Canada has vast oil shale resources (estimated at 180 billion barrels proved recoverable oil shale reserve) similar to the estimated Canadian oil reserve of 179 billion barrels. These deposits consist of various oil shale types deposited in terrestrial, lake, and marine environments. These Canadian oil shale deposits are assessed under auspices of Canada/Israel Industrial Research and Development Program and Geological Survey of Canada for their possible use for extraction of hydrocarbon. The organic rich oil shale deposit with thickness of >60m are suitable for this purpose. This paper reviews the oil shale deposits of Arctic Canada from Ordovician to Carboniferous age. Ordovician shale of Baffin Island, Southampton Island, and Akpatok Islands consist of organic lean, calcareous deposits with variable thickness. The Devonian cannel and canneloid deposit of Melville Island, Arctic Canada are liptinitic rich, but are thin and therefore have low mining potential. The Lower Carboniferous Emma Fjord oil shale deposit is the only promising deposit for in-situ extraction of hydrocarbon from Arctic Canada at present.

In The Name of God the Merciful The availability of energy resources is of paramount importance to society. The greatest challenge facing the energy sector today is how to meet the rising demand for energy and on the other hand, the depletion of crude oil resources. To solve this dilemma, greater efforts should be devoted to develop alternative energy resources such as oil shale as a supplement of conventional oil supplies. However combinations of high oil prices, improved extraction technologies and increasing energy depend have reignited interest oil shale industry. Oil shale is a rock that contains kerogen, an organic substance that breaks down when heated to yield combustible liquids, gases, and solids. The liquid product – crude shale oil can be transformed into a replacement for conventional crude. Shale oil is expensive to produce, and it has never been able to compete with conventional crude for very long time. However, crude prices have risen in the past few years and are expected to stay high which could make oil shale development practical. The quality of oil shale is either expressed by its heating value or the amount of shale oil that can derived from it liter/ton. Oil shale is considered commercial for use if its quality from 100 – 200 liter/ton. Processes for producing shale oil generally fall into one of two groups: mining followed by surface retorting and in-situ retorting. In this paper we try to study the strategic significance of oil shale development in Egypt from many aspects (economic profit – employment benefits – socioeconomic). On the other hand there are critical issues with oil shale project, I try to suggest practical solutions that can help to reduce the severity of these critical issues and improve shale oil production cost.

Oman's petroleum systems are related to four known source rocks: the Precambrian-Lower Cambrian Huqf, the Lower Silurian Sahmah, the Late Jurassic Shuaiba-Tuwaiq and the Cretaceous Natih. The Huqf and the Natih have sourced almost all the discovered fields in the country. This study examines the shale-gas and shale-oil potential of the Lower Silurian Sahmah in the Omani side of the Rub al Khali basin along the Saudi border. The prospective area exceeds 12,000 square miles (31,300 km 2 ). The Silurian hot shale at the base of the Sahmah shale is equivalent to the known world-class source rock, widespread throughout North Africa (Tannezouft) and the Arabian Peninsula (Sahmah/Qusaiba). Both thickness and thermal maturities increase northward toward Saudi Arabia, with an apparent depocentre extending southward into Oman Block 36 where the hot shale is up to 55 m thick and reached 1.4% vitrinite reflectance (in Burkanah-1 and ATA-1 wells). The present-day measured TOC and estimated from log signatures range from 0.8 to 9%. 1D thermal modeling and burial history of the Sahmah source rock in some wells indicate that, depending on the used kinetics, hydrocarbon generation/expulsion began from the Early Jurassic (ca 160 M.a.b.p) to Cretaceous. Shale oil/gas resource density estimates, particularly in countries and plays outside North America remain highly uncertain, due to the lack of geochemical data, the lack of history of shale oil/gas production, and the valuation method undertaken. Based on available geological and geochemical data, we applied both Jarvie (2007) and Talukdar (2010) methods for the resource estimation of: (1) the amount of hydrocarbon generated and expelled into conventional reservoirs and (2) the amount of hydrocarbon retained within the Silurian hot shale. Preliminary results show that the hydrocarbon potential is distributed equally between wet natural gas and oil within an area of 11,000 square mile. The Silurian Sahmah shale has generated and expelled (and/or partly lost) about 116.8 billion of oil and 275.6 TCF of gas. Likewise, our estimates indicate that 56 billion of oil and 273.4 TCF of gas are potentially retained within the Sahmah source rock, making this interval a future unconventional resource play. The average calculated retained oil and gas yields are estimated to be 6 MMbbl/mi 2 (or 117 bbl oil/ac-ft) and 25.3 bcf/mi 2 (or 403 mcf gas/ac-ft) respectively. To better compare our estimates with Advanced Resources International (EIA/ARI) studies on several Silurian shale plays, we also carried out estimates based on the volumetric method. The total oil in-place is 50.2 billion barrels, while the total gas in-place is 107.6 TCF. The average oil and gas yield is respectively 7 MMbbl/mi 2 and 15.5 bcf/mi 2 . Our findings, in term of oil and gas concentration, are in line or often smaller than all the shale oil/gas plays assessed by EIA/ARI and others.

The creep and relaxation characteristics of gas and oil shale create unique challenges to the characterization, modeling, and production from these unconventional reservoirs. Notable problems include modeling of stress relaxation and stress inhomogeneity during reservoir deformation, wellbore closure during and after drilling, reduction of brittle hydraulic fracture initiation and growth, and closure of hydraulic fracture and proppant embedment after stimulation. Moreover, the mineral structure and composition in addition to the extremely fine lamination and depositional modes forming the thin beddings in gas and oil shale creates geomechanical transversely isotropic behavior observable from the nano scale to the macro scale and adds further complexity to these problems. In this study, the effects of shale rock viscoelasticity, induced pore pressure, and shale rock anisotropy on time-dependent wellbore deformation and contraction during and after drilling were investigated using a fully-coupled geomechanics (poromechanics) approach. The complex interplay between time-dependent rock deformation and pore fluid pressure buildup and diffusion processes was explicitly modeled within the realm of poroviscoelasticity. Studies on the Haynesville Shale and the Colony Pilot Mine Shale have also been carried out using material parameters determined from laboratory creep tests. It was found that the viscoelasticity of the rock matrix controls not only the final magnitude but also the rate of wellbore closure during and after drilling. Moreover, the transversely isotropic nature of the reservoir shale must be accounted for in the estimation of wellbore wall displacement. The common assumption of material isotropy for traditional reservoirs led to severe errors in the estimation of the magnitude as well as the rate of wellbore contraction.

Unconventional shale oil resources have emerged as a significant source of fossil fuels in recent years. The oil contained in shales is held in natural microfractures, micropores, and inside nanopores of the organic matter. The strong capillary forces in these pores can bind the oil to the surface with strengths that are inversely proportional to the pore radius. In order to recover more oil from these pores, it is beneficial to reduce the capillary pressure by manipulating the interfacial tension and contact angle of oil/brine/shale systems using surfactant solutions. The main consideration in surfactant flooding is to optimize brine salinity and surfactant concentration while minimizing their adsorption on rock surfaces. Although the effect of some surfactants on recovery in shale oil reservoirs has been studied in the past, the mechanism is still unclear. Moreover, the limited data available in the literature is not representative of the actual reservoir conditions. The objective of this study is to elucidate the oil displacement mechanisms in shale oil by surfactant flooding. The phase behavior of several anionic surfactants was studied in the presence of crude oil at reservoir temperature (i.e. 80 °C). The results of these tests were used to screen the best surfactants. Dynamic interfacial tensions (IFT) and contact angles (CA) of selected surfactant-in-brine/oil/shale systems were measured by the rising/captive bubble technique using a state-of-the-art IFT/CA apparatus. The apparatus was thoroughly validated with various systems using the axisymmetric drop shape analysis technique. Using the same methodology, the effects of surfactant concentration (0.01 to 0.1 wt%) and brine salinity (0.1 to 5 M NaCl) on IFT and CA at ambient and reservoir conditions (i.e. 80 °C and 3000 psig) were studied. Surfactant adsorption on shale samples was also measured in brines at ambient conditions. Our data reveal that the most effective surfactant was able to reduce the oil-brine IFT from its original value (23 mN/m) down to 0.3 mN/m at reservoir condition. A reduction in the IFT value and an increase in the dynamic contact angle of oil drop on polished shale surface were observed with the addition of surfactant and salt to the system. A trend between these parameters, pressure, and temperature was also reported.

An experimental investigation was performed on vertical core samples obtained in Mahogany shale of the Green River formation from the Anvil Points mine site. The samples were analyzed for XRD, SEM and other geological characterization before they were tested to determine the role of thermal maturation of Type-I organic matter within core samples on the geomechanical properties of the oil shale formation. Hydrous pyrolysis was performed at four different temperature ranges to simulate the bitumen generation (300°C), initial oil generation (330°C), oil generation (360°C) and the oil cracking to gas (390°C) conditions. 1. INTRODUCTION The samples were undergone thermal maturation in the designated temperatures for a span of 72 hours and afterwards were analyzed to observe the changes took place in their geochemical, geomechanical and acoustic properties Dynamic elastic moduli were utilized to determine the geomechanical property changes before and after they underwent thermal maturation that presented substantial reduction in mechanical integrity resulting in their infringement. Post thermal maturation also revealed significant decrease in the elastic properties of the materials including Young’s Modulus as well as bulk and shear moduli The maturation resulted in the generation of oil and gas triggering pore volume expansion and micro-crack development that often caused the failure of the samples.

Abstract Shale and tight rocks are associated with tiny pore throats, on the order of nanometers, and subsequently large capillary pressure. The calculation of the minimum miscibility pressure (MMP) in nanopore space is complex because the phase compositions from flash calculations are affected by capillary pressure. This paper examines the effect of capillary pressure on the calculation of MMP using cubic equation-of-state (EOS) and three techniques: the method of characteristics (MOC), multiple mixing cells, and slim tube simulation. Ternary mixtures of hydrocarbons and real reservoir fluids are considered. Using MOC, capillary pressure changes both liquid and vapor compositions and alters the tie lines. The reason for the change in the MMP is illustrated graphically with ternary and quaternary diagrams. The modified slim tube simulation tool is also used to estimate MMPs of CO 2 with Bakken and Eagle Ford oil. We use an upgraded flash calculation in the slim tube procedure to estimate MMPs with large capillary pressures for real reservoir fluids. The results show that high capillary pressure changes liquid and vapor phase compositions and this change tends to either decrease or increase the CO 2 MMP depending on the original oil composition. The importance of MMP for gas injection in shales as well as the effect of large gas-oil capillary pressure on the characteristics of immiscible floods in shales is discussed. Introduction Unconventional oil and gas resources, such as shale gas, tight oil, and shale oil contribute significantly to hydrocarbon production in North America (Hakimelahi and Jafarpour, 2015). Although strong oil and gas demand and technological progress have led to major unconventional resources production increase in the USA, and worldwide, in recent years, there are still uncertainties in understanding the complex behavior of such reservoirs as reported by Dong et al (2011). Despite multiple research studies in the area, the altered phase behavior of hydrocarbon fluids due to large gas-oil capillary pressure in the confined space of shales and tight rocks is not yet fully understood. Numerous research studies have been conducted to investigate the phase behavior of reservoir fluids in confined space of shale reservoirs. Based on the previous studies by Zarragoicoechea et al (2004) and Singh. et al (2009), the confined space in shale nanopores can alter the phase behavior of petroleum mixtures either by changing the petroleum mixture constituent components critical properties, such as critical pressures and temperatures, or such an alteration can be owing to large gas-oil capillary pressure in confined nanopores which is proposed in the studies by Shapiro et al (2000), Nojabaei, B. et al (2013) and Sugata P. Tan. et al (2015).

Oil shale is the most abundant fossil energy resource discovered in Jordan. The objective of this paper is to investigate reservoir characteristics and evaluate the resource potential of the Sultani oil shale deposit in central Jordan, based on their mineral composition, geochemical characteristics and reservoir microstructures. The samples used for this study were taken from the outcrop in Sultani deposits, South-East of Al-Karak city adjacent to the desert highway. The collected samples were cleaned and made into powder sample, kerogen sample, thin section sample, and ion beam polishing sample. The powder sample was analyzed by X-Ray Diffraction and Organic Carbon Analyzer to clarify the mineral composition and TOC value. The kerogen samples were tested for evaluate the kerogen type and maturity of organic matter. The thin section and ion beam polishing sample were examined by Optical Microscope and Electron Backscattered Diffraction to observe reservoir microstructures. The Sultani shale is formed by various types of minerals, the majority composition is 67.25% calcite and 18.38% quartz, with little apatite, dolomite, and pyrite. The geochemical test shows that: The Kerogen type is dominated by type II 1 ; the Sultani shale can be burned directly and continuously in the air, due to it contains a large amount of organic matter, TOC average value is 14.82%; the value of equivalent vitrinite reflectance is between 0.55% and 0.67%. The Sultani shale is high-quality source rock but with low maturity. Based on Optical Microscope and EBSD result, the micrite (calcite grain size<0.004mm) constitute Sultani shale. Normally, the reservoir should have extremely low porosity, but there is an amount of foraminifer shell fossil which forms the pore structure. The remarkable thing is that the fossil pore have large pore volume and it is poorly connected to its neighbor, the hydrocarbon reserve in the isolated pores. The Sultani shale is tight reservoir (large pore volume, but poorly connection) with economically attractive resource potential. However, there will be difficult for exploitation, due to it’s specially pore structure. Acid fracturing is feasible technology to connect the isolated fossil pore, thus significantly increase oil production. The Sultani shale can also be burned directly for power generation and get the lime product at the same time, Surface mining is also feasible exploitation patterns.

The Devonian Duvernay Formation in Alberta, characterized as a carbonate-siliceous source rock, is ramping up to be one of the largest and most prolific shale oil plays in Canada. In the southern part of the Duvernay Shale Basin (i.e. East Shale Basin), tight limestone beds are interbedded with laminated organic-rich calcareous shales, which show an organic maturity ranging mostly from early oil- to condensate-window. This new light oil shale play is still in the initial stages of development and the nature of these deposits requires hydraulic fracturing to increase stimulated rock volume. General completion programs involve ≥50 clustered plug ‘n’ perf stages with slickwater treatments in excess of 40,000 m 3 with ~4000 tonnes of proppant per well. The large water volume treatments will inevitably interact directly with the rock surface in the stimulated area and cause both oil-water and rock-water interactions. Post-hydraulic fracturing water retention is especially pronounced in light oil shale plays. The oil-wet nature of the Duvernay, along with calcareous and siliceous shale lithologies, adds to the complexity of water retention and perceived water-blockage. In addition, because of operational delays such as road bans and pipeline constraints, some wells may be shut-in after the fracturing treatment for weeks and even months, which will affect rock-oil-water behavior (i.e. production). The extent of water displacing into the matrix of the rocks of the Duvernay Formation in the East Shale Basin, as measured by load fluid recovery, varies significantly and appears to heavily rely on the choice of surfactant. Although the use of surfactants is generally accepted for this play, detailed understanding of the rock-fluid interaction mechanisms is still incomplete. This paper investigated the response of Duvernay Shale rocks from the East Shale Basin to various types of surfactants and analyzed production and fluid flowback data. Amott Cell analyses, which test for spontaneous oil displacement using various stimulation fluid types, demonstrated that in the East Shale Basin, nano-sized surfactants including multi-functional surfactants (MFS) and microemulsions significantly outperformed common surfactant chemistry when tested with mixed wettability shale core samples. The results provide an estimate as to extent of water migration into the matrix of the Duvernay as a result of the choice of surfactant. Our analysis is made possible from publicly available cores, laboratory analysis and high quality well production data from the Alberta Energy Regulator.

ABSTRACT This paper describes the world's shale oil resources; introduces the available oil shale retorting technologies including the lump oil shale retorting and particulate oil shale retorting. And this paper also gives the forecast of shale oil production. INTRODUCTION Due to the high crude oil price, the oil shale retorting for producing shale oil have being paid much attention. It is recognized that the world's proven shale oil reserves are higher than the crude oil exploitable resources. Now in the world, there are three countries produce shale oil commercially: China, Estonia and Brazil. China uses Fushun type retorting, Estonia uses Galoter and Kiviter retorting, Brazil uses Petrosix retorting. Total annual production of shale oil in the world accounts no more than one million tons currently. It is predicted that till 2015, it may reach 3.5 million tons. WORLD's SHALE OIL RESERVES Based on the data, published by Dr. Dyni(2003), and modified by Jialin Qian(2008), the world. in place shale oil,(converted from the in-situ oil shale) accounts for about 400 billion tons, this resources are higher than that of crude oil(more than 300 billion tons). Among the top ten countries, United States ranks first with highest reserves of in place shale oil(300billion tons), the rest nine countries with the decreasing order are as follows: Russia(39billion tons), Zaire(14billion tons), Brazil(12billion tons), Jordan(5.2billion tons), Morocco(5 billion tons), Australia(4.5billion tons), China(2.7billion tons), Estonia(2.5billion tons), and Italia(1.4billion tons) (Dyni,2003;Qian,2008).It should be mentioned that the above figures may not be so accurate, due to the fact that some countries have no proven figures, but only estimated resources. And for some countries such as United States, Russia, Brazil, Jordan, Australia, Estonia and China, the above figures represent their proven reserves. Besides, China's oil shale resources are estimated more than several hundred.

Abstract The goal of this work to apply a chemical blend to enhance oil recovery from shale formations by stimulating the near fracture matrix. The chemical blend consisting of a surfactant, an oxidizing agent (which produces a weak acid) and an organic solvent was tested on shale plates and fractured cores to evaluate the reaction kinetics and the surface interactions. Reactivity of the chemical blend with the shale was compared with the reactivity of HCl. Laboratory tests demonstrated that chemical blend preserved surface hardness and surface roughness on treated shale samples compared to traditional acids. For the shale samples exposed to HCl, the surface hardness decreased to 130 MPa compared to 170 MPa for the shale samples treated with the chemical blend. When a shale sample is treated with HCl solution, the pH of the solution changed from 0.9 to 6.5 within 10 minutes, whereas that of the chemical blend showed a pH change from 2.4 to 4.5 in 3 days. The presence of sulfate ions and surfactants in the weak acid significantly delayed reactivity of the acid compared to that of the strong acid. Chemical blend changed the wettability of the shale surface into preferentially water-wet thus improving water imbibition. Micro-CT imaging showed formation of new micro-fractures after treating shale plates with the chemical blend. The fracture conductivity decreased more than 60﹪ during HCl treatment due to mud generation, but not in the chemical blend treatment. Introduction Unconventional shales contribute more than half of the US oil production (Hughs, 2013; Maugeri, 2013). Shale reservoirs are fine grained, multi-mineral, sedimentary rocks with ultra-low porosity and permeability (Eugster et al., 1975). Due to the complexity of the matrix, shale oil production declines about 75﹪ in the first year (Baihly et al., 2010). Hydraulic fracturing increases the stimulated reservoir volume (SRV) and helps drain out the oil from the SRV. Efficiency of this process can be improved mechanically and chemically. In the last decade, scientists have tried to develop chemical formulations for shale enhanced oil recovery (Nasr-El-Din et al., 2003).

ABSTRACT: A process utilized in the proprietary Red Leaf Resources EcoShale ® technology involves mining oil shale, and either screening, or crushing and screening, to produce a rockfill product. Engineering properties of the rockfill are utilized across a variety of engineering disciplines. Full-scale field testing was commissioned to measure the permeability and porosity on oil shale rockfill with particles up to 203 mm (8 inches) and particle size distribution analyses were performed on rockfill with up to 914 mm (36 inch) particles. Large construction equipment was utilized to perform what would otherwise be simple tasks in a standard laboratory setting. A specially designed 2600 kg (5720 lb) permeameter was constructed and utilized for the full-scale field testing; the permeameter was designed to minimize rigid wall effects and provided a minimum specimen dimension to the maximum particle size ratio of 10:1. Laboratory testing was performed to provide supporting data, including specific gravity, absorption, modified Fischer assay (MFA), as well as PSD analysis for the smaller particle size fraction.

ABSTRACT: Formation pressures, stresses and failure condition analysis is critical in the planning and development of any shale or “unconventional” play. Commonly encountered wellbore stability problems and optimization of hydraulic fracturing treatments depend on the accuracy of these estimations. This paper introduces a case study located in an active tectonic setting, the Neuquén Basin of western Argentina, with special focus on the Vaca Muerta shale interval. Geological controls on spatial property distributions are discussed. The paper describes the workflow used for building 1D mechanical earth models, showing the approaches used for estimating overpressure and its causes, for assessing material anisotropy, and for deriving the poroelastic parameters needed for stress estimation. Results of the 1D models are compared with results from a 3D finite element model that was built using the “nested” or sub-modeling approach. The model was calibrated using failure analysis on breakouts and instantaneous shut in pressure values from pre-frac tests.

ABSTRACT An oil shale field was found to exhibit classic signs of a heavy microbial burden, including incidences of hydrogen sulfide production, downhole and surface microbially influenced corrosion, downhole pump and surface equipment fouling and fracturing fluid and drilling mud degradation. Over 140 samples, including formation core material, drilling muds, fracturing fluid source waters, production well samples, samples collected from failed pipe surfaces and samples from salt water disposal facilities, were collected in a comprehensive survey. Microbial activity was measured in parallel using four different bacterial quantification methods: 1) traditional MPN culture-based assay for SRB, APB, GHB (aka “bug bottles”), 2) direct visualization and counting bacterial cells utilizing live/dead staining coupled to flow cytometry, 3) an ATP-based assay for metabolically active cells, and 4) a hydrolase-based assay for metabolically active cells. Additionally, the microbial populations of some samples were characterized genetically using 16S amplicon metagenomics. Biocide selection tests were performed with frac water sources and a drilling mud sample. Metagenomics analysis of the formation core material indicated that the indigenous microbial populations were predominantly biodegrading and general heterotrophic microorganisms with minimal to no known problem-causing organisms recovered. The survey results suggested that the bacterial activity could be attributed primarily to introduced water sources as opposed to indigenous formation microbes. Data generated by this exhaustive testing and screening were used to influence biocide choice and applications in the field. The impact of biocides on the field microbial characteristics are described and discussed. INTRODUCTION The Permian Basin, extending through parts of West Texas and southeastern New Mexico, is one of the largest and oldest oil and natural gas fields in continuous operation. Over 14% of the United States' crude oil supply is produced in this basin. Historically, the basin has been typified by vertical, single or multi-zone production wells that require artificial lift early in life and are often water flooded for secondary oil recovery as the wells age. In the last decade, several shale zones have been discovered and exploited using horizontal drilling and hydraulic fracturing technologies. Management of wells has not been methodical, with numerous companies and interests taking part in the drilling and maintenance of the formations, wells, and infrastructure. According to the Texas Railroad Commission, the Permian Basin currently has 133,000 total wells with 22,000 of these being active injection/disposal wells and 82,000 listed as active producing wells. Interviews with Permian operators indicate that a typical average failure rate for Permian wells is approximately 0.5 failures/well/year. If you assume an average failure workover repair cost of approximately $30,000 per failure, this equates to an estimated annualized Permian Basin operator workover spend of $1.2 billion.

ABSTRACT: Oil shale is a compact laminated rock of sedimentary origin containing organic matter known as kerogen. The steps involved for in-situ extraction process are hydrofracturing, injection to achieve communication, and fluid migration at the underground location. Therefore, it is very important to understand the physico-mechanical behaviour of such anisotropic rocks. The favourable characteristics of Assam coal for conversion to liquid fuels have been known for a long time. Studies have indicated that these coals and carbonaceous shale constitute the principal source rocks that have generated the hydrocarbons produced from the region. In the present work an attempt is made to understand the engineering behavior of Indian oil shales experimentally. The in situ coring is performed to get the samples for testing purposes, as coring in laboratory is very difficult due to its highly anisotropic nature. Different tests are performed to understand the petrology of these samples, further the chemical analyses are also done to exactly quantify the organic and inorganic contents in these rocks. The physical and mechanical properties of these rocks are investigated by considering different anisotropic angles. Further, the petrophysical test results are correlated with the mechanical properties. These properties and correlations will further help in increasing the yield of these rocks.

The Green River, Utah holds the world's greatest oil shale resources. However, the hydrocarbon, which is namely kerogen, extraction from shales is limited due to environmental and technical challenges. In this study, we investigated the effectiveness of the combustion process for shale oil extraction. Samples collected from the Green River formation were first characterized by X-ray Diffraction (XRD) and Scanning Electron Microscopy (SEM). Then, series of dry combustion tests were conducted at different heating rates and wet combustion tests by water addition. The combustion efficiency was enhanced by mixing oil shale samples with an iron based catalyst. The effectiveness of dry, wet, and catalyst added combustion processes was examined by the thermal decomposition temperature of kerogen. Because the conventional oil shale extraction methods are pyrolysis (retorting) and steaming, the same experiments were conducted also under nitrogen injection to mimic retorting. It has been observed that the combustion process is a more efficient method for the extraction of kerogen from oil shale than the conventional techniques. The addition of water and catalyst to combustion has been found to lower the required temperature for kerogen decomposition for lower heating rate. This study provides insight for the optimization of the thermal methods for the kerogen extraction.

Summary Understanding organic porosity and its structural development in source rock reservoirs is essential to understanding how it can influence flow properties. A field emission scanning electron microscope (FESEM) was used to study the structure of the organic matter (OM) in shale samples as maturity increases. Argon ion milling of shale samples has proven to be a very powerful tool in understanding pore systems in shale, however, artifacts from this technique have been shown to obscure the OM structure. Consequently, fresh cleavage samples were imaged in addition to the argon ion-milled samples. The presence of oil/bitumen creates a challenge to observe the OM pore system by SEM techniques. To overcome this problem eight shale samples, from six different geological formations with a maturity range from 0.66 to 1.82 %Ro equivalent were observed, before and after CO 2 -toluene cleaning. OM at low maturity levels (<0.7 %Ro equivalent, from T-max values) is composed of sub-spherical units, generally 7–12 nm in diameter. With increasing maturity, these spherical subunits are connected, creating a network of OM. The spaces between these particles and the spaces within the connected framework determine the OM pore sizes, shapes, and distribution. Observations made by SEM showed OM structural changes from spherical structures to a crosslinked network in the OM that may be associated with maturity. Introduction Porosity occurring within the OM of potentially oil producing shales is not as well understood as in gas producing shale plays. Understanding the OM structure in oil plays may help understand flow and porosity measurements and help resolve challenges in establishing a multiscale approach. Coring is defined as the downhole acquisition and recovery of reservoir formation material, so it is important to understand that all laboratory testing is conducted on samples in as received (AR) state which may not be in their unaltered in situ state prior to core retrieval, and it is likely that some changes have occurred during coring, sampling, and handling procedures (Handwerger et.al. 2012). Observing pore systems in oil producing plays is difficult as the pore spaces may be filled or partially filled by fluids (indigenous and/or coring fluids) which makes it difficult to distinguish OM structures by SEM techniques. For this reason, observation of shale samples needs to be performed on AR samples as well as after cleaning to better observe changes in the pore system. There are several laboratory techniques available to clean core samples and, in general, they all have positive and negative attributes. The selection of best solvents greatly depends on rock type, the ability to remove fluids, and must not react with the rock sample. The CO 2 -toluene (CO 2 -tol) core cleaner is a widely used apparatus to clean crude oil, water, and drilling mud liquids from whole core samples in preparation for porosity and permeability measurements and was used in this study for the after cleaning SEM observations. While the removal of pore filling material will increase porosity, shrinkage of the OM may also take place thus increasing porosity. In 2010 Loucks et.al. described a type of pores that appeared to be the result of OM shrinkage. SEM observation of CO 2 -tol cleaned samples helped to understand to what extent the OM had undergone shrinkage compared to the AR samples when using this method.

Globally, with a rapidly growing world population, increasing prosperity and improved access to reliable electricity the IEA expects the demand for energy on the planet to increase significantly in the next decades i . Meeting this demand globally and in Jordan will be a formidable challenge and requires exploring for conventional hydrocarbons as well as tight / shale oil and gas resources. Jordan has one of the largest oil shale resources in the world and although previous attempts to harness this energy source have been made in Jordan, none have resulted in large scale production of energy from oil shale. In May 2009, Royal Dutch Shell plc ("Shell") signed an Oil Shale Concession Agreement to explore and evaluate the commercial potential of the deeper layers of Jordanian oil shale. Since then, the Jordan Oil Shale Company (JOSCO), a wholly owned subsidiary of Shell, has gathered seismic data over an area of 22, 270 km2 across the country and drilled/tested over 300 wells. JOSCO also established one of the most advanced geochemical and geological laboratories in the Middle East to analyze thousands of rock samples, and currently employs more than 200 people of which more than 95% are Jordanian. Being part of Shell provides JOSCO with access to a network of experts world-wide, providing invaluable technical know-how, operational expertise, cutting-edge research capabilities and global commercial insight. Shell's approach to oil shale development utilizes a technology called In-situ Conversion Process (ICP). This is different from conventional surface retorting methods and direct firing of oil shale for power generation, and is aimed at heating the oil shale by thermal conduction using a closely spaced array of horizontal heaters. JOSCO's current activities are focused on demonstrating the technical feasibility of ICP technology in Jordan. The first ICP field test (Jordan Field Experiment, JFE) has been designed and will aim to validate JOSCO's subsurface understanding of the ICP process. After the JFE, further piloting is required in Jordan before a commercial project is envisioned. When successful, oil shale can play an important role in supporting the Jordan's energy mix, and may also help encourage further benefits to Jordan's energy industry, economy and society in the future.

Abstract In this study, the coefficient of thermal expansion (CTE) and thermal conductivity (TC) of shale in two perpendicular directions, vertical and parallel to the bedding of the rock, are firstly measured by experiment. The experimental results show that the CTE of the shale in the vertical direction is 1.69 times as much as that in the parallel direction, while the TC in the parallel direction is 1.83 times larger than that of the vertical direction. Based on the no initial strain assumptions, numerical simulations for the thermal cracking in shale are carried out with the obtained coefficients. Using finite element method and thermal-mechanical coupling theory, two fracture mechanical parameters, KI and J-integral of the shale are also analyzed for the shale thermal fracturing. The simulation results show that both KI and J-integral reach the maximum when the fracturing angle equals to 0° in the shale, namely parallel to the bedding direciton. It is also found that the two fracture parameters decrease with the fracturing angle increasing. Additionally, the thermal fracturing effect of the shale is evaluated under a given scenario. The study is significant for shale oil or gas recovery by in situ pyrolyzing method. Introduction Oil shale is regarded as a kind of unconventional resource that can contribute to production of shale oil and hydrocarbon gases (Rahm & Dianne, 2011). As is known that there is a large deposit of oil shale in China, and present technology for exploiting oil shale still concentrates on open-pit mining, obtaining shale oil by retorting shale on the ground (Li, Tang, Xue, Zheng, & Du, 2014; Qian, Yin, 2008). However, this technology has a bad effect on the environment and leads to severe resource waste for utilizing oil shale. Exploiting oil shale by in-situ method for ‘green mining’ is widely necessary in China (Kang, Wang, Cao, Liang, Chang, & Liu, 2013; Waters, Dean, Downie, Kerrihard, Austbo, & McPherson, 2009; Zoback, Kohli, Das, & McClure, 2012). One of effective method to exploit shale oil is heating oil shale in-situ underground. For instance, the in-situ conversion process (ICP technique) from Shell Company etc. used a direct heating method, and convectional heating oil shale underground by injecting superheated steam from Mining Technology Institute, Taiyuan University of Technology and constructing horizontal fracture in vertical wellbore from Chevron Company use indirect heating method (Chaudhary, Ehlig, & Wattenbarger, 2011; Hazra, Lee, Economides, & Moridis, 2013; Zhao et al ., 2010). The convectional heating method contains complicated procedures with phase transition in double-media of fracture-matrix of oil shale subjected to multi-physical fields coupling including stress, fluid and temperature (Zhao et al ., 2010). The characteristics of thermodynamics, solid mechanics and seepage of oil shale have been investigated separately (Hopkins, Rosen, & Hill,1998; Kang, Zhao, & Yang, 2008; Yang, Zhao, Kang, 2010; Zhao, Yang, Feng, Liang, & Kang, 2008; Zhao, Cao, Zhao, Lin, & Wang, 2008). However, it is quite difficult to solve constrained problem of each physical parameter in multi-physical fields coupling for oil shale pyrolysis.