Pulse interference tests, which are conducted by monitoring the response in an observation well to a slug test conducted in a source well, are an attractive alternative to the pumping test method for determining the transmissivity and storativity of low-storativity geological formations. An analytical model for analyzing the results of pulse interference tests affected by well bore storage in the observation well is developed in this paper using the Laplace transform method. By numerically inverting the Laplace space solution the practical range of the pulse interference test method and the influence of radial distance and well bore storage on the response in the observation well are explored. Results show that the influence of observation well storage can be significant, particularly for larger well bore storage coefficients and for almost all practical radial distances. In addition, a graphical method, based on the analytical model, is developed for analyzing the results of pulse interference tests in which observation well bore storage is negligible and for the case where the source and observation well storage coefficients are equal. A field example is also presented to illustrate and compare the use of the analytical model and graphical method for the field case where observation well storage is present and the case where it is not.000000000000000000000000000000000000000000000

Injection Fall-off (IFO) testing

 

Injection fall-off (IFO) testing typically refers to testing done in either Water disposal wells or injector wells for pressure maintenance or secondary/tertiary recovery methods.  

They are most often employed when either a new wells is drilled and completed for this purpose or more commonly a pre-existing production well is converted into a disposal/injection well.  The IFO is the mirror image of a Pressure Build-Up (PBU) on a producing well and analysis can derive the same types of fundamental wellbore/reservoir information on an injector well that you can with a producing well...skin, permeability and reservoir pressure.  The main interest in the IFO is to understand skin and its affect on your injector.  Because you are limited to 0.5 psi/ft. on injection surface pressures, an increasing skin will require ever higher injection pressures to maintain the same injection rates.  At some future point you will be limited by the surface injection pressure limitation, as set by the state, not mentioning the increased cost of fueling your injection pumps.  If the well in question is a Saltwater Disposal (SWD) well, which often have less stringent separation/filter requirements for the injected fluid, skin accretion can happen quickly.  Knowing your "original" wellbore condition before injection begins and then testing periodically thereafter or when you notice increasing injection pressures,  would be a good idea. 

There is ever increasing scrutiny being placed upon these injector wells and especially so near population centers or even in rural areas if water is being pulled from wells for

consumption and use.  Better to have performed tests and be able to demonstrate, via documentation, that your wells are operating normally and within state guidelines.

As mentioned previously on this website, if your disposal/injector well can hold a column of fluid without going on a vacuum, then performing the test via surface measurements to keep costs low and RISK FREE is the recommended way to go and yields virtually identical values as you would obtain by running wire and pressure gauges downhole.

Fall-of-Potential MeasurementThe Fall-of-Potential test method is used to measure the ability of an earth ground system or an individual electrode to dissipate energy from a site.

How Does the Fall-of-Potential Test Work?First, the earth electrode of interest must be disconnected from its connection to the site. Second, the tester is connected to the earth electrode. Then, for the 3-pole Fall-of-Potential test, two earth stakes are placed in the soil in a direct line—away from the earth electrode. Normally, spacing of 20 meters (65 feet) is sufficient. For more detail on placing the stakes, see the next section.

A known current is generated by the Fluke 1625 between the outer stake (auxiliary earth stake) and the earth electrode, while the drop in voltage potential is measured between the inner earth stake and the earth electrode. Using Ohm's Law (V = IR), the tester automatically calculates the resistance of the earth electrode.

Connect the ground tester as shown in the picture. Press START and read out the RE (resistance) value. This is the actual value of the ground electrode under test. If this ground

electrode is in parallel or series with other ground rods, the RE value is the total value of all resistances.

How Do You Place the Stakes?To achieve the highest degree of accuracy when performing a 3–pole ground resistance test, it is essential that the probe is placed outside the sphere of influence of the ground electrode under test and the auxiliary earth.

If you do not get outside the sphere of influence, the effective areas of resistance will overlap and invalidate any measurements that you are taking. The table is a guide for appropriately setting the probe (inner stake) and auxiliary ground (outer stake).

To test the accuracy of the results and to ensure that the ground stakes are outside the spheres of influence, reposition the inner stake (probe) 1 meter (3 feet) in either direction and take a fresh measurement. If there is a significant change in the reading (30 %), you need to increase the distance between the ground rod under test, the inner stake (probe) and the outer stake (auxiliary ground) until the measured values remain fairly constant when repositioning the inner stake (probe).

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Depth of the

groundelectrode

Distanceto the inner stake

Distanceto theouter stake

2 m 15 m 25 m

3 m 20 m 30 m

6 m 25 m 40 m

10 m 30 m 50 m

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Chapter 13: Interference and Pulse Test Analysis MethodsBy Amanat Chaudhry

From Oil Well Testing Handbook

13.1 Introduction

Both interference and pulse tests, also known as multiple-well testing, involve more than one well. These types of tests can be used to obtain an adequate reservoir description for homogeneous (both isotropic and aniso-tropic) and heterogeneous systems. Numerical solutions must be used to analyze pressure transient data from heterogeneous systems. At the same time, it is one of the most important and useful tests to understand the well behavior in a water flood and enhanced oil recovery projects. Figure 13-1 shows field application of interference and pulse tests.

Figure 13-1: Field application of interference and pulse tests

13.2 Interference Test Analysis Techniques

Interference testing is one form of multiple-well testing. These tests are used to determine whether two or more wells are in pressure communication in the same reservoir and, when communication exists, to provide estimates of vertical formation permeability k and porosity/compressibility product ? C t, in the vicinity of the tested wells. In the homogeneous isotropic system, the porosity and thickness are the same everywhere in the reservoir. Permeability k is also the same everywhere and in all direction. Interference is conducted by producing from or injecting into one of these wells (active well) and the pressure response is observed in the other well (observation well) (see Figure 13-2). The active well starts producing at uniform pressure at time zero and the other pressure response in the observation well at a distance r from active well begins after some time lag.

DST (Drill Stem Test) Por Marcelo Madrid 8/04/2013 Yacimiento 4 comentarios

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Un Drill Stem Test (DST) es una prueba la cual se usan herramientas especiales colocadas al final de la sarta de perforación. Esta prueba es generalmente practicada para probar pozos nuevos, ya que solo puede llevarse a cabo con el taladro en sitio. En un DST, el pozo es abierto a flujo a través de una válvula ubicada en el fondo de la herramienta de prueba, y el fluido de yacimiento fluye hacia superficie por la sarta de perforación (que generalmente esta vacía al momento de comenzar la prueba). Una prueba común es una secuencia de períodos de cierre de acuerdo a las necesidades de evaluación que se requieran practicar en el pozo.

Un DST permite evaluar el potencial de producción de alguna arena particular en el yacimiento, presión y características de la roca yacimiento. La prueba es una importante medición del comportamiento del yacimiento, y una manera valiosa de obtener fluidos en fondo. Toda la información recolectada en el DST permite saber si el pozo puede producir hidrocarburos de manera comercial.

Los DST generalmente son pruebas cortas, ya que un cierre positivo de las válvulas de fondo evitan los efectos de almacenamiento durante la prueba de restauración de presión. Los DST requieren de especial técnicas de análisis, ya que generalmente las tasas de producción encontradas no son estables debido al período corto de flujo, adicionalmente que el pozo no se encuentre totalmente limpio de los fluidos utilizados durante la operación de perforación y completación.

Historia

Trabajando en los años 20 en el Dorado, Arkansas, E.C. Johnston y su hermano M.O. Johnston desarrollaron el primer DST y corrieron por primera vez de manera comercial en 1926. En Abril de 1929, la Johnston Formation Testing Corporation patentaron la técnica (U.S. Patent 1.709.940) y posteriormente mejoraron el sistema a principios de los años 30. En los años 50, Schlumberger introdujo un método para evaluación de formaciones usando equipo de wireline. La herramienta de evaluación de formación de Schlumberger, la cual puso en funcionamiento en 1953, la cual disparó una carga hueca a través de una

almohadilla de goma que se había extendido en el agujero en la profundidad requerida. Los fluidos de formación salían a través de los perforados y un tubo de conexión permitía depositar los fluidos producidos hacia un contenedor. Luego la herramienta es sacada a superficie con el contenedor cerrado con los fluidos de fondo a condiciones de yacimiento. En 1956, Schlumberger compra la Johnston Testers y continúan realizando pruebas DST y con probadores de formación tanto en pozos a hoyo entubado, como desnudo.

Prueba DST – Diseño

Generalmente, las pruebas DST se realizan en un corto período de tiempo, por lo que se debe tener claro cuales son los objetivos de la misma, que información queremos obtener para la caracterización del yacimiento, etc. Las pruebas DST casi siempre se llevan a cabo en pozos exploratorios, o en áreas que no se tienen suficiente grado de certeza, por ejemplo, áreas de reservas probables/posibles, la cual requiere comprobar si las reservas tienen algún atractivo comercial. Con la prueba DST permite evaluar los siguientes aspectos del yacimiento:

Productividad: permite evaluar el potencial de la arena productora, con distintos reductores, evaluar efectos de turbulencia (daño), presión de fondo fluyentes, y otros efectos en la cara de la arena (resistencia inercial y despojamiento capilar).

Propiedades de Yacimiento: con el cierre para restauración de presión, permite evaluar la presión promedio de la formación, permeabilidad, capacidad de la formación, skin, efectos de barrera o límites de yacimiento.

Muestreo de fluidos: con las muestras de fluido en fondo permite caracterizar en fluido original de yacimiento, la cual juega un papel importante en la estimación de fluidos originales en sitio, monitoreo y estudios de yacimiento, diseño de las facilidades de superficie, etc.

Generalmente la prueba DST inicia con la bajada de la herramienta hasta su posicionamiento en fondo (ya desde el comienzo de la bajada se va haciendo registros de presión y temperatura). Posteriormente se realiza el cañoneo (dependiendo) si se tiene acoplado los cañones en la sección final de la sarta, que generalmente pueden contener soltadores para enviarlos al fondo del pozo o pueden ser recuperadores posterior a la operación. Luego de la ejecución del cañoneo, y teniendo el pozo alineado en superficie con unidad de well testing (separador portátil), se alinea el pozo a producción con reductor de mínimo diámetro. Es aquí cuando empieza los períodos de flujo y cierre la cual podemos detallar a continuación:

1. Primer período de flujo y primer cierre (opcional): generalmente queda a consideración de la compañía operadora, y se hace a las pocas horas de haber realizado el cañoneo del pozo. En este período el pozo solo desplazará lodo de perforación, pero permitirá verificar la conexión yacimiento-pozo. Debido al poco período de cierre, el BU realizado no permitirá una interpretación.

2. Segundo período de flujo y cierre (período de limpieza): este período de flujo y cierre puede realizarse con varios reductores dependiendo de la respuestas energética que tenga el pozo, con el equipo de well testing se monitorean los parámetros de corte de agua y API hasta desplazar totalmente el lodo de perforación. Generalmente el período de cierre ulterior es el doble del período tiempo de flujo. La BU realizada permitirá analizar la condición de daño que pueda tener la arena productora.

3. Tercer período de flujo (prueba multitasa) y cierre (BU principal): este se considera el período principal de flujo, generalmente se hace con 3 o 4 reductores, dependiendo de la respuesta de la arena productora. Generalmente estas pruebas son de 24 horas con cada reductor y siempre se realiza fiscalizada ante el ente regulador. El período de cierre se realiza al menos el doble de tiempo de la prueba multitasa (en ocasiones, bajando una herramienta de lectura de sensores con equipo de wireline en el BHA), para realizar seguimiento de la prueba de restauración. Con esta información de BU, permitirá observar el daño del pozo (compararla con la BU del período de limpieza), estimar permeabilidad, capacidad de formación, y si el tiempo lo permite, analizar límites o barreras.

4. Cuarto período de flujo y cierre (toma de muestras): ya con el pozo con suficiente desplazamiento, se realiza el muestreo de fondo o superficie (de acuerdo al tipo de yacimiento), con el propósito de realizar estudios convencionales PVT y/o análisis especiales, según sea el requerimiento.

Con esta etapa, en líneas generales se culminaría la prueba DST, se procede operacionalmente a realizar el control del pozo, ya sea para seguir probando otra arena superior o bajar la completación permanente. En la Figura 1, se puede ver un esquemático de una prueba DST, de acuerdo con la explicación dada previamente.

Figura 1. Esquemático de prueba DST con cada uno de los períodos de flujo y cierre.

En la Figura 2, se muestran comportamientos de referencia de pruebas DST realizadas a yacimientos, de acuerdo a la permeabilidad registrada (solo referencia):

Figura 2. Rangos de respuesta de Yacimiento en prueba DST, de acuerdo a la K.

En el video a continuación se muestra la maniobra operacional durante una prueba DST. En este caso la prueba se realiza offshore, por lo que el requerimiento de tecnologías es aún mayor con lo observado en las pruebas DST onshore.

Video de descripción operacional de prueba DST

Drill stem testFrom Wikipedia, the free encyclopedia

Drill Stem Test

A drill stem test (DST) is a procedure for isolating and testing the pressure, permeability and productive capacity of a geological formation during the drilling of a well. The test is an important measurement of pressure behaviour at the drill stem and is a valuable way of obtaining information on the formation fluid and establishing whether a well has found a commercial hydrocarbon reservoir.

History

Working in El Dorado, Arkansas, in the 1920s, E.C. Johnston and his brother M.O. Johnston developed the first drill stem tester and ran the first commercial drill stem test in 1926. In April 1929, the Johnston Formation Testing Corporation was granted a patent (U.S. Patent 1,709,940) and they subsequently refined the testing system in the early 1930s.[1]

In the 1950s, Schlumberger introduced a method for testing formations using wireline. The Schlumberger formation-testing tool, placed in operation in 1953, fired a shaped charge through a rubber pad that had been expanded in the hole until it was securely fixed in the hole at the depth required. Formation fluids flowed through the perforation and connecting tubing into a container housed inside the tool. When filled, the container was closed, sealing the fluid sample at the formation pressure. The tool was then brought to the surface, where the sample could be examined. In 1956, Schlumberger acquired Johnston Testers and continues to perform drill stem tests and wireline formation tests in both open and cased holes.

About Drill Stem Testing

Drill stem testing is an oil and gas exploration procedure to isolate, stimulate and flow a downhole formation to determine the fluids present and the rate at which they can be produced. The main objective of a DST is to evaluate the commercial viability of a zones economic potential by identifying productive capacity, pressure, permeability or extent of an oil or gas reservoir. These tests can be performed in both open and cased hole environments and provide exploration teams with valuable information about the nature of the reservoir. Drill stem testing involves deploying a series of tools known as a test bottomhole assembly (BHA). A basic drill stem test BHA consist of a packer or packers, which act as an expanding plug to be used to isolate sections of the well for the testing process, valves that may be opened or closed from the surface during the test, and recorders used to document pressure during the test. In addition to packers a downhole valve is used to open and close the formation to measure reservoir characteristics such as pressure and temperature which are charted on downhole recorders within the BHA. Below are two types of BHA DST, Cased Hole which can be applied after the well has been cased, and Open Hole which may be preformed before casing.

APPLICATIONS OF DRILLSTEM TESTING: Cased Hole

Performed after the well is cased, cased hole drill stem testing uses a retrievable production packer that is set above the zone of interest. The well is then flow tested through

perforations in the casing. The two types of cased hole testing are pressure operated and mechanically operated.

Open Hole

Because it's performed before casing is run, open hole drill stem testing can be the most economical way to determine productive capacity, pressure, permeability or the extent of an oil or gas reservoir. The testing equipment is run into the well and the zone of interest is isolated using inflate or compression-set packers, depending on your requirements and drilling conditions.

Alternate Procedures

Depending on testing objectives and scope of work, drill stem testing may also be performed in combination with various other exploration and completion process such as fluid loss control and well control, closed chamber tests, well stimulation, and a combination of DST and TCP.

Procedure

During normal well drilling, drilling mud is pumped through the drill stem and out of the drill bit. In a drill stem test, the drill bit is removed and replaced with the DST tool and devices are inflated above and below the section to be tested.[2] These devices are known as packers and are used to make a seal between the borehole wall and the drill pipe, isolating the region of interest.[3] A valve is opened, reducing the pressure in the drill stem to surface pressure, causing fluid to flow out of the packed-off formation and up to the surface.

Results

In a low permeability or low pressure formation, surface production may not be achieved but the volume and flow rate of fluid can still be analysed within the drill stem.

See also

Delta-P Test Corp Intl, DST Closed Chamber IPE Northstar Drillstem Testing Drilling rig Horizontal Well Testing Oil well