Top PDF Improving Fluid Recovery and Permeability to Gas in Shale Formations

Improving Fluid Recovery and Permeability to Gas in Shale Formations

Improving Fluid Recovery and Permeability to Gas in Shale Formations

microemulsion caused a pressure decrease needed to displace injected fluids from low permeability core samples and enhanced relative permeability to gas. Several field examples were presented for unconventional coals and shales treatments. Water recovery and producibility were increased by 50% (Penny et al. 2005). Paktinat et al. (2005) presented the laboratory experiments of using microemulsion which showed 80% permeability enhancement in sandstone cores. Babadagli (2005) studied the injection of several pore volumes of microemulsion into the sandstone plugs, which contained 35% of residual oil, observing a linear relationship between the values of injected pore volume and the oil recovery. Low interfacial tensions between aqueous and oily phases as well as improved solubilization for both polar and non-polar compounds were explained as the most desirable properties of microemulsion for enhance recovery applications. Yang et al. (2009) tested a microemulsion based demulsifier (ME-DeM) on a range of crude oils. The results showed effectiveness of the microemulsion-demulsifier, ME-DeM, compared with commercially available non-microemulsion based demulsifiers. Liu et al. (2010) discussed the benefits of applying the microemulsion together with a polymer in hydraulic fracturing. Ali et al. (2011) studied microemulsions in wettability alteration of the rock and resulted that the amount of water imbibed into the formation was reduced after using microemulsion. Nguyen (2013) developed a microemulsion as a flowback aid added to stimulation fluid that showed enhanced relative oil and gas permeabilities.
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Evaluation of the Organic Carbon Content in the Low-Permeability Shale Formations (As in the Case of the Khadum Suite in the Ciscaucasia Region)

Evaluation of the Organic Carbon Content in the Low-Permeability Shale Formations (As in the Case of the Khadum Suite in the Ciscaucasia Region)

Due to the catagenetic consumption of OMs for the formation of hydrocarbons (liquid and gas) and non-hydrocarbon products (water, gases – CO 2 , H 2 S, N, etc.), a reduction in the mass of OMs in catagenesis occurs, and at each stage of OM transformation we are dealing with the residual concentrations. To restore the initial values of TOC by the beginning of catagenesis, i.e. by the beginning of HCs generation, we recommend using the conversion factors that take into account the type and concentration of the substance, as well as catagenesis gradations, reached by the oil source rock deposits.
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Isotopic investigation of subsurface rock and fluid interactions: Case studies of CO2 sequestration and gas-bearing shale formations

Isotopic investigation of subsurface rock and fluid interactions: Case studies of CO2 sequestration and gas-bearing shale formations

Geologic carbon storage and unconventional gas drilling are both activities that change the physical and chemical state of the geologic formations that they target. Both cause increases in formation pressure that can result in the displacement of deep-seated brines and an increase in formation porosity and permeability. These brines have the potential to travel along porous pathways and interact with adjacent or overlying fluids. Aside from the physical changes in the formation, the formation can dissolve and new minerals can precipitate. The reactions that occur between the anthropogenic fluids and the overlying seal rock are also important, as this seal rock provides the pressure necessary for successful carbon storage and recovery of hydrocarbons. If seal rock integrity is compromised, the result could be a permeable pathway for upward fluid migration.
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Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States

Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States

Although the terms shale oil 2 and tight oil are often used interchangeably in public discourse, shale formations are only a subset of all low permeability tight formations, which include sandstones and carbonates, as well as shales, as sources of tight oil production. Within the United States, the oil and natural gas industry typically refers to tight oil production rather than shale oil production, because it is a more encompassing and accurate term with respect to the geologic formations producing oil at any particular well. EIA has adopted this convention, and develops estimates of tight oil production and resources in the United States that include, but are not limited to, production from shale formations. The ARI assessment of shale formations presented in this report, however, looks exclusively at shale resources and does not consider other types of tight formations.
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Investigating Effects Of Carbonate Minerals On Shale- Hydraulic Fracturing Fluid Interactions In The Marcellus Shale

Investigating Effects Of Carbonate Minerals On Shale- Hydraulic Fracturing Fluid Interactions In The Marcellus Shale

Hydraulic fracturing, often referred to as fracturing, is generically the fracturing of rocks around a wellbore in order to increase the permeability of the rock and therefore the flow of gas from it. Many wells are drilled in close proximity on a well pad and after reaching the depth of the target formation, such as the Marcellus Shale, the drill pivots to go horizontally into the formation. This multitude of wells creates a wheel-spoke pattern in the gas bearing shale formation, and dramatically increases the yield of hydrocarbons from shale compared to what was available through conventional means (Arthur and Layne, 2008). Approximately 4.25 million gallons of water per well are used to hydraulically fracture the Marcellus Shale with other formations varying (Kondash and Vengosh, 2015). The water is mixed with a variety of chemicals to create fractures and maintain the well. In order to prop open these fractures, silica granules called proppant are injected along with gelling agents to help push the proppant into place (PA DEP). This is followed by breaker chemicals, such as persulfates, which break down the gelled water in order to pull it back out following a shut-in period of several days to weeks (Marcon et al., 2017). After this shut in period, a portion of this water and the natural brine in the formation, totaling to 1.37 million gallons per well in the Marcellus Shale (Kondash and
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Numerical Simulation Study on Miscible EOR Techniques for Improving Oil Recovery in Shale Oil Reservoirs

Numerical Simulation Study on Miscible EOR Techniques for Improving Oil Recovery in Shale Oil Reservoirs

Since these reservoirs have huge original oil in place, any improvement in oil recovery factor would result in enormous produced oil volumes. Therefore, IOR methods have huge potential to be the major stirrer in these huge reserves. Although IOR methods are well understood in conventional reservoirs, they are a new concept in unconventional ones. All the basic logic steps for investigating the applicability of different IOR methods such as experimental works, simu- lation studies, and pilot tests have just started over the last decade (Alfarge et al. 2017 ). Miscible gas injection has shown excellent results in conventional reservoirs with low permeability and light oils. Extending this approach to unconventional reservoirs including shale oil reservoirs in North America has been extensively investigated over the last decade. The gases which have been investigated are CO 2 ,
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Hydraulic Fractures for Shale Gas Production

Hydraulic Fractures for Shale Gas Production

Determining the true porosity of a gas-filled formation has always been a problem in the oil industry. During the calibration process, water-filled formations are used to develop porosity algorithms, and under these conditions, a lower number of hydrogen atoms is equivalent to a lower porosity. Consequently, when a gas-filled formation is logged, which has a lower number of hydrogen atoms than a water-filled formation of the same porosity, the porosity estimate will be lower than the true porosity. The most well-established technique is to apply the hydraulic fracturing on a regular basis. Another strategy is to switch between production and well shut-ins in a cyclic manner. Well shut-ins allow recharging of fractures with gas and pressure build up in the stimulated regions of the reservoir. This second approach will be the focus of this research; assessing the potential of applying model-based optimization as a mean to maximize production and long-term recovery in particular.
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Geochemical features and genesis of shale gas in the Jiaoshiba Block of Fuling Shale Gas Field, Chongqing, China

Geochemical features and genesis of shale gas in the Jiaoshiba Block of Fuling Shale Gas Field, Chongqing, China

( Table 4 ). The geothermal gradient in the Jiaoshiba area is 2.83  C, and the highest temperature in shale gas production history is approximately 200  C, which conforms to the bal- ance conditions for Galimov 's [31] carbon isotope exchange, but this high temperature may cause the mixing of secondary pyrolysis gas from organic matters and kerogen pyrolysis gas, which will eventually lead to the reversal of carbon isotopes. As discussed above, the natural gas in the Fuling Shale Gas Field belongs to pyrolysis gas by high temperature from organic matters, it comes from two different ways. The first one is pyrolysis gas from crude oil, and the other is initial pyrolysis gas from kerogens. When these two kinds of gas mix together up to some proportion, the reversal comes into being
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Banded iron formations, pyritic black shale, and gold deposits : a re evaluation

Banded iron formations, pyritic black shale, and gold deposits : a re evaluation

Fine-grained, carbonaceous, sulfidic black shale such as that reported here from Lucky Bay is often spatially associated with orogenic gold deposits of all ages around the world (e.g., St. Ives, Australia; Sukhoi Log, Russia; Bendigo, Australia; Kumtor, Kyrgyzstan; and Muruntau, Uzbekistan). Prevailing models for the formation of these gold reserves typically involve syn- or post-orogenic timing of ore deposition and a deep-seated fluid and metal source (Groves et al., 1998; Goldfarb et al., 2005). Recent work by Large et al. (2007; 2009; 2011) and Thomas et al. (2011) on sulfide paragenesis in four sediment-hosted orogenic gold deposits around the world counters the latter component of the reigning paradigm by presenting evidence to suggest the mineralizing fluids and metals may be relatively locally derived (i.e., sourced from the surrounding sediments, which are fine-grained, often carbonaceous and sulfidic). In the deposits studied by these authors, fine-grained carbonaceous sediments containing pyrite and/or pyrrhotite are common to abundant in and around the ore zone, and in these lithologies a multi-stage history of pyrite growth, dissolution, and re-growth is preserved. At Sukhoi Log, fine-grained bedding-parallel pyrite nodules and clusters of micro-euhedra, with a large, diverse trace element inventory (including Au, Ni, Ag, and As) and a broad range in S isotope values, were interpreted to be early diagenetic, while coarser-grained pyrite with subhedral to euhedral crystal shapes and comparatively minor trace element enrichments (i.e., low Au, As, Ni, and Ag) was interpreted as metamorphic or hydrothermal (Large et al., 2007; Chang et al., 2008). Lead isotope analyses of the various pyrite types showed that the early diagenetic pyrite contained the least radiogenic Pb, which supported the paragenetic classifications (Meffre et al., 2008). A complete history of gold paragenesis in the deposit, from sedimentation to ore-formation, was thus developed using detailed petrography, whole-rock XRF, and LA-ICPMS trace element and Pb isotope analyses on individual pyrite generations. A similar multi-faceted geochemical approach has been applied to this study, elucidating the paragenesis of pyrite nodules contained within the carbonaceous black shale at the Lucky Bay gold prospect, and bolstering the arguments put forth in Large et al. (2009; 2011) concerning the origins of sediment-hosted gold resources, which in this case are associated with BIFs.
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Field Development of Shale Gas Reservoirs

Field Development of Shale Gas Reservoirs

Unconventional natural gas is usually found in reservoirs with relatively low permeability and thus, it can not be either extracted or produced in common ways compared to conventional natural gas. One of the natural gas which has high demand in this industry is gas from shale formation called “shale gas”. The gas is trapped in the very tiny pores spaces between the grain inside the shale formation and it is impermeable nature of the source rock. Shale gas technology has been largely raised in the United States (U.S.), since the first shale gas well was discovered here in 1821 from a well near Fredonia, New York. There are some issues on field development by using vertical drilling because it requires more time and definitely has high cost as it need to spend more time on packing and moving the rig and preparing at a new drilling site. The main objective of this paper is to propose an appropriate development plan for shale gas reservoir. In conducting this project, few research methodologies such as analysis, evaluation of result, and comparison of case study to ensure this project to be successfully completed in achieving its objectives. Field developments of reservoir consist of information from Geophysic and Geology part (G&G), Reservoir Engineering, Production Engineering, Facilities Engineering and Project Economics. One of the important development of shale gas reservoirs are depend on the technology such as horizontal drilling as well as hydraulic fracturing for optimizing the production of shale gas. Horizontal drilling is helpful in increasing the exposed section length through the reservoir, while hydraulic fracturing enhances the flow of gas from reservoir to the wellbore. Thus, this paper can be used as the guideline to have further understanding on field development of shale reservoirs.
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Shale gas development and respiratory health

Shale gas development and respiratory health

The Pennsylvania Department of Environmental Protection (PDEP) provides statewide oil and gas reports in the form of a GIS shapefile. It includes all oil and gas wells drilled within the state since 1900, and is updated quarterly. The shapefile includes the longitude and latitude of the well, operator, well type (gas, oil, etc.), well status (active, plugged, abandoned, etc.), well pad name, well configuration, date permitted, date drilled, date plugged (if applicable), and if the well is conventional or unconventional. To create the dataset of fracking wells, observations were first limited to fracking wells by selecting those wells that were indicated to be both horizontal and unconventional. This limitation reduced the dataset to 15,478 observations from 159,196. Next, the dataset was limited to only those Pennsylvania counties of interest, by using the clip geoprocessing function in ArcGIS, limiting the dataset to 8,864 observations. Of these wells, 4,271 had no “spud date”, or date the well was drilled, because these wells were only permitted, but not drilled. Therefore these 4,271 observations were removed from the dataset, leaving 4,593 observations. This is not cause for concern because these wells were simply included in the dataset because the wells were only permitted but not drilled. The dataset was then narrowed to the study time period, Quarter 1 of 2007 through Quarter 4 of 2012 (January 1, 2007 through December 31, 2012), by selecting those wells with a spud date before December 31, 2012, thus limiting the dataset to 3,236 observations. Of these wells, one well was removed because its spud date was invalid, leaving the total number of wells to 3,235. A spatial join in ArcGIS was then used to assign zip codes to the wells of interest, based on their location. Figure 5 demonstrates the fracking wells within the study area.
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Laboratory characterization of the porosity and permeability of gas shales using the crushed shale method: Insights from experiments and numerical modelling

Laboratory characterization of the porosity and permeability of gas shales using the crushed shale method: Insights from experiments and numerical modelling

on the weight of the shale fragments and their bulk density is significantly higher than the pressure estimated by extrapolating pressure to t 0.5 = 0. The likely reason for this is that a significant amount of gas has entered the particles very soon (i.e. <1 s) after the valve connecting the sample chamber to the reference chamber is opened. The results obtained during this study cannot be used with certainty to identify the type of pore space into which this gas flows. It is possible that this pore space was created as a result of damage during coring, core retrieval or during sample preparation; such porosity has no relevance to subsurface performance and should be ignored. It is, however, possible that such pore space represents natural fracture and matrix porosity, which would be present in the subsurface. Such porosity would be incredibly important to characterize because it may be providing the highest permeability pathways in the subsurface. However, it is clear that the CSM cannot be used to measure the permeability of such pathways as they become filled with gas before temperature equilibrium has been reached within the sample chamber. Eclipse TM simulations were also run to assess the sensitivity of the crushed shale method to key parameters such as sample permeability. For this sensitivity test, a series of models were run in which the permeability of the sample was varied between 100nD and 10 pD (10 -
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Permeability evolution of pyrolytically-fractured oil shale
under in situ conditions

Permeability evolution of pyrolytically-fractured oil shale under in situ conditions

gas flow properties in oil shale stratum during in-situ extracting oil shale by injecting heating, Kang reported his preliminary results on quantity of fissure observed by CT imaging technology in heated Fushun oil shale. It was demonstrated that a small quantity of micro—fissures formed in the specimen mainly along the raw original bedding and the border of hard mineral particles under 300 ℃ and the thermal fissure surfaces were basically parallel to the original bedding. The quantity, length and width of the fissures increased rapidly at above 300 ℃ due to chemical reaction in oil shale [17-18] . The corresponding permeability coefficient was measured at temperature
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Diagnostic Fracture Injection Tests (DFIT ) in Ultra Low Permeability Formations

Diagnostic Fracture Injection Tests (DFIT ) in Ultra Low Permeability Formations

Figure 7 - Recorded Pressure and Injection Rate A DFIT™ test is an optimal test to perform using surface acquired pressure data. Because the fluid being injected is an incompressible fluid and is continuous from the perforations to the wellhead, the conversion to downhole pressures is straight forward. However, there have been concerns on the analysis

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The Effects of Shale Gas Production on Natural Gas Prices

The Effects of Shale Gas Production on Natural Gas Prices

The Producer Price Index (PPI) for natural gas, measured on an annual average basis, fell 56.8 percent between 2007 and 2012, in response to strong growth in domestic energy production. The application of horizontal hydraulic fracturing (fracking) to shale rock formations contributed significantly to this increase in supply, as the technique boosted natural gas production yield by more than 25 percent over this period. Since shale gas has been a key player in domestic natural gas production for only a few years, and because it has been tracked over a relatively short period (since 2007) by the Energy Information Administration (EIA), analysts find that it is difficult to quantify precisely the effects that shale gas has had on natural gas prices. However, data indicate that increasingly higher natural gas prices during the first half of 2008 lured additional shale gas to the market. As natural gas prices peaked in July 2008, drilling activity (as measured by rig counts) hit an all-time high.2 Eventually, effects of oversupply took hold.
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Figures Figure 1 Shale gas production process...7 Figure 2 EIA Study of shale gas resources...8 Figure 3 Shale gas well design...

Figures Figure 1 Shale gas production process...7 Figure 2 EIA Study of shale gas resources...8 Figure 3 Shale gas well design...

This briefing has been developed to provide guidance to financiers seeking to understand the key issues associated with shale gas exploration and production, and to assist in identifying the types of responsible business practices that might be reasonably expected from companies operating in this arena. While many examples and practices are drawn from experience in the US, this note is intended to be relevant to a global audience. The International Energy Agency (IEA) has described natural gas as poised to enter a golden age 1 , if a significant proportion of the world’s vast resources of unconventional gas
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Getting ready for UK shale gas

Getting ready for UK shale gas

Figure 7: Direct, indirect, and induced jobs generated at peak For the purpose of this study, we have chosen to focus on direct roles and services considered critical to developing a shale pad. The categories for these roles include: drilling and completions; hydraulic fracturing; petroleum engineering and geosciences; planning approvals and permitting issuance, health, safety and environmental monitoring. Providing enabling services are roles and suppliers within operations management, construction, and office support categories. By unlocking the shale reserves, these roles are critical to opening up the wider supply chain opportunities (e.g., steel, rigs, ancillary equipment, cement, proppant, chemicals).
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Gas versus oil prices The impact of shale gas 1

Gas versus oil prices The impact of shale gas 1

Doomsday prophecies for the gas market appear to build on a view that gas – which is very utilisable in such areas as heating, electricity generation and to some extent transport – will be much cheaper in the long term than competing energy bearers, and that gas-to-gas competition will eliminate substitution opportunities between gas and oil. This conflicts with a fundamental economic principle – people will normally choose the cheapest energy source. That reasoning is subject to certain modifications. If a move to gas incurs conversion costs, it will not be made until the price change is seen to be lasting. In other words, temporary price differentials can arise, but the displacement of demand over time will encourage prices for various energy bearers to equalise. Declining prices, security of supply and increased climate awareness suggest that demand for natural gas to generate power in the USA could rise from 19 to 35 billion cubic feet (Bcf) per day by 2030. 13 Confidence in long-term gas supplies has increased. In addition, higher shale gas output, greater LNG import capacity, and more
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Prices and Profits: US Shale Gas

Prices and Profits: US Shale Gas

Hedging—locking in futures prices with buyers through swaps and col- lars—also helps shale producers keep their realized prices high. The US’ top shale producer and number two natural gas producer, Chesapeake Energy, has been particularly adept at keeping its realized prices higher than the NYMEX benchmark. The company adds mil- lions of dollars to the well head price of its gas through hedging, although sharp reversals in prices, as occurred in 2008 when gas prices plunged from record highs, can deeply dent the com- pany’s results when it has to mark its books to market every quarter.
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Description of Biofuels and Shale Gas Development

Description of Biofuels and Shale Gas Development

and hydraulic fracturing. Hydraulic fracturing is a drilling method used to recover shale gas. It is a process when water, sand and chemicals are injected into rock formation under high pressure in order to break up the rock and extract gas or oil. There are great concerns whether the mixture of water and chemicals can contaminate adjacent drinking water sources (Asche et al., 2012). In addition, there are some clues that unconventional production of shale gas is connected with earthquake occurrence. Europe is more densely populated then the US, thus it will be much difficult to find place where drilling wells could be set up to be both far from inhabited area and in proximity of pipeline network. Due to many environmental hazards, numerous countries proceed with caution in shale gas development. For instance, French government banned hydraulic fracturing for shale gas in 2011 due to concerns about its environmental impacts. Government cancelled ex- ploration licences as well. President Francois Hollande (2013) added: ”As long as I am president, there will be no exploration for shale gas in France.” On the contrary, majority of Poles support shale gas exploitation as well as Polish government. They promised tax exemption for shale gas extraction until the end of 2020 to encourage exploration. Nevertheless, the first attempts of drilling did not reach expectations. Furthermore, the EC started investigation of Geological and Mining law that Polish government adjusted to be more favourable with respect to shale gas exploration. The EC claims that the law violates environmental impact assessment directive. While there are some more countries that support shale gas exploration like the United Kingdom (UK) and Romania, general stance on the EU states can be described with words ”caution” and ”negative attitude” towards future development or waiting for appropriate environmental and social impact studies.
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