Drill-in fluids

Mixed metal hydroxide drilling muds have been successfully used in horizontal wells in tunneling under rivers, roads, and bays for drilling in fluids for drilling large-diameter holes with coiled tubing and to ream out cemented pipe. 

Polyacrylates are often added to drilling fluids to increase viscosity and limit formation damage. The filter-cake is critical in preventing reservoir invasion by mud filtrate. Polymer invasion of the reservoir has been shown to have a great impact on permeability reduction [98]. The invasion of filtrate and solids in drilling in fluid can cause serious reservoir damage. 

The drill-in fluids are typically composed of either starch or cellulose polymers, xanthan polymer, and sized calcium carbonate or salt particulates. Insufficient degradation of the filter-cakes resulting from even these clean drill-in fluids can significantly impede the flow capacity at the wellbore wall. Partially dehydrated, gelled drilling fluid and filter-cake must be displaced from the wellbore annulus to achieve a successful primary cement job. 

Specially designed drill-in fluids or workover and completion fluids, minimize formation damage. 

Thixotropy and Other Time Effects. In addition to the nonideal behavior described, many fluids exhibit time-dependent effects. Some fluids increase in viscosity (rheopexy) or decrease in viscosity (thixotropy) with time when sheared at a constant shear rate. These effects can occur in fluids with or without yield values. Rheopexy is a rare phenomenon, but thixotropic fluids are common. Examples of thixotropic materials are starch pastes, gelatin, mayoimaise, drilling muds, and latex paints. The thixotropic effect is shown in Figure 5, where the curves are for a specimen exposed first to increasing and then to decreasing shear rates. Because of the decrease in viscosity with time as weU as shear rate, the up-and-down flow curves do not superimpose. Instead, they form a hysteresis loop, often called a thixotropic loop. Because flow curves for thixotropic or rheopectic Hquids depend on the shear history of the sample, different curves for the same material can be obtained, depending on the experimental procedure. 

These distributors are fabricated of pipe lengths tied to a central distribution header (usually) %vith orifice holes drilled in the bottom of the various pipe laterals off the header. This style of distributor can be fed by pressure or gravity for clean fluids. The gravity feed is considered better for critical distillation application when uniformity of the flow of the drip points (or flow points) through out the cross-section of the tower is extremely important, and is excellent for low flow requirements such as below 10 gpm/ft2 [131]. 

Figure 2-56 shows a plot of the theoretical maximum overburden pressure and the theoretical minimum pressure as a function of depth. Also plotted are various bottomhole fluid pressures from actual wells drilled in the Gulf Coast region [33]. These experimentally obtained pressures are the measurements of the pressures in the fluids that result from a combination of rock overburden and the fluid hydraulic column to the surface. These data show the bottomhole fluid pressure extremes. The abnormally high pressures can be explained by the fact that the sedimentary basins in the Gulf Coast region are immature basins and are... 

In oil-producing formations with high fluid loss, drilling in with foam and foam completion proves beneficial. Usually, these formations cannot stand a column of water—so it is impossible to establish returns with conventional mud. The use of foam for drilling in and completion results in substantial increases in production. 

One of the basic mechanisms in fluid loss prevention is shown in Figure 2-1. The fluid contains suspended particles. These particles move with the lateral flow out of the drill hole into the porous formation. The porous formation acts like a sieve for the suspended particles. The particles therefore will be captured near the surface and accumulated as a filter-cake. 

C. P. Anderson, S. A. Blenkinsopp, F. M. Cusack, and J. W. Costerton. Drilling mud fluid loss—an alternative to expensive bulk polymers. In Proceedings Volume, pages 481—489. 4th Inst Gas Technol Gas, Oil, Environ Biotechnol Int Symp (Colorado Springs, CO, 12/9-12/11),... 

W. S. Halliday, D. K. Clapper, M. R. Smalling, and R. G. Bland. Glycol derivatives and blends thereof as gas hydrate inhibitors in water base drilling, drill-in, and completion fluids. Patent WO 9840446, 1998. 

Z. R. Lemanczyk. The use of polymers in well stimulation performance, availability and economics. In Proceedings Volume. Plast Rubber Inst Use of Polymers in Drilling Oilfield Fluids Conf (London, England, 12/9), 1991. 

R. Munro, G. Hanni, and A. Young. The economics of a synthetic drilling fluid for exploration drilling in the UK sector of the North Sea. In Proceedings Volume. IBC Tech Serv Ltd Prev Oil Discharge Drilling Oper—The Options Conf (Aberdeen, Scotland, 6/23-6/24), 1993. 

R. C. Navarrete, J. M. Seheult, and M. D. Coffey. New biopolymers for drilling, drill-in, completions, spacer, and coil-tubing fluids Pt 2. In Proceedings Volume. SPE Oilfield Chem Int Symp (Houston, TX, 2/13-2/16), 2001. 

A commonly employed method to minimise ohmic potential drop effects is to place the reference electrode very close to the working electrode by means of a Luggin capillary. The disadvantage of very close placement, which may be unacceptable, is disturbance of the fluid flow. To avoid this, other methods are sometimes used. For example, a rotating disc electrode has been described in which the reference electrode is placed in a tiny compartment within the rotating electrode assembly and linked to the solution via a tiny orifice (0.7 mm) drilled in the centre of the disc [88]. 

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