A factorial design experiment was used to identify the hydrothermal reactions between the pore fluid, kaolinite, quartz and dolomite under conditions that simulate in-situ steam injection. One gram samples of kaolinite, quartz and dolomite mixed in the proportions 1:1:0.05 or 1:1:1 were reacted with 10 ml of solution at 250 °C and 300 °C for five and seven-day periods at neutral, intermediate and high pH. X-ray diffraction was used to identify the solids and inductively coupled argon plasma analysis was used to determine changes in the fluid composition. These reconnaissance experiments showed that smectite is synthesized rapidly and is then transformed to analcime in sodic-rich alkaline solutions. Maintaining a high sodium concentration in solution and an alkaline pH appear to be the most important control in this process. The rapid transformation of kaolinite and smectite into analcime could have a beneficial effect on permeability and recovery rates during thermal in-situ projects. Introduction This study was conducted to identify and examine the reactions between kaolinite, quartz and dolomite under conditions typical of in-situ steam injection. Temperatures are in the range of 200 °C to 300 °C and pressures can reach 13.8 MPa(1). The hydrothermal reactions between kaolinite, quartz and dolomite at 25 °C to 300 °C have been discussed in several publications(2–5). These investigators have reported that clays of the smectite group are a common reaction product. Smectite is a swelling clay which can expand and/or disperse when contacted by low salinity water and contribute to formation damage via pore plugging. As little as two per cent smectite can cause a 50 fold reduction in permeability(5). The effects of smectite clays during conventional oil recovery operations have been discussed extensively in the technical literature and no attempt will be made to review them. The effects of smectite formation during thermal recovery operations are less well known although its growth has been recorded in post-steam cores(6). Young et al.(7) summarize the effects of clay formation damage in steam environment and discuss its control through clay stabilizing agents. A factorial design was chosen for these experiments because it allows the evaluation of the combined effects of several variables in a single experiment(8,9). A maximum of four independent variables, temperature, pH, ionic composition of the pore fluid and time were in operation simultaneously during these experiments. Predicting the hydrothermal reactions in this multi-component system becomes more realistic when the interaction of several variables can be considered. Experimental Procedures Experimental Design In these experiments, two of the variables were set at one of two levels: temperature 250 °C or 300 °C and duration, 5 or 7 Days. In addition, fluid composition was varied by using different quantities of NaCl, NaOH, Na2CO3, Na2B1O7, 10H2O and Na2HPO4 to adjust the salinity and pH of the starting solutions. NaOH was used to adjust the pH in most of the experiments which was set at one of three levels, neutral (pH 7), intermediate (pH 10) or high (pH 12) at room temperature, The pH at run temperature was not calculated but will be different from that at room temperature.

Drilling fluids utilized in horizontal wells must be as non-damaging as possible. In vertical wellbores, localized damage induced by invading drilling fluids and solids can often be bypassed through cementing and perforating. Due to the high cost associated with perforating horizontal wells, cleanup must be achieved with wellbore flow Or chemical stimulation techniques. With long horizontal sections, reservoir drawdown may not be sufficient to remove formation damage. To this end, stimulation attempts can be costly, and in some cases, ineffective. If damage is severe, productivity may be at an uneconomic level and a viable drilling play could subsequently be abandoned. By conducting core displacement tests with various drilling fluids on representative reservoir samples, the least damaging drilling fluid can be selected. Proper testing and core preparation procedures must be followed to ensure that results are representative. This paper will outline core displacement test methodology and present the results of several core displacement studies. The findings are substantiated with case histories of production data. These results illustrate that although damage due to drilling cannot be eliminated, it can be minimized. Introduction Formation damage is defined as any type of a process which results in a reduction of the flow capacity of an oil-. water- or gas-bearing formation. Formation damage has long been recognized as a source of serious productivity reductions in many oil anti gas reservoirs and as a cause of water injectivity problems in many waterflood projects (Bennion, 1991). Introduction Formation damage can occur whenever non-equilbrium or solid bearing fluids enter a reservoir, or when equilibrium fluids are displaced at extreme velocities. Thus, many processes used to drill, complete or stimulate reservoirs have the potential to cause formation damage. Some of these processes might include:DrillingCementingCompletions/Stimulation erforating acidizing fracturing Workovers kill fluids hot oil treatments Waterflooding or water disposal Ehanced oil recovery Enhanced oil recovery processes miscible flooding chemical flooding thermal flooding (in situ combustion/steamflooding) Excessive injection or production rates Horizontal wells are much more susceptible to damage than their vertical counterparts due to a number of reasons, these being:Substantially longer contact time with the drilling fluid. In a vertical well, drilling fluid may only be in contact with the pay zone a matter of hours while in a horizontal well, the time may be measured in weeks.Most horizontal wells are not cased and perforated and remain as open hole completions. Relatively shallow damage, which would be easily perforated through on a standard conventionally-cased vertical well, remains a major source of permeability reduction in many horizontal wells.Uniform drawdowns are difficult to obtain on horizontal wells due to the length of the well in the pay zone. This makes it much more difficult to clean up damage due to invaded fluid and/or solids except in selected zones.The physical mechanics of flow into horizontal wells are substantially different from vertical wells due to the fact that the vertical and horizontal permabilities in most formations differ.