Formation fluid influx

A formation fluid influx (a kick) may result from one of the following reasons ... 

A gas-cut mud is a warning signal of possible formation fluid influx, although it is not necessarily a serious problem. Due to gas expandibility, it usually gives the appearance of being a more serious problem than it actually is. 

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... 

If a situation arises whereby formation fluid or gas enters the bore bole the driller will notice an increase in the total volume of mud. Other indications such as a sudden increase in penetration rate and a decrease in pump pressure may also indicate an influx. Much depends on a quick response of the driller to close in the well before substantial volumes of formation fluid have entered the borehole. Onoe the BOP is closed, the new mud gradient required to restore balance to the system can be calculated. The heavier mud is then circulated in through the kill line and the lighter mud and influx is circulated out through the choke line. Once overbalance is restored, the BOP can be opened again and drilling operations continue. 

Upon shutting in the well, the pressure builds up both on the drillpipe and casing sides. The rate of pressure buildup and time required for stabilization depend upon formation fluid type, formation properties, initial differential pressure and drilling fluid properties. In Ref. [143] technique is provided for determining the shut-in pressures if the drillpipe pressure is recorded as a function of time. Here we assume that after a relatively short time the conditions are stabilized. At this time we record the shut-in drillpipe pressure (SIDPP) and the shut-in casing pressure (SICP). A small difference between their pressures indicates liquid kick (oil, saltwater) while a large difference is evidence of gas influx. This is true for the same kick size (pit gain). 

If formation pressure increases, mud density should also be increased, often with barite (or other weighting materials) to balance pressure and keep the well-bore stable. Unbalanced formation pressures will cause an imexpected influx of pressure in the well-bore possibly leading to a blowout from pressured formation fluids. 

Now let us rework the preceding cylindrical radial problem, and alter the analytical and numerical formulations so that they handle spherical radial flows. Such formulations model invasion at the drillbit and also point fluid influx into formation testers at small times. We will replace the governing equation for cylindrical radial flows, namely, d2p(r)/dr2 -i- (1/r) dp(r)/dr = 0 in Equation 20-33, by the spherical flow equation... 

Similarly, when drilling into an underpressured formation, the mud weight must be reduced to avoid excessive losses into the formation. If the rate of loss is greater than the rate at which mud can be made up, then the level of fluid in the wellbore will drop and there is a risk of influx from the normally pressured overlying formations. Again, it may be necessary to set a casing before drilling into underpressures. 

In most air and gas drilling operations, open-hole well completions are common. This type of completion is consistent with low pore pressure and the desire to avoid formation damage. It is often used for gas wells where nitrogen foam fracturing stimulation is necessary to provide production. In oil wells drilled with natural gas as the drilling fluid, the well is often an open hole completed with a screen set on a liner hanger to control sand influx to the well. 

If there is no constant influx of fluid of a certain composition, decomposition of magnetite ceases. The limiting case is a dry system closed to CO2. By analogy with systems closed to water, in such a system with constant pressure P — Pf = const) the fluid phase disappears entirely, and the Mgt + Sid + Hem association (system Fe-C-O) becomes bivariant and can exist stably below the P-T curve (see Fig. 77) in the stability field of the Sid -1- Hem (+ fluid) association. From these considerations the Mgt -I- Sid + Hem association cannot be used to judge the low-temperature limit of mineral formation the upper limit is fixed quite definitely inasmuch as removal of CO2 begins at P P and the reaction proceeds irreversibly to the right. The extensive occurrence of magnetite in oxide-carbonate iron-formations of low-rank metamorphism apparently indicates the absence of equilibrium or even a deficiency of COj and special dry conditions. 

Recently, MALDI-TOF (matrix-assisted laser desorption/ionisation-reflection time-of-flight) mass spectrometry was introduced as a new approach for the investigation of pellicle composition [39], Using mass spectrometry for compositional analysis, it was found that more intact salivary protein species were present in an in vitro-formed pellicle compared to an in vivo-formed pellicle [39], This finding suggests that the in vivo pellicle is an entity formed with components undergoing more extensive enzymatic (proteolytic) processing than in the in vitro pellicle. Therefore, in vitro-formed pellicle layers cannot completely mirror what occurs within the oral cavity [39], This difference may be due to differences in the proteolytic capacity of the saliva supernatant used for in vitro pellicle formation and that of the oral environment. In addition, a particular saliva sample used for in vitro pellicle formation is a closed system, whereas the oral environment is an open system with continuous influx and clearance of oral fluids [39]. 

Secondary porosity development as the main contributor to the present reservoir porosity in Hibernia Field is closely related to the former presence of early calcite cements. The fraction of total porosity which is secondary increases with depth, from 20% in Avalon/Ben Nevis Sandstone (Hauterivian-Albian), to 60% in Catalina Sandstone (Lower Hauterivian), and to >80% in Hibernia Formation (Berriasian to Mid-Valanginian). In the Avalon/Ben Nevis Sandstone the formation of secondary porosity may have been caused by meteoric water influx. In the deeper reservoirs it was caused by acidic pore fluids generated by organic-matter maturation. The present average geothermal gradient of 26°C/km suggests that the most deeply buried sandstone reservoirs in Hibernia (Tithonian Jeanne d Arc Formation) did not experience temperatures in excess of 130°C. 

Formation pressure data were obtained from repeat formation tester (RFT) or modular dynamic tester (MDT) measurements of numerous deep wells in the Central North Sea. These data were used as the primary pressure dataset as they are the most accurate pressure measurements possible down-hole. The MDT/RFT wireline tool takes a pressure reading within a permeable formation, by setting a seal at a precise depth determined by using an accompanying gamma ray tool for depth correlation. Drill stem test (DST), mudweight data and kick (influxes of pore fluids into the wellbore) information was also used where RFT or MDT data were not available or of very poor quality. A summary of the various approaches used to derive formation pressures is provided by Holm (1998). 

Prior to the drilling of the well all geological data, including the seismic was thoroughly reviewed and analyzed. From the data at hand there was no reason to expect an influx of fluid during the second core run in the Prairie Evaporite Formation. Not only is it unusual to encounter fluids in the middle of the salt bed, the pressures encountered in this well are abnormally high for the potash exploration industry. The zero casing and drill pipe pressure was achieved when the fluid column was at 2000 kg/m3. This equates to a bottom-hole pressure of approximately 30 MPa which is hydrostatically over-pressured by about 15 MPa. 

Large Diameter Well with Recyclable Foam. The objective on this well was to drill a 26-inch surface hole to 1500 feet and a 17.5-inch intermediate hole to 6000 feet with foam. Previous drilling in this particular region had proven to be excessively expensive due to low penetration rates. There existed a known potential for lost circulation, large fresh water influxes, and unconsolidated formations in the upper section of the well. Foam was chosen as the drilling fluid of choice, due to its ability to function effectively in the presence of high water influxes and... 

Al-Marhoun, M.A. Rahman, S.S. (1988). Optimizing the Properties of Water-Based Polymer Drilling Fluids for Penetrating Formations with Electrolyte Influx. Erdoel, Erdgas, Kohle, Vol. 104, No. 7-8, (September 1988), pp. (318-323), ISSN 0179-3187... 

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