Category Archives: Fuidos de Perforacion
PROCESO DE INVASION DEL LODO HACIA EL WELLBORE
PROCESO DE INVASION DEL LODO HACIA EL WELLBORE. Durante la perforación de un pozo, la presión hidrostática de la columna de lodo es generalmente mayor que la presión de poro de las formaciones. Esto evita a que el pozo se descontrole. La diferencia de presión resultante entre la columna de lodo y de la formación obliga al lodo filtrado a entrar en la formación permeable; las partículas sólidas del lodo se depositan en la pared del agujero donde se forman un enjarre de lodo, el cual por lo general tiene una permeabilidad muy baja (de 10-2 a 10-4 md) y, una vez desarrollada, reduce la velocidad de la invasión posterior por el lodo filtrado.
FILTRADO DEL LODO
Muy cercano al agujero, el filtrado desplaza la mayor parte del agua de formación y parte de los hidrocarburos. Esta zona se conoce como “Zona Lavada”. Contiene, si la limpieza es completa, solo filtrado de lodo; si la zona contenía originalmente hidrocarburos, solo tendrá hidrocarburos residuales.
A mayor distancia del pozo, el desplazamiento de los líquidos de formación por medio del filtrado de lodo es cada vez menos completo; lo que resulta en la transición de la saturación del filtrado de lodo a la saturación original de agua de formación. Dicha zona se conoce como la “Zona Invadida” o de “Transición”. La extensión o profundidad de las zonas lavada y de transición depende de muchos parámetros.
Entre ellos están el tipo y características del lodo de perforación, la porosidad de la formación, la permeabilidad de la formación, el diferencial de presión y el tiempo desde que se perforo la formación por primera vez. Sin embargo, por lo general mientras la porosidad de la formación sea menor, la invasión será más profunda. La formación inalterada después de la zona de transición se conoce como “zona no invadida, virgen o no contaminada”.
Algunas veces las formaciones que contiene petróleo o gas, y en donde la movilidad de los hidrocarburos es mayor a la del agua debido a diferencias en la permeabilidad relativa, el petróleo o el gas se alejan más rápido que el agua intersticial. En este caso, quizá se forme entre la zona lavada y la zona virgen una zona anular con una alta saturación de agua de formación. Es probable que hasta cierto grado, se presenten anillos en la mayoría de las formaciones con contenido de petróleo. Su influencia en las mediciones de registros depende de la ubicación radial anillo y de su severidad (esto es la magnitud de la saturación de agua de formación en los anillos con respecto a la saturación de agua de formación en la zona no invadida). Con el tiempo, los anillos desaparecen por medio de la dispersión.
En las formaciones fracturadas, el filtrado de lodo invade con facilidad las fracturas, pero quizá penetre muy poco en los bloques no fracturados de la matriz de roca de baja permeabilidad. Por lo tanto, el filtrado solo desplaza una pequeña porción de los líquidos de formación originales (agua de formación y, en caso de estar presentes hidrocarburos), inclusive a corta distancia del pozo. En este caso, no existe en realidad una zona lavada.
SOLID CONTROL EQUIPMENT SHALE SHAKER
SHALE SHAKER’S DEFINITION. The purpose of a shale shaker is to remove large drilled solids from the drilling fluid. The shale shaker is the first piece of solids-control equipment to treat or condition the drilling fluid. Good shaker performance is necessary if the entire system is to function at or near design efficiency or capability. Shakers now come in a dazzling assortment of sizes, shapes, and motions. Their performance is controlled by the size(s) and shape(s) of the openings in the screen(s), the drilling-fluid properties, the amount and type of cuttings arriving at the shaker, and the general mechanical condition of the equipment.
The shaker selected for your rig may or may not be the best for the drilling at hand. Unfortunately,
PARTES EN EL PROCESO DE CIRCULACION
if it is not, it must still be kept operational, and with intelligent, conscientious work perhaps can be made to do the job. All commercial shale shakers, however, remove cuttings—and they remove cuttings better when properly maintained and operated. Obviously cuttings cannot be removed until the drilling fluid first brings them to the surface. Solids coming off the end of shaker screens should have sharp edges. Cuttings that ‘‘roll around’’ in the borehole on the way to the surface have rounded edges. Rounded edges, or round cuttings, indicate that the cuttings are not being transported directly to the surface as fast, or directly, as they should be. The driller and/or mud engineer should be advised as to the shape of the cuttings coming over the shaker in regard to round edges. Rounded-edge cuttings indicate that there are many drilled cuttings stored in the annulus. This increases the mud weight in the annulus and the pressure at the bottom of the hole.
8 RULES TO ASSURE SHALE SHAKERS WORK WELL:
The excess pressure significantly decreases the drilling rate and cuttings removal from beneath the drill bit. Eight general rules to assure shale shakers will work properly and remove cuttings:
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The shale shaker should be run continuously while circulating. Cuttings cannot be separated if the shaker bed is not in motion.
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Fluid should cover most of the screen. If only one quarter or onethird of the screen is covered, the screen is too coarse and should be replaced with a finer screen.
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If fluid flows through a hole or tear, cuttings are not removed. Any screen with a hole or tear should be replaced immediately. With a panel screen, the hole or tear can be plugged.
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Shaker screen replacements should be made as quickly as possible. Minimize downtime by planning your work. Locate and arrange tools and screens before starting. If possible, get help. This will decrease the amount of cuttings being kept in the mud because the shaker is not running. If possible, change screens during a connection. In critical situations, drilling may be interrupted and the pumps stopped while the screen is replaced.
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Dilution fluid (water or oil) should not be added in the possum belly or on the shaker screen.
SHALE SHAKERS
Dilution fluid should be added downstream. Dilution-fluid (even water) additions should be metered or otherwise measured.
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Except for cases of lost circulation (when it is necessary to retain lost circulation material), the shaker should not be bypassed, not even for a short time.
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Large cuttings should be removed from the possum belly when mud is not being circulated. If the possum belly is dumped into the sand trap just before making a bit or wiper trip, the sand trap should also be cleaned. Otherwise, when fluid circulation starts after a trip, the large cuttings dumped into the sand trap will likely move down the pit system and plug desilters or desanders.
Note: The possum belly and/or sand trap is not always used with synthetic-based mud or some specialized fluid systems.
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As much as possible, flow from the well (bell nipple) should be evenly distributed among all the shakers.
REMOCION DE FILTER CAKE PARA LA CEMENTACION
Jessenai escribe: Tengo una duda. ¿Que tanto afecta a la cementacion si un pozo se encuentra 54 horas inmóvil debido a operaciones de pesca?
La cementacion a realizar es en una zona productora. Gracias.
THE FUNDAMENTALS OF FLUID CONTROL ARE KEY TO WELL CONTROL
The general functions of drilling fluids are fairly standardized. Since most drilling operations rely on liquid drilling fluids, we will make them our main concern. The eight basic functions of drilling fluids are listed below.
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Transportation of cuttings to surface.
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Suspension of cuttings when circulation is stopped.
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Control of annular pressure.
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Lubrication and cooling of the drilling assembly.
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Provision of wall support
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Suspension of drilling assembly and casing
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Delivery of hydraulic energy
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Provision of a suitable medium for wireline logging.
DRILLING FLUID PROCCESS
TRANSPORT CUTTINGS TO SURFACE:
The hole must be properly cleaned to prevent cuttings from accumulating in the annulus, which could cause increased torque, drag, fill or hydrostatic pressure.
DRILLING FLUIDS
This may result in stuck pipe, loss circulation, pipe failure or a decrease in penetration. Since cuttings are heavier than the drilling fluid, they are lifted out of the hole by the fluid flowing in the annulus. Gravity will try to cause the cuttings to fall toward the bottom of the hole. The speed at which the cuttings fall depends on particle size, shape, density and fluid viscosity.
SUSPENSION OF CUTTINGS:
Cuttings will try to fall to bottom when circulation is stopped unless the drilling fluid forms a gel-like structure. This gel-like structure should suspend or hold the cuttings in place until circulation is started again. Excessive surge and swab pressures may be caused if the mud remains in a gel-like structure once circulation has started.
ANNULAR PRESSURE CONTROL:
Since formation fluids (oil, water or gas) are under great pressure, they must be balanced or overbalanced to prevent uncontrolled flow. The hydrostatic pressure of the mud in the annulus accomplishes this.
LUBRICATION AND COOLING:
As the bit drills on bottom and the drillstring turns in the hole extreme heat is developed. This heat must be absorbed by the drilling fluid and carried away from the bottom of the hole. The drilling fluid must also lubricate the casing, drillstring and bit. Lubricating properties can be improved by the addition of special materials (dispersants, friction reducers). This may also increase bit life, decrease torque and drag, reduce pump pressure and reduce frictional wear on the drillstring and casing.
WALL SUPPORT:
The formation could fall into the wellbore before casing is set unless support is replaced by the drilling fluid. The amount of support required to prevent this from occurring depends on the formation. Little support is needed in a very firm formation, whereas consolidated or fairly firm formations may be supported just by the mud density. In weak or unconsolidated formations the drilling fluid must have the ability to form a thin, tough wall cake in the hole.
DRILLING ASSEMBLY/ CASING SUSPENSION:
The drillstring and casing weight can exceed many thousands of pounds and develop extreme stress on the rig’s structure. These extreme weights can be partly supported by the buoyant force of the drilling fluid. This force is dependent on the weight of the fluid and the displacement of the pipe.
DELIVER HYDRAULIC ENERGY:
The drillstring and casing weight can exceed many thousands of pounds and develop extreme stress on the rig’s structure. These extreme weights can be partly supported by the buoyant force of the drilling fluid. This force is dependent on the weight of the fluid and the displacement of the pipe.
A high velocity is developed as drilling fluid passes through bit nozzles during circulation. This velocity, or hydraulic force, will keep the area under the bit clean, so the bit will not have to regrind the old cuttings, causing a reduction in penetration rate. The physical properties and velocity of the drilling fluid help keep the area under the bit clean.
SIDE EFFECTS:
The following side effects should be minimized while drilling.
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Open hole formation damage.
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Casing and drillstring corrosion.
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Penetration rate reduction.
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Circulation, surge and swab problems.
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Lost circulation.
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Drill string sticking.
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Wellbore erosion.
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Settling in the pits.
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Mud pump wear.
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Cement and environmental contamination.
Formation damage can appear in two different forms: a reduction in hydrocarbon production or wellbore stability. Many types of drilling fluids will alter formation characteristics, but some formations are more sensitive than others and some fluids more damaging. Particularly sensitive formations (e.g., hydropressured or bentonitic shale may require special drilling fluids, treating chemicals or other considerations.
CASING AND DRILLSTRING CORROSION
The steel tubulars in the hole may be subject to a corrosive environment from the drilling fluid and formation. Chemical treatment of the drilling fluid or adding a protective coating to the surface of the steel can minimize the corrosive effect.
PENETRATION RATE PRODUCTION
Many factors affect the penetration rate, but the difference between formation pressure and hydrostatic pressure is the most significant. If the hydrostatic pressure of the drilling fluid is much higher than the formation pressure, a reduction in penetration rate will occur.
CIRCULATION, SURGE AND SWAB PROBLEMS
A thick filter cake can also contribute to surge and swab pressures that might result in a kick. Excessive viscosity limits the flow rate, puts extra stress on the pump and may also reduce penetration rates if sufficient pressure at the bit cannot be achieved.
LOST CIRCULATION
Lost circulation can be caused when hydrostatic pressure exceeds the strength of the formation. High pressures can also be the result of bad tripping or drilling practices, high mud weight and/or fluid viscosity. High drilling fluid and well cost, along with the chance of taking a kick are the results of lost circulation.
LOST CIRCULATION
DRILLSTRING STICKING
An excessive amount of cuttings in the hole is one cause of pipe sticking, but the most significant type of sticking is when the pipe is embedded in a thick filter cake. Pipe sticking can lead to expensive fishing jobs and increase the well cost.
WELLBORE EROSION
Problems with wireline logging, cementing and stuck pipe are just a few of the difficulties of wellbore erosion. There are two types of wellbore erosion, physical and chemical. Pumping the drilling fluid up the annulus at a lower velocity will help reduce physical erosion. Chemical erosion depends on the chemical reaction between the drilling fluid and the formation.
SETTLING IN THE PITS
The same gel strength that prevents the cutting from falling in the well when circulation is stopped can also prevent unwanted solids from falling in the pits. Gravity does cause some of the solids to fall to the pit bottom.
MUD PUMP WEAR
Those same solids can cause excessive pump wear if solids are not removed. The most abrasive solid is probably sand incorporated into the fluid while drilling. This sand should be removed by solids control equipment.
CEMENT/ ENVIRONMENTAL CONTAMINATION
Some drilling fluids that are good for drilling operations are incompatible with slurries of cement. A flush, wash or spacer fluid should be used to separate the cement and the drilling fluid.
DRILLING MUD
INTECARB INTEVEP – PDVSA
Intecarb es el nombre comercial de carbonato de calcio y magnesio, de granulometría controlada, para fluidos de perforación, completación y rehabilitación de pozos, que permite controlar la invasión hacia la formación.
Entre los tipos de Intecarb existentes se encuentran:
- Carbonato Comercial Intecarb Grado CM-1015
- Carbonato Comercial Intecarb Grado CM-3035
