The offshore Sierra Leone basin is an exploration frontier area with commercial hydrocarbon potential. The basin is located at the northernmost end of the equatorial Atlantic margin in the South Atlantic; it is bound to the South by the Gulf of Guinea Petroleum province. The Sierra Leone margin has not had the exploration attention like most basins in the equatorial Atlantic, such lack of attention may be explained by the structural complexity of the basin. Despite the recent successful petroleum activities in the basin, very little geological information have been placed in the public domain by the operators. This research will be the first published detailed analysis of the offshore Sierra Leone basin. This work focuses on the broader aspects of basin structural evolution, seismic stratigraphy and reservoir development. The basin analysis is based on 2D seismic dataset, acquired in 2002 by TGS-NPEC. Seven megasequence boundaries have been identified in the offshore Sierra Leone basin. There is one megasequence boundary each in the pre-transform and syn-transform phases. The post-transform phase is composed of five megasequences. They have been dated using well data information and through correlation with the seismic surfaces of adjacent basins in the region. The Sierra Leone margin is structurally divided into three segments, which evolved through transtensional and/or extensional rifting. From a geological perspective, this basin straddles a major tectonic transition zone (the Sierra Leone Transform). The Mesozoic-Cenozoic tectonic evolution of the basin was partly controlled by basement heterogeneity and plate kinematics. This study also highlights the importance of N-S and ENE-WSW trending Archaean structural lineaments, which were vectors for the Sierra Leone margin segmentation. The structural division of the Sierra Leone margin into the Northern, Central andSouthern segments is based on varying structural geometries. The Northern and Central segments developed as rift-transform margins, while the Southern segment developed as a volcanic rifted margin. Syn-transform sequences (late Early Cretaceous) show the influence of normal fault related subsidence and uplift, modified by localised transpressional deformation. The basin bounding faults and half grabens are oriented at high angles to the ensuing passive margin slope strike. Post-transform sequences (Late Cretaceous to Present) are dominated by major phases of slope failure and the development of extensive lowstand submarine fan systems. Some models of slope failure and synchronous development of submarine channel and canyon systems have been developed for this basin. Extensional slope failure is controlled by pre-existing structural trends. Submarine canyons which developed in the hanging-walls of these fault-blocks, became the site of rapid head-ward expansion of turbidite filled channels. The temporal development of these systems are expected to have profoundly affected the distribution and quality of key play elements, such as reservoirs and stratigraphic traps in slope settings, and the distribution of sands in deeper water and base of slope plays.

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Shale gas reservoirs have become a major source of energy in recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these reservoirs comes from desorption. Ignoring a major component of production, such as desorption, could result in significant errors in analysis of these wells. Therefore it is important to understand the adsorption phenomenon and to include its effect in order to avoid erroneous analysis. The objective of this work was to imbed the adsorbed gas in the techniques used previously for the analysis of tight gas reservoirs. Most of the desorption from shale gas reservoirs takes place in later time when there is considerable depletion of free gas and the well is undergoing boundary dominated flow (BDF). For that matter BDF methods, to estimate original gas in place (OGIP), that are presented in previous literature are reviewed to include adsorbed gas in them. More over end of the transient time data can also be used to estimate OGIP. Kings modified z* and Bumb and McKee’s adsorption compressibility factor for adsorbed gas are used in this work to include adsorption in the BDF and end of transient time methods. Employing a mass balance, including adsorbed gas, and the productivity index equation for BDF, a procedure is presented to analyze the decline trend when adsorbed gas is included. This procedure was programmed in EXCEL VBA named as shale gas PSS with adsorption (SGPA). SGPA is used for field data analysis to show the contribution of adsorbed gas during the life of the well and to apply the BDF methods to estimate OGIP with and without adsorbed gas. The estimated OGIP’s were than used to forecast future performance of wells with and without adsorption. OGIP estimation methods when applied on field data from selected wells showed that inclusion of adsorbed gas resulted in approximately 30 percent increase in OGIP estimates and 17 percent decrease in recovery factor (RF) estimates. This work also demonstrates that including adsorbed gas results in approximately 5percent less stimulated reservoir volume estimate.