Şeyl gazı ve petrolü için arama, üretim, rezerv kestirimive araştırma çalışmalarının incelenmesi ve değerlendirilmesi

Shale is a fine-grained sedimentary rock that consists of significant amount of clays, in addition to sand and silt size minerals. During the sedimentation period, depending on the aqueous sedimentation environment, some organic material in the form of the remnants of dead organisms might accumulate along with some inorganic material, such as the organic or inorganic compounds nickel, zinc, vanadium, molybdenum, selenium, etc, among the grains of shale constituents. Shale is formed as the result of compaction of its constituents under the overburden stress (pressure) of overlaying strata that are accumulated later and under the rising temperature with increasing burial depth, throughout the vast geological time periods. During the millions of years of diagenesis, the period in which the sediments go through various physical and chemical alterations and deformations, the in-situ water in between the granules provides the means for the consolidation and cementation of compacting constituents to form a somewhat firm rock of shale, while some part of the in-situ water being expelled out due to compaction. In addition to pressure the increasing temperature and the radiation from the radioactive elements among the constituents cause shale to experience thermal maturity. Contained organic material, if there is any, in shale would eventually be decomposed into hydrocarbons, partially in the form of kerogen and partially in the form of petroleum, until thermal maturity has reached a certain level. Kerogen is the organic material with long and complex molecular chains that was not converted into petroleum. During diagenesis, oil and gas type hydrocarbons may escape out of shale into other adjacent, preferably sedimentary, formations via the pathways, such as pore networks, cracks, fractures, joints, or faults, and form conventional oil and gas reservoirs if they get hydrodynamically trapped. Therefore, shale is a easy-splitting laminated soft rock and such feature makes it different than the rock called mudstone. Economic oil and gas accumulations in shale formations are classified as unconventional reserves, since pore size and permeability levels in such rocks are much below microscopic scale and, hence, the application of conventional production and reserve estimation techniques is invalid. In this study the interest is in the shale formations that contain unconventional reservoirs of oil and gas. A shale formation is considered to have a prospective reservoir if its organic kerogen content is between 2 to 14 percent. The hydrocarbon that can form in shale is determined by the kerogen type and thermal maturity level in shale. Kerogen, as a solid matter, might have pores with size in the range from few nanometers to few hundred nanometers. Production of oil and gas from shale formations was started during the World War II by the U.S.A. to fuel war tanks. After the war, however, it was uneconomical to produce from the shale formations due to unfeasible technology and low price of oil and gas. The adverse effect of significant increase in oil and gas prices, due to Yom Kippur war between Egypt and Israel in 1973, has forced the U.S. to explore new technology for feasable exploitation of oil and gas in shale formations. In the past two decades, many researchers have introduced new and various methods and techniques for classifying shale formations, estimating oil and gas reserves, and drilling, completing, and stimulating wells for producing unconventional shale plays. Substantial investment in research has led to the development and use of horizontal well drilling and hydraulic fracturing technology that has draw a massive interest in the industry and has enormously increased the shale gas and oil production in the U.S., e.g. the U.S. hydrocarbon gas reserves have increased about 35 percent in 2008. Such success has led many countries worldwide to attempt to explore unconventional oil and gas in shale formations in their sedimentary basins. While research is still continuing worldwide for futher improvement in aforementioned methods and techniques to maximize ultimate recovery from shale formations, only Russia and China other than the U.S. had some limited success in shale gas and oil play so far. Among the shale classification methods, real-time classification is based on well logs to estimate the petrophysical, compositional, and elastic properties of shale rocks. Another technique attempts to identify hydrocarbon-bearing shale groups, based on similar compositional properties exhibited on a combination of well logs, and also to minimize the shoulder-bed effects using the inversion of log derived layer properties. Other method integrates core analysis and well log information to classifying shale in terms of porosity, capillary pressure, mineralogy, and TOC. Though, all the methods are found to yield good results, all of them have to be applied on the same formation to ascertain which method is better than the others, since each shale play is unique. Although conventional reserve estimate methods seem not to work in unconventional shale gas and oil reservoirs, a group of researchers tried to use the usual hyperbolic decline curve analysis technique on a production rate versus time plot to estimate the recoverable reserves. They came up with a nine–equation bivariate regression model based on initial test and recovery data to estimate the reserves in the Devonian shale. A new volumetric total-gas-in-place estimation equation that incorporates Langmuir adsorption isotherm was formulated to take the pore space occupied by the sorbed phase into account. Hydrocarbon phase behavior is realized to be quite different in pores and capillaries with characteristic length less than 100 nanometers, since gas density varies under the influence of organic pore walls of kerogen. Interest in drilling and completion of horizontal wells has increased during the last two decades to enhance productivity and ultimate recovery from shale reservoirs. The most commonly used completion method is casing and perforating the horizontal section of wells. In horizontal wells an optimized multi-stage hydraulic fracturing through perforations is the inevitable stimulation technique to create interconnected fracture network for maximizing the flow into wellbore. Various explosive or impact methods of dynamic fracture and fragmentation data on shale rocks has showed that the interaction of transient wave with the local free surfaces in rock generates tension in some regions of rock where fracture and fragmentation is initiated. Studies has also showed that the static strength of a rock can be less than the dynamic fracture strength as much as one order of magnitude. A researcher with the objective of intersecting as many natural fractures as possible with the hydraulic fractures has developed a rationale for stimulation design for the Devonian shale. The MHF (massive hydraulic fracturing) technique has long been used for the same purpose. It has been found that shale thickness and fracture density are important factors in determining the stimulation technology and strategy. A new hydraulic fracturing technique is CHF (channel hydraulic fracturing) that was first applied in Marcellus shale. In CHF technique; which integrates the geomechanical modeling and perforation strategy, fiber-laden fluid is pumped in a unique manner to create high-conductivity stable channels in the proppant pack placed in the created fracture. Hydrocarbon fluids flow through these high conductivity channels rather than being dependent on the permeability within the proppant pack. Appreciable increase in fracture conductivity by these flow channels has been proven in practice. Reliable forecast of production from shale reservoirs has been another requirement in the industry. The methods of analytical simulation, numerical simulation and various decline curve analyses (DCA) have been utilized. Each method has its own particular advantages and disadvantages. Rapidity and extent of accuracy in production forecast are among the factors considered in these methods. Another model, called the Shale Gas Predictive Model (SGPM), was developed with an alternative approach and was proposed to mitigate the challenges associated with shale gas production. Simple and easy to use model focuses essentially on the flow around individual wells while conserving overall mass. The model has the advantage of generating rapid and repetitive results, in situations where quick turnaround is required to estimate the production and reserves from a large number of wells in a single or multiple shale gas plays. Such situations arise frequently if the operating companies plan to drill hundreds of wells year by year on the millions of acres of land. The model can be run in conjunction with a fracture mechanics software for better fracture design. Production forecasting capability of the model was validated against the actual production from various shale gas plays in different regions. Thus, the model can be reliably used for both matching the past production history and the future production forecast. Oil-rich play and multi-phase flow features of the model provides insight to the condensate production. However, the inaccuracies in recovery prediction are highlighted if the presence of condensate is not considered. When the development of Eagle Ford shale in South Texas was started in 2008, there was not any data analysis available on the production from this shale at that time. Linear dual-porosity type-curve analysis technique was employed for modelling the production behavior and for estimating the essential reservoir parameters. The type curves used were constructed based on the transient production rate at constant well pressure and closed-boundary double-porosity stimulated reservoir volume (SRV.) Two different approaches of Bello-and-Nobakht method were employed to account for apparent skin in analyzing the early-time and the late-time production data. The production from Eagle Ford shale exhibited linear flow, bilinear flow, and boundary dominated flow regimes. Based on bilinear flow analysis and the assumption of slab-type fracture model, the fracture permeability was estimated to be about 820 nano Darcy. On the other hand, the matrix permeability was estimated to be in the range of 181 to 255 nano Darcy, based on linear matrix flow analysis. The results were validated by means of numerical simulation, due to the fact that the permeability values obtained from the numerical simulation study were in the range of agreement with those obtained from the type curve analysis. In order to carry out production forecasting for Eagle Ford shale different adsorption isotherms were used. It was deduced from the results of production forecasting that the gas desorption depends on both the reservoir pressure and adsorption isotherm. The gas desorption in early times, when the reservoir pressure is high, was found to be usually not that important. However, based on the laboratory measured adsorption isotherms, long-term production forecasting is needed for desorption to be effective. A genesis of decline curves with the use of a simple hydrodynamic analogy was also provided. Some physical factors that are critical to well productivity were also examined, based on several studies on production decline curves. It was observed that an exponential or hyperbolic decline curve would adequately fit the production decline data for the wells producing from Devonian Shale. An attempt has also been made to characterize the production decline based on open flow, rock pressure, and specific shale production mechanisms. An analytical tri-linear-flow solution was presented to simulate the transient pressure behavior and production behavior in fractured horizontal wells in unconventional shale reservoirs. Though the model is simple, it is versatile enough to incorporate the fundamental petrophysical characteristics including the intrinsic properties of both matrix and natural fractures of a shale reservoir. Various reservoir components in addition to the special characteristics of fluid exchange may also be considered. A practical analytical model is presented and discussed in this study for the analysis of pressure transient responses in multiple fractured horizontal wells in unconventional shale reservoirs. Oil and gas production from unconventional shale reserves in the U.S. has become feasible both technically and economically, after the remarkable rise of oil and gas prices. Among the mature shale plays in the U.S., and in the World, Barnett shale near Forth Worth, Texas, is the one for which there is satisfactory production history. Therefore, the examination of the economics of exploitation of Barnett shale, as the field had been developed with more than 6000 producing wells, can be considered as the role model for establishing an idea of how shale plays can become commercial. For the costs and prices during this thesis work is conducted, an ultimate recovery of about 550 to 900 million standard cubic feet of gas has to be produced to pay out for one well. In oil production from shales, for a mature field with 100 000 barrels per day oil production the minimum oil price should be at least 43 USD per barrel.