

Probable reserves are attributed to known accumulations and claim a 50%

confidence level of recovery. Industry specialists refer to them as P50 (i.e.,

having a 50% certainty of being produced). These reserves are also referred

to in the industry as 2P (proven plus probable).

Possible reserves are attributed to known accumulations that have a less

likely chance of being recovered than probable reserves. This term is often

used for reserves which are claimed to have at least a 10% certainty of being

produced (P10). Reasons for classifying reserves as possible include varying

interpretations of geology, reserves not producible at commercial rates,

uncertainty due to reserve infill (seepage from adjacent areas) and projected

reserves based on future recovery methods. They are referred to in the

industry as 3P (proven plus probable plus possible)

Strategic petroleum reserves

Many countries maintain government-controlled oil reserves for both

economic and national security reasons. According to the United States

Energy Information Administration, approximately 4.1 billion barrels

(650,000,000 m3) of oil are held in strategic reserves, of which 1.4 billion is

government-controlled. These reserves are generally not counted when

computing a nation's oil reserves.

A more sophisticated system of evaluating petroleum accumulations was

adopted in 2007 by the Society of Petroleum Engineers (SPE), World

Petroleum Council (WPC), American Association of Petroleum Geologists

(AAPG), and Society of Petroleum Evaluation Engineers (SPEE). It

incorporates the 1997 definitions for reserves, but adds categories for

contingent resources and prospective resources.

Contingent resources are those quantities of petroleum estimated, as of a

given date, to be potentially recoverable from known accumulations, but the

applied project(s) are not yet considered mature enough for commercial

development due to one or more contingencies. Contingent resources may

include, for example, projects for which there are currently no viable

markets, or where commercial recovery is dependent on technology under

development, or where evaluation of the accumulation is insufficient to

clearly assess commerciality.

Prospective resources are those quantities of petroleum estimated, as of a

given date, to be potentially recoverable from undiscovered accumulations

by application of future development projects. Prospective resources have

both an associated chance of discovery and a chance of development.

The United States Geological Survey uses the terms technically and

economically recoverable resources when making its petroleum resource

assessments. Technically recoverable resources represent that proportion of

assessed in-place petroleum that may be recoverable using current recovery

technology, without regard to cost. Economically recoverable resources are

technically recoverable petroleum for which the costs of discovery,

development, production, and transport, including a return to capital, can be

recovered at a given market price.

Unconventional resources exist in petroleum accumulations that are

pervasive throughout a large area. Examples include extra heavy oil, natural

bitumen, and oil shale deposits. Unlike conventional resources, in which the

petroleum is recovered through well bores and typically requires minimal

processing prior to sale, unconventional resources require specialized

extraction technology to produce. For example, steam and/or solvents are

used to mobilize bitumen for in-situ recovery. Moreover, the extracted

petroleum may require significant processing prior to sale (e.g., bitumen

upgraders). The total amount of unconventional oil resources in the world

considerably exceeds the amount of conventional oil reserves, but is much

more difficult and expensive to develop.

Volumetric estimation

• Most commonly used after discovery and early stage of production.

• Standard reserve equation with appropriate choice of parameter:

Area

Reservoir parameter (Area, Thickness, Porosity, water saturation,

formation volume factor).

Recovery factor.

Volumetric Estimate of hydrocarbon in place consists of the following steps:

– Determination of rock volume (hydrocarbon saturated portion) from area

and thickness.

– Determination of average porosity.

– Determination of water saturation to obtain hydrocarbon saturation.

– Volume correction of hydrocarbon at atmospheric pressure and

temperature.

Material Balance Method

Can be applied after obtaining certain amount of production data e.g.

– Production Volume.

– Reservoir Pressure and Temperature.

– Fluid analysis data.

– Log Data, Core data.

– Drive Mechanism.

Decline Curve Analysis

Analysis of production decline curve can provide estimation of three

important items.

Remaining Oil and gas reserves.

Future expected production rate.

Remaining productive life of well or reservoir.

Additionally explanation of any anomalies that appear on the graph is useful.

Analysis is only valid provided that the well (s) is (are) not altered and the

drainage is constant.

Reservoir simulation method

Reservoir simulation models are used by oil and gas companies in the

development of new fields. Also, models are used in developed fields where

production forecasts are needed to help make investment decisions. As

building and maintaining a robust, reliable model of a field is often time-

consuming and expensive; models are typically only constructed where large

investment decisions are at stake. Improvements in simulation software have

lowered the time to develop a model. Also, models can be run on personal

computers rather than more expensive workstations.

For new fields, models may help development by identifying the number of

wells required, the optimal completion of wells, the present and future needs

for artificial lift, and the expected production of oil, water and gas.

For ongoing reservoir management, models may help in improved oil

recovery by hydraulic fracturing. Highly deviated or horizontal wells can

also be represented. Specialized software may be used in the design of

hydraulic fracturing, and then the improvements in productivity can be

included in the field model. Also, future improvement in oil recovery with

pressure maintenance by re-injection of produced gas or by water injection

into an aquifer can be evaluated. Water flooding resulting in the improved

displacement of oil is commonly evaluated using reservoir simulation.

The application of enhanced oil recovery (EOR) processes requires that the

field possesses the necessary characteristics to make application successful.

Model studies can assist in this evaluation. EOR processes include miscible

displacement by natural gas, CO2 or nitrogen and chemical flooding

(polymer, alkaline, surfactant, or a combination of these). Special features in

simulation software are needed to represent these processes. In some

miscible applications, the "smearing" of the flood front, also called

numerical dispersion, may be a problem.

Reservoir simulation is used extensively to identify opportunities to increase

oil production in heavy oil deposits. Oil recovery is improved by lowering

the oil viscosity by injecting steam or hot water. Typical processes are steam

soaks (steam is injected, then oil produced from the same well) and steam

flooding (separate steam injectors and oil producers). These processes

require simulators with special features to account for heat transfer to the

fluids present and the formation, the subsequent property changes and heat

losses outside of the formation.

A recent application of reservoir simulation is the modeling of coal bed

methane (CBM) production. This application requires a specialized CBM

simulator. In addition to the normal fractured (fissured) formation data,

CBM simulation requires gas content data values at initial pressure, sorption

isotherms, diffusion coefficient, and parameters to estimate the changes in

absolute permeability as a function of pore-pressure depletion and gas

desorption.

Fundamentals

Traditional finite difference simulators dominate both theoretical and

practical work in reservoir simulation. Conventional FD simulation is

underpinned by three physical concepts: conservation of mass, isothermal

fluid phase behavior, and the Darcy approximation of fluid flow through

porous media. Thermal simulators (most commonly used for heavy oil

applications) add conservation of energy to this list, allowing temperatures

to change within the reservoirs

Numerical techniques and approaches that is common in modern simulators:

Most modern FD simulation programs allow for construction of 3-D

representations for use in either full-field or single-well models. 2-D

approximations are also used in various conceptual models, such as

cross-sections and 2-D radial grid models.

Theoretically, finite difference models permit discredit of the reservoir

using both structured and more complex unstructured grids to accurately

represent the geometry of the reservoir. Local grid refinements (a finer

grid embedded inside of a coarse grid) are also a feature provided by

many simulators to more accurately represent the near wellbore multi-

phase flow affects. This "refined meshing" near wellbores is extremely

important when analyzing issues such as water and gas coning in

reservoirs.

Representation of faults and their transmissibility are advanced features

provided in many simulators. In these models, inter-cell flow

transmissibility’s must be computed for non-adjacent layers outside of

conventional neighbor-to-neighbor connections.

Natural fracture simulation (known as dual-porosity and dual-

permeability) is an advanced feature which model hydrocarbons in tight

matrix blocks.

A black oil simulator does not consider changes in composition of the

hydrocarbons as the field is produced. The compositional model is a

more complex model, where the PVT properties of oil and gas phases

have been fitted to an equation of state (EOS), as a mixture of

components. The simulator then uses the fitted EOS equation to

dynamically track the movement of both phases and components in

field.

The simulation model computes the saturation change of three phases (oil,

water and gas) and pressure of each phase in each cell at each time step. As a

result of declining pressure as in a reservoir depletion study, gas will be

liberated from the oil. If pressures increase as a result of water or gas

injection, the gas is re-dissolved into the oil phase.

A simulation project of a developed field, usually requires "history

matching" where historical field production and pressures are compared to

calculated values. In recent years optimisation tools such as MEPO has

helped to accelerate this process, as well as improve the quality of the match

obtained. The model's parameters are adjusted until a reasonable match is

achieved on a field basis and usually for all wells. Commonly, producing

water cuts or water-oil ratios and gas-oil ratios are matched.

Enhanced / Improved Oil Recovery Methods

Enhanced oil recovery (EOR) refers to the process of producing liquid

hydrocarbons by methods other than the conventional use of reservoir

energy and reservoir re-pressurizing schemes with gas or water. On the

average, conventional methods of production produce about one-third of the

initial oil in place in a given reservoir. The remaining oil, nearly two-thirds

of the initial resource, is a large and attractive target for EOR methods. The

next few sections provide an introduction to this important topic in reservoir

engineering.

Formula for estimation of oil reserve

OIIP = Oil initially in Place

OIIP = VR x Ф x 1/Bo x (1-Sw)

VR = Rock Volume (Area x Average Thickness)

Ф = Porosity

Bo = Formation Volume Factor

Sw = Water saturation

Unit-4

Enhanced/improved oil recovery methods

Mobilization of Residual Oil

During the early stages of a water flood in a water-wet reservoir system,

the brine exists as a film around the sand grains and the oil fills the

remaining pore space. At a time intermediate during the flood, the oil

saturation has been decreased and exists partly as a continuous phase in

some pore channels but as discontinuous droplets in other channels. At the

end of the flood, when the oil has been reduced to residual oil saturation, the

oil exists primarily as a discontinuous phase of droplets or globules that

have been isolated and trapped by the displacing brine.

The water flooding of oil in an oil-wet system yields a different fluid

distribution at. Early in the water flood, the brine forms continuous flow

paths through the center portions of some of the pore channels. The brine

enters more and more of the pore channels as the water flood progresses. At

residual oil saturation, the brine has entered a sufficient number of pore

channels to shut off the oil flow. The residual oil exists as a film around the

sand grains. In the smaller flow channels, this film may occupy the entire

void space.

The mobilization of the residual oil saturation in a water-wet system

requires that the discontinuous globules be connected to form a continuous

flow channel that leads to a producing well. In an oil-wet porous medium,

the film of oil around the sand grains must be displaced to large pore

channels and be connected in a continuous phase before it can be mobilized.

The mobilization of oil is governed by the viscous forces (pressure

gradients) and the inter-facial tension forces that exist in the sand grain-oil-

water system.

Miscible Injection Processes

It was noted that microscopic displacement efficiency is largely a function

of interfacial forces acting among the oil, rock, and displacing fluid. If the

interfacial tension between the trapped oil and displacing fluid could be

lowered to 10~2 to 10"3 dyne/cm, the oil droplets could be deformed so that

they would squeeze through the pore constrictions and combine with other

droplets to yield a continuous oil phase. A miscible process is one in which

the interfacial tension is zero; that is, the displacing fluid and residual oil

mix to form one phase. If the interfacial tension is zero, the capillary

number becomes infinite and the microscopic displacement efficiency is

maximized.

There are, in general, two types of miscible processes.

One is referred to as the single-contact miscible process and involves

such injection fluids as liquefied petroleum gases (LPG) and alcohols. The

injected fluids are miscible with residual oil immediately on contact.

The second type is the multiple-contact, or dynamic, miscible process.

The injected fluids in this case are usually methane, inert fluids, or an

enriched methane gas supplemented with a CrQi fraction; this fraction of

alkanes has the unique ability of behaving like a liquid or a gas at many

reservoir conditions. The injected fluid and oil are usually not miscible on

first contact but rely on a process of chemical exchange of the intermediate

hydrocarbons between phases to achieve miscibility.

Chemical Injection Processes

Chemical flooding relies on the addition of one or more chemical

compounds to an injected fluid either to reduce the interfacial tension

between the reservoir oil and injected fluid or to improve the sweep

efficiency of the injected fluid by making it more viscous, thereby

improving the mobility ratio. Both mechanisms are designed to increase the

capillary number.

Three general methods are used in chemical flooding technology.

The first is polymer flooding, in which a large macromolecule is used to

increase the displacing fluid viscosity. This process leads to improved sweep

efficiency in the reservoir of the injected fluid. The remaining two methods,

micellar-polymer flooding and alkaline flooding, make use of chemicals that

reduce the interfacial tension between an oil and a displacing fluid.

The addition of molecules of large molecular weight (i.e., polymers) to

injected water can often increase the effectiveness of a conventional water-

flood. Polymers are usually added to the water in concentrations ranging

from 250 to 2000 parts per million (ppm). A polymer solution is more

viscous than a brine without polymer. In a flooding application, the

increased viscosity alters the mobility ratio between the injected fluid and

the reservoir oil. The improved mobility ratio leads to better vertical and

areal sweep efficiencies and thus higher oil recoveries. Polymers have also

been used to alter gross permeability variations in some reservoirs. In this

application, polymers form a gel-like material by cross-linking with other

chemical species. The polymer gel sets up in high permeability streaks and

diverts the flow of subsequently injected fluids to a different location.

The improvement in oil recovery when using polymers is a result of

improved sweep efficiency over what is obtained during a conventional

water-flood. Typical oil recoveries from polymer flooding are in the range

of 1 to 5% of the initial oil in place. It has been found that a polymer flood

is more likely to be successful if it is started early in the producing life of

the reservoir.

The micellar-polymer process uses a surfactant to lower the interfacial

tension between the injected fluid and the reservoir oil. A surfactant is a

surface-active agent that contains a hydrophobic ("dislikes" water) part to

the molecule and a hydrophilic ("likes" water) part. The surfactant migrates

to the interface between the oil and water phases and helps make the two

phases more miscible. Interfacial tensions can be reduced from —30

dyne/cm, found in typical water flooding applications, to 10"4 dyne/cm with

the addition of as little as 0.1 to 5.0 weight % surfactant to water-oil

systems. Soaps and detergents used in the cleaning industry are examples of

surfactants. The same principles involved in washing soiled linen or greasy

hands are used in "washing" residual oil off of rock formations.

As the interfacial tension between an oil phase and a water phase is

reduced, the capacity of the aqueous phase to displace the trapped oil phase

from the pores of the rock matrix increases. The reduction of interfacial

tension results in a shifting of the relative permeability curves such that the

oil will flow more readily at lower oil saturations.

When an alkaline solution is mixed with certain crude oils, surfactant

molecules are formed by chemical reactions between the alkaline solution

and the oil. When the formation of surfactant molecules occurs in situ, the

interfacial tension between the brine and oil phases can be significantly

reduced. The reduction of interfacial tension causes the microscopic

displacement efficiency to increase, thereby increasing oil recovery.

Thermal Processes

Primary and secondary production from reservoirs containing heavy, low-

gravity crude oils is usually a very small fraction of the initial oil in place.

These types of oils are very thick and viscous and as a result do not migrate

readily to producing wells. It is not uncommon for viscosities of certain

heavy crude to decrease by several orders of magnitude with an increase of

temperature of 100 to 200T. This suggests that if the temperature of a crude

oil in the reservoir can be raised by 100 to 200°F over the normal reservoir

temperature, the oil viscosity will be reduced significantly and will flow

much more easily to a producing well. The temperature of a reservoir can be

raised by injecting a hot fluid or by generating thermal energy in situ by

combusting the oil. Hot water or steam can be injected as the hot fluid.

Three types of processes are generally used in the industry: (1) the

continuous injection of hot fluids, such as hot water or steam; (2) the

intermittent injection of steam, referred to as steam cycling; and (3) the

injection of air or oxygen-enriched air to aid in the combustion of reservoir

oil.

The continuous injection of hot fluids is usually accomplished by

injecting either hot water or steam and is much like a conventional water

flood. When steam is injected into the formation, the thermal energy is used

to heat the reservoir oil. Unfortunately, the energy also heats the entire

environment, such as formation rock and water. Some energy is also lost to

the under burden and overburden. Once the oil viscosity is reduced by the

increased temperature, the oil can flow more readily to the producing wells.

The steam moves through the reservoir and comes in contact with cold oil,

rock, and water. As the steam contacts the cold environment, it condenses. A

hot water bank is formed and acts as a water flood, pushing additional oil to

the producing wells.

Several mechanisms responsible for the production of oil from a steam

injection process have been identified. These include thermal expansion of

the crude oil, viscosity reduction of the crude oil, changes in surface forces

as the reservoir temperature increases, and steam distillation of the lighter

portions of the crude oil.

The intermittent injection of steam, referred to as the steam stimulation

process or the cyclic steam process, begins with the injection of steam for a

period of days to weeks. The well is then shut in, and the steam is allowed to

soak the area around the injection well. This soak period is fairly short,

usually from one to five days. The injection well is then placed on

production. The length of the production period is dictated by the oil

production rate, and it can last from several months to a year or more. The

cycle is repeated as many times as economically feasible. The oil production

decreases with each new cycle.

Mechanisms of oil recovery that result from this process include (1)

reduction of flow resistance near the wellbore by reducing the crude oil

viscosity and (2) enhancement of the solution gas drive mechanism by

decreasing the gas solubility in an oil as temperature increases.

In heavy oil reservoirs, the steam stimulation process is often applied to

develop injectivity around an injection well so that a continuous steam injec-

tion process can be conducted.

The injection of air or oxygen-enriched air is referred to as the in situ

combustion process. Early attempts to apply the combustion process

involved what is called the forward dry combustion process. The crude oil

was ignited down hole, and then a stream of air or oxygen-enriched air was

injected into the well where the combustion was originated. The flame front

was then propagated through the reservoir. Large portions of heat energy

were lost to the surroundings with this process. To reduce the heat losses, a

reverse combustion process was conceived. In reverse combustion, the oil is

ignited as in forward combustion, but the air stream is injected into a

different well. The air is then "pushed" through the flame front as the flame

front moves in the opposite direction. Researchers found the process to

work in the laboratory, but when it was tried in the field on a pilot scale, it

was never successful. In the field, the flame would shut off because there

was no oxygen supply. When oxygen was injected, the oil would often self-

ignite. The whole process would then revert to a forward combustion

process.

When the reverse combustion process failed, a new technique called the

forward wet combustion process was introduced. This process begins as a

forward dry combustion, but once the flame front has been established, the

oxygen stream is replaced with water. As the water comes in contact with

the hot zone left by the combustion front, it flashes to steam, using energy

that otherwise would have been wasted. The steam moves through the

reservoir and aids in the displacement of oil. The wet combustion process

has become the primary method of conducting combustion processes.

Not all crude oils are amenable to the combustion process. For the com-

bustion process to function properly, the crude oil must contain enough

heavy components to serve as the source of fuel for the combustion. This

usually requires an oil of low API gravity.

Most of the oil that has been produced by EOR methods to date has been

a result of applying thermal processes. There is a practical reason for this, as

well as several technical reasons. To produce more than 1 to 2% of the

initial oil in place from a heavy oil reservoir, thermal methods had to be em-

ployed. As a result, thermal methods were investigated much earlier than

either miscible or chemical methods, and the resulting technology was

developed much more rapidly.

OVERALL RECOVERY EFFICIENCY

The overall recovery factor (efficiency) RF of any secondary or tertiary

oil recovery method is the product of a combination of three individual

efficiency factors as given by the following generalized expression:

RF = ED EA EV

In terms of cumulative oil production, NP = NS ED EA EV

Where

RF = overall recovery factor

NS = initial oil-in-place at the start of the flood,

STB NP = cumulative oil produced,

STB ED = displacement efficiency

EA = areal sweep efficiency

EV = vertical sweep efficiency

The displacement efficiency ED is the fraction of movable oil that has been

displaced from the swept zone at any given time or pore volume injected.

Because an immiscible gas injection or water flood will always leave behind

some residual oil, ED will always be less than 1.0.

The areal sweep efficiency EA is the fractional area of the pattern that

is swept by the displacing fluid. The major factors determining areal sweep

are:

•Fluid mobilities

•Pattern type

•Areal heterogeneity

•Total volume of fluid injected

The vertical sweep efficiency EV is the fraction of the vertical section of

the pay zone that is contacted by injected fluids. The vertical sweep

efficiency is primarily a function of:

Vertical heterogeneity

Degree of gravity segregation

Fluid motilities

Total volume injection

Note that the product of EA EV is called the volumetric sweep efficiency

and represents the overall fraction of the flood pattern that is contacted by

the injected fluid.

In general, reservoir heterogeneity probably has more influence

than any other factor on the performance of a secondary or tertiary

injection project. The most important two types of heterogeneity

affecting sweep efficiencies, EA and EV, are the reservoir vertical

heterogeneity and areal heterogeneity.

Vertical heterogeneity is by far the most significant parameter influ-

encing the vertical sweep and in particular its degree of variation in the

vertical direction. A reservoir may exhibit many different layers in the

vertical section that have highly contrasting properties. This stratification

can result from many factors, including change in depositional

environment, change in depositional source, or particle segregation.

Water injected into a stratified system will preferentially enter the layers

of highest permeability and will move at a higher velocity. Consequently,

at the time of water breakthrough in higher-permeability zones, a

significant fraction of the less-permeable zones will remain unflooded.

Although a flood will generally continue beyond breakthrough, the

economic limit is often reached at an earlier time.

Areal heterogeneity includes areal variation in formation properties (e.g.,

h, k,ϕ, Swc), geometrical factors such as the position, any sealing nature of

faults, and boundary conditions due to the presence of an aquifer or gas

cap. Operators spend millions of dollars coring, logging, and listing

appraisal wells, all of which permits direct observation of vertical

heterogeneity. Therefore, if the data are interpreted correctly, it should be

possible to quantify the vertical sweep, EV, quite accurately. Areally, of

course, matters are much more uncertain since methods of defining

heterogeneity are indirect, such as attempting to locate faults from well

testing analysis. Consequently, the areal sweep efficiency is to be

regarded as the unknown in reservoir-development studies. All three

efficiency factors (i.e., ED, EA, and EV) are variables that increase during

the flood and reach maximum values at the economic limit of the

injection project. Each of the three efficiency factors is discussed

individually and methods of estimating these efficiencies are presented.

Unit-5

Reservoir Management Concepts

This chapter presents a historical review of reservoir management

practices and discusses technological advances made and computer tools

developed in recent years to facilitate better reservoir management. It also

provides a reservoir management definition, discusses synergy and

teamwork, examines the integration of geosciences and engineering, and

analyzes the timing for reservoir management.

DEFINITION OF RESERVOIR MANAGEMENT

There are many reservoir engineers, geologists, and geophysicists who

realize that the maximum coordination of their disciplines is essential to the

future success of the petroleum industry. With this in mind, they follow the

principles of reservoir management for maximizing economic recovery of

oil and gas. One of the objectives of this section is to define reservoir

management The Webster Dictionary defines management as the "judicious

use of means to accomplish an end." Thus, the management of reservoirs can

be interpreted as the judicious use of various means available to a

businessman in order to maximize his benefits (profits) from a reservoir.

Reservoir management has been defined by a number of other authors.

Basically, sound reservoir management practice relies on the utilization of

available resources (i.e., human, technological and financial) to maximize

profits/profitability index from a reservoir by optimizing recovery while

minimizing capital investments and operating expenses. Reservoir

management involves making certain choices. Either let it happen, or make

it happen.

HISTORY OF RESERVOIR MANAGEMENT

Most people considered reservoir management synonymous with reservoir

engineering. As recently as the early 1970s, reservoir engineering was

considered the most important technical item in the management of

reservoirs. However, after understanding the value of geology, synergism

between geology and reservoir engineering became very popular and proved

to be quite beneficial.

Reservoir management has advanced through various stages in the past 30

years. The developmental stages of reservoir management could be

described as the following:

Stage 1—before 1970, reservoir engineering was considered the most

important technical item in the management of reservoirs. In 1962, Wyllie

emphasized two key items: (1) clear thinking utilizing fundamental reservoir

mechanics concepts and (2) automation using basic computers. In 1965,

Essley described "reservoir engineering" and concluded that in spite of the

technical advancement of reservoir engineering, vital engineering

considerations are often neglected or ignored.

Stage 2—This covers the time period of the 1970s and 1980s. Craig et al.

(1977) and Harris and Hewitt (1977) explained the value of synergism

between engineering and geology. Craig emphasized the value of detailed

reservoir description, utilizing geological, geophysical, and reservoir

simulation concepts. He challenged explorationists, with the knowledge of

geophysical tools, to provide a more accurate reservoir description to be

used in engineering calculations. Harris and Hewitt presented a geological

perspective of the synergism in reservoir management. They explained the

reservoir heterogeneity due to complex variations of reservoir continuity,

thickness patterns, and pore-space properties (e.g., porosity, permeability,

and capillary pressure).

FUNDAMENTALS OF RESERVOIR MANAGEMENT

Although the synergism provided by the interaction between geology and

reservoir engineering has been quite successful, reservoir management has

generally been unsuccessful in recognizing the value of other disciplines

(e.g., geophysics, production operations, drilling, and different engineering

functions).

The prime objective of reservoir management is the economic optimization

of oil and gas recovery, which can be obtained by the following steps:

Identify and define all individual reservoirs in a particular field and

their physical properties.

Deduce past and predict future reservoir performance.

Minimize drilling of unnecessary wells.

Define and modify (if necessary) wellbore and surface systems.

Initiate operating controls at the proper time.

Consider all pertinent economic and legal factors.

Thus, the basic purpose of reservoir management is to control operations to

obtain the maximum possible economic recovery from a reservoir based on

facts, information, and knowledge.

In 1963, Calhoun described the engineering system of concern to the

petroleum engineer as being composed of three principal subsystems:

Creation and operation of wells.

Surface processing of the fluids.

Fluids and their behavior within the reservoir.

The first two subsystems depend on the third because the type of fluids (i.e.,

oil, gas, and water) and their behavior in the reservoir will dictate how many

wells to drill and where, and how they should be produced and processed to

maximize profits.

Since the goal is to maximize profits, neglecting or de-emphasizing any of

the previous items could jeopardize our objective. For example, we could do

well in studying the fluids and their interaction with rock (i.e., reservoir

engineering), but if the proper well and/or surface system design is not

considered, then recovery of oil and/or gas will not be optimized

The suggested reservoir management approach emphasizes interaction

between various functions and their interaction with management,

economics, proration, and legal groups. The reservoir management model

that involves interdisciplinary functions has provided useful results for many

projects.

SYNERGY AND TEAM

Successful reservoir management requires synergy and team efforts. It is

recognized more and more that reservoir management is not synonymous

with reservoir engineering and/or reservoir geology. Success requires

multidisciplinary, integrated team efforts. The players are everybody who

has anything to do with the reservoir. The team members must work together

to ensure development and execution of the management plan. By crossing

the traditional boundaries and integrating their functions, corporate resources

are better utilized to achieve the common goal.

All development and operating decisions should be made by the reservoir

management team, which recognizes the dependence of the entire system

upon the nature and behavior of the reservoir. It is not necessary that all

decisions be made by a reservoir engineer; in fact, a team member who

considers the entire system, rather than just the reservoir aspect, will be a

more effective decision maker. It will help tremendously if the person has

background knowledge of reservoir engineering, geology, production and

drilling engineering, well completion and performance, and surface

facilities. Not many people in an organization have knowledge in all areas.

However, many persons develop an intuition for the entire system and know

when to ask for technical advice regarding various elements of the system.

The team effort in reservoir management cannot be overemphasized. It is

even more necessary now than it has ever been because the current trend of

the oil industry is not one of expansion. Most companies are carrying on

their production activities with a staff much smaller than had existed just

five years ago.

Also, with the advent of technology and the complex nature of

different subsystems, it is difficult for anyone to become an expert in all

areas. Therefore, it is obvious that the reduction of talent and the

increasingly complex technologies must be offset by an increase in

quality, productivity, and emphasis on the team effort.

A team approach to reservoir management can be enhanced by the

following:

Facilitate communication among various engineering disciplines,

geology, and operations staff by: (a) meeting periodically, (b)

interdisciplinary cooperation in teaching each other's functional

objectives, and (c) building trust and mutual respect. Also, each

member of the team should learn to be a good teacher.

To some degree, the engineer must develop the geologist's knowledge

of rock characteristics and depositional environment, and a geologist

must cultivate knowledge in well completion and other engineering

tasks, as they relate to the project at hand.

Each member should subordinate their ambitions and egos to the goals

of the reservoir management team.

Each team member must maintain a high level of technical

competence.

Reservoir engineers should not wait on geologists to complete their

work and then start the reservoir engineering work. Rather, a constant

interaction between the functional groups should take place. For

example, it is better to know early if the isopach and cumulative

oil/gas production maps do not agree rather than finalize all isopach

maps and then find out that cumulative production maps are indicating

another interpretation of the reservoir. Using an integrated approach to

reservoir management along with the latest technological advances

will allow companies to extract the utmost economic recovery during

the life of an oil field. It can prolong the economic life of the

reservoir.

In summary, the synergism of the team approach can yield a "whole greater

than the sum of its parts”

Today, it is becoming common for large reservoir studies to be integrated

through a team approach. However, creating a team does not guarantee an

integration that leads to success. Team skills, team authority, team

compatibility with the line management structure, and overall understanding

of the reservoir management process by all team members are essential for

the success of the project. Also, most reservoir management teams are being

assembled only at key investment times. Missing today are ongoing

multidisciplinary reservoir management efforts for all significant reservoirs.

Synergy is not a new concept. Halbouty, chairman and CEO of Michael T.

Halbouty Energy Co. in Houston, a long-time advocate of synergy and team

approach, recognized this concept as basic to future petroleum reserves and

production.

Major producers also have used the integrated approach for years. As an

early example, Amoco IntL Oil Co. used a multidisciplinary approach in the

East Unit of the North Sea Leman field from the time the field came pn

stream in 1968. The field contained more than 10 Tcf [280 x 106 m3] of gas

—then the world's largest producing offshore gas field.

Working in a complex fault system, the company's reservoir engineers

worked closely with geologists to "produce an accurate a priori reservoir

description." The team tested the description against field perforrmance in a

2D fine-grid, single-phase model and refined it with measured pressures

from the first six years of production. The team gained valuable insight into

fault configurations and the relationships of gas in place, permeability, and

reserves.

Geologists reviewed the locations of faults and reservoir boundaries in the

historical map. The resulting model successfully predicted pressure for an

additional two years. The proven accuracy of the model led to confident

planning of future platform and compression requirements, providing more

than three years' lead time to install equipment.

Organization and management of the reservoir management team requires

special attention. Formation of the team, selection of team members,

appropriate motivational tools, and composition of the team should be

carefully considered.

Other aspects such as team leadership, establishment of team goals and

objectives, and performance appraisals of the team members are some

matters that play a key role in effective reservoir management.

Once a team is formed and begins to function, another item of significance

is how to sustain team effort. It is easy to get excited when the teams are set

up, at times of major expenditures, development effort, 3-D seismic

program, and so forth; however, to get the ongoing attention by a

multidisciplinary team for all major reservoirs requires great commitment by

the operating company.

One model of the team approach follows:

Functional management nominates team members to work on a

project team with specific tasks in mind.

The team reports to the production manager for this project. Also, the

team selects a team leader, whose responsibility is to coordinate all

activities and keep the production manager informed.

The team members consist of representatives from geology and

geophysics, various engineering functions, field operations, drilling,

finance, and so forth.

Team members prepare a reservoir management plan and define their

goals and objectives by involving all functional groups. The plan is

then presented to the production manager; and after receiving the

manager's feedback, appropriate changes are made. Next the plan is

published and all members follow the plan.

The team members' performance evaluation is conducted by their

functional heads with input from the team leader and the production

manager. The performance appraisal, in addition to various

dimensions of performance, includes teamwork as a job requirement.

Teams are rewarded recognition/cash awards upon timely and

effective completion of their tasks. These awards provide an extra

motivation for team members to do well.

As the project goals change (e.g., from primary development to

secondary process), the team composition changes to include

members with the required expertise. Also, this provides an

opportunity to change/rotate team members with time.

Approvals for project AFE's (Appropriation For Expenditures) are

initiated by the team members; however, the engineering/ operations

supervisor and/or production manager have the final approval

authority.

Sometimes conflicting priorities for the team members develop

because they essentially have two bosses (i.e., their functional heads

and the team leader). These conflicts are generally resolved by

constant communication among the team leader, functional heads, and

the production manager.

INTEGRATION OF GEOSCIENCE & ENGINEERING

Halbouty stated in 1977: "It is the duty and responsibility of industry

managers to encourage full coordination of geologists, geophysicists, and

petroleum engineers to advance petroleum exploration, development, and

production."

Despite the emphasis, progress on integration has been slow.

Sessions and Lehman presented the concept of increased interaction between

geologists and reservoir engineers through multifunctional teams and cross-

training between the disciplines. They stated that production geology and

reservoir engineering within the conventional organization function

separately, and very seldom does a production geologist get in-depth

experience in reservoir engineering and vice versa. They advocated cross-

exposure and cross-training between disciplines. Integrated reservoir

management training for geoscientists and engineers offered by many major

oil and gas companies is designed to address these needs.

Sessions and Lehman presented Exxon's three case histories where the

geology-reservoir engineering relationship was promoted through both a

team approach and an individual approach. The results of the three cases

(project-based approach, team-based approach, and multi-skilled individual

approach) were very positive.

Synergy and team concepts are the essential elements for integration 0f

geosciences and engineering. It involves people, technology, tools, and data.

Success for integration depends on:

Overall understanding of the reservoir management process,

technology, and tools through integrated training and integrated job

assignments.

Openness, flexibility, communication, and coordination.

Working as a team.

Persistence.

Reservoir engineers and geologists are beginning to benefit from seismic

and cross-hole seismology data. Also, it is essential that geological and

engineering ideas and reasoning be incorporated into all seismic results if the

full economic value of the seismic data is to be realized.

Perfectly conscientious and capable seismologists may overlook a possible

extension in a proven area because of their unfamiliarity with the detailed

geology and engineering data obtained through development.

For this reason, geological and engineering data should be reviewed

and coordinated with the geophysicists to determine whether or not an

extension is possible for the drilling of an exploratory well. Most of the

difficulties encountered in incorporating geological and engineering

knowledge into seismic results and vice versa may be averted by an

exchange of these ideas between the three disciplines.

Robertson of Arco points out that the geologic detail needed to properly

develop most hydrocarbon reservoirs substantially exceeds the detail

required to find them.21 This perception has accelerated the application of

3D-seismic analysis to reservoir management. A 3D-seismic analysis can

lead to identification of reserves that may not be produced optimally (or

perhaps not produced at all) by the existing reservoir management plan. In

addition, it can save costs by minimizing dry holes and poor producers.

The initial interpretation of a 3D-seismic survey affects the original

development plan. With the development of the field, additional information

is collected and is used to revise and refine the original interpretation. Note

that the usefulness of a 3D-seismic survey lasts for the life of the reservoir.

The geophysicists' interpretation of the 3D-seismic data may be combined

with the other relevant information regarding the reservoir (i.e., trap, fault,

fracture pattern, shapes of the deposits). The 3D-seismic data guide interwell

interpolations of reservoir properties. The reservoir engineer can use the

seismic volume to understand lateral changes.

The 3D-seismic analysis can be used to look at the flow of fluids in a

reservoir. Such flow surveillance is possible by acquiring baseline 3D-data

before and after the fluid flow and pressure/temperature changes. Although

flow surveillance with multiple 3D-seismic surveys is at an early stage of

application, it has been successfully applied in thermal recovery projects.

Cross-well seismic tomography is developing into an important tool for

reservoir management, and within the last few years there have been notable

advances in the understanding of the imaging capability of cross-well

tomograms. The fundamental requirements for the technology have been

demonstrated. High-frequency seismic waves capable of traveling long

interwell distances can be generated without damaging the borehole, and

tomographic inversion techniques can give reliable images as long as the

problems associated with nonuniform and incomplete sampling are handled

correctly.

Cross-well seismology is becoming an important tool in reservoir

management. Current applications focus on the monitoring of enhanced oil

recovery processes, but perhaps most important is the potential of the

method to improve our geological knowledge of the reservoir. So far, most

cross-well seismic surveys have been done for the purpose of mapping steam

zones in steam flood operations. Seismology is well suited for this

application, since the presence of live steam in the reservoir sharply reduces

the P-wave velocity. Moreover, for high-gravity oils in unconsolidated sand

reservoirs the seismic P-wave velocity decreases significantly with increased

temperature. Consequently, seismic velocities can be used as a measure of

reservoir temperature and/or an indicator of live steam within the reservoir.

The role of geology in reservoir simulation studies was well described by

Harris in 1975. He described the geological activities required for

constructing realistic mathematical reservoir models. These models are used

increasingly to evaluate both new and mature fields and to determine the

most efficient management scheme. Part of the information contained in the

model is provided by the geologist, based on studies of the physical

framework of the reservoir. However, for the studies to be useful the

geologist must develop quantitative data. It is important that the geologist

and the engineer understand each other's data.

As described by Harris, both engineering and geological judgment must

guide the development and use of the simulation model. The geologist

usually concentrates on the rock attributes in four stages:

(1) rock studies establish lithology and determine depositional environment,

and reservoir rock is distinguished from nonreservoir rock

(2) framework studies establish the structural style and determine the three-

dimensional continuity character and gross-thickness trends of the reservoir

rock

(3) reservoir-quality studies determine the framework variability of the

reservoir rock in terms of porosity, permeability, and capillary properties

(the aquifer surrounding the field is similarly studied)

(4) integration studies develop the hydrocarbon pore volume and fluid

transmissibility patterns in three dimensions.

Throughout his work, the geologist requires input and feedback from the

engineer. Core-analysis measurements of samples selected by the geologist

provide data for the preliminary identification of reservoir rock types. Well-

test studies aid in recognizing flow barriers, fractures, and variations in

permeability. Various simulation studies can be used to test the physical

model against pressure-production performance; adjustments are made to the

model until a match is achieved.

Many companies have initiated the development of a three-dimensional

geological modeling program to automate the generation of geologic maps

and cross-sections from exploration data.

INTEGRATING EXPLORATION AND DEVELOPMENT

TECHNOLOGY

New developments in computer hardware, technology, and software are

enhancing integration of multidisciplinary skills and activities. The

mainframe supercomputers, more powerful personal computers, and

workstations have revolutionized interdiscipline technical activities and

industry business practices, making them more responsive and effective.

Recently, Oil and Gas Journal published a special report on "Integrating

Exploration and Development Technology" using state-of-the-art computing

and communications. The OGJ special report states that integration is

changing the way oil companies work. However, integration also creates

challenges, from managing computer systems to designing organizations, to

making best use of interdisciplinary teams.

Advancements in 3-D seismic acquisition and processing are credited to the

massive number-crunching supercomputers such as Cray computers. 3-D

seismic data along with computer-processed logs and core analyses

characterize or describe more realistically and accurately the reservoir

providing the 3-D computer maps. The reservoir engineers use these maps

along with rock and fluid properties and production/injection data to

simulate reservoir performance and to design depletion and development

strategies for new and old fields. The supercomputers made reservoir

simulators work faster and more accurately. The integration process from

reservoir characterization to reservoir simulation, which requires

interdisciplinary teamwork has been made practical and efficient by

utilization of computers.

Interactive workstations interface several machines together locally in a

physical cluster or using networks and software to link central processing

units (CPUs) from various sites into a virtual cluster. The machines include

high-end PCs, Suns, DECs, IBMs, MicroVAX’s, Hewlett-Packard (HPs),

and Silicon Graphics hardware. Contrary to the workings of the

supercomputers and mainframe computers, the interactive workstations

allow data migration, analysis, and interpretation on truly interactive domain

rather than batch mode. The workstations are also capable of utilizing many

geoscience and engineering software interactively. The demands for

workstations of various kinds are ever increasing in the industry because

they are becoming the workhorse of the integrated geoscience and

engineering teams.

The computer networks that link the IBM mainframe computers, Cray

supercomputers, Unix workstations, and PC token ring networks together

provide the mechanism for effective communication and coordination from

various geographical office locations. Major oil companies have worldwide

computer links between all divisions and regional offices. The office-to-

office communication has been made very quick (almost instantaneous),

productive, and cost-effective by computer networking. The IBM

mainframe-based PROFS/Office Vision electronic mail facili-ties,

videoconference centers in various geographical locations, and workstations'

images of maps, graphs, and reports via network communications are

excellent examples of networking. The networks have made the tasks of the

integrated teams easier, faster, and immensely productive.

While networks provide an efficient means to move digital data, retrieval

and storing of data pose a major challenge in the petroleum industry today.

The problems are:

• Incompatibility of the software and data sets from the different

disciplines.

• Databases usually do not communicate with each other.

Many oil companies are staging an integrated approach to solving these

problems. In late 1990, several major domestic and foreign oil companies

formed Petrotechnical Open Software Corporation (POSC) to establish

industry standards and a common set of rules for applications and data

systems within the industry. POSC's technical objective is to provide a

common set of specifications for computing systems, which will allow data

to flow smoothly between products from different organizations and will

allow users to move smoothly from one application to another. POSC

members are counting on POSC and its major software vendors to provide a

long-term solution to database-related issues.

3-D computer visualization via a video monitor of a reservoir at a micro- or

macro-scale is the latest major breakthrough in computer technology. The

awesome power of visualization lies in its ability to synthesize diverse data

types viz., geology, land, geophysics, petrophysics, drilling, and reservoir

engineering, and attributes for better understanding and capturing by human

senses. 3-D visualization technique will enhance our understanding of the

reservoir, providing better reservoir description and simulation of reservoir

performance. It may very well be the most powerful and persuasive

communication tool of the integrated teams for decades to come.

Now, a time and cost-effective way to integrate exploration and production

activities using existing hardware and software is available. A fully open-

data exchange system, which was jointly created by Finder Graphics

Systems Inc., GeoQuest, and Schlumberger, is being distributed as the

Geoshare standards. Members of the Geoshare user's group, which consists

of many geoscientific software developers and oil and gas operators, will

soon be able to transfer data and interpretations among their various data

bases in support of E&P techniques.

It is a completely open and expandable standard whose future lies with the

Geoshare user's group.

Traditionally, finding and producing hydrocarbons were considered the

essence of success in the upstream end of the petroleum industry. Now,

companies are viewing their options as far more flexible, and a diversified

portfolio of skills within an integrated and flexible business framework is

emerging .

The use of asset management teams is now standard practice in many

companies. Even though this kind of teamwork and flexibility is a step in the

right direction, it does not really address broader organization and

information technology issues. In the emerging second approach, which

works from the bottom up, changes in information technology alone (both

hardware and software) are intended to eliminate problems of knowledge

transfer and communication.

The modern reservoir management process involves establishing a purpose

or strategy and developing a plan, implementing and monitoring the plan,

and evaluating the results. None of the components of reservoir management

is independent of the others. Integration of all these are essential for

successful reservoir management. It is dynamic and ongoing. As additional

data become available, the reservoir management plan is refined and

implemented with appropriate changes. While a comprehensive plan for

reservoir management is highly desirable, every reservoir may not warrant

such a detailed plan because of cost effectiveness. However, the key to

success is to have a management plan (whether so comprehensive or not)

and implement it from day one.

SETTING GOALS

Recognizing the specific need and setting a realistic and achievable purpose

is the first step in reservoir management. The key elements for setting a

reservoir management goal are:

• Reservoir characteristics.

• Total environment.

• Available technology.

Understanding of each of these elements is the prerequisite to establishing

short- and long-term strategies for managing reservoirs.

Reservoir Characteristics

The nature of the reservoir being managed is vitally important in setting its

management strategy. Understanding the nature of the reservoir requires a

knowledge of the geology, rock and fluid properties, fluid flow and recovery

mechanisms, drilling and well completions, and past production

performance

Total Environment

Understanding of the following environments is essential in developing

management strategy and effectiveness:

Corporate—goal, financial strength, culture, and attitude.

Economic—business climate, oil/gas price, inflation, capital, and

personnel availability.

Social—conservation, safety, and environmental regulations.

Technology and Technological Toolbox

The success of reservoir management depends upon the reliability and

proper utilization of the technology being applied concerning exploration,

drilling and completions, recovery processes, and production. Many

technological advances have been made in all of these areas. However, they

offer opportunities that may or may not be appropriate for every reservoir.

DEVELOPING PLAN AND ECONOMICS

Formulating a comprehensive reservoir management plan is essential for the

success of a project. It needs to be carefully worked out involving many

time-consuming development steps.

Development and Depletion Strategy

The most important aspect of reservoir management deals with the strategies

for depleting the reservoir to recover petroleum by primary and applicable

secondary and enhanced oil recovery methods.

Development and depletion strategies will depend upon the reservoir's life

stage.

Developing Plan

Development & Depletion Strategies

Environmental Considerations

Data Acquisition & Analyses

Geological & Numerical Model Studies

Production & Reserves Forecasts

Facilities Requirements

Economic Optimization

Management Approval

In case of a new discovery, we need to address the question of how to best

develop the field (i.e., well spacing, number of wells, recovery schemes,

primary, and subsequently secondary and tertiary). If the reservoir has been

depleted by primary means, secondary and even tertiary recovery schemes

need to be investigated.

Environmental Considerations

In developing and subsequently operating a field, environmental and

ecological considerations have to be included. Regulatory agency constraints

will also have to be satisfied. These are very sensitive and important aspects

of the reservoir management process.

Data Acquisition 8c Analysis

Reservoir management starting from developing a plan, implementing the

plan, monitoring and evaluating the performance of the reservoir requires a

knowledge of the reservoir that should be gained through an integrated data

acquisition and analysis program. The key steps are

(1) plan, justify, time, and prioritize,

(2) collect and analyze, and

(3) validate/store

(data base).

An enormous amount of data are collected and analyzed during the life of a

reservoir. An efficient data management program—consisting of collecting,

analyzing, storing and retrieving—is needed for sound reservoir

management. It poses a great challenge.

Geological and Numerical Model Studies

The geological model is derived by extending localized core and log

measurements to the full reservoir using many technologies, such as

geophysics, mineralogy, depositional environment and diagenesis. The

geological model, particularly the definition of geological units and their

continuity and compartmentalization, is an integral part of geostatistical and

ultimately reservoir simulation models.

Production and Reserves Forecasts

The economic viability of a petroleum recovery project is greatly

influenced by the reservoir production performance under the current and

future operating conditions. Therefore, the evaluation of the past and present

reservoir performance and forecast of its future behavior is an essential

aspect of the reservoir management process. Classical volumetric, material-

balance, and decline-curve analysis methods, and high-technology black oil,

compositional and enhanced oil recovery numerical simulators are used for

analyzing reservoir performance and estimating reserves. Reservoir

simulators play a very important role in formulating initial development

plans, history matching and optimizing future production, and in planning

and designing enhanced oil recovery projects.

Facilities Requirements

Facilities are the physical link to the reservoir. Everything we do to

the reservoir, we do through the facilities. These include drilling,

completion, pumping, injecting, processing, and storing. Proper design and

maintenance of facilities has a profound effect on profitability. The facilities

must be capable of carrying out the reservoir management plan, but they

cannot be wastefully designed.

Economic Optimization

Economic optimization is the ultimate goal selected for reservoir

management. Figure 3-6 presents the key steps involved in economic

optimization.

Management Approval

Management support and field personnel commitment are essential for the

success of a project.

IMPLEMENTATION

Once the goals and objectives have been set and an integrated reservoir

management plan has been developed, the next step is to implement the

plan.

The first step involves starting with a plan of action, including all

functions. It is common for many reservoir management efforts to

devise a plan, but this plan usually does not involve all functional

groups. Thus, not all groups buy into these programs, and the

cooperation between various functions is below the desired level. If a

plan is to be developed and implemented in the best way, it must have

commitment from all disciplines, including management.

Start with a plan of action, involving all functions.

Flexible plan.

Management support.

Commitment of field personnel.

Periodic review meetings, involving all team members

(interdisciplinary cooperation in teaching each other's functional

objectives).

The plan must be flexible. Even if the reservoir management team

members prepare plans by involving all functional groups, it does not

guarantee success if it can not be adapted to surrounding

circumstances (e.g., economic, legal, and environmental).

The plan must have management support. No matter how technically

good the plan, it must have local and higher level management

blessings. Without their support, it would not be approved. Thus, it is

necessary that we get management involved from "day one."

No reservoir management plan can be implemented properly without

the support of the field personnel. Time and time again we have seen

reservoir management plans fail because either they are imposed on

field personnel without thorough explanations or they are prepared

without their involvement. Thus, the field personnel do not have a

commitment to these plans.

It is critical to have periodic review meetings, involving all team

members. Most, if not all, of these meetings should be held in the field

offices. The success of these meetings will depend upon the ability of

each team member to teach their functional objectives.2

The important reasons for failure to successfully implement a plan

are: (1) lack of overall knowledge of the project on the part of all team

members, (2) failure to interact and coordinate the various functional

groups, and (3) delay in initiating the management process.

SURVEILLANCE AND MONITORING

Sound reservoir management requires constant monitoring and

surveillance of the reservoir performance as a whole in order to determine if

the reservoir performance is conforming to the management plan. In order to

carry out the monitoring and surveillance program successfully, coordinated

efforts of the various functional groups working on the project are needed.

An integrated and comprehensive program needs to be developed for

successful monitoring and surveillance of the management project. The

engineers, geologists, and operations personnel should work together on the

program with management support. The program will depend upon the

nature of the project. Ordinarily, the major areas of monitoring and

surveillance involving data acquisition and management include:

(1) oil, water and gas production,

(2) gas and water injection,

(3) static and flowing bottom hole pressures,

(4) production and injection tests,

(5) injection and production profiles, and any others aiding surveillance.

In case of enhanced oil recovery projects, the monitoring and surveillance

program is particularly critical because of the inherent uncertainties.

EVALUATION

The plan must be reviewed periodically to ensure that it is being

followed, that it is working, and that it is still the best plan. The success of

the plan needs to be evaluated by checking the actual reservoir performance

against the anticipated behavior.

It would be unrealistic to expect the actual project performance to match

exactly the planned behavior. Therefore, certain technical and economic

criteria need to be established by the functional groups working on the

project to determine the success of the project. The criteria will depend upon

the nature of the project. A project may be a technical success but an

economic failure.

How well is the reservoir management plan working? The answer lies in the

careful evaluation of the project performance. The actual performance (e.g.,

reservoir pressure, gas-oil-ratio, water-oil-ratio, and production) needs to be

compared routinely with the expected

In the final analysis, the economic yardsticks will determine the success or

failure of the project.

REVISION OF PLANS & STRATEGIES

Revision of plans and strategies is needed when the reservoir performance

does not conform to the management plan or when conditions change. The

answers to questions such as is it working, what needs to be done to make it

work, what would work better, must be asked and answered on an ongoing

basis in order for us to say we are practicing sound reservoir management.

REASONS FOR FAILURE OF RESERVOIR MANAGEMENT

PROGRAMS

There are numerous reasons why reservoir management programs have

failed. Some of the reasons are listed below:

Un-integrated System

It was not considered as a part of a coupled system consisting of wells,

surface facilities, and the reservoir. Not all of these were emphasized in a

balanced way. For example, one could do well in studying the fluids and

their interaction with rock (i.e., reservoir engineering); but, by not

considering the well and/or the surface system design, the recovery of oil

and/or gas was not optimized. Most people can cite examples of mistakes

made where we thoroughly studied various aspects of the reservoir and made

decisions resulting in too many wells drilled, improper application of well

completion technology, and/or inadequate surface facilities available for

future expansion.

Perhaps the most important reason why a reservoir management program is

developed and implemented poorly is an unintegrated group effort.

Sometimes the operating decisions are made by people who do not recognize

the dependence of one system on the other. Also, the people may not have

the required background knowledge in critical areas (e.g., reservoir

engineering, geology and geophysics, production and drilling engineering,

and surface facilities). Although it may not be absolutely necessary for

reservoir-management decision makers to have a working knowledge in all

areas, they must have an intuitive feel for them.

The team approach to reservoir management involving interaction between

various functions has been recently emphasized

Starting Too Late

Reservoir management was not started early enough; and when

initiated, management became necessary because of a crisis that occurred,

and it required a major problem to be solved. Early initiation of a

coordinated reservoir management program could have provided a better

monitoring and evaluating tool, and it could have cost less in the long run.

For example, a few early Drill Stem Tests (DSTs) could have helped decide

if and where to set pipe. Also, performing some early tests could have

indicated the size of the reservoir.

Early definition and evaluation of the reservoir system is a prerequisite to

good reservoir management. The collection and analysis of data play an

important role in the evaluation of the system. Most often, an integrated

approach of data collection is not followed, especially immediately after the

discovery of a reservoir. Also, in this endeavor not all functions are

generally involved. Sometimes the reservoir management staff has

difficulties in justifying the data collection effort to management because the

need for the data, along with its costs and benefits, are not clearly shown.

Lack of Maintenance

Calhoun draws an analogy between reservoir and health management.

According to his concept, it is not sufficient for the reservoir management

team to determine the state of a reservoir's health and then attempt to

improve it. One reason for reservoir management ineffectiveness is that the

reservoir and its attached system's (wells and surface facilities) health

(condition) is not maintained from the start.