Brine completion fluids

Figure 4-123. Salts used in clear brine completion fluids of various densities [28]. (Courtesy International Drilling Fluids, Inc.)...

Density control in brine-polymer systems can be achieved with salt solutions or with weighting materials. When mixing heavy brine completion fluids, the following factors should be considered ... 

Controlling fluid loss loss is particularly important in the case of the expensive high density brine completion fluids. While copolymers and terpolymers of vinyl monomers such as sodium poly(2-acrylamido-2-methylpropanesulfonate-co-N,N-dimethylacrylamide-coacrylic acid) has been used (H)), hydroxyethyl cellulose is the most commonly used fluid loss additive (11). It is difficult to get most polymers to hydrate in these brines (which may contain less than 50% wt. water). The treatment of HEC particle surfaces with aldehydes such as glyoxal can delay hydration until the HEC particles are well dispersed (12). Slurries in low viscosity oils (13) and alcohols have been used to disperse HEC particles prior to their addition to high density brines. This and the use of hot brines has been found to aid HEC dissolution. Wetting agents such as sulfosuccinate diesters have been found to result in increased permeability in cores invaded by high density brines (14). 

High density brine completion fluids also often require the use of corrosion inhibitors (8,9). Blends of thioglycolates and thiourea alkyl, alkenyl, or alkynyl phosphonium salts thiocyanate salts mercaptoacetic acid and its salts and the reaction products of pyridine or pyrazine derivatives with dicarboxylic acid monoanhydrides have been used as high density brine corrosion inhibitors. 

Hydroxyethyl cellulose (HEC), a nonionic thickening agent, is prepared from alkali cellulose and ethylene oxide in the presence of isopropyl alcohol (46). HEC is used in drilling muds, but more commonly in completion fluids where its acid-degradable nature is advantageous. Magnesium oxide stabilizes the viscosity-building action of HEC in salt brines up to 135°C (47). HEC concentrations are ca 0.6—6 kg/m (0.2—21b/bbl). 

Oilfield Uses. Calcium chloride has two uses in the oilfield as a primary ingredient in completion fluids and as the brine phase in an invert emulsion oil mud. An excellent review of oil well drilling fluids is available (36) (see also Petroleum, drilling fluids). 

Perforating fluids used may be filtered clear brine or CaCO, type completion fluids, oil, seawater, acetic acid, gas or mud. 

Prepared saltwater completion fluids are made of fresh surface water, with sufficient salts added to produce the proper salt concentration. Usually, the addition of 5 to 10% NaCl, 2% CaClj, or 2% KCl is considered satisfactory for clay inhibition in most formations. Sodium chloride solutions have been extensively used for many years as completion fluids these brines have densities up to 10 Ib/gal. Calcium chloride solutions may have densities up to 11.7 lb/ gal. The limitations of CaClj solutions are (1) flocculation of certain clays, causing permeability reduction, and (2) high pH (10 to 10.5) that may accelerate formation clays dispersion. In such cases, CaC12-based completion fluids should be replaced with potassium chloride solutions. Other clear brines can be formulated using various salts over wide range of densities, as shown in Figure 4-123 [28]. 

A typical formulation of a brine-polymer completion fluid might include 8.5 to 11 Ib/gal salt water solution (NaCl, CaCl, KCI, or a mixture), 0.25 to 1.0 Ib/bbl polymer and 5 to 15% calcium carbonate. 

An injectivity test is performed using clean, solids-free water or brine. If a low fluid loss completion fluid is in the hole, it must be displaced from the perforations before starting the injecting. This test will give an idea of the permeability of the formation to the cement filtrate. 

In normal operations, there is little chance for spent acid to contact the completion fluid as the well will usually be produced after perforation, effecting the removal of completion fluid prior to acidization. The fact that a calcium precipitation reaction can occur should be recognized by those using TKPP solutions as a clear completion fluid in well operations. A KC1 spacer is recommended to avoid completion problems in formations having high calcium brines. 

Completion fluids are not always compatible with formation mineralogy. This is of more concern in water-sensitive sandstones than in carbonates. Core flow tests can be used to evaluate sensitivity of the formation to various brine formulations. Core testing can be used to select the proper fluid or to modify a fluid with additives to address water sensitivity. 

Uses Viscosifierfor oil field applies., low solids drilling and completion fluid systems, KCI muds, field brines, sea water and sat. NaCI brines emulsifier Features Salt tolerant high carrying capacity more shear-thinning Environmental Nontoxic to marine, fresh water, and tenestrial species... 

Sohd salt, ground and packaged in several particle size grades, can be used in saturated salt brines to increase the fluid density (28). However, sized salt is most often used as a water-soluble material for bridging or sealing porous formations. At one time the sized salt systems were used primarily for completion or workover operations, but use has increased as ddU-in fluids for horizontal wells (29). 

Wells which are completed to the Main Zone inject brine and produce fluids from four sands, termed the C-, D-, E- and F-sands. The C-sand is well isolated from the D-, E-, and F-sands which were not discrete. Spinner surveys obtained before and after injection of TFSA indicate that the TFSA did not adversely alter the injectivity of the formation and that the formation was not damaged by TFSA injection. 

Solutions of TKPP were mixed with aqueous fluids commonly encountered in drilling or completion of wells. Unlike saturated zinc bromide, concentrated TKPP solutions can be mixed in any proportion with fresh water with the only result being a decrease in solution density. Similar results were obtained with conventional oil field brines containing as much as 400 parts per million polyvalent cations, mostly calcium. Saturated solutions of calcium hydroxide also can be added to TKPP in any proportion without promoting precipitation as can concentrated hydrochloric acid solutions, conventionally used for well stimulation. The acid tends to generate a slight haze as the pH is reduced from 11.5 to approximately 8 however, this haze rapidly disappears as the pH is lowered by further addition of acid. 

The Eastern Mediterranean is the site of 5 deep-sea basins that were discovered in the 1980s (e.g., Jongsma et al. 1983) and 1990s (MEDRIFF-Consortium 1996). Detailed noble gas studies were completed in three of them, the Elrania, Atalante and Discovery brines, in order to investigate their origin and fluid kinematics. 

The elution of hardness ions following injection of 0.1 pore volume or 0.5 pore volume of 0.5% Na2C02 in 3% NaCl solution, followed by 3% NaCl solution to completion, showed significant increases in hardness ion levels after one pore volume of fluid had been injected. These high levels of hardness ion eluted from the core suggest that the removal of Ca ion by precipitation does not occur under these conditions. High levels of hardness ion are exchanged from the clays, as shown by the increase in concentration above that of the resident brine. 

---