Search results for: hydrated oil shale ash

Authors: Zakiullah Kalwar, Shabeer Ahmed Abbasi

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This research encompasses the study of Cretaceous Sembar Formation Shale Gas potential at Hajipur area. This study has been done with the approach of geophysical data integration. The structure is NE – SW trending anticline with two map able compartments at Cretaceous Sembar level. The study area is located within proven petroleum system. Cretaceous Sembar/Goru formation is in a Wet gas window and Tertiary source is possibly in the oil window. Potential seals are present in Upper Ranikot shale beds and Intra-Lower Ranikot shales. The effectiveness and presence of source and reservoir rocks are favorable in the area of interest. Cretaceous Sembar Shale and Goru Shale beds with good organic content (TOC upto 4%, Type II/III) are currently in gas generation window in the area. Source rock intervals are also reported in Eocene Kirthar Group (TOC upto 8%, Type –II). Good reservoir quality Paleocene Lower Ranikot and Cretaceous Sembar shale beds exist in the area. The collision between Indian and Eurasian Plates during Tertiary initiated folding and thrusting. The first phase of thrusting involved ophiolite emplacement along the western margins of the Indian Plate (west of the area under review). The main phase of thrusting in the Sulaiman region was from Late Miocene to the present. The study area contains Permian to Recent clastics and carbonates. The succession generally is younger in the southeast than in northwest. Intraformational sedimentation breaks are pronounced in Permian and Jurassic. Sulaiman Range is bounded by the Western Sulaiman Transform Fault Zone (of which the Kingri Fault is the major fault) to the west and by the Domanda Fault to the east. The Domanda Fault also constitutes the western boundary of the Sulaiman Foredeep, lies in sulaiman foredeep where subsurface having prominent independent closure. Several reservoir horizons of Jurassic to Eocene are established hydrocarbon producers in the Hajipur area.

Keywords: enough size, good potential, shale gas, structure closure

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Authors: Michael Kenomore, Mohamed Hassan, Amjad Shah, Hom Dhakal

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Shale gas reservoirs have been of greater importance compared to shale oil reservoirs since 2009 and with the current nature of the oil market, understanding the technical and economic performance of shale gas reservoirs is of importance. Using the Barnett shale as a case study, an economic model was developed to quantify the effect of finding and development costs and gas prices on the basins in the Barnett shale using net present value as an evaluation parameter. A rate of return of 20% and a payback period of 60 months or less was used as the investment hurdle in the model. The Barnett was split into four basins (Strawn Basin, Ouachita Folded Belt, Forth-worth Syncline and Bend-arch Basin) with analysis conducted on each of the basin to provide a holistic outlook. The dataset consisted of only horizontal wells that started production from 2008 to at most 2015 with 1835 wells coming from the strawn basin, 137 wells from the Ouachita folded belt, 55 wells from the bend-arch basin and 724 wells from the forth-worth syncline. The data was analyzed initially on Microsoft Excel to determine the estimated ultimate recoverable (EUR). The range of EUR from each basin were loaded in the Palisade Risk software and a log normal distribution typical of Barnett shale wells was fitted to the dataset. Monte Carlo simulation was then carried out over a 1000 iterations to obtain a cumulative distribution plot showing the probabilistic distribution of EUR for each basin. From the cumulative distribution plot, the P10, P50 and P90 EUR values for each basin were used in the economic model. Gas production from an individual well with a EUR similar to the calculated EUR was chosen and rescaled to fit the calculated EUR values for each basin at the respective percentiles i.e. P10, P50 and P90. The rescaled production was entered into the economic model to determine the effect of the finding and development cost and gas price on the net present value (10% discount rate/year) as well as also determine the scenario that satisfied the proposed investment hurdle. The finding and development costs used in this paper (assumed to consist only of the drilling and completion costs) were £1 million, £2 million and £4 million while the gas price was varied from $2/MCF-$13/MCF based on Henry Hub spot prices from 2008-2015. One of the major findings in this study was that wells in the bend-arch basin were least economic, higher gas prices are needed in basins containing non-core counties and 90% of the Barnet shale wells were not economic at all finding and development costs irrespective of the gas price in all the basins. This study helps to determine the percentage of wells that are economic at different range of costs and gas prices, determine the basins that are most economic and the wells that satisfy the investment hurdle.

Keywords: shale gas, Barnett shale, unconventional gas, estimated ultimate recoverable

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Authors: Adetunji Olusegun Aderigibigbe

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Shales, especially black shales, are of great geological significance, in the study of heavy/trace metal contamination. This is due to their abundance in occurrence and high concentration of heavy metals embedded which are released during their weathering. Heavy metals constitute one of the most dangerous pollution known to human because they are toxic (i.e., carcinogenic), non-biodegradable and can enter the global eco-biological circle. In the past, heavy metal contamination in aquatic environment and agricultural top soil has been attributed to industrial wastes, mining extractions and pollution from traffic vehicles; only a few studies have focused on weathering of shale as possible source of heavy metal contamination. Based on the above background, this study attempts to establish weathering of shale as possible source of trace/heavy metal contaminations. This was done by carefully selecting fresh and their corresponding weathered shale samples from selected localities in Bida and Anambra Basins. The samples were analysed in Activation Laboratories Ltd; Ontario, Canada for trace/heavy metal. It was observed that some major and trace metals were released during weathering, i.e., some were depleted and some enriched. By this contamination of water zones and agricultural top soils are not only traceable to biogenic processes but geogenic inputs (weathering of shale) as well.

Keywords: contamination, fresh samples, heavy metals, pollution, shales, trace metals, weathered samples

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Authors: Bhargav Baruah, Ali Shemsedin Reshad, Pankaj Tiwari

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This work presents a detailed study on the thermal degradation kinetics of co-pyrolysis of oil shale of Upper Assam, India with rubber seed shell, and lab-scale pyrolysis to investigate the influence of pyrolysis parameters on product yield and composition of products. The physicochemical characteristics of oil shale and rubber seed shell were studied by proximate analysis, elemental analysis, Fourier transform infrared spectroscopy and X-ray diffraction. The physicochemical study showed the mixture to be of low moisture, high ash, siliceous, sour with the presence of aliphatic, aromatic, and phenolic compounds. The thermal decomposition of the oil shale with rubber seed shell was studied using thermogravimetric analysis at heating rates of 5, 10, 20, 30, and 50 °C/min. The kinetic study of the oil shale pyrolysis process was performed on the thermogravimetric (TGA) data using three model-free isoconversional methods viz. Friedman, Flynn Wall Ozawa (FWO), and Kissinger Akahira Sunnose (KAS). The reaction mechanisms were determined using the Criado master plot. The understanding of the composition of Indian oil shale and rubber seed shell and pyrolysis process kinetics can help to establish the experimental parameters for the extraction of valuable products from the mixture. Response surface methodology (RSM) was employed usinf central composite design (CCD) model to setup the lab-scale experiment using TGA data, and optimization of process parameters viz. heating rate, temperature, and particle size. The samples were pre-dried at 115°C for 24 hours prior to pyrolysis. The pyrolysis temperatures were set from 450 to 650 °C, at heating rates of 2 to 20°C/min. The retention time was set between 2 to 8 hours. The optimum oil yield was observed at 5°C/min and 550°C with a retention time of 5 hours. The pyrolytic oil and gas obtained at optimum conditions were subjected to characterization using Fourier transform infrared spectroscopy (FT-IR) gas chromatography and mass spectrometry (GC-MS) and nuclear magnetic resonance spectroscopy (NMR).

Keywords: Indian oil shale, rubber seed shell, co-pyrolysis, isoconversional methods, gas chromatography, nuclear magnetic resonance, Fourier transform infrared spectroscopy

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Authors: F. C. Amadi, G. C. Enyi, G. G. Nasr

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Hydraulic fracturing is one of the most important stimulation techniques available to the petroleum engineer to extract hydrocarbons in tight gas sandstones. It allows more oil and gas production in tight reservoirs as compared to conventional means. The main aim of the study is to optimize the hydraulic fracturing as technique and for this purpose three multi-zones layer formation is considered and fractured contemporaneously. The three zones are named as Zone1 (upper zone), Zone2 (middle zone) and Zone3 (lower zone) respectively and they all occur in shale rock. Simulation was performed with Mfrac integrated software which gives a variety of 3D fracture options. This simulation process yielded an average fracture efficiency of 93.8%for the three respective zones and an increase of the average permeability of the rock system. An average fracture length of 909 ft with net height (propped height) of 210 ft (average) was achieved. Optimum fracturing results was also achieved with maximum fracture width of 0.379 inches at an injection rate of 13.01 bpm with 17995 Mscf of gas production.

Keywords: hydraulic fracturing, optimisation, shale, tight reservoir

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Authors: Sina Kazemi, Farshid Torabi, Todd Peterson

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Drilling in shale formations is frequently time-consuming, challenging, and fraught with mechanical failures such as stuck pipes or hole packing off when the cutting removal rate is not sufficient to clean the bottom hole. Crossing the heavy oil shale and sand reservoirs with active shale and microfractures is generally associated with severe fluid losses causing a reduction in the rate of the cuttings removal. These circumstances compromise a well’s integrity and result in a lower rate of penetration (ROP). This study presents collective results of field studies and theoretical analysis conducted on data from South Pars and North Dome in an Iran-Qatar offshore field. Solutions to complications related to drilling in shale formations are proposed through systemically analyzing and applying modeling techniques to select field mud logging data. Field data measurements during actual drilling operations indicate that in a shale formation where the return flow of polymer mud was almost lost in the upper dolomite layer, the performance of hole cleaning and ROP progressively change when higher string rotations are initiated. Likewise, it was observed that this effect minimized the force of rotational torque and improved well integrity in the subsequent casing running. Given similar geologic conditions and drilling operations in reservoirs targeting shale as the producing zone like the Bakken formation within the Williston Basin and Lloydminster, Saskatchewan, a drill bench dynamic modeling simulation was used to simulate borehole cleaning efficiency and mud optimization. The results obtained by altering RPM (string revolution per minute) at the same pump rate and optimized mud properties exhibit a positive correlation with field measurements. The field investigation and developed model in this report show that increasing the speed of string revolution as far as geomechanics and drilling bit conditions permit can minimize the risk of mechanically stuck pipes while reaching a higher than expected ROP in shale formations. Data obtained from modeling and field data analysis, optimized drilling parameters, and hole cleaning procedures are suggested for minimizing the risk of a hole packing off and enhancing well integrity in shale reservoirs. Whereas optimization of ROP at a lower pump rate maintains the wellbore stability, it saves time for the operator while reducing carbon emissions and fatigue of mud motors and power supply engines.

Keywords: ROP, circulating density, drilling parameters, return flow, shale reservoir, well integrity

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Authors: Fazl Ullah, Rahmat Ullah

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This paper shows a comprehensive learning focused on the optimization of gas production in shale gas reservoirs through hydraulic fracturing. Shale gas has emerged as an important unconventional vigor resource, necessitating innovative techniques to enhance its extraction. The key objective of this study is to examine the influence of fracture parameters on reservoir productivity and formulate strategies for production optimization. A sophisticated model integrating gas flow dynamics and real stress considerations is developed for hydraulic fracturing in multi-stage shale gas reservoirs. This model encompasses distinct zones: a single-porosity medium region, a dual-porosity average region, and a hydraulic fracture region. The apparent permeability of the matrix and fracture system is modeled using principles like effective stress mechanics, porous elastic medium theory, fractal dimension evolution, and fluid transport apparatuses. The developed model is then validated using field data from the Barnett and Marcellus formations, enhancing its reliability and accuracy. By solving the partial differential equation by means of COMSOL software, the research yields valuable insights into optimal fracture parameters. The findings reveal the influence of fracture length, diversion capacity, and width on gas production. For reservoirs with higher permeability, extending hydraulic fracture lengths proves beneficial, while complex fracture geometries offer potential for low-permeability reservoirs. Overall, this study contributes to a deeper understanding of hydraulic cracking dynamics in shale gas reservoirs and provides essential guidance for optimizing gas production. The research findings are instrumental for energy industry professionals, researchers, and policymakers alike, shaping the future of sustainable energy extraction from unconventional resources.

Keywords: fluid-solid coupling, apparent permeability, shale gas reservoir, fracture property, numerical simulation

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Authors: Shubham Damke, Md Imtiaz, Sanchita Dei

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To stimulate the well and to enhance the production from the shaly formations, fracturing is essential. Presently the chiefly employed technology is Hydraulic Fracturing. However Hydraulic Fracturing accompanies itself with problems like disposing large volumes of fracturing wastewater, removal of water from the pores, formation damage due to injection of large amount of chemicals into underground formations and many more. Therefore embarking on the path of innovation new techniques have been developed which uses different gases such as Nitrogen, Carbon dioxide, Frac Oil, LPG, etc. are used as a base fluid for fracturing formation. However LPG proves to be the most favorable of them which eliminates the use of water and chemicals. When using it as a fracturing fluid, within the surface equipment, it is stored, gelled, and proppant blended at a constant pressure. It is then pressurized with high pressure pumps to the required surface injection pressure With lowering the total cost and increasing the productivity, LPG is also very noteworthy for fracturing shale, where if the hydraulic fracturing is done the water ‘swells’ the formation and creates surface tension, both of which inhibit the flow of oil and gas. Also fracturing with LPG increases the effective fracture length and since propane, butane and pentane is used which are already present in the natural gas therefore there is no problem of back flow because these gases get mixed with the natural gas. LPG Fracturing technology can be a promising substitute of the Hydraulic Fracturing, which could substantially reduce the capital cost of fracturing shale and will also restrict the problems with the disposal of water and on the same hand increasing the fracture length and the productivity from the shale.

Keywords: Fracking, Shale, Surface Tension, Viscosity

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Authors: Dhruvit S. Berawala, Jann R. Ursin, Obrad Slijepcevic

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Shale gas is one of the most rapidly growing forms of natural gas. Unconventional natural gas deposits are difficult to characterize overall, but in general are often lower in resource concentration and dispersed over large areas. Moreover, gas is densely packed into the matrix through adsorption which accounts for large volume of gas reserves. Gas production from tight shale deposits are made possible by extensive and deep well fracturing which contacts large fractions of the formation. The conventional reservoir modelling and production forecasting methods, which rely on fluid-flow processes dominated by viscous forces, have proved to be very pessimistic and inaccurate. This paper presents a new approach to forecast shale gas production by detailed modeling of gas desorption, diffusion and non-linear flow mechanisms in combination with statistical representation of these processes. The representation of the model involves a cube as a porous media where free gas is present and a sphere (SiC: Sphere in Cube model) inside it where gas is adsorbed on to the kerogen or organic matter. Further, the sphere is considered consisting of many layers of adsorbed gas in an onion-like structure. With pressure decline, the gas desorbs first from the outer most layer of sphere causing decrease in its molecular concentration. The new available surface area and change in concentration triggers the diffusion of gas from kerogen. The process continues until all the gas present internally diffuses out of the kerogen, gets adsorbs onto available surface area and then desorbs into the nanopores and micro-fractures in the cube. Each SiC idealizes a gas pathway and is characterized by sphere diameter and length of the cube. The diameter allows to model gas storage, diffusion and desorption; the cube length takes into account the pathway for flow in nanopores and micro-fractures. Many of these representative but general cells of the reservoir are put together and linked to a well or hydraulic fracture. The paper quantitatively describes these processes as well as clarifies the geological conditions under which a successful shale gas production could be expected. A numerical model has been derived which is then compiled on FORTRAN to develop a simulator for the production of shale gas by considering the spheres as a source term in each of the grid blocks. By applying SiC to field data, we demonstrate that the model provides an effective way to quickly access gas production rates from shale formations. We also examine the effect of model input properties on gas production.

Keywords: adsorption, diffusion, non-linear flow, shale gas production

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Authors: Gustave Semugaza, Anne Zora Gierth, Tommy Mielke, Marianela Escobar Castillo, Nat Doru C. Lupascu

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The generation of Construction and Demolition Waste (CDW) has globally increased enormously due to the enhanced need in construction, renovation, and demolition of construction structures. Several studies investigated the use of CDW materials in the production of new concrete and indicated the lower mechanical properties of the resulting concrete. Many other researchers considered the possibility of using the Hydrated Cement Powder (HCP) to replace a part of Ordinary Portland Cement (OPC), but only very few investigated the use of Recycled Concrete Powder (RCP) from CDW. The partial replacement of OPC for making new concrete intends to decrease the CO₂ emissions associated with OPC production. However, the RCP and HCP need treatment to produce the new concrete of required mechanical properties. The thermal treatment method has proven to improve HCP properties before their use. Previous research has stated that for using HCP in concrete, the optimum results are achievable by heating HCP between 400°C and 800°C. The optimum heating temperature depends on the type of cement used to make the Hydrated Cement Specimens (HCS), the crushing and heating method of HCP, and the curing method of the Rehydrated Cement Specimens (RCS). This research assessed the quality of recycled materials by using different techniques such as X-ray Diffraction (XRD), Differential Scanning Calorimetry (DSC) and thermogravimetry (TG), Scanning electron Microscopy (SEM), and X-ray Fluorescence (XRF). These recycled materials were thermally pretreated at different temperatures from 200°C to 1000°C. Additionally, the research investigated to what extent the thermally treated recycled cement could partially replace the OPC and if the new concrete produced would achieve the required mechanical properties. The mechanical properties were evaluated on the RCS, obtained by mixing the Dehydrated Cement Powder and Recycled Powder (DCP and DRP) with water (w/c = 0.6 and w/c = 0.45). The research used the compressive testing machine for compressive strength testing, and the three-point bending test was used to assess the flexural strength.

Keywords: hydrated cement powder, dehydrated cement powder, recycled concrete powder, thermal treatment, reactivation, mechanical performance

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Authors: Dongkwon Han, Sangho Kim, Sunil Kwon

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Unconventional gas resources have dramatically changed the future energy landscape. Unlike conventional gas resources, the key challenges in unconventional gas have been the requirement that applies to advanced approaches for production forecasting due to uncertainty and complexity of fluid flow. In this study, artificial neural network (ANN) model which integrates machine learning and data-driven approach was developed to predict productivity in shale gas. The database of 129 wells of Eagle Ford shale basin used for testing and training of the ANN model. The Input data related to hydraulic fracturing, well completion and productivity of shale gas were selected and the output data is a cumulative production. The performance of the ANN using all data sets, clustering and variables importance (VI) models were compared in the mean absolute percentage error (MAPE). ANN model using all data sets, clustering, and VI were obtained as 44.22%, 10.08% (cluster 1), 5.26% (cluster 2), 6.35%(cluster 3), and 32.23% (ANN VI), 23.19% (SVM VI), respectively. The results showed that the pre-trained ANN model provides more accurate results than the ANN model using all data sets.

Keywords: unconventional gas, artificial neural network, machine learning, clustering, variables importance

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Authors: Ivan Poza Martínez

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The international energy landscape has been significantly affected by the Covid-19 pandemic and te conflict in Ukraine. The Vaca Muerta sedimentary formation in Argentina´s Neuquén province has become a crucial area for energy production, specifically in the shale gas ad shale oil sectors. The massive investment required for theexploitation of this reserve make it essential to understand te determinants of the investment in the upstream sector at both local ad international levels. The aim of this study is to identify the qualitative and quantitative determinants of investment in Vaca Muerta. The research methodolody employs both quantiative ( econometrics ) and qualitative approaches. A linear regression model is used to analyze the impact in non-conventional hydrocarbons. The study highlights that, in addition to quantitative factors, qualitative variables, particularly the design of a regulatory framework, significantly influence the level of the investment in Vaca Muerta. The analysis reveals the importance of attracting both domestic and foreign capital investment. This research contributes to understanding the factors influencing investment inthe Vaca Muerta regioncomapred to other published studies. It emphasizes to role of qualitative varibles, such as regulatory frameworks, in the development of the shale gas and oil sectors. The study uses a combination ofquantitative data , such a investment figures, and qualitative data, such a regulatory frameworks. The data is collected from various rpeorts and industry publications. The linear regression model is used to analyze the relationship between the variables and the investment in Vaca Muerta. The research addresses the question of what factors drive investment in the Vaca Muerta region, both from a quantitative and qualitative perspective. The study concludes that a combination of quantitative and qualitative factors, including the design of a regulatory framework, plays a significant role in attracting investment in Vaca Muerta. It highlights the importance of these determinants in the developmentof the local energy sector and the potential economic benefits for Argentina and the Southern Cone region.

Keywords: vaca muerta, FDI, shale gas, shale oil, YPF

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Authors: Kumator Taku, Bilkisu Amartey

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This research used Grid indentation technique to investigate the effect of the addition of Coconut Shell Ash (CSA) on the nanomechanical properties of the main phases of the hydrated cement paste. Portland cement was partially replaced with 15% CSA at a water-binder ratio of 0.5 and cubes casted and cured for 28 days after which they were polished to reduce surface roughness to the barest minimum. The result of nanoindentation shows that addition of 15% CSA to cement paste transforms portlandite to C-S-H by the pozzolanic reaction. More so, there is reduced porosity and a reduction in the volume of CH by the addition of the CSA. Even though the addition of 15% CSA does not drastically change the average values of the hardness and elastic modulus of the two phases of the C-S-H, it greatly modifies their relative proportions, leading to the production of more HD C-S-H. Overall, incorporating 15%CSA to cement mortar improves the Nanomechanical properties of the four main phases of the hydrated cement paste.

Keywords: Coconut Shell Ash, Elastic Modulus, Hardness, Nanoindentation, Porosity

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Authors: M. Wigwe, M. Y Soloman, E. Pirayesh, R. Eghorieta, N. Stegent

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The moving reference point (MRP) technique has been used in the analyses of the first three stages of two fracturing jobs. The results obtained verify the proposition that a hydraulic fracture in shale grows in spurts rather than in a continuous pattern as originally interpreted by Nolte-Smith technique. Rather than a continuous Mode I fracture that is followed by Mode II, III or IV fractures, these fracture modes could alternate throughout the pumping period. It is also shown that the Nolte-Smith time parameter plot can be very helpful in identifying the presence of natural fractures that have been intersected by the hydraulic fracture. In addition, with the aid of a fracture length-time plot generated from any fracture simulation that matches the data, the distance from the wellbore to the natural fractures, which also translates to the actual fracture length for the stage, can be determined. An algorithm for this technique is developed. This procedure was used for the first 9 minutes of the simulated frac job data. It was observed that after 7mins, the actual fracture length is about 150ft, instead of 250ft predicted by the simulator output. This difference gets larger as the analysis proceeds.

Keywords: shale, fracturing, reservoir, simulation, frac-length, moving-reference-point

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Authors: Husam Mohammed Saleh Alziyadi

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The drilling fluid has a significant impact on drilling efficiency. Drilling fluids have several functions which make them most important within the drilling process, such as lubricating and cooling the drill bit, removing cuttings from down of hole, preventing formation damage, suspending drill bit cuttings, , and also removing permeable formation as a result, the flow of fluid into the formation process is delayed. In the oil and gas sector, unconventional shale reserves have been a central player in meeting world energy demands. Oil-based drilling fluids (OBM) are generally favored for drilling shale plays due to negligible chemical interactions. Nevertheless, the industry has been inspired by strict environmental regulations to design water-based drilling fluids (WBM) capable of regulating shale-water interactions to boost their efficiency. However, traditional additives are too large to plug the micro-fractures and nanopores of the shale. Recently, nanotechnology in the oil and gas industries has shown a lot of promise, especially with drilling fluids based on nanoparticles. Nanotechnology has already made a huge contribution to technical developments in the energy sector. In the drilling industry, nanotechnology can make revolutionary changes. Nanotechnology creates nanomaterials with many attractive properties that can play an important role in improving the consistency of mud cake, reducing friction, preventing differential pipe sticking, preserving the stability of the borehole, protecting reservoirs, and improving the recovery of oil and gas. The selection of suitable nanomaterials should be based on the shale formation characteristics intended for drilling. The size, concentration, and stability of the NPs are three more important considerations. The effects of the environment are highly sensitive to these materials, such as changes in ionic strength, temperature, or pH, all of which occur under downhole conditions. This review paper focused on the previous research and recent development of environmentally friendly drilling fluids according to the regulatory environment and cost challenges.

Keywords: nanotechnology, WBM, Drilling Fluid, nanofluids

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Authors: Muhammad Tarmidzi, Reza M. G. Gani, Andri Luthfi

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The purpose of this study is to identify rock zone containing hydrocarbons with calculating rock property includes volume shale, total porosity, effective porosity and water saturation. Identification method rock property based on GR log, resistivity log, neutron log and density rock. Zoning is based on sequence stratigraphic markers that are sequence boundary (SB), transgressive surface (TS) and flooding surface (FS) which correlating ten well log in blok “M”. The results of sequence stratigraphic correlation consist of eight zone that are two LST zone, three TST zone and three HST zone. The result of rock property calculation in each zone is showing two LST zone containing hydrocarbons. LST-1 zone has average volume shale (Vsh) 25%, average total porosity (PHIT) 14%, average effective porosity (PHIE) 11% and average water saturation 0,83. LST-2 zone has average volume shale (Vsh) 19%, average total porosity (PHIT) 21%, average effective porosity (PHIE) 17% and average water saturation 0,82.

Keywords: hydrocarbons zone, petrophysic, rock property, sequence stratigraphic

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Authors: Amaechi O. Azi, Uche D. Aluge, Lim H. San, Godwin A. Agbo

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This paper is centered on the investigation of mineral deposits in selected locations in Oshiri province in Ebonyi State. Mineral deposits contribute immensely to the economic growth of a society. In researching lead and zinc oxide-bearing sites at Oshiri, geological and geophysical research technique was employed. Petrozenith, Earth Resistivity Meter, and Schlumberger setup were selected to examine the electrical characteristics of the subsurface. To determine the apparent resistivity of the subsurface, five soundings were taken, and the field data were processed using WinResist software. The mudstone, lead-shale, shale-granite, and lateritic topsoil were the four geoelectric strata that were found. The third layer, which corresponds to the shale-lead lithology, has a resistivity value between 211.9 m to 807.7 m at a depth of 25 m. Due to its resistivity levels and geological trend, this layer makes an excellent signature for lead-zinc occurrence. This zone is expected to house deposits of lead and zinc oxide in commercial quantity.

Keywords: Schlumberger, current, resistivity, lithology

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Authors: Przemyslaw Brzyski, Stanislaw Fic

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Hydrated lime, because of the life cycle (return to its natural form as a result of the setting and hardening) has a positive environmental impact. The lime binder is used in mortars. Lime is a slow setting binder with low mechanical properties. The aim of the study was to evaluate the possibility of improving the properties of the lime binder by using different pozzolanic materials as partial replacement of hydrated lime binder. Pozzolan materials are the natural or industrial waste, so do not affect the environmental impact of the lime binder. The following laboratory tests were performed: the analysis of the physical characteristics of the tested samples of lime mortars (bulk density, porosity), flexural and compressive strength, water absorption and the capillary rise of samples and consistency of fresh mortars. As a partial replacement of hydrated lime (in the amount of 10%, 20%, 30% by weight of lime) a metakaolin, silica fume, and zeolite were used. The shortest setting and hardening time showed mortars with the addition of metakaolin. All additives noticeably improved strength characteristic of lime mortars. With the increase in the amount of additive, the increase in strength was also observed. The highest flexural strength was obtained by using the addition of metakaolin in an amount of 20% by weight of lime (2.08 MPa). The highest compressive strength was obtained by using also the addition of metakaolin but in an amount of 30% by weight of lime (9.43 MPa). The addition of pozzolan caused an increase in the mortar tightness which contributed to the limitation of absorbability. Due to the different surface area, pozzolanic additives affected the consistency of fresh mortars. Initial consistency was assumed as plastic. Only the addition of silica fume an amount of 20 and 30% by weight of lime changed the consistency to the thick-plastic. The conducted study demonstrated the possibility of applying lime mortar with satisfactory properties. The features of lime mortars do not differ significantly from cement-based mortar properties and show a lower environmental impact due to CO₂ absorption during lime hardening. Taking into consideration the setting time, strength and consistency, the best results can be obtained with metakaolin addition to the lime mortar.

Keywords: lime, binder, mortar, pozzolan, properties

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Authors: Hyomin Lee, Jinhyun Lee, Jinyeon Hwang, Younghoon Choi, Byeongseo Son

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Global warming is a world-wide issue. Various carbon capture and storage (CCS) technologies for reducing CO2 concentration in the atmosphere have been increasingly studied. Mineral carbonation is one of promising method for CO2 sequestration. Waste cement generating from aggregate recycling processes of waste concrete is potentially a good raw material containing reactive components for mineral carbonation. The major goal of our long-term project is to developed effective methods for CO2 sequestration using waste cement. In the present study, the carbonation characteristics of hydrated cement were examined by conducting two different direct aqueous carbonation experiments. We also evaluate the influence of NaCl and MgCl2 as additives to increase mineral carbonation efficiency of hydrated cement. Cement paste was made with W:C= 6:4 and stored for 28 days in water bath. The prepared cement paste was pulverized to the size less than 0.15 mm. 15 g of pulverized cement paste and 200 ml of solutions containing additives were reacted in ambient temperature and pressure conditions. 1M NaCl and 0.25 M MgCl2 was selected for additives after leaching test. Two different sources of CO2 was applied for direct aqueous carbonation experiment: 0.64 M NaHCO3 was used for CO2 donor in method 1 and pure CO2 gas (99.9%) was bubbling into reacting solution at the flow rate of 20 ml/min in method 2. The pH and Ca ion concentration were continuously measured with pH/ISE Multiparameter to observe carbonation behaviors. Material characterization of reacted solids was performed by TGA, XRD, SEM/EDS analyses. The carbonation characteristics of hydrated cement were significantly different with additives. Calcite was a dominant calcium carbonate mineral after the two carbonation experiments with no additive and NaCl additive. The significant amount of aragonite and vaterite as well as very fine calcite of poorer crystallinity was formed with MgCl2 additive. CSH (calcium silicate hydrate) in hydrated cement were changed to MSH (magnesium silicate hydrate). This transformation contributed to the high carbonation efficiency. Carbonation experiment with method 1 revealed that that the carbonation of hydrated cement took relatively long time in MgCl2 solution compared to that in NaCl solution and the contents of aragonite and vaterite were increased as increasing reaction time. In order to maximize carbonation efficiency in direct aqueous carbonation with CO2 gas injection (method 2), the control of solution pH was important. The solution pH was decreased with injection of CO2 gas. Therefore, the carbonation efficiency in direct aqueous carbonation was closely related to the stability of calcium carbonate minerals with pH changes. With no additive and NaCl additive, the maximum carbonation was achieved when the solution pH was greater than 11. Calcium carbonate form by mineral carbonation seemed to be re-dissolved as pH decreased below 11 with continuous CO2 gas injection. The type of calcium carbonate mineral formed during carbonation in MgCl2 solution was closely related to the variation of solution pH caused by CO2 gas injection. The amount of aragonite significantly increased with decreasing solution pH, whereas the amount of calcite decreased.

Keywords: CO2 sequestration, Mineral carbonation, Cement and concrete, MgCl2 and NaCl

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Authors: Weiyao Zhu, Qian Qi, Ming Yue, Dongxu Ma

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Due to the nano-micro pore structures and the massive multi-stage multi-cluster hydraulic fracturing in shale gas reservoirs, the multi-scale seepage flows are much more complicated than in most other conventional reservoirs, and are crucial for the economic development of shale gas. In this study, a new multi-scale non-linear flow model was established and simplified, based on different diffusion and slip correction coefficients. Due to the fact that different flow laws existed between the fracture network and matrix zone, a three-zone composite model was proposed. Then, according to the conformal transformation combined with the law of equivalent percolation resistance, the productivity equation of a horizontal fractured well, with consideration given to diffusion, slip, desorption, and absorption, was built. Also, an analytic solution was derived, and the interference of the multi-cluster fractures was analyzed. The results indicated that the diffusion of the shale gas was mainly in the transition and Fick diffusion regions. The matrix permeability was found to be influenced by slippage and diffusion, which was determined by the pore pressure and diameter according to the Knudsen number. It was determined that, with the increased half-lengths of the fracture clusters, flow conductivity of the fractures, and permeability of the fracture network, the productivity of the fractured well also increased. Meanwhile, with the increased number of fractures, the distance between the fractures decreased, and the productivity slowly increased due to the mutual interference of the fractures. In regard to the fractured horizontal wells, the free gas was found to majorly contribute to the productivity, while the contribution of the desorption increased with the increased pressure differences.

Keywords: multi-scale, fracture network, composite model, productivity

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Authors: Richardson M. Abraham-A., Colombo Celso Gaeta Tassinari

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The correlation between Total Organic Carbon (TOC) and flow units have been carried out to predict and compare the carbon dioxide (CO₂) storage potential of the shale and carbonate rocks in Irati Formation of the Parana Basin. The equations for permeability (K), reservoir quality index (RQI) and flow zone indicator (FZI) are redefined and engaged to evaluate the flow units in both potential reservoir rocks. Shales show higher values of TOC compared to carbonates, as such,  porosity (Ф) is most likely to be higher in shales compared to carbonates. The increase in Ф corresponds to the increase in K (in both rocks). Nonetheless, at lower values of Ф, K is higher in carbonates compared to shales. This shows that at lower values of TOC in carbonates, Ф is low, yet, K is likely to be high compared to shale. In the same vein, at higher values of TOC in shales, Ф is high, yet, K is expected to be low compared to carbonates.  Overall, the flow unit factors (RQI and FZI) are better in the carbonates compared to the shales. Moreso, within the study location,  there are some portions where the thicknesses of the carbonate units are higher compared to the shale units. Most parts of the carbonate strata in the study location are fractured in situ, hence,  this could provide easy access for the storage of CO₂. Therefore, based on these points and the disparities between the flow units in the evaluated rock types, the carbonate units are expected to show better potentials for the storage of CO₂. The shale units may be considered as potential cap rocks or seals.

Keywords: total organic content, flow units, carbon dioxide storage, geologic structures

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Authors: Hatem K. Hamed, Mohamed S. Hrouda

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The Middle Paleocene Lower Beda Formation was deposited in a ramp system with local shoaling. The main constituent is limestone, with subordinate dolomites and Shales. Reservoir quality is largely influenced by depositional environments and diagenesis processes. Generally the reservoir quality of Lower Beda Formation is low risk on the Inferred Horst and in the Southern Shelf where the Lower Beda formation comprises mainly of calcarenties. In the vicinity of the well GG1 the Lower Beda comprise mainly of argillaceous calcilutites and shale. The reservoir quality gradually improves from high risk to moderate risk towards KK1, LL1 and NN1 wells. The average gross thickness of Lower Beda Formation is about 300 ft. The net thickness varies from about 270 ft. in the E1-71 well to about 30 ft. in the vicinity of GG1-71 well. The net thickest of Lower Beda form a NNW-SSW trend with an average of 250 ft. the change in facies is due to change in the depositional environment, from lagoonal to shoal barrier to open marine affected the reservoir quality. The Upper Cretaceous Sirte Shale is the main source rock. It is developed within the three troughs surrounding the study area. S-Marada Trough to the N- E, Gerad Trough to the N N-W, and Abu Tummym Sub-basin to the S-W of the Inferred Horst. Sirte shale reaches 1000ft, of organically rich section. It has good organic contents over large area 2% to 3%. Hydrocarbon shows were encountered in several wells in Beda Formation this is an indication of vertical and lateral migration of hydrocarbon. The overlying Upper Paleocene Khalifa Formation is a transgressive shale, it is an effective regional top seal. Lithofacies variations in Khalifa Shale, from shales to limestones in the southern shelf in R1-71 well approximately 50-75% of the secession is limestone. About 47 million barrel of hydrocarbon recoverable reserves is expected to be trapped in structural and stratigraphic traps in Beda Formation in the study area.

Keywords: Sirte basin, Beda formation, concession 71, petroleum play fairway analysis

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Authors: Arturo Maldonado

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In the iron ore mining industry, the intact strength of rock units is defined using the uniaxial compressive strength (UCS). This parameter is very important for the classification of shale materials, allowing the split between rock and cohesive soils based on the magnitude of UCS. For this research, it is assumed that UCS less than or equal to 1 MPa is representative of soils. Several researchers have anticipated that the magnitude of UCS reduces with weathering progression, also since UCS is a directional property, its magnitude depends upon the rock fabric orientation. Thus, the paper presents how the UCS of shales is affected by both weathering grade and bedding orientation. The mineralogy of shales has been defined using Hyper-spectral and chemical assays to define the mineral constituents of shale and other non-shale materials. Geological classification tools have been used to define distinct lithological types, and in this manner, the author uses mineralogical datasets to recognize and isolate shales from other rock types and develop tertiary plots for fresh and weathered shales. The mineralogical classification of shales has reduced the contamination of lithology types and facilitated the study of the physical factors affecting the intact strength of shales, like anisotropic strength due to bedding orientation. The analysis of mineralogical characteristics of shales is perhaps the most important contribution of this paper to other researchers who may wish to explore similar methods.

Keywords: rock mechanics, mineralogy, shales, weathering, anisotropy

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Authors: Khaled Albriki, Feiyu Wang

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The failed rifted epicratonic Sirt basin is located in the northern margin of the African Plate with an area of approximately 600,000 km2. The organofacies' classification, characterization, and its distribution vertically and horizontally are carried out in 7 main troughs with 32 typical selected wells. 7 geological and geochemical cross sections including Rock-Eval data and % TOC data are considered in order to analyze and to characterize the main organofacies with respect to their geochemical and geological controls and also to remove the ambiguity behind the complexity of the orgnofacies types and distributions in the basin troughs from where the oil and gas are generated and migrated. This study confirmes that there are four different classical types of organofacies distributed in Sirt basin F, D/E, C, and B. these four clasical types of organofacies controls the type and amount of the hydrocarbon discovered in Sirt basin. Oil bulk property data from more than 20 oil and gas fields indicate that D/E organoface are significant oil and gas contributors similar to B organoface. In the western Sirt basin in Zallah-Dur Al Abd, Hagfa, Kotla, and Dur Atallha troughs, F organoface is identified for Etel formation, Kalash formation and Hagfa formation having % TOC < 0.6, whereas the good quality D/E and B organofacies present in Rachmat formation and Sirte shale formation both have % TOC > 1.1. Results from the deepest trough (Ajdabiya), Etel (Gas pron in Whadyat trough), Kalash, and Hagfa constitute F organofacies, mainly. The Rachmat and Sirt shale both have D/E to B organofacies with % TOC > 1.2, thus indicating the best organofacies quality in Ajdabiya trough. In Maragh trough, results show that Etel F organofacies and D/E, C to B organofacies related to Middle Nubian, Rachmat, and Sirte shale have %TOC > 0.66. Towards the eastern Sirt basin, in troughs (Hameimat, Faregh, and Sarir), results show that the Middle Nubian, Etel, Rachmat, and Sirte shales are strongly dominated by D/E, C to B (% TOC > 0.75) organofacies.

Keywords: Etel, Mid-Nubian, organic facies, Rachmat, Sirt basin, Sirte shale

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Authors: Jyoti Bharj, Sarabjit Singh, Subhash Chander, Rabinder Singh

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The outstanding mechanical properties of Carbon Nanotubes (CNTs) have generated great interest for their potential as reinforcements in high performance cementitious composites. The main challenge in research is the proper dispersion of carbon nanotubes in the cement matrix. The present work discusses the role of dispersion of Multiwall Carbon Nanotubes (MWCNTs) on the compressive strength characteristics of hydrated Portland IS 1489 cement paste. Cement-MWCNT composites with different mixing techniques were prepared by adding 0.2% (by weight) of MWCNTs to Portland IS 1489 cement. Rectangle specimens of size approximately 40mm × 40mm ×160mm were prepared and curing of samples was done for 7, 14, 28, and 35 days. An appreciable increase in compressive strength with both techniques; mixture of MWCNTs with cement in powder form and mixture of MWCNTs with cement in hydrated form 7 to 28 days of curing time for all the samples was observed.

Keywords: carbon nanotubes, Portland cement, composite, compressive strength

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Authors: Ma Lanting, S. Eguilior, A. Hurtado, Juan F. Llamas Borrajo

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Horizontal hydraulic fracturing is a technology to increase natural gas flow and improve productivity in the low permeability formation. During this drilling operation tons of flowback and produced water which contains many organic compounds return to the surface with a potential risk of influencing the surrounding environment and human health. A mathematical model is urgently needed to represent organic compounds in water transportation process behavior and the concentration change with time throughout the hydraulic fracturing operation life cycle. A comprehensive model combined Organic Matter Transport Dynamic Model with Two-Compartment First-order Model Constant (TFRC) Model has been established to quantify the organic compounds concentration. This algorithm model is composed of two transportation parts based on time factor. For the fast part, the curve fitting technique is applied using flowback water data from the Marcellus shale gas site fracturing and the coefficients of determination (R2) from all analyzed compounds demonstrate a high experimental feasibility of this numerical model. Furthermore, along a decade of drilling the concentration ratio curves have been estimated by the slow part of this model. The result shows that the larger value of Koc in chemicals, the later maximum concentration in water will reach, as well as all the maximum concentrations percentage would reach up to 90% of initial concentration from shale formation within a long sufficient period.

Keywords: model, shale gas, concentration, organic compounds

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Authors: Mohammad Moridzadeh, Mohammad Djavid, Barry Doyle

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An assessment of the long-term stability of a cavern in Chagrin shale excavated by the sequential excavation method was performed during and after construction. During the excavation of the cavern, deformations of rock mass were measured at the surface of excavation and within the rock mass by surface and deep measurement instruments. Rock deformations were measured during construction which appeared to result from the as-built excavation sequence that had potentially disturbed the rock and its behavior. Also some additional time dependent rock deformations were observed during and post excavation. Several opinions have been expressed to explain this time dependent deformation including stress changes induced by excavation, strain softening (or creep) in the beddings with and without clay and creep of the shaley rock under compressive stresses. In order to analyze and replicate rock behavior observed during excavation, including current and post excavation elastic, plastic, and time dependent deformation, Finite Element Analysis (FEA) was performed. The analysis was also intended to estimate long term deformation of the rock mass around the excavation. Rock mass behavior including time dependent deformation was measured by means of rock surface convergence points, MPBXs, extended creep testing on the long anchors, and load history data from load cells attached to several long anchors. Direct creep testing of Chagrin Shale was performed on core samples from the wall of the Pump Room. Results of these measurements were used to calibrate the FEA of the excavation. These analyses incorporate time dependent constitutive modeling for the rock to evaluate the potential long term movement in the roof, walls, and invert of the cavern. The modeling was performed due to the concerns regarding the unanticipated behavior of the rock mass as well as the forecast of long term deformation and stability of rock around the excavation.

Keywords: Cavern, Chagrin shale, creep, finite element.

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Authors: M. Dieb, T. Hodairi

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In the Southwest Libya area, the Palaeozoic deposits are an important petroleum system, with Silurian shale considered a hydrocarbon source rock and Cambro-Ordovician recognized as a good reservoir. The Palaeozoic petroleum system has the greatest potential for conventional and is thought to represent the significant prospect of unconventional petroleum resources in Southwest Libya. Until now, the lateral and vertical heterogeneity of the source rock was not well evaluated, and oil-source correlation is still a matter of debate. One source rock, which is considered the main source potential in Marzuq Basin, was investigated for its uranium contents using gamma-ray logs, rock-eval pyrolysis, and organic petrography for their bulk kinetic characteristics to determine the petroleum potential qualitatively and quantitatively. Thirty source rock samples and fifteen oil samples from the Tannezzuft source rock were analyzed by Rock-Eval Pyrolysis, microscopely investigation, GC, and GC-MS to detect acyclic isoprenoids and aliphatic, aromatic, and NSO biomarkers. Geochemistry tools were applied to screen source and age-significant biomarkers to high-spot genetic relationships. A grating heterogeneity exists among source rock zones from different levels of depth with varying uranium contents according to gamma-ray logs, rock-eval pyrolysis results, and kinetic features. The uranium-rich Tannezzuft Formations (Hot Shales) produce oils and oil-to-gas hydrocarbons based on their richness, kerogen type, and thermal maturity. Biomarker results such as C₂₇, C₂₈, and C₂₉ steranes concentrations and C₂₄ tetracyclic terpane/C₂₉ tricyclic terpane ratios, with sterane and hopane ratios, are considered the most promising biomarker information in differentiating within the Silurian Shale Tannezzuft Formation and in correlating with its expelled oils. The Tannezzuft Hot Shale is considered the main source rock for oil and gas accumulations in the Cambro-Ordovician reservoirs within the Marzuq Basin. Migration of the generated and expelled oil and gas from the Tannezzuft source rock to the reservoirs of the Cambro-Ordovician petroleum system was interpreted to have occurred along vertical and lateral pathways along the faults in the Palaeozoic Strata. The Upper Tannezzuft Formation (cold shale) is considered the primary seal in the Marzuq Basin.

Keywords: heterogeneity, hot shale, kerogen, Silurian, uranium

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Authors: Raed Hameed Allawi

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Wellbore instability problems are considered the majority challenge for several wells in the Ratawi shale formation. However, it results in non-productive (NPT) time and increased well-drilling expenditures. This work aims to construct an integrated mechanical earth model (MEM) to predict the wellbore failure and design optimum mud weight to improve the drilling efficiency of future wells. The MEM was based on field data, including open-hole wireline logging and measurement data. Several failure criteria were applied in this work, including Modified Lade, Mogi-Coulomb, and Mohr-Coulomb that utilized to calculate the proper mud weight and practical drilling paths and orientations. Results showed that the leading cause of wellbore instability problems was inadequate mud weight. Moreover, some improper drilling practices and heterogeneity of Ratawi formation were additional causes of the increased risk of wellbore instability. Therefore, the suitable mud weight for safe drilling in the Ratawi shale formation should be 11.5-13.5 ppg. Furthermore, the mud weight should be increased as required depending on the trajectory of the planned well. The outcome of this study is as practical tools to reduce non-productive time and well costs and design future neighboring deviated wells to get high drilling efficiency. In addition, the current results serve as a reference for similar fields in that region because of the lacking of published studies regarding wellbore instability problems of the Ratawi Formation in southern Iraqi oilfields.

Keywords: wellbore stability, hole collapse, horizontal stress, MEM, mud window

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Authors: Abeer Tariq, Mohammed S. Aljawad, Khaldoun S. Alfarisi

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This paper aimed to estimate the petrophysical properties (porosity, permeability, and fluid saturation) of the Ajeel well (Aj-1) Shale reservoir. Petrophysical properties of the Naokelekan Formation at Ajeel field are determined from the interpretation of open hole log data of one well which penetrated the source rock reservoir. However, depending on these properties, it is possible to divide the Formation which has a thickness of approximately 28-34 m, into three lithological units: A is the upper unit (thickness about 9 to 13 m) consisting of dolomitized limestones; B is a middle unit (thickness about 13 to 20 m) which is composed of dolomitic limestone, and C is a lower unit (>22 m thick) which consists of shale-rich and dolomitic limestones. The results showed that the average formation water resistivity for the formation (Rw = 0.024), the average resistivity of the mud filtration (Rmf = 0.46), and the Archie parameters were determined by the picket plot method, where (m) value equal to 1.86, (n) value equal to 2 and (a) value equal to 1. Also, this reservoir proved to be economical for future developments to increase the production rate of the field by dealing with challenging reservoirs. In addition, Porosity values and water saturation Sw were calculated along with the depth of the composition using Interactive Petrophysics (IP) V4.5 software. The interpretation of the computer process (CPI) showed that the better porous zone holds the highest amount of hydrocarbons in the second and third zone. From the flow zone indicator FZI method, there are two rock types in the studied reservoir.

Keywords: petrophysical properties, porosity, permeability, ajeel field, Naokelekan formation, Jurassic sequences, carbonate reservoir, source rock

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