Search results for: shale reservoir

Authors: N. K. Thakur

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A major proportion of the formations drilled for the production of hydrocarbons consists of clay containing shales. The petroleum industry has hugely investigated the role of clay minerals and their subsequent effect on wellbore stability during the drilling and production of hydrocarbons. It has been found that when the shale formation comes in contact with water-based drilling fluid, the interaction of clay minerals like montmorillonite with infiltrated water leads to hydration of the clay minerals, which causes shale swelling. When shale swelling proceeds further, it may lead to major drilling complications like caving, pipe sticking, which invariably influences wellbore stability, wellbore diameter, the mechanical strength of shale, stress distribution in the wellbore, etc. These problems ultimately lead to an increase in nonproductive time and additional costs during drilling. Several additives are used to prevent shale instability. Among the popular additives used for shale inhibition in drilling muds, ionic liquids and nanoparticles are emerging to be the best additives. The efficiency of the proposed additives will be studied and compared with conventional clay inhibitors like KCl. The main objective is to develop a highly efficient water-based mud for mitigating shale instability and reducing fluid loss which is environmentally friendly and does not alter the formation permeability. The use of nanoparticles has been exploited to enhance the rheological and fluid loss properties in water-based drilling fluid ionic liquid have attracted significant research interest due to its unique thermal stability. It is referred to as ‘green chemical’. The preliminary experimental studies performed are promising. The application of more effective mud additives is always desirable to make the drilling process techno-economically proficient.

Keywords: ionic liquid, shale inhibitor, wellbore stability, unconventional

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Authors: Ovye Yohanna Musah

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Shale formations of the Middle Benue Trough in North Central Nigeria present a variety of opportunities for the exploration, development and exploitation of unconventional natural gas. Prospective formations range in age from Albian through Coniacian; they include the Asu River Group, Awe, Ezeaku and the Awgu formations, however, the Keana and Lafia formations are thought to be of lesser importance. The Awgu formation presents the best prospect when compared to the Barnett Shales of Fort Worth Basin in Texa, United States with regards to the organic matter maturition, TOC content of formation and shale thicknesses which are key attributes that aid in determining the economic viability of any shale gas play. The vitrinite reflectance value from Rock Eval pyrolysis for Awe and Awgu formations are 0.89—1.34(%) and 0.83—1.13(%) respectively and are good and sufficiently mature to generate gas from the Benue Trough. The TOC value are good for Awgu formation which is 0.83—6.54(%) and closest to that of the Barnett at 1—4.5(%). Asu River and Ezeaku are less viable. Furthermore, the High to Medium Volatile bituminous coals found in the Awgu formation are characterized by high TOC contents which may enhance gas generation and this is good for further examination and possible development.

Keywords: shale gas, resource, unconventional, benue, TOC

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Authors: Yousef S. Kh. S. Hashem

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Accurate estimation of initial gas in place (IGIP) plays an important factor in the decision to develop a gas field. One of the methods that are available in the industry to estimate the IGIP is material balance. This method required that the well has to be shut-in while pressure is measured as it builds to average reservoir pressure. Since gas demand is high and shut-in well surveys are very expensive, flowing gas material balance (FGMB) is sometimes used instead of material balance. This work investigated the effect of reservoir properties (pressure, permeability, and reservoir size) on the estimation of IGIP when using FGMB. A gas reservoir simulator that accounts for friction loss, wellbore storage, and the non-Darcy effect was used to simulate 165 different possible causes (3 pressures, 5 reservoir sizes, and 11 permeabilities). Both tubing pressure and bottom-hole pressure were analyzed using FGMB. The results showed that the FGMB method is very sensitive for tied reservoirs (k < 10). Also, it showed which method is best to be used for different reservoir properties. This study can be used as a guideline for the application of the FGMB method.

Keywords: flowing material balance, gas reservoir, reserves, gas simulator

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Authors: Ana Jurkeviciute, Larisa Grigorieva, Ksenia Moskvinа

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Oil shale alkylresorcinols are formed as a by-product in oil shale processing. They are unique raw material for chemical industry. Polycondensation resins obtaining is one of the worthwhile directions of oil shale alkylresorcinols use. These resins are widely applied in many branches of industry such as wood-working, metallurgic, tire, rubber products, construction etc. Possibility of resins obtaining using overall alkylresorcinols will allow to cheapen finished products on their base and to widen the range of resins offered on the market. Synthesis of polycondensation resins on the basis of alkylresorcinols was conducted by several methods in the process of investigations. In the formulations a part of resorcinol was replaced by fractions of oil shale alkylresorcinols containing different amount of 5-methylresorcinol (40-80 mass %). Some resins were modified by aromatic alkene at the stage of synthesis. Thermal stability and degradation behavior of resins were investigated by thermogravimetric analysis (TGA) method both in an inert nitrogen environment and in an oxidative environment of air. TGA integral curves were obtained and processed in dynamic mode for interval of temperatures from 25 to 830 °C. Rate of temperature rise was 5°C/min, gas flow rate - 50 ml/min. Resins power for carbonization was evaluated by carbon residue. Physical-chemical parameters of the resins were determined. Content of resorcinol and 5-methylresorcinol not reacted in the process of synthesis were determined by gas chromatography method.

Keywords: resorcinol, oil shale alkylresorcinols, aromatic alkene, polycondensation resins, modified resins

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

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Relative permeabilities are practical factors that are used to correct the single phase Darcy’s law for application to multiphase flow. For effective characterisation of large-scale multiphase flow in hydrocarbon recovery, relative permeability and capillary pressures are used. These parameters are acquired via special core flooding experiments. Special core analysis (SCAL) module of reservoir simulation is applied by engineers for the evaluation of these parameters. But, core flooding experiments in shale core sample are expensive and time consuming before various flow assumptions are achieved for instance Darcy’s law. This makes it imperative for the application of coreflooding simulations in which various analysis of relative permeabilities and capillary pressures of multiphase flow can be carried out efficiently and effectively at a relative pace. This paper presents a Sendra software simulation of core flooding to achieve to relative permeabilities and capillary pressures using different correlations. The approach used in this study was three steps. The first step, the basic petrophysical parameters of Marcellus shale sample such as porosity was determined using laboratory techniques. Secondly, core flooding was simulated for particular scenario of injection using different correlations. And thirdly the best fit correlations for the estimation of relative permeability and capillary pressure was obtained. This research approach saves cost and time and very reliable in the computation of relative permeability and capillary pressures at steady or unsteady state, drainage or imbibition processes in oil and gas industry when compared to other methods.

Keywords: relative permeabilty, porosity, 1-D black oil simulator, capillary pressures

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Authors: Talal Al-Bazali, S. Mohammad

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The threshold capillary pressure of shale caprocks is an important parameter in CO₂ storage modeling. A correct estimation of the threshold capillary pressure is not only essential for CO₂ storage modeling but also important to assess the overall economical and environmental impact of the design process. A standard step by step approach has to be used to measure the threshold capillary pressure of shale and non-wetting fluids at different temperatures. The objective of this work is to assess the impact of high temperature on the threshold capillary pressure of four different shales as they interacted with four different oil based muds, air, CO₂, N₂, and methane. This study shows that the threshold capillary pressure of shale and non-wetting fluid is highly impacted by temperature. An empirical correlation for the dependence of threshold capillary pressure on temperature when different shales interacted with oil based muds and gasses has been developed. This correlation shows that the threshold capillary pressure decreases exponentially as the temperature increases. In this correlation, an experimental constant (α) appears, and this constant may depend on the properties of shale and non-wetting fluid. The value for α factor was found to be higher for gasses than for oil based muds. This is consistent with our intuition since the interfacial tension for gasses is higher than those for oil based muds. The author believes that measured threshold capillary pressure at ambient temperature is misleading and could yield higher values than those encountered at in situ conditions. Therefore one must correct for the impact of temperature when measuring threshold capillary pressure of shale at ambient temperature.

Keywords: capillary pressure, shale, temperature, thresshold

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Authors: Segun Steven Bodunde

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Mudlogging is the continuous analysis of rock cuttings and drilling fluids to ascertain the presence or absence of oil and gas from the formation penetrated by the drilling bit. This research highlighted a case study of Well BSS-99ST from ‘Bisas Field’, Niger Delta, with depth extending from 1950m to 3640m (Measured Depth). It was focused on identifying the lithologies encountered at specified depth intervals and to accurately delineate the targeted potential reservoir on the field and prepare the lithology and Master log. Equipment such as the Microscope, Fluoroscope, spin drier, oven, and chemicals, which includes: hydrochloric acid, chloroethene, and phenolphthalein, were used to check the cuttings for their calcareous nature, for oil show and for the presence of Cement respectively. Gas analysis was done using the gas chromatograph and the Flame Ionization Detector, which was connected to the Total Hydrocarbon Analyzer (THA). Drilling Parameters and Gas concentration logs were used alongside the lithology log to predict and accurately delineate the targeted reservoir on the field. The result showed continuous intercalation of sand and shale, with the presence of small quantities of siltstone at a depth of 2300m. The lithology log was generated using Log Plot software. The targeted reservoir was identified between 3478m to 3510m after inspection of the gas analysis, lithology log, electric logs, and the drilling parameters. Total gas of about 345 units and five Alkane Gas components were identified in the specific depth range. A comparative check with the Gamma ray log from the well further confirmed the lithologic sequence and the accurate delineation of the targeted potential reservoir using mudlogging.

Keywords: mudlogging, chromatograph, drilling fluids, calcareous

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Authors: Meng Xu, Alexis K. H. Lau, Ming Xu, Bill Barron, Narges Shahraki

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As an emerging unconventional energy, shale gas has been an economically viable step towards a cleaner energy future in U.S. China also has shale resources that are estimated to be potentially the largest in the world. In addition, China has enormous unmet for a clean alternative to substitute coal. Nonetheless, the geological complexity of China’s shale basins and issues of water scarcity potentially impose serious constraints on shale gas development in China. Further, even if China could replicate to a significant degree the U.S. shale gas boom, China faces the problem of transporting the gas efficiently overland with its limited pipeline network throughput capacity and coverage. The aim of this study is to identify the potential bottlenecks in China’s gas transmission network, as well as to examine the shale gas development affecting particular supply locations and demand centers. We examine this through application of three scenarios with projecting domestic shale gas supply by 2020: optimistic, medium and conservative shale gas supply, taking references from the International Energy Agency’s (IEA’s) projections and China’s shale gas development plans. Separately we project the gas demand at provincial level, since shale gas will have more significant impact regionally than nationally. To quantitatively assess each shale gas development scenario, we formulated a gas pipeline optimization model. We used ArcGIS to generate the connectivity parameters and pipeline segment length. Other parameters are collected from provincial “twelfth-five year” plans and “China Oil and Gas Pipeline Atlas”. The multi-objective optimization model uses GAMs and Matlab. It aims to minimize the demands that are unable to be met, while simultaneously seeking to minimize total gas supply and transmission costs. The results indicate that, even if the primary objective is to meet the projected gas demand rather than cost minimization, there’s a shortfall of 9% in meeting total demand under the medium scenario. Comparing the results between the optimistic and medium supply of shale gas scenarios, almost half of the shale gas produced in Sichuan province and Chongqing won’t be able to be transmitted out by pipeline. On the demand side, the Henan province and Shanghai gas demand gap could be filled as much as 82% and 39% respectively, with increased shale gas supply. To conclude, the pipeline network in China is currently not sufficient in meeting the projected natural gas demand in 2020 under medium and optimistic scenarios, indicating the need for substantial pipeline capacity expansion for some of the existing network, and the importance of constructing new pipelines from particular supply to demand sites. If the pipeline constraint is overcame, Beijing, Shanghai, Jiangsu and Henan’s gas demand gap could potentially be filled, and China could thereby reduce almost 25% its dependency on LNG imports under the optimistic scenario.

Keywords: energy policy, energy systematic analysis, scenario analysis, shale gas in China

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Authors: Rezki Akkal, Mohamed Khodja, Slimane Azzi

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Acidification is a technique used in oil reservoirs to improve annual production, reduce the skin and increase the pressure of an oil well while eliminating the formation damage that occurs during the drilling process, completion and, amongst others, to create new channels allowing the easy circulation of oil around a producing well. This is achieved by injecting an acidizing fluid at a relatively low pressure to prevent fracturing formation. The treatment fluid used depends on the type and nature of the reservoir rock traversed as well as its petrophysical properties. In order to understand the interaction mechanisms between the treatment fluids used for the reservoir rock acidizing, several candidate wells for stimulation were selected in the large Hassi Messaoud deposit in southern Algeria. The stimulation of these wells is completed using different fluids composed mainly of HCl acid with other additives such as corrosion inhibitors, clay stabilizers and iron controllers. These treatment fluids are injected over two phases, namely with clean tube (7.5% HCl) and matrix aidizing with HCl (15%). The stimulation results obtained are variable according to the type of rock traversed and its mineralogical composition. These results show that there has been an increase in production flow and head pressure respectively from 1.99 m3 / h to 3.56 m3 / h and from 13 Kgf / cm2 to 20 kgf / cm2 in the sands formation having good petrophysical properties of (porosity = 16%) and low amount of clay (Vsh = 6%).

Keywords: acidizing, Hassi-Messaoud reservoir, tube clean, matrix stimulation

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Authors: Akm Badrul Alam, Yoshiaki Fujii, Nahid Hasan Dipu, Shakil Ahmed Razo

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Shale rockmasses often include silt layers, impacting slope stability in construction and mining. Analyzing their interaction is crucial for long-term stability. A study used an elastoplastic model, incorporating the stress transfer method and Coulomb's criterion, to assess a shale rock mass with silt layers. It computed stress distribution, assessed failure potential, and identified vulnerable regions where nodal forces were calculated for a comprehensive analysis. A shale rock mass ranging from 14.75 to 16.75 meters thick, with silt layers varying from 0.36 to 0.5 meters, was considered in the model. It examined four silt layer conditions: horizontal (SiHL), vertical (SiVL), inclined against slope (SiIincAGS), and along slope (SilincALO). Mechanical parameters like uniaxial compressive strength (UCS), tensile strength (TS), Young’s modulus (E), Poisson’s ratio, and density were adjusted for varied scenarios: UCS (0.5 to 5 MPa), TS (0.1 to 1 MPa), and E (6 to 60 MPa). In elastic analysis of shale rock masses, stress distributions vary based on layer properties. When shale and silt layers have the same elasticity modulus (E), stress concentrates at corners. If the silt layer has a lower E than shale, marginal changes in maximum stress (σmax) occur for SilHL. A decrease in σmax is evident at SilVL. Slight variations in σmax are observed for SilincAGS and SilincALO. In the elastoplastic analysis, the overall decrease of 20%, 40%, 60%, 80%, and 90% was considered. For SilHL:(i) Same E, UCS, and TS for silt layer and shale, UCS/TS ratio 5: strength decrease led to shear (S), tension then shear (T then S) failure; noticeable failure at 60% decrease, significant at 80%, collapse at 90%. (ii) Lower E for silt layer, same strength as shale: No significant differences. (iii) Lower E and UCS, silt layer strength 1/10: No significant differences. For SilVL: (i) Same E, UCS, and TS for silt layer and shale, UCS/TS ratio 5: Similar effects as SilHL. (ii) Lower E for silt layer, same strength as shale: Slip occurred. (iii) Lower E and UCS, silt layer strength 1/10: Bitension failure also observed with larger slip. For SilincAGS: (i) Same E, UCS, and TS for silt layer and shale, UCS/TS ratio 5: Effects similar to SilHL. (ii) Lower E for silt layer, same strength as shale: Slip occurred. (iii) Lower E and UCS, silt layer strength 1/10: Tension failure also observed with larger slip. For SilincALO: (i) Same E, UCS, and TS for silt layer and shale, UCS/TS ratio 5: Similar to SilHL with tension failure. (ii) Lower E for silt layer, same strength as shale: No significant differences; failure diverged. (iii) Lower E and UCS, silt layer strength 1/10: Bitension failure also observed with larger slip; failure diverged. Toppling failure was observed for lower E cases of SilVL and SilincAGS. The presence of silt interlayers in shale greatly impacts slope stability. Designing slopes requires careful consideration of both the silt and shale's mechanical properties. The temporal degradation of strength in these layers is a major concern. Thus, slope design must comprehensively analyze the immediate and long-term mechanical behavior of interlayer silt and shale to effectively mitigate instability.

Keywords: shale rock masses, silt layers, slope stability, elasto-plastic model, temporal degradation

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Authors: Riky Tri Hartagung, Mohammad Syamsu Rosid

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The lithology prediction process, as well as the fluid content is the most important part in the reservoir characterization. One of the methods used in this process is the simultaneous seismic inversion method. In the Posseidon field, Browse Basin, Australia, the parameters generated through simultaneous seismic inversion are not able to characterize the reservoir accurately because of the overlapping impedance values between hydrocarbon sand, water sand, and shale, which causes a high level of ambiguity in the interpretation. The Poisson Impedance inversion provides a solution to this problem by rotating the impedance a few degrees, which is obtained through the coefficient c. Coefficient c is obtained through the Target Correlation Coefficient Analysis (TCCA) by finding the optimum correlation coefficient between Poisson Impedance and the target log, namely gamma ray, effective porosity, and resistivity. Correlation of each of these target logs will produce Lithology Impedance (LI) which is sensitive to lithology sand, Porosity Impedance (ϕI) which is sensitive to porous sand, and Fluid Impedance (FI) which is sensitive to fluid content. The results show that PI gives better results in separating hydrocarbon saturated reservoir zones. Based on the results of the LI-GR crossplot, the ϕI-effective porosity crossplot, and the FI-Sw crossplot with optimum correlations of 0.74, 0.91, and 0.82 respectively, it shows that the lithology of hidrocarbon-saturated porous sand is at the value of LI ≤ 2800 (m/s)(g *cc), ϕI ≤ 5500 (m/s)(g*cc), and FI ≤ 4000 (m/s)(g*cc). The presence of low values of LI, ϕI, and FI correlates accurately with the presence of hydrocarbons in the well. Each value of c is then applied to the seismic data. The results show that the PI inversion gives a good distribution of Hydrocarbon-saturated porous sand lithology. The distribution of hydrocarbon saturated porous sand on the seismic inversion section is seen in the northeast – southwest direction, which is estimated as the direction of gas distribution.

Keywords: reservoir characterization, poisson impedance, browse basin, poseidon field

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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: Hui Li, Xiongqi Pang

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In recent years, tight oil has become a hot spot for unconventional oil and gas exploration and development in the world. Dongpu Depression is a typical hydrocarbon-rich basin in the southwest of Bohai Bay Basin, in which tight sandstone oil and gas have been discovered in deep reservoirs, most of which are buried more than 3500m. The distribution and development characteristics of deep tight sandstone reservoirs need to be studied. The main source rocks in study area are dark mudstone and shale of the middle and lower third sub-member of Shahejie Formation. Total Organic Carbon (TOC) content of source rock is between 0.08-11.54%, generally higher than 0.6% and the value of S1+S2 is between 0.04–72.93 mg/g, generally higher than 2 mg/g. It can be evaluated as middle to fine level overall. The kerogen type of organic matter is predominantly typeⅡ1 andⅡ2. Vitrinite reflectance (Ro) is mostly greater than 0.6% indicating that the source rock entered the hydrocarbon generation threshold. The physical property of reservoir was poor, the most reservoir has a porosity lower than 12% and a permeability of less than 1×10⁻³μm. The rocks in this area showed great heterogeneity, some areas developed desserts with high porosity and permeability. According to SEM, thin section image, inclusion test and so on, the reservoir was affected by compaction and cementation during early diagenesis stage (44-31Ma). The diagenesis caused the tight reservoir in Huzhuangji, Pucheng, Weicheng Area while the porosity in Machang, Qiaokou, Wenliu Area was still over 12%. In the process of middle diagenesis phase stage A (31-17Ma), the reservoir porosity in Machang, Pucheng, Huzhuangji Area increased due to dissolution; after that the oil generation window of source rock was achieved for the first phase hydrocarbon charging (31-23Ma), formed the conventional oil deposition in Machang, Qiaokou, Wenliu, Huzhuangji Area and unconventional tight reservoir in Pucheng, Weicheng Area. Then came to stage B of middle diagenesis phase (17-7Ma), in this stage, the porosity of reservoir continued to decrease after the dissolution and led to a situation that the reservoirs were generally compacted. And since then, the second hydrocarbon filling has been processing since 7Ma. Most of the pools charged and formed in this procedure are tight sandstone oil reservoir. In conclusion, tight sandstone oil was formed in two patterns in Dongpu Depression, which could be concluded as ‘density fist then accumulation’ pattern and ‘accumulation fist next density’ pattern.

Keywords: accumulation process, diagenesis, dongpu depression, tight sandstone oil

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Authors: Nitin Dewangan, Nitin Kattula, Megha Anawat

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Hydraulic reservoir is the key component in the mobile construction vehicles; most of the off-road earth moving construction machinery requires bigger side hydraulic reservoirs. Their reservoir construction is very much non-uniform and designers used such design to utilize the space available under the vehicle. There is no way to find out the space utilization of the reservoir by oil and validity of design except virtual simulation. Computational fluid dynamics (CFD) helps to predict the reservoir space utilization by vortex mapping, path line plots and dwell time prediction to make sure the design is valid and efficient for the vehicle. The dwell time acceptance criteria for effective reservoir design is 15 seconds. The paper will describe the hydraulic reservoir simulation which is carried out using CFD tool acuSolve using automated mesh strategy. The free surface flow and moving reference mesh is used to define the oil flow level inside the reservoir. The first baseline design is not able to meet the acceptance criteria, i.e., dwell time below 15 seconds because the oil entry and exit ports were very close. CFD is used to redefine the port locations for the reservoir so that oil dwell time increases in the reservoir. CFD also proposed baffle design the effective space utilization. The final design proposed through CFD analysis is used for physical validation on the machine.

Keywords: reservoir, turbulence model, transient model, level set, free-surface flow, moving frame of reference

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Authors: Mitchell T. Grothaus, Cory Grigsby, Timothy S. Hare

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This study aims to determine if there is a relationship between elevated cancer risks in eastern Kentucky and the environmental effects of black shale. Previous research shows that black shale formations, such as those in eastern Kentucky contain high levels of toxic elements including arsenic and radon compared to average rocks and sediment. Similarly, the population of eastern Kentucky has higher rates of many health conditions, including lung cancer and cardiovascular disease, than surrounding regions. These poor health outcomes are typically explained in relation to social, economic, behavioral, and healthcare factors. The rates of many conditions, however, have not decreased as these factors improve with regional development. Black shale is known to affect environmental conditions such as by increasing radiation levels and heavy metal toxicity. We are mapping the effects of black shale through monitoring radiation, microbes, and chemical standards of water sources. In this presentation, we report on our measuring pH, dissolved oxygen, total dissolved solids, conductivity, temperature, and discharge and comparison with water quality standards from the Kentucky Department for Environmental Protection. The conditions of water sources combined with an environmental survey of the surrounding areas provide a greater understanding of why the people in eastern Kentucky face the current health issues.

Keywords: black shale, eastern Kentucky, environmental impact, water quality

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Authors: Almas Rajguru

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The Oligocene succession of the Tapti- Daman area is one of the established petroleum plays in Tapti-Daman block of the Mumbai Offshore Basin. Despite good control and production history, the sand geometry and continuity of reservoir character of these sediments are less understood as most reservoirs are thin and fall below seismic resolution. The present work focuses on a detailed analysis of the Early Oligocene Mahuva Formation at the reservoir scale through laboratory studies (sedimentology and biostratigraphy) of core and sidewall cores in integration with electro logs for firming up facies’ distribution, micro-depositional environment and sequence stratigraphy, diagenesis and reservoir characterization from seventeen wells from North Tapti-C-37 area in Tapti Daman Block, WOB. The thick shale/claystone with thin interbeds of sandstone and siltstones of deeper marine in the lower part of Mahuva Fm represents deposition in a transgressive regime. The overlying interbedded sandstone, glauconitic-siltstone/fine-grained sandstone, and thin beds of packstone/grainstone within highly fissile shale were deposited in a prograding tide-dominated delta during late-rise normal regression. Nine litho facies (F1-F9) representing deposition in various microenvironments of the tide-dominated delta are identified based on their characteristic sediment texture, structure and microfacies. Massive, gritty sandstone (F1) with poorly sorted sands lithic fragments with calcareous and Fe-rich matrix represents channel fill sediments. High-angle cross-stratified sandstone (F2) deposited in rapidly shifting/migrating bars under strong tidal currents. F3 records the laterally accreted tidal-channel point bars. F3 (low-angle cross-stratified to parallel bedded sandstone) and F4 (Clean sandstone) are often associated with F2 in a tidal bar complex. F5 (interbedded thin sand and mud) and F6 (bioturbated sandstone) represent tidal flat deposits. High energy open marine carbonate shoals (F8) and fossiliferous sandstone in offshore bars (F7) represent deepening up facies. Shallow marine standstill conditions facilitated the deposition of thick shale (F9) beds. The reservoir facies (F1-F6) are commonly poorly to moderately sorted; bimodal, immature sandstone represented by quartz-wacke. The framework grains are sub-angular to sub-rounded, medium to coarse-grained (occasionally gritty) embedded within argillaceous (kaolinite/chlorite/chamosite) to highly Fe-rich matrix (sideritic). The facies F7 and F8, representing the sandy packstone and grainstone facies, respectively, exhibit poor reservoir characteristics due to sanitization, diagenetic compaction and matrix-filled intergranular spaces. The various diagenetic features such as the presence of authigenic clays (kaolinite/dickite/smectite); ferruginous minerals like siderite, pyrite, hematite and other iron oxides; bioturbations; glauconite; calcite and quartz cementation, precipitation of gypsum, pressure solution and other compaction effects are identified. These diagenetic features, wherever present, have reduced porosity and permeability thereby adversely affecting reservoir quality. Tidal bar sandstones possess good reservoir characteristics such as moderate to good sorting, fair to good porosity and geometry that facilitates efficient lateral extension and vertical thickness of reservoir. The sand bodies of F2, F3 and F4 facies of Well L, M and Q deposited in a tidal bar complex exhibit good reservoir quality represented by relatively cleaner, poorly burrowed, loose, friable sandstone with good porosity. Sandstone facies around these wells could prove a potential hydrocarbon reservoir and could be considered for further exploration.

Keywords: reservoir sedimentology, facies analysis, HST, tide dominated delta, tidal bars

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Authors: Ahmed El-Banbi

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Several PVT models exist to represent how PVT properties are handled in sub-surface and surface engineering calculations for oil and gas production. The most commonly used models include black oil, modified black oil (MBO), and compositional models. These models are used in calculations that allow engineers to optimize and forecast well and reservoir performance (e.g., reservoir simulation calculations, material balance, nodal analysis, surface facilities, etc.). The choice of which model is dependent on fluid type and the production process (e.g., depletion, water injection, gas injection, etc.). Based on close to 2,000 reservoir fluid samples collected from different basins and locations, this paper presents some conclusions on the occurrence of reservoir fluids. It also reviews the common methods used to classify reservoir fluid types. Based on new criteria related to the production behavior of different fluids and economic considerations, an updated classification of reservoir fluid types is presented in the paper. Recommendations on the use of different PVT models to simulate the behavior of different reservoir fluid types are discussed. Each PVT model requirement is highlighted. Available methods for the calculation of PVT properties from each model are also discussed. Practical recommendations and tips on how to control the calculations to achieve the most accurate results are given.

Keywords: PVT models, fluid types, PVT properties, fluids classification

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Authors: Numair A. Siddiqui, Usman Muhammad, Manoj J. Mathew, Ramkumar M., Benjamin Sautter, Muhammad A. K. El-Ghali, David Menier, Shiqi Zhang

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The sedimentological parameterization of shallow-marine siliciclastic reservoirs in terms of reservoir quality and heterogeneity from outcrop study can help improve the subsurface reservoir prediction. An architectural analysis has documented variations in sandstone geometry and rock properties within shallow-marine sandstone exposed in the Miocene Sandakan Formation of Sabah, Borneo. This study demonstrates reservoir sandstone quality assessment for subsurface rock evaluation, from well-exposed successions of the Sandakan Formation, Borneo, with which applicable analogues can be identified. The analyses were based on traditional conventional field investigation of outcrops, grain-size and petrographic studies of hand specimens of different sandstone facies and gamma-ray and permeability measurements. On the bases of these evaluations, the studied sandstone was grouped into three qualitative reservoir rock classes; high (Ø=18.10 – 43.60%; k=1265.20 – 5986.25 mD), moderate (Ø=17.60 – 37%; k=21.36 – 568 mD) and low quality (Ø=3.4 – 15.7%; k=3.21 – 201.30 mD) for visualization and prediction of subsurface reservoir quality. These results provided analogy for shallow marine sandstone reservoir complexity that can be utilized in the evaluation of reservoir quality of regional and subsurface analogues.

Keywords: architecture and sedimentology, subsurface rock evaluation, reservoir quality, borneo

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Authors: Sayed Abdallah Mohamed Dahy

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Aswan High Dam Reservoir extends for 500 km along the Nile River; it is a vast reservoir in southern Egypt and northern Sudan. It was created as a result of the construction of the Aswan High Dam between 1958 and 1970; about 95% of the main water resources for Egypt are from it. The purpose of this study is to discuss and understand the effect of the fluctuation of the water level in the reservoir on natural and human-induced environmental like earthquakes in the Aswan area, Egypt. In summary, the correlation between the temporal variations of earthquake activity and water level changes in the Aswan reservoir from 1982 to 2014 are investigated and analyzed. This analysis confirms a weak relation between the fluctuation of the water level and earthquake activity in the area around Aswan reservoir. The result suggests that the seismicity in the area becomes active during a period when the water level is decreasing from the maximum to the minimum. Behavior of the water level in this reservoir characterized by a special manner that is the unloading season extends to July or August, and the loading season starts to reach its maximum in October or November every year. Finally, daily rate of change in the water level did not show any direct relation with the size of the earthquakes, hence, it is not possible to be used as a single tool for prediction.

Keywords: Aswan high dam reservoir, earthquake activity, environmental, Egypt

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Authors: Szymon Kuczynski

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Poland is characterized by the presence of numerous sedimentary basins and hydrocarbon provinces. Since 2006 exploration for hydrocarbons in Poland become gradually more focus on new unconventional targets, particularly on the shale gas potential of the Upper Ordovician and Lower Silurian in the Baltic-Podlasie-Lublin Basin. The first forecast prepared by US Energy Information Administration in 2011 indicated to 5.3 Tcm of natural gas. In 2012, Polish Geological Institute presented its own forecast which estimated maximum reserves on 1.92 Tcm. The difference in the estimates was caused by problems with calculations of the initial amount of adsorbed, as well as free, gas trapped in shale rocks (GIIP - Gas Initially in Place). This value is dependent from sorption capacity, gas saturation and mutual interactions between gas, water, and rock. Determination of the reservoir type in the initial exploration phase brings essential knowledge, which has an impact on decisions related to the production. The study of porosity impact for phase envelope shift eliminates errors and improves production profitability. Confinement phenomenon affects flow characteristics, fluid properties, and phase equilibrium. The thermodynamic behavior of confined fluids in porous media is subject to the basic considerations for industrial applications such as hydrocarbons production. In particular the knowledge of the phase equilibrium and the critical properties of the contained fluid is essential for the design and optimization of such process. In pores with a small diameter (nanopores), the effect of the wall interaction with the fluid particles becomes significant and occurs in shale formations. Nano pore size is similar to the fluid particles’ diameter and the area of particles which flow without interaction with pore wall is almost equal to the area where this phenomenon occurs. The molecular simulation studies have shown an effect of confinement to the pseudo critical properties. Therefore, the critical parameters pressure and temperature and the flow characteristics of hydrocarbons in terms of nano-scale are under the strong influence of fluid particles with the pore wall. It can be concluded that the impact of a single pore size is crucial when it comes to the nanoscale because there is possible the above-described effect. Nano- porosity makes it difficult to predict the flow of reservoir fluid. Research are conducted to explain the mechanisms of fluid flow in the nanopores and gas extraction from porous media by desorption.

Keywords: adsorption, capillary condensation, phase envelope, nanopores, unconventional natural gas

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Authors: Elizabeth G. Hereford, Geoffrey W. Gearner

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Logan’s Branch, within the Triplett Creek Watershed of Rowan County, Kentucky, is a waterway located near important agricultural and residential areas. Part of Logan’s Branch flows over an exposed black shale formation with elevated radioactivity and heavy metals. Three sites were chosen in relation to the formation and sampled five times over a thirty-day period during the recreational season. A fourth site in North Fork in Rowan County, Kentucky was also sampled periodically as it too has contact with the shale formation. These sites were then sampled monthly. All samples are analyzed for concentrations of Escherichia coli, heterotrophic bacteria, and total coliform bacteria utilizing the membrane filtration method and various culture media. Current data suggests that the radioactivity of the shale formation influences the bacteriological growth present in the waterway; however, further data will be collected and compared with that of my colleagues to confirm this trend.

Keywords: bacteriological analysis, Escherichia coli, heterotrophic bacteria, radioactive black shale formation, water quality

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Authors: Sumei Cai, Hong Li

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Either during water or gas injection into reservoir, in order to understand the areal flow pressure distribution underground, associated bounding deformation is prevalently monitored by ground or downhole tiltmeters. In this paper, an inverse solution to elastic response of far field displacements induced by reservoir pressure change due to flow injection was studied. Furthermore, the fundamental theory on inverse solution to elastic problem as well as its spatial smoothing approach is presented. Taking advantage of source code development based on Boundary Element Method, numerical analysis on the monitoring data of ground surface displacements to further understand the behavior of reservoir process was developed. Numerical examples were also conducted to verify the effectiveness.

Keywords: remote displacement, inverse problem, boundary element method, BEM, reservoir process

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Authors: Odai Ibrahim Mohammed Al Balasmeh, Tapas Karmaker, Richa Babbar

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In this study, the reservoir capacity and sediment deposition were estimated using remote sensing data. The satellite images were synchronized with water level and storage capacity to find out the change in sediment deposition due to soil erosion and transport by streamflow. The water bodies spread area was estimated using vegetation indices, e.g., normalize differences vegetation index (NDVI) and normalize differences water index (NDWI). The 3D reservoir bathymetry was modeled by integrated water level, storage capacity, and area. From the models of different time span, the change in reservoir storage capacity was estimated. Another reservoir with known water level, storage capacity, area, and sediment deposition was used to validate the estimation technique. The t-test was used to assess the results between observed and estimated reservoir capacity and sediment deposition.

Keywords: satellite data, normalize differences vegetation index, NDVI, normalize differences water index, NDWI, reservoir capacity, sedimentation, t-test hypothesis

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Authors: Chao Yang, Jinchuan Zhang, Yongqiang Xiong

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The Lower Cambrian Niutitang Formation shale (NFS) deposited in the marine deep-shelf environment in Southeast Upper Yangtze (SUY), possess excellent source rock basis for shale gas generation, however, it is currently challenged by being over-mature with strong tectonic deformations, leading to much uncertainty of gas-bearing potential. With emphasis on the shale gas enrichment of the NFS, analyses were made based on the regional gas-bearing differences obtained from field gas-desorption testing of 18 geological survey wells across the study area. Results show that the NFS bears low gas content of 0.2-2.5 m³/t, and the eastern region of SUY is higher than the western region in gas content. Moreover, the methane fraction also presents the similar regional differentiation with the western region less than 10 vol.% while the eastern region generally more than 70 vol.%. Through the analysis of geological theory, the following conclusions are drawn: Depositional environment determines the gas-enriching zones. In the western region, the Dengying Formation underlying the NFS in unconformity contact was mainly plateau facies dolomite with caves and thereby bears poor gas-sealing ability. Whereas the Laobao Formation underling the NFS in eastern region was a set of siliceous rocks of shelf-slope facies, which can effectively prevent the shale gas from escaping away from the NFS. The tectonic conditions control the gas-enriching bands in the SUY, which is located in the fold zones formed by the thrust of the Southern China plate towards to the Sichuan Basin. Compared with the western region located in the trough-like folds, the eastern region at the fold-thrust belts was uplifted early and deformed weakly, resulting in the relatively less mature level and relatively slight tectonic deformation of the NFS. Faults determine whether shale gas can be accumulated in large scale. Four deep and large normal faults in the study area cut through the Niutitang Formation to the Sinian strata, directly causing a large spillover of natural gas in the adjacent areas. For the secondary faults developed within the shale formation, the reverse faults generally have a positive influence on the shale accumulation while the normal faults perform the opposite influence. Overall, shale gas enrichment targets of the NFS, are the areas with certain thickness of siliceous rocks at the basement of the Niutitang Formation, and near the margin of the paleouplift with less developed faults. These findings provide direction for shale gas exploration in South China, and also provide references for the areas with similar geological conditions all over the world.

Keywords: over-mature marine shale, shale gas accumulation, structure-complicated area, Southeast Upper Yangtze

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Authors: Rayleigh Dada Abu, Halilu Ahmad Shaba

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Siltation is a serious problem that affects public water supply infrastructures such as dams and reservoirs. It is a major problem which threatens the performance and sustainability of dams and reservoirs. It reduces the dam capacity for flood control, potable water supply, changes water stage, reduces water quality and recreational benefits. The focus of this study is the Lower Usuma reservoir. At completion the reservoir had a gross storage capacity of 100 × 106 m3 (100 million cubic metres), a maximum operational level of 587.440 m a.s.l., with a maximum depth of 49 m and a catchment area of 241 km2 at dam site with a daily designed production capacity of 10,000 cubic metres per hour. The reservoir is 1,300 m long and feeds the treatment plant mainly by gravity. The reservoir became operational in 1986 and no survey has been conducted to determine its current storage capacity and rate of siltation. Hydrographic survey of the reservoir by integrated acoustic echo-sounding technique was conducted in November 2012 to determine the level and rate of siltation. The result obtained shows that the reservoir has lost 12.0 meters depth to siltation in 26 years of its operation; indicating 24.5% loss in installed storage capacity. The present bathymetric survey provides baseline information for future work on siltation depth and annual rates of storage capacity loss for the Lower Usuma reservoir.

Keywords: sedimentation, lower Usuma reservoir, acoustic echo sounder, bathymetric survey

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Authors: Amjad Ali Khan, Muhammad Ishaq Saqi, Kashif Ali

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The focus of hydrocarbon exploration in Pakistan has been primarily on conventional hydrocarbon resources. Directorate General Petroleum Concessions (DGPC) has taken the lead on the assessment of indigenous unconventional oil and gas resources, which has resulted in a ‘Shale Oil/Gas Resource Assessment Study’ conducted with the help of USAID. This was critically required in the energy-starved Pakistan, where the gap between indigenous oil & gas production and demand continues to widen for a long time. Exploration & exploitation of indigenous unconventional resources of Pakistan have become vital to meet our energy demand and reduction of oil and gas import bill of the country. This study has attempted to bridge a critical gap in geological information about the potential of shale gas & oil in Pakistan in the four formations, i.e., Sembar, Lower Goru, Ranikot and Ghazij in the Middle and Lower Indus Basins, which were selected for the study as for resource assessment for shale gas & oil. The primary objective of the study was to estimate and establish shale oil/gas resource assessment of the study area by carrying out extensive geological analysis of exploration, appraisal and development wells drilled in the Middle and Lower Indus Basins, along with identification of fairway(s) and sweet spots in the study area. The Study covers the Lower parts of the Middle Indus basins located in Sindh, southern Punjab & eastern parts of the Baluchistan provinces, with a total sedimentary area of 271,795 km2. Initially, 1611 wells were reviewed, including 1324 wells drilled through different shale formations. Based on the availability of required technical data, a detailed petrophysical analysis of 124 wells (21 Confidential & 103 in the public domain) has been conducted for the shale gas/oil potential of the above-referred formations. The core & cuttings samples of 32 wells and 33 geochemical reports of prospective Shale Formations were available, which were analyzed to calibrate the results of petrophysical analysis with petrographic/ laboratory analyses to increase the credibility of the Shale Gas Resource assessment. This study has identified the most prospective intervals, mainly in Sembar and Lower Goru Formations, for shale gas/oil exploration in the Middle and Lower Indus Basins of Pakistan. The study recommends seven (07) sweet spots for undertaking pilot projects, which will enable to evaluate of the actual production capability and production sustainability of shale oil/gas reservoirs of Pakistan for formulating future strategies to explore and exploit shale/oil resources of Pakistan including fiscal incentives required for developing shale oil/gas resources of Pakistan. Some E&P Companies are being persuaded to make a consortium for undertaking pilot projects that have shown their willingness to participate in the pilot project at appropriate times. The location for undertaking the pilot project has been finalized as a result of a series of technical sessions by geoscientists of the potential consortium members after the review and evaluation of available studies.

Keywords: conventional resources, petrographic analysis, petrophysical analysis, unconventional resources, shale gas & oil, sweet spots

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Authors: Aimen Saleh

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The Silurian Lower Acacus sandstone is one of the main reservoirs in North West Libya. Our aim in this study is to grasp a robust understanding of the hydrocarbon potential and distribution in the area. To date, the depositional environment of the Lower Acacus reservoir still open to discussion and contradiction. Henceforth, building three dimensional (3D) property modelling is one way to support the analysis and description of the reservoir, its properties and characterizations, so this will be of great value in this project. The 3D model integrates different data set, these incorporates well logs data, petrophysical reservoir properties and seismic data as well. The finalized depositional environment model of the Lower Acacus concludes that the area is located in a deltaic transitional depositional setting, which ranges from a wave dominated delta into tide dominated delta type. This interpretation carried out through a series of steps of model generation, core description and Formation Microresistivity Image tool (FMI) interpretation. After the analysis of the core data, the Lower Acacus layers shows a strong effect of tidal energy. Whereas these traces found imprinted in different types of sedimentary structures, for examples; presence of some crossbedding, such as herringbones structures, wavy and flaser cross beddings. In spite of recognition of some minor marine transgression events in the area, on the contrary, the coarsening upward cycles of sand and shale layers in the Lower Acacus demonstrate presence of a major regressive phase of the sea level. However, consequently, we produced a final package of this model in a complemented set of facies distribution, porosity and oil presence. And also it shows the record of the petroleum system, and the procedure of Hydrocarbon migration and accumulation. Finally, this model suggests that the area can be outlined into three main segments of hydrocarbon potential, which can be a textbook guide for future exploration and production strategies in the area.

Keywords: Acacus, Ghadames , Libya, Silurian

Procedia PDF Downloads 114

Authors: Babak Rezaei, Arash Zargar Shoushtari

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Kangan anticline is located in the Coastal Fars area, southwest of Nar and west of west Assaluyeh anticlines and north of Kangan harbor in Boushehr province. The Kangan anticline is nearly asymmetric and with 55Km long and 6Km wide base on structural map of Kangan Formation. The youngest and the oldest Formations on surface are Bakhtiyari (Pliocene) and Sarvak (Cenomanian) respectively. The highest dip angles of 30 and 40 degree were observed in north and south flanks of Kangan anticline respectively and two reverse faults cut these flanks parallel to structure strike. Existence of sweet gas in Kangan Fm. and Upper Dalan in this structure is confirmed with probable Silurian shales origin. Main facies belts in these formations include super tidal and intertidal flat, lagoon, oolitic-bioclastic shoals and open marine sub environments that expand in a homoclinal and shallow water carbonate ramp under the arid climates. Digenetic processes studies, indicates the influence of all digenetic environments (marine, meteoric, burial) in the reservoir succession. These processes sometimes has led to reservoir quality improvement (such as dolomitization and dissolution) but in many instances reservoir units has been destroyed (such as compaction, anhydrite and calcite cementation). In this study, petrophysical evaluation is made in Kangan and upper Dalan formations by using well log data of five selected wells. Probabilistic method is used for petrophysical evaluation by applying appropriate soft wares. According to this evaluation the lithology of Kangan and upper Dalan Formations mainly consist of limestone and dolomite with thin beds of Shale and evaporates. In these formations 11 Zones with different reservoir characteristic have been identified. Based on wire line data analyses, in some part of these formations, high porosity can be observed. The range of porosity (PHIE) and water saturation (Sw) are estimated around 10-20% and 20-30%, respectively.

Keywords: microfacies, electrofacies, petrophysics, diagenese, gas fields

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Authors: H. Khanfari, M. Johari Fard

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Dealing with carbonate reservoirs can be mind-boggling for the reservoir engineers due to various digenetic processes that cause a variety of properties through the reservoir. A good estimation of the reservoir heterogeneity which is defined as the quality of variation in rock properties with location in a reservoir or formation, can better help modeling the reservoir and thus can offer better understanding of the behavior of that reservoir. Most of reservoirs are heterogeneous formations whose mineralogy, organic content, natural fractures, and other properties vary from place to place. Over years, reservoir engineers have tried to establish methods to describe the heterogeneity, because heterogeneity is important in modeling the reservoir flow and in well testing. Geological methods are used to describe the variations in the rock properties because of the similarities of environments in which different beds have deposited in. To illustrate the heterogeneity of a reservoir vertically, two methods are generally used in petroleum work: Dykstra-Parsons permeability variations (V) and Lorenz coefficient (L) that are reviewed briefly in this paper. The concept of Lorenz is based on statistics and has been used in petroleum from that point of view. In this paper, we correlated the statistical-based Lorenz method to a petroleum concept, i.e. Kozeny-Carman equation and derived the straight line plot of Lorenz graph for a homogeneous system. Finally, we applied the two methods on a heterogeneous field in South Iran and discussed each, separately, with numbers and figures. As expected, these methods show great departure from homogeneity. Therefore, for future investment, the reservoir needs to be treated carefully.

Keywords: carbonate reservoirs, heterogeneity, homogeneous system, Dykstra-Parsons permeability variations (V), Lorenz coefficient (L)

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Authors: Atif Zafar, Fan Haijun

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A sequence of different Reservoir Engineering methods and tools in reservoir characterization and field development are presented in this paper. The real data of Jin Gas Field of L-Basin of Pakistan is used. The basic concept behind this work is to enlighten the importance of well test analysis in a broader way (i.e. reservoir characterization and field development) unlike to just determine the permeability and skin parameters. Normally in the case of reservoir characterization we rely on well test analysis to some extent but for field development plan, the well test analysis has become a forgotten tool specifically for locations of new development wells. This paper describes the successful implementation of well test analysis in Jin Gas Field where the main uncertainties are identified during initial stage of field development when location of new development well was marked only on the basis of G&G (Geologic and Geophysical) data. The seismic interpretation could not encounter one of the boundary (fault, sub-seismic fault, heterogeneity) near the main and only producing well of Jin Gas Field whereas the results of the model from the well test analysis played a very crucial rule in order to propose the location of second well of the newly discovered field. The results from different methods of well test analysis of Jin Gas Field are also integrated with and supported by other tools of Reservoir Engineering i.e. Material Balance Method and Volumetric Method. In this way, a comprehensive way out and algorithm is obtained in order to integrate the well test analyses with Geological and Geophysical analyses for reservoir characterization and field development. On the strong basis of this working and algorithm, it was successfully evaluated that the proposed location of new development well was not justified and it must be somewhere else except South direction.

Keywords: field development plan, reservoir characterization, reservoir engineering, well test analysis

Procedia PDF Downloads 336