Experimental data are provided for the solubility of C I, C 2 , CO 2 , and a n.a~ral gas mi~t.ure in base .oils and emulsifiers used to prepare oil-based drilling fluids over a range of temperatures. In additIOn, an empmcal c~rre~atI~n for . predicting gas solubility in oil-based drilling fluids at low to moderate pressures is presented and a field application IS outlined. IntroductionGas contamination of an oil-based drilling fluid during drilling operations, whether it be by the uncontrolled flow of formation gas into the wellbore (gas kick) or by the drilling of gas-bearing formations (drilled gas), poses a potential hazard to the drilling equipment, environment, and personnel. This danger is the greatest when bottomhole conditions are such that the gas will completely dissolve into the drilling fluid and rapidly evolve as the gas-cut drilling fluid is circulated up the well. Before this phenomenon can be well understood and modeled, the solubility of natural gases in a wide variety of oil-based drilling fluids must be known as a function of temperature and pressure.O'Brien I was the first to report the results of a study on wellcontrol problems caused by gas solubility in oil-based drilling fluids. Although O'Brien made no experimental measurements, he concluded that at the same pressure and temperature, the solubility of gas in an oil-based drilling fluid would be 10 to 100 times greater than the solubility in water-based fluids.
Summary The method presented in this paper uses an experimentally calibrated equation-of-state (EOS) model to estimate the swelling of oil-based drilling fluids caused by dissolved methane. With this method, the pit gain associated with a given kick size can be determined. The calculation method was verified by experiments conducted in a 6,000-ft [828.8-m] test well. Example calculations are also presented. Introduction A major problem with the use of oil-based drilling fluids is the increased difficulty of detecting gas that enters the borehole and dissolves in the drilling fluid. Thomas et al. used a proprietary computer program to show that the surface responses to a gas kick (i.e., annular flow rate and pit gain) are less in oil-based drilling fluids than in water-based drilling fluids. They attributed the difficulty of detecting a gas kick during use of an oil-based drilling fluid to the increased solubility of the gas in the oil phase of the drilling fluid. In one example well geometry, Thomas et al. compared the observed pit gains and annular flow rates resulting from gas kicks in oil- and water-based drilling fluids and concluded that pit gain was the most reliable indicator of a kick in both oil- and water-based drilling fluids. This paper presents a method that uses an experimentally calibrated EOS model to estimate the swelling of oil-based drilling fluids caused by dissolved methane. With this method, the pit gain associated with a given kick size can be determined. The calculation method was verified by experiments conducted in a 6,000-ft [1828.8-m] test well. Examples that show typical computed values for swelling volumes at various depths, drilling fluid densities, and gas concentrations are presented. Pit-gain comparisons are made with water-based drilling fluids for a wide range of conditions. These examples illustrate situations in which it is difficult to detect a gas kick in an oil-based drilling fluid. The method can also be used to determine the sensitivity requirements of kick-detection equipment for any specified hole geometry. The method applies to surface and subsurface kick-detection equipment. Oil-Based Drilling-Fluid Swelling Liquid swelling caused by dissolved gas is usually represented by an FVF, B, defined as the ratio of the volume of liquid and dissolved gas at a given pressure and temperature to the volume of gas-free liquid at standard pressure and temperature. The FVF for an oil-based drilling fluid, Bf, is a function of the volume fraction of base oil and water used in the preparation of the drilling fluid and the FVF of each phase. Swelling of a base oil caused by dissolved gas, Bo, is calculated with the Peng-Robinson EOS2 (PREOS), which is outlined in the Appendix. Table 1 lists the compositions, critical pressures and temperatures, and acentric factors used m the EOS model for several base oils commonly used in drilling fluids. It also lists the binary interaction coefficients used to calibrate the EOS model.
A major problem associated with the use of oil-base drilling fluids is the increased difficulty of detecting gas which enters the borehole and dissolves in the drilling fluid. Previous authors have made computer-simulated comparisons between a water-base and an oil-base drilling fluid for one specific field example. However, a method is needed that will permit field personnel to quickly estimate the amount of dissolved gas that can be associated with an observed pit gain for the field conditions present. In this paper, a method is presented for estimating the swelling of oil-based-drilling fluids due to dissolved gas. The method can be applied both (1) when the gas is fully miscible with the drilling fluid, and downhole mixing is limited and (2) when gas initially contacts the drilling fluid in volumes above the solution gas-mud ratio, and m1x1ng is enhanced by the initial development of gas bubbles. Experimental PVT data were used to verify the calculation method presented for a range of compositions, temperatures, and pressures. The method was also verified by experiments in a 6000-foot test well. Examples are presented showing typical computed values for swelling volumes at various depths, mud densities, and gas concentrations. Pit gain comparisons are made with water-base drilling fluids for a wide range of conditions. These examples illustrate situations in which it is difficult to detect a gas kick in an oil-base drilling fluid. In addition to determining the amount of the dissolved gas present in a given field situation, the method can also be used to determine the sensitivity requirements of kick-detection equipment for any specified hole geometry. The method applies to both surface and subsurface kick-detection equipment. Introduction In previous work done by Thomas, Lea, and Turek (Reference 1), it was shown, using a proprietary computer program, that the surface responses to a gas kick (i.e., annular flow rate and pit gain) are less in oil-based drilling fluids. For one example well geometry, they compared the observed pit gain and annular flow rate due to a gas kick taken in an oil-base and a water-based drilling fluid. From this study, it was concluded that the pit gain was the most reliable indicator of a kick in both oil and water-base drilling fluids. In addition, it was concluded that the damping of surface responses when a gas kick is taken in an oil-base drilling fluid occurs due to gas solubility in the drilling fluid. In this paper, a method will be presented that uses an experimentally verified equation of state model for estimating the swelling of oil-base drilling fluids due to dissolved natural gas. Curves are presented that will permit field personnel to quickly estimate the amount of dissolved gas that will be associated with an observed pit gain for the field conditions present. The method relies on a calibrated equation of state model for determining the amount of oil swelling resulting from a given volume of dissolved gas. A new empirical correlation is used to determine the maximum amount of gas that can be dissolved in the oil for a given well situation. Oil Swelling The Peng-Robinson Equation of State (Reference 2) was used to calculate the density of the oil-phase of a mud containing dissolved natural gas. The equations used in this work are-presented in Appendix A. In order to calibrate the equation of state model, acentric factors and binary interaction coefficients must be selected. In addition, the use of an adjusted molecular weight for the gas-free oil phase was found to be necessary.
This paper presents a study done to determine the base of fresh water in the southern San Joaquin basin in California. Presented is a base of fresh water contour map for the study area as well as a Rwe versus Rw correlation for determining Rw from the SP which was developed for fresh waters found in the study area.
This paper presents calculation methods for predicting the behavior of drilled-gas contamination of oil-based drilling fluids. The methods are verified by experiments conducted in a 6, OOO-ft [1828.8-m] test well. This paper also presents field-handling procedures developed with the calculation methods. IntroductionDuring drilling operations, the bit routinely drills through gasbearing formations. Although proper drilling-fluid density selection will prevent gas from flowing from these formations into the borehole, the gas contained in the pore space of the rock destroyed by the bit will always become mixed with the drilling fluid. This gas is often called "drilled gas." If an oil-based drilling fluid is used, drilled gas will normally dissolve completely in the drilling fluid at bottomhole conditions because the volume of gas is small compared with the volume of drilling fluid in which it is mixed (Fig. I). When this gas/drilling-fluid mixture is pumped near the surface, however, gas will come out of solution and expand rapidly because of the greatly reduced pressure. This gas evolution will often begin when the gas/drilling-fluid mixture is within a few hundred feet of the surface, providing little time for the rig crew to react before gas reaches the surface. Hazardous situations have been reported where significant amounts of gas have been released on the rig floor and drilling fluid has been spewed over the crown block while the annular blowout preventers (BOP's) are being closed.These problems occur because the equipment and procedures sometimes used are not adequate for some of the well conditions experienced. To design a system properly for safe handling of drilled gas in oil-based drilling fluids, a calculation procedure is needed for predicting well behavior under various field conditions. This type of calculation procedure would also permit evaluation of existing rig equipment for the purpose of imposing operationallimitations, such as a maximum safe penetration rate (ROP). This paper presents techniques for estimating the amount of drilled gas entering an oil-based drilling fluid and for predicting the behavior of the gas/drilling-fluid mixture in the annulus as it is circulated to the surface. With the methods presented, the gas/ drilling-fluid bubblepoint depth, the maximum loss in bottomhole pressure (BHP), and an approximate annular pressure profile can be calculated. The volume of drilling fluid that would be expelled from the well and the associated gas rate can also be estimated. The calculation procedures presented were verified by experiments conducted in a 6,000-ft [1828.8-m] test well.Several alternative methods for handling drilled gas in oil-based drilling fluids were explored with the calculation procedure. Special considerations for deepwater floating drilling operations are also discussed. Calculation ProcedureThe calculation procedure developed requires completion of three steps: (I) determination of the concentration and total volume of drilled gas entering the drilling fluid at the...
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