## PROPERTIES OF FLUID RESERVOIRS – PVT TESTS

FLASH VAPORIZATION. A sample of the reservoir liquid is placed in a laboratory cell. Pressure is adjusted to a value equal to or greater than initial reservoir pressure. Temperature is set at reservoir temperature. Pressure is reduced by increasing the volume in increments.

This procedure is called FLASH VAPORIZATION, there is a graphic that represents the process of this porcedure where the plot reporduces part of an isotherm of a pressure-volume diagram. The shape is similar to that shown in below.

PRESSURE VS VOLUME

The pressure at which the slope changes is the bubble point pressure of the mixture. The volume at this point is the volume of the bubble -point liquid. Often it is given the symbol Vsat. The volume of the bubble point

FLASH VAPORIZATION

liquid can be divided by the mass of reservoir fluid in the cell to obtain a value of specific volume at the bubble point. Specific volume at the bubble point also is meaasured during other tests and is used as a check on the quality of the data.

All values of total volume, Vt, are divided by volume at the bubble point, and the data or information is reported as relative volume. Sometimes the symbol  V/Vsat is used; however, we will use the sysmbol (Vt/Vb)f. The sysmbol (Vt/Vb)f means total volume divided by volume at the bubble point for a flash vaporization.

DIFFERENTIAL VAPORIZATION:

The sample of reservoir liquid in the laboratory cell is brought to bubble-point pressure, and the temperature is set at reservoir temperature. Pressure is reduced by increasing cell volume, and the cell is agitated to ensure equilibrium between the gas and liquid. Then, all the gas is expelled from the cell while pressure in the cell is held constant by reducing cell volume.

DIFFERENTIAL VAPORIZATION PROCEDURE

The gas is collected, and its quantity and specific gravity are measured. The volume of liquid remaining in the cell, V0, is measured. The process is repeated in steps until atmospheric pressure is reached. Then  temperature is reduced to 60·F, and the volume of remaining liquid is measured. This is called residual oil from differential vaporization or residual oil.

Each of the values of volume of cell liquid, Vo, is divided by the volume of the residual oil. The result is called relative oil volume and is given the symbol BoD. In addition, the volume of gas removed during each step is measured both at cell conditions and at standard conditions.

The total volume of gas removed during the entire process is the amount of gas in solution at the bubble point. This total volume is divided by the volume of residual oil, and the untis are converted to standard cubic feet per barrrel of residual oil. The symbol RsDb represents atandard cubic feet of gas removed per barrel of residual oil. The gas remaining in solution at any lower pressure is calculated by subtracting the sum of the gas removed down to and including the pressure of interest from the total volume of gas removed. The result is divided by the volume of residual oil, converted to SCF/residual bbl, and reported as RsD.

SEPARATOR TESTS:

A sample of reservoir liquid is placed in the laboratory cell and brougt to reservoir temperature and bubble point pressure. Then the liquid is expelled from the cell through two stages of separation.The vessel representing the stock tank is a stage of separation

SEPARATOR TESTS

if it has lower pressure than the separator. Pressure in the cells held constant at the bubble point by reducing cell volume as the liquid is expelled.The temperatures of the laboratory separator and stock tank usually are set to represent average in the field. The stock tank is always at atmospheric pressure. The pressure in the separator is selected by the operator. The specific gravities of the separator gas and stock tank gas are measured. Often the composition of the separator gas is determined. Finally, a separator volume factor is calculated. It is the volume of separator liquid measured at separator conditions divided by the volume of stock-tank oil at standrad conditions, SP BBl/ STB.

## GAS NATURAL DE CAMISEA EN EL PERU

GAS NATURAL – DEFINICION.

Es un conjunto de hidrocarburos que se encuentra en estado gaseoso o en disolución con el petróleo. El término gas natural son las mezclas de gases combustibles hidrocarburos o no, que se encuentran en el subsuelo donde se hallan asociados con petróleo líquido. El principal constituyente del gas natural es siempre el metano, que representa generalmente entre el 75 y el 95 % del volumen total de la mezcla, razón por la cual se suele llamar metano al gas natural.

Los otros hidrocarburos gaseosos que suelen estar presentes, etano, butano y propano, aparecen siempre en proporciones menores. Entre los constituyentes distintos a los hidrocarburos suelen ser nitrógeno, dióxido de carbono, sulfuro de hidrógeno, helio y argón los más importantes.

Clasificación:

• Gas natural asociado – como subproducto del petróleo.
• Gas natural no asociado – sin presencia de petróleo crudo.
• Gas Húmedo – Camisea, Aguaytia.
• Gas Seco – Olympic, Sechura.

Es una de las fuentes de energía más modernas, limpias y ventajosas que ofrece a los usuarios beneficios importantes en cuanto a costos, calidad y protección del ambiente.

HISTORIA DEL GAS DE CAMISEA:

En Julio de 1981,  Se suscribió el Contrato de Operaciones Petrolíferas por los Lotes 38 y 42 con la Compañia SHELL, luego de ello entre los años de 1,983 y  1,987  Como resultado de la perforación de 5 pozos exploratorios, la Cia. SHELL descubre los

PROYECTO CAMISEA

Yacimientos de Gas de Camisea. En 1986, SHELL informo sobre los hallazgos comerciales de gas en el área de Camisea. 2 años mas tarde (Marzo 1,988)  Se firmo el  Acuerdo de Bases para la explotación de Camisea entre SHELL y PETROPERU; justo en ese mismo año NO se da por  concluida la negociación del Contrato con la Cia. SHELL , y como consecuencia no llegan a ningún acuerdo.

En Marzo 1,994, se firma el  Convenio para Evaluación y Desarrollo de los Yacimientos de Camisea entre SHELL y PERUPETRO y un año mas tarde La Cia. SHELL entrega Estudio de Factibilidad y solicita a PERUPETRO el inicio de la negociación de un Contrato de Explotación de los Yacimientos de Camisea. En Mayo de 1996, se completó la negociación y se suscribió el Contrato de Explotación de los Yacimientos de Camisea entre el consorcio SHELL/MOBIL y PERUPETRO, así que el Consorcio SHELL/MOBIL comunica su decisión de no continuar con el Segundo Periodo del Contrato, por consiguiente el Contrato queda resuelto en el año de 1998.

La Comisión de Promoción de la Inversión Privada (COPRI) acuerda llevar adelante un proceso de promoción para desarrollar el Proyecto Camisea mediante un esquema segmentado, que comprende módulos independientes de negocios, y  el Comité Especial

TENDIDO DEL DUCTO

del Proyecto Camisea (CECAM) convocó a Concurso Público Internacional para otorgar el Contrato de Licencia para la Explotación de Camisea, y las Concesiones de Transporte de Líquidos y de Gas desde Camisea hasta la costa y de Distribución de Gas en Lima y Callao ocurriendo todo esto en el año de 1999. En Diciembre del 2000, se suscriben los Contratos para el desarrollo del Proyecto Camisea con los consorcios adjudicatarios de los Concursos llevados a cabo por el CECAM.

A inicios de mayo de 2002, se suscribió el contrato de concesión para el transporte y distribución del gas de Camisea a la Costa Peruana, mediante el cual Tractebel se convierte en el tercer operador del proyecto (siendo PlusPetrol y Techint los otros dos). Este paso completa el esquema de desarrollo de Camisea, hasta ese momento con el gas de menor costo en el mundo ( al no trasladarse al costo final lo invertido por el consorcio Shell-Mobil ).

En los yacimientos de San Martin y Cashiriari, conjuntamente conocidos como Lote 88 Camisea, el volumen de gas IN SITU probado es de 8.7 TPC ( trillones de pies cubicos) con un estimado de recuperacion final de 6.8 TCP de gas natural asociados (propano, butano y condensados). En los lotes 56 (Pagoreni) y 57 (Kinteroni)se han hallado reservas probadas de aproximadamente 3 TPC y 2 TPC, respectivamente.

El Proyecto Camisea consiste en la Extraccion del Gas Natural y Liquidos Asociados desde los yacimientos ubicados en la Selva del departamento de del Cuzco, para transportarlos por medio de los ductos; uno de liquidos y otro de Gas Natural , hasta la costa y Lima. Para que este gas llegue a la

EXTENSION DEL GASODUCTO

poblacion, se hace necesario distribuirlo, lo cual esta a cargo de la Compañia Gas Natural de Lima y Callao ( GNLC) y es el tercer eslabon de la cadena del Gas Natural y tambien  se realiza a travez de una red de tuberias enterradas. La Compañia GNLC, es una empresa 100% Belga , TRACTEBEL quien se encargara de la construccion, operacion y matenimiento de la red de distribucion para Lima y Callao. Primero construira un Gasoducto Troncal y sus ramales primarios con un total de 85 km de tuberias, con una capacidad maxima de 7,2 MMm3/day. que ira desde el City Gate de Lurin hasta la Central Termica de Ventanilla en el Callao. Actualmente (2013) esas obras quedaron ejecutadas y la distribucion del gas llega a cubrir a un sector de las familias ( Consumo Domestico).

Observacion:

La exploración realizada por la empresa SHELL en un Lote de 2 millones de hectáreas, en la parte sur de la Cuenca Ucayali, durante el período 1981 – 1987, mediante la ejecución de 3,000 kilómetros de líneas sísmicas y la perforación de 5 pozos

CAMPAÑA DE EXPLORACION Y PERFORACION DE SHELL.

exploratorios, permitió que en el área de Camisea se descubrieran dos yacimientos de Gas Natural no asociado, los cuales se denominaron San Martín y Cashiriari. Los mencionados yacimientos se encuentran ubicados en una región de selva tropical conocida como Bajo Urubamba y forman parte del distrito de Echarate, provincia de La Convención, departamento de Cusco. Durante una segunda campaña exploratoria realizada por el consorcio Shell/Mobil, en 1996-1998, se perforan 3 pozos de evaluación y se realizan los estudios necesarios para desarrollar un proyecto de explotación y comercialización del Gas de Camisea.

EL PROYECTO CAMISEA REUNE TRES COMPONENTES:

• Explotación, que comprende la exploración y explotación de las reservas de gas natural en Camisea y su procesamiento en la planta de Malvinas, ubicada en la selva del Cusco, una planta de fraccionamiento de líquidos de gas natural y un terminal marítimo ubicados al sur de Pisco.
• Transporte, que consiste en el transporte de gas natural desde Las Malvinas hasta el City Gate de Lurín, y el transporte de líquidos de gas natural desde Malvinas hasta la planta de fraccionamiento.
• Distribución, que consiste en la distribución de gas natural a Lima y Callao.

CARACTERISTICAS DEL TRANSPORTE DEL GAS NATURAL Y GAS NATURAL LICUEFACTADO:

EL Gas Natural se transporta desde los campos o yacimientos hasta las compañias de distribucion o grandes clientes del sector atravez de un SISTEMA DE DUCTOS (SD). Estos son cañerias de gran diametro que operan a elevadas presiones, para tratar de mantener las presiones en un rango estable a lo largo de grandes distancias, se utilizan las Estaciones de Compresion, los cuales estan situadas en Puntos Estrategicos.

El Sistema de Transporte por Ductos (STD) esta formado por 2 tuberias; uno es el GASODUCTO de 729 Kms el cual transporta Gas Natural y el segundo es el POLIDUCTO de 557 kms, que transporta Liquidos del Gas Natural ( LGN) (C3+). dichos ductos se inician en la Cuenca Amazonica del Rio Malvinas, distrito de Echarate, provincia de la Convencion, Cuzco atravesando  la Cordillera de los Andes y llegan a las costas del Océano Pacífico; finalizando en el City Gate de Lurín y en la Planta de fraccionamiento en Pisco, respectivamente.

El sistema de transporte fue diseñado para trasladar 314 millones de pies cúbicos de gas natural (8,9 MMSCMD) y 70 mil barriles de líquidos de gas natural (BPD) por día. A estos se sumó durante el 2009 la construcción de la planta compresora construida en el sector Sierra y el gasoducto paralelo (loop) de 107 km instalado en la Costa. En el caso del gasoducto, una estación de compresión, ubicada en Malvinas y 22 válvulas de bloqueo ubicadas cada 30 kms. aproximadamente- permiten el flujo a lo largo del mismo hasta su destino. Por otro lado, cuatro estaciones de bombeo y tres estaciones reductoras de presión controlan la circulación de los líquidos del gas natural a lo largo de toda la ruta que en su recorrido cruza más de 35 ríos principales, 2 túneles en la zona de sierra (de 251 y 365 metros de largo) y un puente soporte de tuberías sobre el Río Comerciato.

Además, al igual que el gasoducto, cuenta con 19 válvulas con bloqueo por baja presión y sistema de detección de fugas. Para la operación y mantenimiento del STD, TGP cuenta con cuatro bases ubicadas en la selva, sierra y costa: Kiteni, Ayacucho, Pisco y Lurín. Asimismo, los flujos de gas y líquidos, así como las instalaciones, son controlados, en forma automática y en tiempo real, por el Sistema de Control y Adquisición de Datos (SCADA).

MAPA DE LA RED DEL GASODUCTO CUZCO-LIMA

Consorcio de empresas lideradas por Pluspetrol, operadora de la explotación del Lote-88 en Camisea, incluye lo siguiente:

1. Relevamiento Sísmico 3D (Actividad concluida).
2. Perforación de pozos exploratorios y de explotación.
3. Construcción de Ductos de Recolección y Reinyección de Gas.
4. Planta de Separación de gas/liquidos (Criogénica) en Malvinas.
5. Planta de Fraccionamiento y la construcción de un Terminal Marítimo para exportación de productos en Pisco.

Transportadora del Gas del Perú S.A. (TGP), operadora de los sistemas de Transporte de Gas y Transporte de Líquidos de Camisea a la costa, a través de ductos.

Gas Natural de Lima y Callao S.R.L. (GNLC), operadora del Sistema de distribución del Gas Natural por red de ductos en Lima y Callao. Red de distribución desde el City Gate en Lurín, hasta la Estacion  Terminalen Ventanilla.

CLIENTES INICIALES:

Para desarrollar el proyecto Camisea se firmaron contratos con las primeras empresas interesadas en trabajar con gas natural, a éstas se les denominó ‘Clientes Iniciales’, los mismos que contrataron cantidades especiales de gas natural a un menor precio. La demanda de los Clientes Iniciales de Camisea hizo posible el desarrollo del proyecto. Estas empresas son las siguientes:

• Electroperú (empresa que cedió su pocisión contractual a ETEVENSA).
• Alicorp.
• Sudamericana de Fibras.
• Cerámica Lima.
• Vidrios Industriales.
• Corporación Cerámica.
• Cerámicas San Lorenzo.

VENTAJAS DEL GAS DE CAMISEA:

• Ventajas Ambientales: Facilita el cumplimiento de exigentes normas ambientales y la baja emisión de contaminantes en su combustión.
• Ventajas Económicas: El gas natural es el combustible de menor precio y permite obtener importantes ahorros en relación con otros combustibles.
• Ventajas Operacionales: No requiere almacenamiento, no requiere preparación previa a su utilización, los equipos son fáciles de limpiar, el rendimiento del gas es mayor que al de otros combustibles.
• Ventajas de Mantenimiento: El control, la limpieza, y la verificación de los equipos utilizados en el mantenimiento del gas se realiza en menor tiempo y con mayor precisión que los de cualquier otro combustible.

RESUMEN:

El Sistema de Transporte por ductos (STD) de TGP está formado por dos tuberías: un gasoducto de 729 kms. que transporta Gas Natural (GN) y un poliducto de 557 kms. que transporta Líquidos de Gas Natural (LGN). Ambos ductos se inician en  la cuenca Amazónica del río Malvinas, departamento del Cusco, atraviesan la Cordillera de los Andes y llegan a las costas del Océano Pacífico; finalizando en el City Gate de Lurín y en la Planta de fraccionamiento en Pisco, respectivamente.

El gas natural llegará a la Planta de licuefacción mediante un ramal que se conectará en la zona de Chiquintirca en Ayacucho, al gasoducto existente de TgP que va de Camisea a Lima.

Con una longitud de 408 kilómetros, el gasoducto atraviesa 100 kilómetros de desierto costero y 308 kilómetros de grandes montañas en la Cordillera de los Andes en donde llega a su punto más alto en los 4,901 metros sobre el nivel del mar. El gasoducto permitirá llevar el gas natural hasta la Planta de licuefacción en la costa y estará completamente enterrado a una profundidad aproximada de un metro.

PLANTA DE LICUEFACCION-PERU

## PETROLEUM RESERVOIR DRIVE MECHANISMS

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.

DISSOLVED GAS DRIVE RESERVOIR

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.

PRODUCTION DATA DISSOLVED GAS DRIVE RESERVOIR

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,

GAS CAP DRIVE RESERVOIR

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.

PRODUCTION DATA GAS CAP DRIVE RESERVOIR

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.

DISSOLVED GAS DRIVE RESERVOIR

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)

PRODUCTION DATA WATER DRIVE RESERVOIR

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.

## CHARACTERISTICS OF DRAWDOWN TESTS IN WELLS

DRAWDOWN TEST OBJECTIVES:

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

DRAWDOWN TEST

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.

INTRODUCTION:

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.

CHARACTERISITICS OF FLOW AND GAS WELL TRANSIENT TESTING.

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.

CHARACTERISITCS OF VARIOUS FLOW REGIMES:

TIME-HISTORIES FOR A CONSTANT-RATE DRAWDOWN TEST

EARLY-TIME FLOW REGIME:

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.

TRANSIENT FLOW REGIME:

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.

USES OF PRESSURE DRAWDOWN 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.

DRAWDOWN TESTS

## TYPES OF NATURAL GAS RESERVOIRS

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.

EQUILIBRIUM CONSTANT GAS-CONDENSATE SYSTEMS:

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 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.

PHASE DIAGRAM FOR A PURE SUBSTANCE

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

PHASE DIAGRAM SHOWING CRICONDENTHERM AND CRICONDENBAR

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.

TYPES OF GAS RESERVOIRS

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.

PHASE DIAGRAM OF A DRY GAS

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

PHASE DIAGRAM OF WET GAS

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.