The densities of thallium amalgams were measured a t 25, 50, 'i0,90,105, 125, and 160 "Cover the concentration range 0 to 42% thallium by weight and the results were fitted to equations of the form d = a + bx + cx2, where d is the density in grams per ml, a, b, and c are constants and x is weight % thallium in the amalgam. The coefficient of expansion was calculated for the temperature range 25 to 90 "C. Viscosities relative to mercury were also determined over the same range of con~position and a t the same temperatures as were used in the density measurements. Equations were resented which show the variation of viscosity with composition and also the variation orviscosity with temperature.

Oil based fluids have been used since the inception of well completion technologies. Formation sensitivity to water has often been the primary consideration for the selection of oil based stimulation fluids. Historically, oil based fracturing designs required complicated procedures to successfully execute a fracturing operation. Rheological properties of fluid compositions used did not produce stimulation fluids with optimum viscosity or transport characteristics. The obvious hazards involved in accomplishing an operation using these types of fluids were also great due to the variability of the fluids caused by different base hydrocarbons. The development of a unique system with rheological, transport, and process advantages, which have long been desired in hydrocarbon based stimulation fluids are discussed in this paper. In addition, the chemical evolution of the oil based gel system will be discussed, and properties of the fluid including rheology, break, and conductivity testing will be presented. Characterization of the rock mineralogy for those formations which can be considered as candidates for stimulation with the hydrocarbon based system are presented. Detailed field case histories of the application of the new system are included. In general, stimulation with the new system provides a rapid clean-up and return to production. Introduction/Statement of Problem Since the late '80s, an important focus for the drilling activity in Canada involves the deep Cretaceous / Jurassic gas formations in the foothills of West Central Alberta. These formations contain water saturations at sub-irreducible levels and are generally relatively low in permeability (0.1 to 1.0 millidarcies.) with temperatures in the range of 70C to 110C. In addition, they usually contain or form condensate during production. These conditions along with the availability of highly effective phosphate ester gelling agents and improved crosslinkers and breakers have given rise to the widespread use of gelled condensates and refined oils as fracturing fluids. The inertness and non clay-swelling nature of hydrocarbons as well as the low interfacial tensions obtained with high pressure gas, leads to superior regained permeability results when compared to water based fracturing fluids. In 1995, however, three refineries located in British Columbia, Alberta and Ontario all experienced rate limiting fouling in the jet draw area of their distillation towers. subsequent shut down and inspection revealed that all three refinery towers were fouled with a glue-like compound that appeared polymeric in origin. Analysis showed that the deposits contained (8–12%) phosphorous in addition to carbon (30–40%) hydrogen (3–4%), nitrogen (3–7%) and copper/nickel (1–2%). subsequent studies into the volatility of phosphorous-containing additives, that could have contaminated crude oil feed stocks, showed that only the phosphate esters used in gelled hydrocarbon fracturing fluids were volatile and likely to be the source of the problem. Although phosphate esters had been used for many years with out any reported fouling, the greatly increased frequency of these fracture treatments and the higher through puts and reduced inventories of crude at refineries in recent years helped rationalize the findings. subsequent to the 1995 fouling incident, monitoring of phosphorous levels in the crude feeds was undertaken. For the next couple of years, there was little evidence to show that there was a continuing problem. However, in 1997 occasional spikes in concentration of phosphorous in the crude streams were observed and, in 1998 inspection of distillation towers showed that phosphate deposits were still occurring in all three towers. Even though many questions remained, it was felt that if phosphorous could be eliminated from the gelled fracturing fluids then the formation of deposits and subsequent fouling could be eliminated.

With the development of cement slurries foamed with air or nitrogen, new methods of cementing wells are now available which will benefit operations in Canada*". Foamed cement has several physical properties which are very advantageous to some cementing operations. The most obvious advantage is its application as an economical, lightweight cement with relatively high strength. Formations which would normally break down when subjected to the hydrostatic pressures exerted by conventional lightweight slurries can now be cemented with foamed cement. The pseudoplastic properties of foamed cement slurries, combined with low density, make this cement ideal for curing lost circulation where conventional slurries containing lost circulation materials are ineffective. The air/nitrogen in the slurry provides compressibility, which will help maintain the hydrostatic pressure On the formation and improve zonal isolation by combatting annular gas channelling. Thermal cement slurries containing normal mix water ratios can also be foamed resulting in low density, set cements exhibiting good thermal stability along with greatly improved insulating qualities. This feature is attractive for cementing operations in Western Canada's thermal recovery projects. Foamed cementing operations can be conducted using conventional cementing equipment with the addition of an air or nitrogen source. This paper will review the physical properties of foamed cement and summarize the design and field operations of applications in Canadian operations. Introduction The use of compressed gases, notably nitrogen, to reduce hydrostatic pressure during primary cementing across severe lost circulation zones has been recognized for some time(1). Also, the use of low-density cement slurries has provided an alternate solution to slurry loss. In the past, these slurries fell into three classes. The first class includes slurries prepared by adding higher ratios of mix water and maintaining free water control (i.e. preventing cement separation) by incorporating clay-sized inorganic solids, or chemical extenders in the cement or mix water. The second class incorporates low-density solids notably organic material such as ground walnut hulls, coal, or gilsonite, into the slurries along with some additional mix water to achieve low density. The third class consists of slurries utilizing very fine glass or ceramic bubbles as the low-density solids(2,3). Both the first and second classes of slurries have been widely used and are still economical solutions to the cement requirements of most wells. Their use is limited however to cementing operations where slurry densities of greater than approximately 1450 kg/m3 are satisfactory as their compressive strength at lower densities are usually inadequate. The additives used in the second class of slurries also serve as bridging type lost circulation additives which are beneficial in cementing some wells. The third class of slurries has the advantage of higher strengths at lower densities, however, the collapse pressure of the additives (<50,000 kPa) and the relatively high cost has severely limited their use. Also, the need for dry blending the additive with the cement, causes complications in offshore applications. Not until recently(4,5) has the practicality of a fourth class of low-density slurry and cement been demonstrated.

The densities of solid thallium amalgams were measured pycnometrically at −79.0 °C with the following results in g/ml: 13.946, 13.851, 13.465, 13.379, 13.219, 13.263, 13.267, 13.264, 13.184, 13.180, 13.177, 13.132, 13.063, 13.055 for the concentrations in weight % thallium of 8.72, 11.15, 19.45, susceptibilities of the amalgams were measured by the Gouy method over the same concentration range at temperatures from −180 °C to 150 °C. The alloys were diamagnetic and the susceptibilities were compatible with the phase diagram. The densities and the e.m.f. measurements on concentration cells show that the alpha phase at −79 °C extends from 21.35 to 30.7 weight % thallium and at 0 °C the alpha phase extends to 33.75 weight % thallium.

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