Formation pressure

In the event of a sudden loss of mud In an Interval containing overpressures the mud column in the annulus will drop, thereby reducing the hydrostatic head acting on the formation to the point where formation pressure exceeds mud pressure. Formation fluids (oil, gas or water) can now enter the borehole and travel upwards. In the process the gas will expand considerably but will maintain its initial pressure. The last line of defence leff is the blowout preventer. However, although the BOP will prevent fluid or gas escape to the surface, closing in the well may lead to two potentially disastrous situations ... 

When drilling through normally pressured formations, the mud weight in the well is controlled to maintain a pressure greater than the formation pressure to prevent the influx of formation fluid. Atypical overbalance would be in the order of 200 psi. A larger overbalance would encourage excessive loss of mud Into the formation, slow down... 

When drilling through normally pressured formations, the mud weight in the well is usually controlled to maintain a pressure greater than the formation pressure to prevent... 

Keywords d rec methods, indirect methods, rock properties, coring, core barrel, standard core analysis, special core analysis, slabbed core, sidewall samples, direct indications, microfossils, sonde, logging unit, invasion, mudcake, formation pressure measurement, fluid sampling, measurement while drilling, formation evaluation while drilling. 

One method of sampling reservoir fluids and taking formation pressures under reservoir conditions in open hole is by using a wireline formation tester. A number of wireline logging companies provide such a tool under the names such as RFT (repeat formation tester) and FMT (formation multi tester), so called because they can take a series of pressure samples in the same logging run. A newer version of the tool is called a modular dynamic tester or MDT (Schlumberger tool), shown in Figure 3.8. 

In some cases when drilling fluids invade a very low permeability zone, pressure equalisation in the formation can take a considerable time. The pressure recorded by the tool will then be close to the pressure of the mud and much higher than the true formation pressure. This is known as supercharging. Supercharging pressures indicate tight formation, but are not useful in establishing the true fluid pressure gradient. 

A traditional abandonment process begins with a well killing operation in which produced fluids are circulated out of the well, or pushed ( bull headed ) into the formation, and replaced by drilling fluids heavy enough to contain any open formation pressures. Once... 

In addition to pressure maintenance in a resei voir, there are other ways to maintain or improve well productivity as the formation pressure falls. A pump can be used to raise the oil, a process called artificial lift. One type is the familiar beam pump with its surface power unit driving up and down one end of a center-mounted beam while the other end executes the opposite down-up motion. The second end is attached to a string of sucker rods that extend down to the bottom of the well and operate a pump arrangement, consisting of a cylinder, plunger, and one-way A alves. Other types of pumps in use eliminate the sucker rod and may have the power unit at... 

The fluid pressure in the rock at the bottom of a well is commonly defined as pore pressure (also called formation pressure, or reservoir pressure). Depending on the maturity of the sedimentary basin, the pore pressure will reflect geologic column overburden that may include a portion of the rock particle weight (i.e., immature basins), or a simple hydrostatic column of fluid (i.e., mature basins). The pore pressure and therefore its gradient can be obtained from well log data as wells are drilled. These pore pressure data are fundamental for the solution of engineering problems in drilling, well completions, production, and reservoir engineering. 

Shut in well. Record drill pipe and casing pressure. Circulate out gas or water influx and separate on surface. Calculate mud weight necessary to balance formation pressure. Kill the well. 

CH. RGED S.AND Pressure control. Weight mud to give hydrostatic pressure above formation pressure. Maintain low viscosity and gels for gas removal. Keep hole full at all times. 

Fluid properties Density Ideal requirements Fluid density should not be greater than that which balances formation pressure. Practical recommendation Differential pressure should not exceed 100-200 psi. 

A gas inflow occurs suddenly when entering an abnormal pressure zone. Compute the flowrate of gas if the formation pressure is 7,000 psi, 1 ft has been penetrated in a 50-ft zone with 500 md, gas viscosity is 0.035 cp. Assume no annulus pressure drop, no cutting. Compute the annular temperature drop. 

Surface measurements on the mud can be used to estimate the mudcake characteristics. If the formation pressure is known, the differential pressure can be calculated, and a chart similar to Figures 4-293a and b can be plotted. 

The normal formation pressure gradient is the density of a column of saltwater of length Zy is expressed in psi-ft in customary units. Table 4-134 gives normal gradient values for areas around the world. Note that for freshwater or quasi-freshwater Gj = 0.433 psi/ft = 8.345 Ib/gal. 

The formation pressure is said normal when it corresponds to the hydrostatic pressure of a column of water of length Zp, the water having the densities stated in Table 4-134. 

An abnormal formation pressure is a formation pressure greater than the normal formation pressure. Subnormal formation pressures are also encountered in drilling they are generally due to depleted reservoirs. 

Abnormal Formation Pressures Origin. Four main causes are attributed to abnormal formation pressures compaction effects, diagenetic effects, differential density effects and fluid migration. 

Normal Formation Pressure Gradients in Various Areas [101]... 

During compaction, if the fluid can escape, the formation pressure stays equal to the normal formation pressure. 

If the fluid cannot escape due to permeability barriers, for example, then the fluid supports part or most of the overburden load. Under these conditions the formation pressure can be up to twice the normal formation pressure. 

Abnormal Formation Pressure Detection with Drilling Parameters. There are four groups of parameters that can be used for abnormal formation pressure detection ... 

No trend line is needed to determine the formation pressure. However, petrophysical data are required to refine the results. A computer is mandatory to implement the technique. 

Apply the Terzaghi relationship (Equation 4-243) to determine the formation pressure. 

A good formation pressure agreement is seen at 9,500 ft with the wireline formation tester data. 

The formation pressure gradient corresponding to the difference of transit times is 0.93 psi/ft. The formation pressure is... 

The various volumes of rock matrix, shale, porosity, overpressure porosity and hydrocarbons are used to compute the various tool responses according to a model. The responses are compared to the measured values and a volume optimization is made to minimize the errors grouped in an incoherence function. The value of the incoherence function for the best fit determines the quality of the answer. Figure 4-335 is an example of formation pressure calculation as well as formation evaluation for lithology and fluid content. 

Abnormal Formation Pressure Detaction with Mud Logging Parameters. The... 

Figure 4-335. Computations of the formation pressure, lithology, and fluid content made with MWD formation-strength, LWD resistivity, gamma ray, neutron, and density measurements. (Courtesy Anadrill [113].,)...

Demonstration. The transition zone is clearly indicated at 12,000 ft. The trend line is determined as an exponential function. The difference between the trend line value (2.48 g/cm ) and the measured value (2.28 g/cm ) at 13,000 ft can be correlated to the formation pressure gradient using the empirical correlation curve established by Boatman and shown in Figure 4-337 [101]. 

The shape of the shale cuttings also gives a qualitative evaluation of the formation pressure. The cuttings are larger and more angular than normal. They... 

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