A continuous growth in the global economy and population requires a sustainable energy supply. Maximizing recovery factor out of the naturally occurring hydrocarbons resources has been an active area of continuous development to meet the globally increasing demand for energy. Coalbed methane (CBM), which is one of the primary resources of natural gas, associates complex storage mechanisms and requires some advanced recovery techniques, rendering conventional reserve assessment methods insufficient. This work presents a literature review on CBM in different aspects. This includes rock characteristics such as porosity, permeability, adsorption capacity, adsorption isotherm, and coal classification. In addition, CBM reservoirs are compared to conventional reservoirs in terms of reservoir quality, reservoir properties, accumulation, and water/gas saturation and production. Different topics that contribute to the production of CBM reservoirs are also discussed. This includes production mechanisms, well spacing, well completion, and petrophysical interpretations. The main part of this work sheds a light on the available techniques to determine initial-gas-in-place in CBM reservoirs such as volumetric, decline curve, and material balance. It also presents the pros and cons of each technique. Lastly, common development and economic challenges in CBM fields are listed in addition to environmental concerns.

Reservoir fluid properties play a crucial role in the upstream field development cycle. Petroleum engineers extensively utilize Pressure-Volume-Temperature (PVT) studies in applications such as calculations of pipelines’ pressure drop, and assessment of Enhanced Oil Recovery (EOR) strategies. These studies are generated from a series of lab experiments conducted on reservoir fluid samples in high pressure-high temperature (HPHT) lab environments, and commonly matched using Equation of State (EOS) software. Feeding and characterizing the composition of a reservoir fluid in a PVT software play a central role towards understanding its behavior. These steps are heavily affected by the last carbon number measured and the lumping scheme used in the simulator. This paper investigates the application of splitting the plus fraction, and utilizing Saturates, Asphaltenes, Resins and Aromatics (SARA) analysis in enhancing viscosity prediction at atmospheric conditions. In this study, three oil samples from fields with suspected flow assurance issues were selected. A fingerprint study was first conducted on all samples to ensure that they are representative of the original reservoir fluid, and free of any drilling fluid contaminants. The methodology used in this study is based on conducting compositional analysis and viscosity test on the selected samples. Furthermore, SARA analysis was conducted to enhance the characterization of reservoir fluid, and confirm asphaltene presence. Lastly, splitting technique and SARA-based lumping scheme were used to predict viscosity values at atmospheric pressure and were compared to experimental data. The results of this work demonstrated the effectiveness of SARA-based lumping scheme on atmospheric viscosity prediction, which captured the plus fraction concentrated in the dead oil without compromising the computational time. Furthermore, the EOS software used studied the sensitivity of the simulation results to different compositions.

An acquisition of representative reservoir fluid samples is important for reservoir management and development. During overbalanced drilling, the high hydrostatic pressure causes mud filtrate invasion into the reservoir. This makes the process of acquiring representative reservoir fluid samples challenging due to the miscibility of Oil-Based Mud (OBM) filtrate with the reservoir fluid. The presence of OBM filtrate impacts the characterization of the reservoir fluid, resulting in inaccurate and not representative PVT laboratory measurements. PVT data generated out of contaminated samples should be avoided as they have the potential of harming field development plans. In this study, OBM level in contaminated samples was quantified and their compositions were restored through skimming and subtraction techniques. Consequently, the key fluid properties of the decontaminated fluid were successfully predicted through an Equation of State (EOS) software. The results demonstrated the impact of OBM filtrate on bubble point pressure and heavy-end properties, as concluded by the EOS modelling software, which compared the phase behavior properties of the contaminated and decontaminated fluids. Subsequently, modeled properties like Formation Volume Factor (Bo), Gas-Oil Ratio (GOR), API gravity, and mixture density were all compared to the measured fluid properties of clean fluids. Additionally, the capability and robustness of each decontamination methods were confirmed against the measured original clean composition.

The presence of crude oil/water emulsions is a burden in the petroleum industry. It leads to several operational and economic issues related to crude production, transportation, and refining processes. The stability of the emulsified oil is affected by water content, presence of organic/inorganic materials, formation brine salinity, and temperature. In reservoir fluid studies, applying chemical demulsifiers on emulsion samples is common to break the emulsion and reduce the water content to an acceptable level (less than 1 wt. %) to generate representative fluid composition results. However, this process depends heavily on the crude and the water compositions and the type of demulsifier used. An incompatible choice of demulsifier could strengthen the emulsion's stability or alter the fluid composition. This introduces the need to understand specific physiochemical properties to identify the root causes of demulsifier ineffectiveness. In this study, two demulsifiers containing different functional groups (Type 1 and Type 2) were evaluated for their emulsion breakage ability. Nine oil samples from various fields were mixed with formation water in the first round and seawater in the second. The water-oil ratio of 80:20 was achieved using a blender for 1.5 minutes at 300 RPM. Saturates, Aromatics, Resins, and Asphaltene (SARA), viscosity, density, and sulfur content were determined for all oil samples. Furthermore, chemical analysis was conducted on all water samples to determine Total Dissolved Solids (TDS). After applying both demulsifiers at the same concentration (1% of total volume), separated water volumes were measured at 5, 10, 15, and 20 minutes and used to calculate the emulsion separation index (ESI). Results of this work showed that Type 1 demulsifier performed better than Type 2 in the formation water and seawater and while using different oils due to the resistance of the non-ionic surfactant to salinity, polarity, and water hardness. This study shows a methodology for effectively determining the optimum chemical demulsifier type to break emulsions by adequately understanding the chemistry of the oil, brine, resulting emulsions, and demulsifiers used.