through shale rock makes the movement of crude oil an energy intensive process, resulting in the rapid decline of the production rate. After five years of production, the oil rate is less than 20 % of the original production rate in most cases (Maugeri 2013, Hughes 2013). To compensate the decline and sustain production, or to increase it, operators must continuously drill and fracture new wells, resulting in the existence of tens of thousands of wells in the main unconventional plays in the US. Primary production in organicrichshalereservoirs also leads to low expected ultimate recovery. The estimates vary widely, ranging from less than 2 % to almost 16% of the original oil in place (OOIP), depending on the methods used, and whether the set of wells taken for the assessment were located inside of a sweet spot or not. In most cases, the expected recovery factor is approximately 8 % (Delaihdem 2013, Dechongkit and Prasad 2011, Bohrer et al. 2008, Clark 2009). This means that by the time oil production declines to a level at which it is no longer economical to maintain the well active, the reservoir will still contain more than 90 % of its OOIP. The presence of a large volume of remaining oil in developed oilfields with thousands of wells and existing infrastructure represents an opportunity for additional profit when complemented with the expected increase of 30% to 50% in the energy demand worldwide during the next two decades, driven by global population growth and the industrialization of countries with developing economies. Although renewables are projected to increase their share of the global energy market during that period, oil and gas are predicted to hold around 70% of the energy market and 60% of the total investment in energy, primarily supported by the limited alternatives for freight, air transportation, and by the petrochemical industry (EIA 2016, IEA 2016, BP 2016).
Microscopic oil displacement of water flooding and sweep efficiency of continuous gasinjection could be improved by water alternating gas (WAG) injection. The WAG injection process aims to squeeze more oil out of the reservoirs; in this method, water and gas are alternatively injected into the reservoir. Also, availability of hydrocarbon or CO 2 gases in the field makes it attractive for gas-based enhancedoilrecovery (EOR) methods such as water alternating gas (WAG) injection. Conducting some simulations are required to optimize EOR methods for investigating the effect of parameters affecting WAG injection. Reducing and controlling the mobility ratio, creating stable front, and preventing early fingering of gas are the advantages of water alternating gasinjection, which have promoted extensive applications throughout the world. Critical parameters, including WAG ratio, injection rates, gas composition variation, cycle times and some others which affect the WAG injection as an enhancedoilrecovery method are studied thoroughly in this paper. Because of higher mobility of water relative to gas, injected water has more efficiency, but the excess use of water will cause early breakthrough. This study suggests that injecting proper volume at suitable times with different rates during injection time provides a 10 -15 % improvement in the recovery factor for one pore volume which is injected by using commercial reservoir simulator ECLIPSE 300. The best rate variation during a cycle time of WAG injection and choosing of first injection phase are discussed in this paper.
Methods of improved oilrecovery processes are classifiable into two groups: secondary production methods and enhancedoilrecovery (EOR) methods. Secondary production methods are based on fluid injection, and they are targeted at providing further energy in order to augment or sustain the production level once well rates de- cline during primary recovery. Such processes include both water flooding and natural gasinjection. Since a considerable amount of oil is left after primary and secondary production methods, the ideal goal of enhancedoilrecovery processes is to mobilize the “residual” oil throughout the entire reservoir. This can be achieved by enhancing microscopic oil displacement and volumetric sweep efficiencies. Oil displacement efficiency can be increased by decreasing oil viscosity using thermal floods or by reducing capillary forces or interfacial tension with chemical floods. Processes here consist of all methods that use external sources of energy and/or materials to recover oil that cannot be produced economically by conventional means; they are broadly classified as ther- mal (steam flooding, hot water flooding, and in situ combustion) and non-thermal (chemical flood, miscible flood, and gas drive). Alternatively, enhancedoilrecovery methods are called tertiary oilrecovery processes.
Water alternating gasinjection (WAG): Water Alternating Gas (WAG) is a process of injecting water followed by gas, followed by more water, followed by more gas, etc. The gas mixes with the water ahead of it, which causes a reduction in gas mobility. This mixture is effective in displacing oil to the production well, since the macroscopic sweep efficiency is larger than for gasinjection only while microscopic efficiency is still high. This is why WAG can improve recovery factor . Water Alternating Gas (WAG) injection is a combination of two conventional EOR techniques; water flooding and gasinjection. In 1957, it was very first time applied on North Pembina field in Alberta, Canada by Mobil. The WAG was adopted by keeping this point of consideration into the mind that the traditional gas and water floods usually leave at least 20- 50% of the residual oil in place. From the laboratory analysis it was calculated that simultaneous water/gasinjection could have sweep efficiency up to 90% and only gas alone results in about 60%. But later on this fact came in front that simultaneous injection of gas and water is impractical because of Mobility instabilities, then after alternate injection method of gas and water (WAG) was adopted. Also it was found to be quite economical. The initial proposed ratio of water and gas was 0.5:4 in frequencies of 0.1 to 2% Pore Volume slugs of each fluid that was being adopted according to the reservoir conditions . Miscible WAG injection has been implemented successfully in a number of fields around the world . In principle, it combines the benefits of miscible gasinjection and water flooding by injecting the two fluids either simultaneously or alternatively . A balance between amounts of injected water and gas must be achieved. Too much gas will lead to viscous fingering and gravity override of the gas, whereas too much water could lead to the trapping of reservoir oil by the water. The addition of foam- generating substances to the brine phase has been suggested as a way to aid in reducing the mobility of the gas phase.
In order to utilize non-dominated ranking multi-objective optimization method, we defined two objective functions for oil production value. We selected these objectives independent of theorem economy (technical function) and there was no need for scaling in contrast to single-objective method. The objectives were optimized independent of price fluctuations. In other words, the objectives were directly optimized in contrast to single-objective method where they are opti- mized indirectly (by help of net present value). The corresponding control pa- rameters are shown in Tables 2-7. In this approach, the optimized gasinjection Table 1. Characteristics of single-objective and multi-objective genetic algorithm used for optimizing continuous CO 2 injection process.
Unlike conventional gasreservoirs such as sandstone etc., shale formations have very low to ultra-low per- meability. Moreover, shale has neighbored the conventional sandstone and carbonate reservoirs that are another reason for considering them as source rock. These shales are considered the source of conventional hydrocarbon accumulations that were migrated upward to accumulate and become trapped in a producible formation below a seal, shale. The organic-matter-rich shales produce uneconomically at usually small amounts of hydrocarbons (gas or oil) through biogenic or thermogenic processes, which is occurred at high pressures through natural fractures and stored in a very low porous reservoir rocks. However, for source shale to offer at commercial value, the quantity of the extracted hydrocarbons was only very low, and a significant amount of hydrocarbon is kept, usually in the form of methane in the matrix pore spaces, pre-existing fractures, and as adsorbed gas onto clay minerals and organic matter, kerogen.
The investigation of CO 2 huff-n-puff applicability to the enhancedrecovery of light oil began in 1984. It accounts for nearly 60 percent of EOR production in the United States. Cyclic injection could be the good EOR option for small or discontinuous reservoirs because the single-well process does not demand well-to-well displacement. The application of huff and puff process has been tested as a means of implementing variety of enhancedoilrecovery processes such as CO 2 and hydrocarbon solvent injection in conventional oilreservoirs. Huff and puff process improves oilrecovery through oil swelling, hydrocarbon extraction, viscosity reduction, and relative permeability effects [1, 2]. Information on the performance of CO 2 huff-n-puff in these conditions is provided in a laboratory core flood study, case histories, field-test evaluations, and a numerical simulation. Tang et al.  used gas huff-n-puff in a case study in Sudan, in which they found the production rate could be optimized using a nodal analysis. Rubin  simulated non-Darcy flow in stimulated fractured shalereservoirs. Wan et al.  first evaluated the huff and puff process in a shaleoil reservoir using the Rubin’s simulation method to set the fracture in the numerical model. He found out that huff-n-puff could increase shaleoilrecovery by 29% more than the primary gas flooding method. Sheng and Chen  also performed a comparison study to compare huff-n-puff with gas flooding. They found out that lower bottom-hole pressure leads to a relative higher oilrecovery. Yu et al. [7, 8] also built a fracture model to simulate CO 2 huff-n-puff in Bakken tight oilreservoirs. They compared the CO 2 flooding in two horizontal wells
Hydrocarbon accumulations in petroleum reservoirs around the world migrated from very fine- grained, dark-gray or black organic-rich sedimentary source rocks, referred to as organic-rich shales. For decades, organic-richshale formations have been regarded as source rocks from which hydrocarbons originated and migrated into sandstone and limestone of various reservoir qualities. Oil- and gas-prone shales form when massive amounts of organic debris deposition occur in swamps, lakes, marine environments, followed by rapid burial without decay (Passey et al., 2010). Subsequently, over geologic time, these organic constituents convert into hydrocarbons under the effect of temperature and pressure changes in the subsurface due to burial. Thus, these organic-rich shales undergo the necessary geologic processes from diagenesis to catagenesis to convert dead organic contents into useful hydrocarbons. The Eagle Ford Shale, located within the Maverick Basin in south Texas, is a perfect example of organic-richshale, and it is a world-class source rock for a number of conventional petroleum systems such as the Austin Chalk and the East Texas oilfields (Sondhi, 2011). The geochemical evidence of Eagle Ford Shale sourcing the Austin Chalk is the presence of similar kerogen type II found in both reservoirs (Martin et al., 2011). The Eagle Ford Shaleoil, however, is generated from kerogen type I, I/II and III, which implies that the overall hydrocarbon composition of the Eagle Ford Shale and Austin Chalk may be significantly different.
The oil and natural gas that is formed in the rock exists in the pore space of the rock formations. Pore space is the open area between the solid grains of material that make up the rock. For example, when water is poured on a piece of sandstone, it is absorbed by the stone–it is flowing into the pore spaces which exist between the sand grains that make up the sandstone rock. The measure of the open space in the rock is called porosity. How well the pore spaces are interconnected determines how quickly and effectively fluids flow through the rock. The measure of this interconnectedness is called permeability. In nature, oil and gas flow from the original rock formation in which they were created (source rock) until it reaches a rock formation with very low permeability. Then the oil and natural gas are trapped. It is the oil and natural gas in these traps that have enabled economic development of oil and natural gas resources for the last 150 years. Just as oil and gas have been trapped beneath caprock for millennia, the injected CO 2 from the EOR process will also be trapped by the same geologic mechanism for millennia. For purposes of CO 2 EOR, this paper focuses on these types of oilreservoirs. However, new technology has enabled production from the source rock itself in the case of shaleoil and gas developments over the past 10 years.
The areal sweep efficiency also seems to increase marginally with pore volume of water injected after breakthrough. This explains why oil keeps on trickling from the heavy oilreservoirs during water flooding. At extremely adverse mobility ratio of more than 50, the areal sweep efficiency approaches only to about 50%, if the water injected is equal to 1.5 PV and gain corresponding to 1.5 PV injected volume seems to peter out and appears to approach to the one corresponding to 1.0 PV injection. This indicates that from highly viscous oilreservoirs, recovery will not increase appreciably with increase in the volume of water injected. The curve also shows that at extreme mobility ratios, i.e. at lower than unity and more than 100; the difference in areal sweep efficiency corresponding to 1.0 PV and 1.5 PV water injections is negligibly small. Notable difference between the two areal sweep efficiencies is found in the intermediate range of mobility ratio i.e. 1 to 10.
In brief, these EnhancedOilRecovery strategies tend to recover additional oil from reservoir by varied mechanisms such as IFT reduction, wettablility alteration, mobility management, modification of physical properties and gravity evacuation. However, it can also be seen from Figure 1, that every one of these conventional EnhancedOilRecovery processes face some damages, and losses of chemicals. Therefore, more cost-effective, additional economical, and vital challenges. For instance, for gas strategies, the injected gas usually quickly penetrates through reservoirs from injection wells to production wells, leading to an oversized quantity of residual crude oil remaining uncovered in reservoirs due to the high mobility magnitude relation of injected gas and oil. Moreover, chemical processes are usually restricted by the high price of chemicals, possible formation damages, and losses of chemicals. Therefore, more cost-effective, additionally efficient, and environmentally friendly EnhancedOilRecovery strategies are greatly required. Nanoparticles (NPs) provide novel pathways to handle the unresolved challenges. NPs are outlined as particles with size ranges from 1 nm to 100 nm and show some helpful characteristics as EnhancedOilRecovery agents when put next to the offered injection fluids employed in the conventional EnhancedOilRecovery processes like gas, water and chemicals:
The selection of a test sample depends on the availability and purpose of the tests. It is expected that under ideal conditions, correctly preserved shale core samples would give accurate results though such samples may not be readily available due to high cost of acquiring them. Shale cuttings taken from drilled formations can also be used for some tests. (Friedheim et al 2011). The core samples used in this study are from the Marcellus shale of the Middle Devonian-age, found in Pennsylvania, New York, Ohio and West of Virginia. It is a black, low density carbonaceous (organic) richshale. The Marcellus formation extends more than 34,000,000 acres of real estate with at least 50 feet formation thickness which could contain 500 Tcf gas in place with estimates of recoverable gas at 50Tcf. (Belvalkar and Oyewole 2010). Like any other shale, the Marcellus has low permeability. Agbaji et al. (2009) pointed out that Marcellus has favourable mineralogy, because it is a lower- density rock with more porosity, which has the potential of been filled with more free gas. Agbaji, further noted stated that Marcellus formation is variable in depth, while some outcrops, appears at the surface in some areas of New York, majority is more than a mile deep and in some areas extends 9,000 feet below the surface.
Sultani OS is a calcareous organic-rich sedimentary rock and not true shale, consisting of very fine-grained matrix; it shows rippled micro-laminated texture and muddy ma- terial of cryptocrystalline micrite. The rock is rich in Cretaceous microfossils filled with OM. The filling OM is bitumen of the migrabitumen type. The geochemistry of major oxides and trace elements suggests high levels of OM production. The OM content reaches up to 17 wt.% with high oil-yielding capacity (up to 12 wt.%). High TOC values of Sultani OS suggest that this is an excellent source rock. Vitrnite reflectance (mean Rr oil = 0.85%) is not a reliable parameter to assess the true thermal maturity of this OS
When the material balance equation is used, the additional assumption about the pressure and uniformity equilibrium between the different reservoirs layers with different permeability drained at the same time of the system of production wells is made. For determining pressure via material balance equation at any time, depending on the production rate, it is assumed that production is uniformly made throughout the entire area according to the distribution of reserves. This assumption would only be possible if the formation is completely homogeneous, and wells are placed uniformly in the field area and production is performed simultaneously in accordance with the drained reserves.
A multi-fractured horizontal well (MFHW) with 20 uniform hydraulic fractures and length of 5000 ft was modeled. The fractures are all infinitely conductive with half lengths of 150 ft. A commercial compositional simulator was used to simulate production from wells with five different reservoir fluids (highly volatile and near-critical oils). 30 years of production was simulated from wells with different minimum bottomhole pressure (BHP) constraints of 500 psi and 1000 psi, reservoirs with different degrees of undersaturation—initial reservoir pressures of 4000 psi and 5000 psi, as well as reservoir fluids with different critical gas saturations—5% and 10% respectively (shown in Table 1). The original base cases are wells (with the ten different fluid samples) having a minimum BHP of 1000 psi, initial reservoir pressure of 5000 psi and critical gas saturation of 5%. Altogether, production data were simulated from 20 different wells. Pressure drop and fluid flow were modeled using logarithmically-spaced local grid refinement (LS-LGR) and the Peng-Robinson equation of state was used for the PVT. Figure 1 shows the MFHW model and Table 2 shows the five different reservoir fluid compositions. Fluids 3 and 4 are near-critical volatile oils. Reservoir data in Table 1 are those of a typical liquid-richshale reservoir.
This paper contains a detail study about the two major basins of India in the perspective of shaleoil and gas. According to estimates by EIA, India has 96 tcf of recoverable shalegas reserves. However there has been a recent downward revision in the estimates. India's shalegas reserve estimates pale in comparison to global standards, however limited exploration has been carried out so far. The Cambay, Krishna Godavari, Cauvery and the Damodar Valley are the most perspective sedimentary basins for carrying out shalegas activities in the country. The Cambay Basin in Gujarat is the largest basin in the country, spreaded across 20,000 gross square miles, with a prospective area of 1940 square miles. Around 20 tcf of gas has been classified as recoverable in this basin. It is estimated that the Krishna Godavari basin, located in eastern India, holds the largest shalegas reserves in the country. It extends over 7800 square miles in gross area with a prospective area of around 4340 sq miles. The basin encloses a series of richorganic materials, containing around 27 -30 tcf.
The impact of sub-surface mining on the surroundings will be less than for open pit mines. However, to produce 50 Mton of shale a year would need the development of a mining industry that surpasses the total hard coal production in Germany. To save costs and to facilitate operations, the spent shale and part of the rocks removed to drive the access shafts and stone drifts are likely to be disposed at the surface. Even if case disposal in the mines is chosen or imposed, some of the mined material will have to be placed on a mine dump due to the volume increase. Sub-surface mining also causes subsidence of the surface. This is due to the collapse of mined-out area and abandoned stone drifts. Surface subsidence can be strongly reduced by using appropriate techniques to fill and work-off mined areas, but can never be totally avoided. Besides damage to buildings and other construction works, subsidence can have an impact on the water runoff pattern of the area affected. In some cases, ground water has to be pumped off to avoid flooding of certain areas.
Having obtained the data for the Albertine oil field from literature and the accessible databases coupled with correlations, the next step is to validate the obtained recovery factor through a numerical reservoir simulation. The reservoir considered is a conventional type reservoir with the parameters as reflected in table 4 below. The reservoir is first produced based on the natural energy of the reservoir for a period of 15 years. The injector well and the producer well are located at strategic positions to yield the maximum oil output. The area of the reservoir is 400000ft 2 . The grid block width in the I direction is 1000ft and the grid block width in the j direction is 400ft. The total number of layers are 3 while 50 and 20 blocks are considered in the I and J directions respectively. The rock fluid properties are obtained using correlations for the sandstone and conglomerate water wet sandstone properties as shown in table 5. During depletion stage, the producer has a flowing bottom-hole pressure of 100 psi. For the injection period, the forecast time is 30 years. Initially the injector is placed at a distance of 1000 ft from the
A smear of the culture was prepared on a clean grease-free glass slide, air-dried and heat fixed. The smear was flooded with crystal violet solution for 30seconds and rinsed in a slow running tap water for 5 seconds. Alcohol (ethanol) was used to decolorize the slide content. The smear was rinsed immediately with water, counter stained with safranin solution for 30seconds and air-dried. The stained smears were then observed under the light microscope using the oil immersion objective lens. Gram B reagent and their composition are presented below.
The fracture properties of fractured shalegasreservoirs have been characterized by many methods. For example, Crafton and Gunderson  used the high frequency single- phase flowback data to characterize fracture properties. Further, Williams-Kovacs et al.  developed a flowing material balance equation with single-phase flow. However, these single-phase flow models ignore the analysis for water flowback data. Their prediction accuracy thus was not well evaluated in the two-phase flow period and later stages. The immediate two-phase flow after the shut-in period was observed in the Barnett shale and the Marcellus shale . A transient flowing model considering the effect of two- phase flow after the hydraulic fracturing was also developed for gas production . This model further analyzes the response of transient pressure. Yang et al.  developed a semianalytical model to simulate the two-phase flow dur- ing the flowback period with complex fracture networks. They found that increasing the fracture network complexity is favorable to gas production enhancement. Ezulike and Dehghanpour  applied a dynamic relative permeability on the two-phase flow in the hydraulic fractures. Their results showed that the relative permeability varies with reservoir parameters in the early flowback period. Xu et al.  analyzed the mechanisms for flowback behaviors and put forward a material balance approach to estimate the effective fracture volume in the Horn River Basin. Ezulike et al.  developed a two-phase flowback tank model for estimating fracture pore volume independent of fracture geometry. Their results indicated that the effective fracture pore volume is the most sensitive to fracture pore volume compressibility. Alkouh et al.  provided an effective method to estimate fracture volume through the water flow- back and gas production data. Therefore, different methods have been used to characterize the fracture properties but the interaction between fracture flow and shalegas diffu- sion has not been considered in the two-phase flowback stage.