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Introduction:Drilling fluid selection plays a key role in preventing major problems encountered during drilling operations such as hole pack-off, stuck pipe and loss circulation. Mud contamination which results from the overtreatment of the mud system with additives or foreign material entering the mud system during drilling operations causes unwanted changes in the properties of the mud. This makes the mud system inefficient in performing its major roles. This research studies the effects of monovalent and divalent salts namely Potassium Chloride, Calcium Chloride, and Magnesium Chloride on the rheological properties of water-based mud system which is most vulnerable to contamination.Methods:Sixteen mud samples were formulated of which fifteen were contaminated each with different concentrations (0.75 g, 1.50 g, 2.50 g, 3.50 g, and 5.0 g) of the various salts at ambient temperature.Results:The results showed that the rheological properties such as plastic viscosity, apparent viscosity and yield point of the mud samples decreased as the concentrations of various salts increase.Conclusion:It was concluded that increase in the concentration of the salts resulted in a decrease in the rheological properties of the mud samples. This indicates that with the monovalent and divalent salt contamination, there is a significant decline in the performance of drilling mud since the salts affect the dispersion, hydration and flocculation behaviour of the particles. The effect was more profound with CaCl2 and MgCl2 salts than the KCl salt.

Predicting pressure distribution in a petroleum reservoir is principal to the reservoir's evaluation and maintenance, as pressure changes with space and time. A convenient approach to effectively achieve this task is to formulate fluid flow equations based on the reservoir characteristics and solve them numerically. Numerical method provides solutions to mathematical fluid flow models developed in a reservoir simulation. This study provides numerical solutions, using both finite difference explicit and implicit method, to a mathematical model by developing MATLAB codes to ascertain the pressure distribution for a singlephase, one-dimensional, slightly compressible fluid flow in a petroleum reservoir. Series of numerical simulations were carried out during the first year of production using timestep sizes of 1, 2 and 3 days, respectively. The explicit method gave poor result (negative values for pressures) for timestep of 1 day, an outcome that is not accurate to describe the problem being solved but gave acceptable pressure results for timestep of 2 and 3 days. This shows that the efficacy of the explicit method is reliant on the chosen timestep and simulation time. In contrast, the implicit method gave a quite satisfactory results for all timesteps, and including less than 1 day, confirming the robustness and unconditionally stable nature of the implicit method. A commercial simulator (CMG software) was also employed to build a one-dimensional black oil model to validate the aforesaid results of which a close match was observed between the simulator results and the numerical solutions. This study provides insights to reservoir's pressure profile during hydrocarbon recovery beforehand so that efficient pressure maintenance decisions can be made to achieve economic hydrocarbon recovery throughout the life of the reservoir.

Oil production by natural energy of the reservoir is usually the first choice for oil reservoir development. Conversely, to effectively develop tight oil reservoir is challenging due to its ultra-low formation permeability. A novel platform for experimental investigation of oil recovery from tight sandstone oil reservoirs by pressure depletion has been proposed in this paper. A series of experiments were conducted to evaluate the effects of pressure depletion degree, pressure depletion rate, reservoir temperature, overburden pressure, formation pressure coefficient and crude oil properties on oil recovery by reservoir pressure depletion. In addition, the characteristics of pressure propagation during the reservoir depletion process were monitored and studied. The experimental results showed that oil recovery factor positively correlated with pressure depletion degree when reservoir pressure was above the bubble point pressure. Moreover, equal pressure depletion degree led to the same oil recovery factor regardless of different pressure depletion rate. However, it was noticed that faster pressure drop resulted in a higher oil recovery rate. For oil reservoir without dissolved gas (dead oil), oil recovery was 2–3% due to the limited reservoir natural energy. In contrast, depletion from live oil reservoir resulted in an increased recovery rate ranging from 11% to 18% due to the presence of dissolved gas. This is attributed to the fact that when reservoir pressure drops below the bubble point pressure, the dissolved gas expands and pushes the oil out of the rock pore spaces which significantly improves the oil recovery. From the pressure propagation curve, the reason for improved oil recovery is that when the reservoir pressure is lower than the bubble point pressure, the dissolved gas constantly separates and provides additional pressure gradient to displace oil. The present study will help engineers to have a better understanding of the drive mechanisms and influencing factors that affect development of tight oil reservoirs, especially for predicting oil recovery by reservoir pressure depletion.

The increasing exploration and production activities in the offshore Cape Three Point Blocks of Ghana have led to the discovery and development of gas condensate fields in addition to the oil fields which produce significant amount of condensate gas. These discoveries require pipelines to transport the fluids avoiding hydrates and wax formation. This paper focuses on subsea pipeline design using Pipesim software that addresses flow assurance problems associated with transporting condensate gas from the Jubilee and TEN Fields to the Atuabo Gas Processing Plant. It also considered an alternate design that eliminates the need for capacity increase of flowlines for the futuristic highest projected flow rates in 2030. The design comprises of two risers and two flowlines. Hydrate formation temperature was determined to be 72.5 ˚F at a pressure of 3 000 psig. The insulation thickness for flowlines 1 and 2 were determined to be 1.5 in. and 2 in. respectively. The pipe size for flowlines 1 and 2 were determined to be 12 in. and 14 in. respectively. The maximum designed flow rate was determined to be 150 MMSCFD. To meet the highest projected flow rate of 700 MMSCFD in the year 2030 at the processing plant, a 16 in. ID pipeline of 44 km length was placed parallel to the 12 in. ID flowline 1. This parallel pipeline increased the designed flow rate by approximately 4.7 times (705 MMSCFD). The alternate design employs 18 in. and 20 in. ID pipes for flowlines 1 and 2 respectively. Keywords: Condensate Gas; Flowline; Flow Assurance; Hydrate; Pipesim