Category Archives: Ingenieria de Yacimientos (Reservorios)



Oil Reservoirs description:

Oil can be recovered from the pore spaces of a reservoir rock, only to the extent that the volume originally occupied by the oil is invaded or occupied in some way. There are several ways in which oil can be displaced and produced from a reservoir, and these may be termed mechanisms or “drives”. Where one replacement mechanism is dominant, the reservoir may be said to be operating under a particular “drive”. Possible sources of replacement for produced fluids are:

  • Expansion of undersaturated oil above the bubble point.
  • Expansion of Rock and connate water.
  • Expansion of gas released from soltion in the oil below the bubble point.
  • Invasion of the original oil bearing reservoir by the expansion of the gas from a free gas cap.
  • Invasion of the original oil bearing reservoir by the expansion of the water from an adjacent or underlying aquifer.

Since all replacement processes are related to expansion mechanisms, a reduction in pressure in the original oil zone is essential. The pressure drops may be small if gas caps and aquifers are large and permeable, and, under favourable circumstances, pressure may stabilise at constant or declining reservoir off take rates. The compressibilities of undersaturated oil, rock and connate water are so small that pressures in undersaturated oil reservoirs will rapidly fall to the bubble point if there is no aquifer to provide water.


So these expansion mechanisms are not usually considered separately, and the three principal categories of reservoir are:

  • Solution gas drive ( or depletion drive) reservoir.
  • Gas cap expansion drive reservoirs.
  • Water drive reservoirs.

Frequently two or all three mechanisms ( together with rock/ connate water expansion) occur simultaneously.

Solution Gas Drive Reservoirs:

If a resevoir at its bubble point is put on production, the pressure will fall below the bubble point pressure and gas will come out of solution. Initially this gas may be a disperse, dicontinuous phase, but, in any case, gas will be essentially immobile until some minimum saturation- the equilibrium, or critical gas saturation, is attained.

The actual order of values for critical saturation are in some doubt, but there is considerable evidence to support the view that values may be very low- in the order of 1% to 2% of the pore volume.


Once the critical gas saturation has been established gas will be mobile, and will flow under whatever potential gradients may be established in the reservoir- towards producing wells if the pressure gradient is dominat- segregation vertically if the gravitational gradient is dominant. Segregation will bee affected by vertical permeability variations in layers, but is known to occur even under apparently unfavourable conditions.

Initially ,the gas-oil ratio of a well producing from a closed reservoir will equal solution GOR. At early times, as pressure declines and gas comes out of solution, but cannot flow to producing wells, the producing GOR will decline. When the critical gas saturation is established and if the potential gradients permit, gas will flow towards producing wells.

The permeability to oil will be lower than at intial conditions, and there will be a finite permeability to gas so that the producing gas oil ratio will rise. As more gas comes out of solution, and gas saturations increase, permeability to gas increases, permeability to oil diminishes and this trend accelerates. Ultimately, as reservoir pressure declines towards abandonment pressure, the change in gas formation volume factor offsets the increasing gas to oil mobility ratio and the gas oil ratio trend is reversed, i.e, although the reservoir GOR may continue to increase, in terms of standard volumes, the ratio standardcubic ft/stock tank barrel may decline. In addition to the effect of gas on saturation of, and permeability to, oil, the loss of gas from solution also increases the viscosity of the oil and decreases the foramtion volume factor of trhe oil.

Gas Cap Expansion Reservoirs:

The general behaviour of gas drive reservoirs is similar to that of solution gas drive reservoirs, except that the presence of free gas retards the decline in pressure. By definition the oil must be saturated at the gas oil contact,


so that decline in pressure will cause the release of gas from solution, but the rate of release of gas from solution, and the build up of gas saturation and of gas permeability, will be retarded. At higher prevailing pressures, oil viscosities are lower (due to entrained gas) and provided that the free gas phase can be controlled, and not produced directly from producing wells, better well productivities and lower producing gas oil ratios can be maintained.

Under residual conditions the stock tank oil left in place is So/Bo and the smaller this factor the greater will be the oil recovery. Consequently the higher the pressure at abandonment, the greater the value of Bo, and the smaller this term becomes. In addition abandonment of wells and reservoirs depends primarily upon an “economic limit” – the rate of production required to pay for operating costs, and direct overheads – and an oil flow rate, which depends upon Ko/ mo Which be greater at any given saturation (and so given Ko) under pressure maintenance conditions due to the lower oil viscosity than under depletion conditions.


Water Drive Reservoir:

If a reservoir is underlain by, or is continuous with a large body of water saturated rock (an aquifer) then reduction in pressure in the oil zone, will cause a reduction in pressure in the aquifer.


Although the compressibility of water is small ( ± 3 x 10 -6 psi -1), the total compressibility of an aquifer includes the rock pore compressibility ( ± 5 x 10 -6 psi -1) making the total compressibility in the order of 8 x 10 -6 .psi -1. The apparent compressibility of an aquifer can be substantially greater if some accumulation of hydrocarbons exist in small structural traps throughout the aquifer. An efficient water driven reservoir requires a large aquifer body with a high degree of transmissivity allowing large volumes of water to move across the oil-water contact in response to small pressure drops.

This replacement mechanism has two particular characteristics – first there must be pressure drops in order to have expansion, and secondly, the aquifer response may lag substantially, particularly if transmissivity deteriorates in the aquifer (through diagenesis).

A water drive reservoir is then particularly rate sensitive, and so the reservoir may behave almost as a depletion reservoir for a long period if off-take rates are very high, or as an almost complete pressure maintained water drive reservoir if off-take rates are low, for the given aquifer. Because of the similarity in oil and water viscosities (for light oils at normal depths)


the displacement of oil by water is reasonably efficient, and provided that localised channelling, fingering or coning of water does not occur, water drive generally represents the most efficient of the natural producing mechanisms for oil reservoirs.

As with gas cap drive reservoirs, the maintained pressures lead to lower viscosities and higher Bo values at any given saturation, reducing the saturation and minimising the term So/Bo hence the stock tank oil left at any given economic limit. While reservoir drive mechanisms may be classified into the three categories we have discussed, most often two or more of these mechanisms act simultaneously in a combination drive.




The objectives of a drawdown test are to determine skin, perm and the distances to the reservoir’s boundaries.


We recommend doing a drawdown test to look for reservoir limits instead of running a build-up because a flowing well test does not interrupt cash flow. Since you can’t see a boundary until the pressure wave hits it, there’s no way to tell how long a build-up is required to see the reservoir limits. On most tests, it is possible to perform an “Integrated Volume Explored” calculation as the test progresses. This allows for a test to be run until a given amount of reserves have been proven.


Important reservoir parameters can be determined by flowing a well at a constant rate and measuring flowing wellbore pressure as a function of time. This is called drawdown testing and it can utilize information obtained in both the transient and pseudo-steady-state flow regimes.

If the flow extends to the pseudo-steady state, the test is referred to as a reservoir limit test and can be used to estimate in-place gas and shape of the reservoir. Both single-rate and two-rate tests are utilized depending on the information required. The purpose of the drawdown testing is to determine the reservoir characteristics that will affect flow performance. Some of the important characteristics are the flow capacity kh, skin factor s, and turbulence coefficient D.


Much of that information can be obtained from pressure transient tests. Pressure transient testing techniques, such as builup, drawdown, interference, and pulse, are important part of reservoir and production engineering. As the term is used in this book, pressure transient testing includes generating and measuring pressure variations with time in gas wells and subsequently, estimating rock, fluid, and well properties and predicting reservoir/ well behaviour. Practical information obtainable from transient testing includes wellbore volume, damage, and improvement; reservoir pressure; permeability; porosity; reserves; reservoir and fluid discontinuities; and other related data. All this information can be used to help analyze, improve, and forecast reservoir performance.

Pressure interference or pulse testing could establish the possible existence and orientation of vertical fracture of a gas reservoir. However, other information (such as profile surveys, production logs, stimulation history, well production tests, packer tests, core descriptions, and other geological data about reservoir lithology and continuity) would be useful in distinguishing between directional permeability and fractures or estimating whether the fractures were induced or natural.




Initially during early-time flow, wellbore storage and skin effects dominate the flow. When the well is opened at the surface for flow at a constant rate, the initial flow comes primarily from the wellbore itself, rather than from the formation. In fact, flow from the reservoir increases gradually from zero until the specified wellhead flow rate Q is reached in a length of time.


In this flow regime the pressure is the same as that created by a line-source well with a constant skin. Since a plot of PD versus To (Time) on semilogarithmic coordinates will yield a straight line, the analysis of transient flow data is often referred to as a semilog analysis. The semilog analysis of drawdown data yields consistent values of reservoir parameters. Only the permeability thickness kh, the skin factor s, and the inertial-turbulence factor D may be determined from such an analysis. This semilog straight line continues as long as the reservoir is infinite-acting. If a fault is encountered in the reservoir, the slope of the  line will double, and a new straight line will be established.

When the reservoir boundary begins to have a significant effect on well drawdown, the transient region ends; the pseudo-steady-state or depletion phase directly follows the transient period.


When a constant-rate drawdown test is run for a long period of time, the boundary effects eventually dominate the pressure behavior at the well. The pressure starts declining at the same rate at all points in the reservoir; hence the name pseudo-steady-state. In effect, then, the total drainage area is being depleted at a constant rate. A plot of ApD versus to on arithmetic cordinates will yield a straight line from which the reservoir pore volume occupied by gas and the reservoir limits can be calculated. Tests utilizing this regime of the drawdown history are often known as reservoir limit tests.


Producing the well at a constant flow rate while continuously recording bottom-hole pressure runs the drawdown test. In this type of test, wellcompletion data details must be known so the effect and duration of wellbore storage may be estimated. While most reservoir information obtained from a drawdown test also can be obtained from a pressure buildup test, there is an economic advantage to drawdown testing since the well is produced during the test. Properly run drawdown tests may provide information about formation permeability K, skin factor, S, and the reservoir volume communicating with the well. The main technical advantage of drawdown testing is the possibility for estimating reservoir volume. The major disadvantage is the difficulty of maintaining a constant production rate.




GAS HYDRATES DEFINITION, PRODUCTION AND FORMATION CONDITIONS. Gas hydrates are crystralline compounds, formed by the chemical combination of natural gas and water under pressure at temperatures considerably above the freezing point of water. In the presence of free water, hydrate formation is often confused with condensation, and the distinction between the two must be clearly understood. Condensation of water form a natural gas under pressure occurs when the temperature is at or below the dew point at that pressure. Free water obtained under such conditions is essential to the formation of hydrates that will occur at or below the hydrate temperature at the same pressure. Hence, the hydrate temperature would be below, and perhaps the same as, but never above the dew point temperature.

In solving gas production problems, it becomes necessary to define, and thereby avoid, conditions that promote the formation of hydrates. Hydrates may chokew the flow string, surface lines, and well testing equipment. Hydrate formation in the flow string would result in a lower value for measured wellhead pressures. In a flow rate measuring device, hydrate formation would result in lower flow rates. Excessive hydrate formation may also completely block flow lines and surface equipment.

Conditions  promoting hydrate formation are:

  • Gas at or below its water dew point with ” free” water present.
  • Low temperature.
  • high pressure.


As the exploration for natural gas is extended to deeper horizons, more reservoirs


containing gas condensates are discovered. The gas may be in the gaseous phase at liquid reservoir conditions but may condense to form some liquid at some point in the path to the separator. Engineering design of these production systems requires some understanding of phase behaviour.


Phase behavior is simple for single component systems but becomes more complicated as more components are added to the system. A discussion of the simplest system will lead to an understanding of the more complex systems.

Single Component Fluid: The phase behaviour of a fluid can be described by determining its response to pressure and temperature changes. In a liquid the molecules are very close together, but in a gas the molecules are widely separated.


Certain forces exist that tend to either confine or disperse the molecules. Confining forces are primarily pressure and molecular attraction. Dispersing forces are kinetic energy and molecular repulsion. The relative magnitudes of the confining and dispersing forces dictate wheter the fluid is a liquid or a gas. An increase in temperature increases the kinetiic energy of the molecules and thus the dispersing forces, while an increase in pressure goes up the confining forces.

Multicomponent Fluids: When more than one fluid is present, the difference in molecule size and energy has an influence on the phase change.There is no sharp transition from liquid to vapor or from vapor to liquid, but the molecules are able


to escape from the liquid or gas at different pressures and temperatures because of molecular attraction. The locus of all points where the first bubble of gas appears in a liquid as pressure and temperature conditions are changed is called the bubble point line. The locus of all points where the first droplet of liquid appears as the conditions for a gas are changed is the dew point line. The highest pressure at which a gas exist is called the cricondenbar while the highest temperature at which liquid can exist is the cricondentherm.


Reservoir  that yield natural gas can be classified into essential four categories, these are:

DRY GAS RESERVOIR DEFINITION:the fluid exists as a gas both in the reservoir and the reservoir and the piping system. The only liquid associated with the gas from a dry gas reservoir is water. A phase diagram is illustrated in the next picture.


WET GAS RESERVOIR DEFINITION: the fluid initially exists as a gas in the reservoir and remains in the gaseous phase as pressure declines


at reservoir temperature. However, in being produced to the surface, the temperature also drops, causing condensation in the pipig system and separator.

RETROGRADE CONDENSATE GAS RESERVOIR DEFINITION: the fluid exists as a gas at initial reservoir conditions, As reservoir pressure declines at reservoir temperature, the dew point line is crossed and liquid forms in the reservoir, Liquid also forms in the piping system and separator.


ASSOCIATED GAS RESERVOIR: many oil reservoirs exist at the bubble point pressure of the fluid system at initial conditions. Free gas can be produced form the gas cap of such a system. Gas which is initially dissolved in the oil can also be produced as free gas at the surface. The phase diagram of such a system will depend on the properties of the oil associated with the gas.

The fact that hydrocarbon liquids are frequently in contact with natural gas makes it imperative that methods be available to calculate the volumes or masses of each phase  and also the composition of each phase existing at various conditions of pressure and temperature.



Analysis Nodal is one of the most important topic you must really know in order to understand how well’s behaviour and the appropriate way to select mechanism of production so that we will produce well with an optimized flow rate.


Reservoir pressure and separator pressure must be considered as constant. Besides, Separator pressure is approximately 100 psig because it would be easier to computize. Therefore, Trial and error solution must either start in Node 1 (Psep) or Node 8 ( Pres) in order to calculate any node which is among them such as Node 3, 4 so on.

To select node depends on which component, may be isolated to be evaluated. All components in the well, beginning from static pressure to separator pressure, have to be considered, this include flow rate through porous media, perforatings, and completion.

In order to computize flow rate, there are two ways which must be known. All system is divided into two components, the reservoir (IPR curve) and total system of drillstrings (which consists of separator, flowline and tubings as well as being assumed that there is no restriction. In addition, It has only considered pressure losses in the flowline and tubings.


The inflow component is IPR ( Inflow Performance Rate) and the outflow component consists of Separator, flowline, and tubing. As I said before, Separator pressure is usually regulated as a constant value; however, some separator pressures change with flow rate and must suitably be determined.

Horizontal Flowing Pressure Gradients must really be based on Flowline size, production rate, gas specific gravity, average flowing, temperature, oil API gravity, water swpecific gravity.



All system is divided into two components in order to calculate flow rate. A component is the Separator Tank and Flowline. And the other component is the reservoir and tubing string. The outflow component begins with separator pressure with the purpose of obtaining the Well head pressure.

Vertical Flowing Pressure Gradients must be focused on water specific gravity, Oil API gravity, tubing size, production rate, gas specific gravity,  average flowing temperature.






After a well is drilled and  completed, itrequires a great effort to transport or flow fluid through the reservoir until the piping system and ultimately flow into a separator for gas-liquid separation which are placed on the surface. the movement of these fluids requires energy to overcome friction losses and to lift the products. The pressure drop in the total system at any time will be the initial fluid pressure minus the final fluid pressure. This pressure drop is the sum of the pressure drops occurring in all of the components of the system. The selection and sizing of the individual component varies with producing rate.

The final desing of a production system cannot be separated into reservoir performance and piping system performance and handle independently. The amount of oil and gas flowing into well from the reservoir relies more on the pressure drop in the piping system, and the pressure of the piping system depends on the amount of fluid flowing through it. Therefore; the entire production system must be analyzed as a unit.


The systems analysis approach, often called NODAL ANALYSIS has been applied for many years to analyse the performance of systems composed of interacting components (Electrical circuits, complex pipeline networks and centrifugal pumping systems are all analyzed using this method. The procedure consists of selecting a division point or node in the well and dividing the system at this point. All components upstream of the now comprise the inflow section, whereas the outflow section consists of all the components downstream of the node. A relationship among flow rate and pressure drop must be available for each component in the system. The flow rate through the system can be determined once the following requirements are satisfied:

  • Flow into the node equals flow out of the node,
  • Only one pressure can exist at a node.

The average pressure of the reservoir (Pavg) and the pressure of the system outlet called separator pressure ( Psep) are not functions of flow rate. Nevertheless, if the Psep is under control by a choke, it could be the Wellhead pressure (Pwh).

Once the node is selected, the node pressure is calculated from both directions starting at the fixed pressures.

Inflow to the node:

Pr – AP ( Upstream componets) = Pnode.

Ouflow from the node:

Psep + AP ( downstream components) = P node.

The pressure drop, AP, in any component varies with flow rate, Q. For that reason, a plot of node pressure versus flow rate will produce two curves, the intersection of which will give the conditions satisfying requirements (Flow into the node equals flow out of the node, and Only one pressure can exist at a node). That is illustrated as follows:


The effect of a change in any of the components can be analyzed by recalculating the node pressure versus flow rate using the features of the component that was changed. If a change was made in an upstream component, the outflow curve will remain unchanged.


Nevertheless, if either curve is changed, the intersection will be shifted, and a new flow capacity and node pressure will exist. The curve will also be shifted if either of the fixed prcssures is changed. which may occur with depletion or a change in separatioll conditions.

The effect on the flow capacity of changing the tubing size is shown as follows , and so does the effect of a change in flowline size.


The effect of increasing the tubing size, as long as the tubing is not too large, is to give a higher node or well-head pressure for a given flow rate, because the pressure drop in the tubing will be decreased. This shifts the inflow curve upward and the intersection to the right. A large flowline will reduce the pressure drop in the flowline, shifting the outflow down and the intersection to the right. The effect of a change in any component in the system can be isolated in this manner. Also, the effect of declaning reservoir pressure or changing separator pressure can be determined.


A more frequently used analysis procedure is to select the node between the reservoir and the piping system. This node does divide   the well into a reservoir system component and a piping system component.

The effect of a change in tubing size on the total system producing capacity when Pwf is the node pressure is illustrated above. An increased in production rate achieved by increasing tubing size is illustrated às well. however, if tubing is too large, the velocity of the fluid moving up the tubing may be too low effectively lift the liquids to the surface. This could be caused by either large tubing or low production rates.


A producing system may be optimized by selecting the combination of component characteristics that will give the maximum production rate for the lowest cost. Although the overall pressure drop available for a system, Psep, might be fixed at a particular time, the producing capacity of the system  relies more on where the pressure drop happens. If too much pressure drop occurs in one particular component or module, there may be insufficient pressure drop remaining for efficient performance of the other modules. Even though the reservoir may be capable of producing a large amount of fluid. If too much pressure drop occurs in the tubing , the well performance suffers.

For this type of well completion, it is obvious that improving the reservoir performance by stimulation would be a waste of effort unless larger tubing were installed.

A case in which the well performance is controlled by the inflow is shown. In this case, the exessive pressure drop could be caused by formation damage or inadequate perforations. It is obvious from the plot that improving the performance of the piping system or outflow or placing the well on artificial lift would be fruitless unless the inflow performance were also improved.