Unconventional gas reservoirs represent a long-term global source of natural gas. Hydraulic fracturing combined with horizontal drilling has turned unproductive unconventional gas reservoirs into the largest natural gas fields in the world. At the early time of production, due to lack of needed variables, using numerical models is challenging, time consuming, and expensive. Production type curves are a dependable tool for predicting the performance of gas reservoirs. The goal of this research was to develop a simple and reliable tool to predict the performance of the production of hydraulically fractured horizontal wells in unconventional gas reservoirs. A set of production type curves were developed. Two set of type curves were developed using the reservoir model. They represent the two flow regimes associated with the horizontal wells, the early time liner flow and the late time pseudo-radial (elliptical) flow. The dimensionless well length and the ratio of well length to reservoir length were found to influence the type curves significantly. The impact of some of the reservoir parameters was reviewed. Drainage area, horizontal permeability, and vertical permeability were found not to impact type curves extensively. Reservoir thickness has a minor effect on type curves. Reservoir porosity has no effect on early production but significant effect on late production. In addition to the reservoir parameters, a range of hydraulic fracture parameters was studied. Number of hydraulic fractures was found to have impact on type curves particularly with very low permeability. Fracture half length, fracture permeability, and fracture width were found to have no major affect on type curves. iii ACKNOWLEDGEMENTS This research project would not have been possible without the support of many people. My heartfelt gratitude goes out to my academic advisor Dr. Kashy Aminian, who is responsible for the successful completion of my research. His untiring effort, commitment, encouragement, guidance and support helped me greatly in the understanding and writing of the research. I would like to gratefully acknowledge the members of the committee, Prof. Sam Amiri and Dr. Ilkin Bilgesu. Without whose knowledge and assistance this study would not have been successful. I would like to express my special thanks to the staff of the petroleum and natural gas department. I really appreciate the help and support of my colleagues and friends who have gladly helped me out during my study at West Virginia University. My deepest appreciation goes to my mother, Moneerah, for her unflagging love and support throughout my life. I can't thank you enough for the tremendous love and care that you always have given me. Finally, I would like to dedicate my thesis to my family members. Thank you for your help, encouragements, motivation and endless love during my life. iv

In wireline formation testing and sampling, a difficult and long standing challenge is the differentiation between mud filtrate and formation fluids, especially in oil-based mud (OBM) (diesel/water mixture) and multiphase formation fluids (oil/formation water) environments. This challenge can cause ambiguities during the interpretation of downhole fluid properties and determination of the contamination levels before sampling.Often, during the sampling process, fluid mixing increases fluid property sensor noise and causes difficulties with accurate fluid identification and contamination levels. Consequently, noisy sensor readings are attributed to the transitional phase of sampling and pertinent information is ignored.This paper presents several examples where fluid mixing has occurred. A high-resolution volumetric densitometer is used to accurately identify fluid properties. It monitors the change of frequency of a vibrating tube immersed in the fluid sample.Because of the high accuracy of this technique, it is also possible to determine additional fluid properties, such as density, water salinity, and fluid compressibility. Furthermore, new processing methods are illustrated, which provide a clearer understanding of flow behavior and allow more accurate estimates of fluid contamination. The examples are verified using fluid volumetrically maintained at the reservoir pressure and temperature (PVT) lab results comparing the downhole real-time fluid property measurements and interpretation with the actual fluid samples recovered.

Spectral gamma-ray (SGR) data were acquired from a new slim logging-while-drilling (LWD) tool and from surface cuttings in a near vertical well and in a horizontal well across clastic deposits. Comparison of the data from both measurements indicates that there are advantages from both methods. X-ray diffraction (XRD) and X-ray fluorescence (XRF) data from cuttings also support the findings. The formation evaluation objective is to quantify the volumes of each mineral and fluid present in the formation. SGR data brings the required additional information to reduce the mineral volume uncertainty, especially for the clays in the formation with complex mineral assemblages. In the studied clastic deposits, several clay types are present (with the dominant contribution from illite and kaolinite) together with feldspars and trace elements like zircon and other heavy minerals. The presence of gas introduces another unknown, since it affects the porosity measurements and fluid volume calculation through bulk density and neutron porosity. The comparison of SGR data from LWD logs and from cuttings brings robustness to our conclusions. Comparison of the thorium, potassium, and uranium concentrations from LWD logs and from cuttings shows good agreement in the measurements for the low-angle well. The high-angle well data also shows good agreement between the two measurements except for the cleaner sand section. The results from the cuttings are affected by the accuracy of sample depth control due to the poor borehole conditions and inefficiency in evacuating cuttings in high-angle wells compared to low-angle wells. The trend of the SGR is maintained. The LWD SGR elemental concentrations are then used to solve the formation mineral fractions, which are compared with the same fractions from the XRD on cuttings. Similar conclusions are drawn for the elemental concentrations. The potassium concentration enables the quantification of illite and potassium feldspar. Uranium brings a significant contribution to the total GR measurement, which could lead to a clay volume overestimation if the uranium contributions weren’t excluded. In conclusion, LWD provides superior quality SGR data compared with SGR from cuttings because of the better depth control and vertical resolution. SGR on cuttings can be an alternative when combined with other LWD measurements and accepting a higher uncertainty, in case LWD SGR cannot be run due to certain borehole conditions. This paper compares the results of a slim tool LWD and cuttings SGR data for the first time and concludes on the applicability of each technique.

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