The Application of Peng Robinson Equation of State to Predict Natural Gas Behaviour in Oil based Drilling Fluid

A major problem associated with the use of oil base drilling fluid 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-based 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, methods were presented for estimating the swelling of oil based drilling fluid due to dissolved gas. This involves the determination of the formation volume factors of the fluids (oil-gas-drilling fluid mixture) at given subsurface conditions using Peng-Robinson equation of state and hence the detection of the natural gas intrusion into a given well and subsequent calculation of the pit gains. The results were compared with similar but empirically obtained data. The pressure profile for a well at given conditions have also been made thereby aiding the several predictions that will lead to proper fluid flow control. INTRODUCTION One of the greatest challenges for the complex oil and gas exploration and exploitation (scenarios such as deep waters and high pressure high temperature wells) is related to the drilling fluids, which must combine the technical requirements with environmental regulatory issues. Synthetic based drilling fluids have been developed to provide the technical performance of the convectional oil based drilling mud without their environmental damage, reducing the impact of cuttings discharge or eventually spill accidents. Among the synthetic oil available for drilling fluids, n-paraffin is the most commonly used around the world. An important aspect that should be addressed when drilling with a synthetic fluid is the peculiarities concerned with well control. Because of the solubility of formation gas in oil based fluids. It could be completely dissolved in the mud at a bottom hole temperature and pressure conditions making kick detection very difficult. Depending on the pressure-volume-temperature (PVT) behaviour of the gas-oil mixture, the amount of gas in a well could be underestimated and the well control procedures affected. In the worst situation, an uncontrolled kick can turn into a blowout with all the inherent financial and environmental damage and possible casualties. The study of the PVT properties of the oil based mud is essential for the complete knowledge of the gas-liquid mixture behaviour in kick situation. This includes determination of properties such as bubble point pressure, gas solubility, density of the gas-oil mixture and formation volume factors. These properties can lead to the computation of the amount of dissolved gas in the mud, and the exact depth the gas influx would come out of solution. The thermodynamic model can also be applied to well control computer simulators for personnel training and the study of the best procedures to reduce the associated problems and risk. It is important to emphasize that the thermodynamics properties and determination are inherent of each formation and drilling fluid pair that will be in contact during well control situation. Considering the importance of the subject, the main objective of this work is to present the application of Peng-Robinson equation of state to natural gas behaviour in drilling fluid, and also to predict their PVT behaviour. The developed relationship was applied to illustrate the pit gain calculations. LITERATURE REVIEW In previous work done by Thomas et al. 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. In addition, it was concluded that the damping of surface responses when a gas kick is taken in an oil-based drilling fluid occurs due to gas solubility in the drilling fluid. O’Bryan et al. 4, 8 performed a comprehensive study about the parameters which affect gas solubility in oil based drilling fluids and its effect on kick detection. Their experimental results for the tested fluids showed that gas solubility increases with pressure and decreases with temperature, molecular weight of the oil and the amount of solid, brine and emulsifier in the drilling fluid. Predictions for gas solubility and formation volume factor considering the additivity hypothesis have shown relative differences varying from 1 to 16%. The authors also proposed a methodology for pit gain calculation and showed that it could be 80% less for an oil based mud. Their data are used to validate the present work. Silva et al. 16 studied the mixture of methane – n-paraffin and methane ester at two temperature (160 O F and 190 O F) for pressure up to 7,500 psi. , their result showed a small influence of the temperature on the PVT properties, for the range of temperatures and pressures of the experiments. Methane solubility in the n-paraffin was shown to be greater than in the ester, requiring a greater attention for kick detection and circulation. Ribeiro et al. 23 reported their experiment conducted on synthetic fluid study presenting experimental data for methane (iso+ paraffin mixtures and discussing the well control consequences of the gas-synthetic fluid mixtures. The authors also presented a thermodynamic modeling of the gas-liquid mixture behaviour based on Krichevsky-Kasarnovsky (KK) correction of Henry’s law. Atolini and Robeiro 24 present a comprehensive literature review about the behaviour of the vapour-liquid mixtures at high temperatures and pressures, particularly directed to the well control problem (as in discussion). Based on the foregoing contributions, the understanding of the gas-synthetic drilling fluid interaction, particularly for the case of methane – n-paraffin unweighted emulsion, would be very beneficial for the present well control modeling and practice, which is the main objective of the present work. This paper presents a method that uses an experimentally calibrated EOS 2 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 HYDROCARBON-GAS-DRILLING FLUID INTERACTION DURING The influx fluid (Natural gas) enters the well-bore where it mixes with the fluid phase of the drilling mud and does not saturate that phase . part of the fluid may be miscible with the fluid phase, that is , the sum of the two mixed volumes may not equal the two volumes. The drilling fluid, whether water based, contains opening or intermolecular voids that the influx gas may enter and occupy. There may also be chemical reaction, but this is beyond the scope of this paper. As the under saturated fluid is circulated up the annulus, both pressure and temperature decline until the resultant decrease in solubility allows any gas to break out of solution and manifest itself as a bubble of gas rather than as a fluid dispersed in the molecular voids of a continuous phase. This sudden release of gas at a specific temperature and pressure is referred to as the bubble point and would normally occur if the fluid were already saturated with gas at another temperature and pressure