Search results for: shale reservoir

Authors: Rudi Ryacudu, Edi Artono, Gema Wahyudi Purnama

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Oil and gas consumption in Indonesia is currently on the rise due to its nation economic improvement. Unfortunately, Indonesia’s domestic oil production cannot meet it’s own consumption and Indonesia has lost its status as Oil and Gas exporter. Even worse, our conventional oil and gas reserve is declining. Unwilling to give up, the government of Indonesia has taken measures to invite investors to invest in domestic oil and gas exploration to find new potential reserve and ultimately increase production. Yet, it has not bear any fruit. Indonesia has taken steps now to explore new unconventional oil and gas play including Shale Gas, Shale Oil and Tight Sands to increase domestic production. These new plays require definite parameters to differentiate each concept. The purpose of this paper is to provide ways in defining unconventional hydrocarbon reservoir parameters in Shale Gas, Shale Oil and Tight Sands. The parameters would serve as an initial baseline for users to perform analysis of unconventional hydrocarbon plays. Some of the on going concerns or question to be answered in regards to unconventional hydrocarbon plays includes: 1. The TOC number, 2. Has it been well “cooked” and become a hydrocarbon, 3. What are the permeability and the porosity values, 4. Does it need a stimulation, 5. Does it has pores, and 6. Does it have sufficient thickness. In contrast with the common oil and gas conventional play, Shale Play assumes that hydrocarbon is retained and trapped in area with very low permeability. In most places in Indonesia, hydrocarbon migrates from source rock to reservoir. From this case, we could derive a theory that Kitchen and Source Rock are located right below the reservoir. It is the starting point for user or engineer to construct basin definition in relation with the tectonic play and depositional environment. Shale Play concept requires definition of characteristic, description and reservoir identification to discover reservoir that is technically and economically possible to develop. These are the steps users and engineers has to do to perform Shale Play: a. Calculate TOC and perform mineralogy analysis using water saturation and porosity value. b. Reconstruct basin that accumulate hydrocarbon c. Brittlenes Index calculated form petrophysical and distributed based on seismic multi attributes d. Integrated natural fracture analysis e. Best location to place a well.

Keywords: unconventional hydrocarbon, shale gas, shale oil tight sand reservoir parameters, shale play

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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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Authors: Yanal Abul Failat

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The production of oil and natural gas from shale formations is becoming a trend, and many countries with technically and economically recoverable unconventional resources are endeavoring to explore how shale formations may benefit the economy and achieve energy security. The trajectory of shale gas development in the UK is highly supported by the government; in the Gas Generation Strategy Paper published by the UK government on 5 December 2013, it is recognized that the shale gas production would decrease reliance on imports and thus enhance the UK’s energy security. Moreover, the UK Institute of Directors report on UK Shale Gas Potential explains that in the UK there is a potential of production peaking at around 1.13 trillion cubic feet (“tcf”) and a sector that could support around 70,000 jobs and secure net benefit to the Treasury in tax revenues. On this basis, there has been a growing interest in the benefits of exploring the UK’s shale gas but a combination of technical challenges faced in shale gas operations, a stern opposition by environmentalists and concerns on the adequacy of the legal framework have slowed the progress of the emerging UK shale industry.

Keywords: shale gas, UK, legal, oil and gas, energy

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Authors: Chinedu Ejike

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The United States is now energy self-sufficient due to the production of shale oil reserves. With more than half of it being tapped daily in the United States, these unconventional reserves are massive and provide immense potential for future energy demands. Drilling horizontal wells and fracking are the primary methods for developing these reserves. Regrettably, recovery efficiency is rarely greater than 10%. As a result, optimizing recuperation offers a significant benefit. Huff and puff gas flooding and cyclic gas injection have all been demonstrated to be more successful than tapping the remaining oil in place. Methane, nitrogen, and carbon (IV) oxide, among other high-pressure gases, can be injected. Operators use Darcy's law to assess a reservoir's productive capacity, but they are unaware that the law may not apply to shale oil reserves. This is due to the fact that, unlike pressure differences alone, diffusion, concentration, and gas selection all play a role in the flow of gas injected into the wellbore. The reservoir drainage and oil sweep efficiency rates are determined by the transport method. This research assesses the parameters that influence the gas injection transport mechanism. Understanding the process causing these factors could accelerate recovery by two to three times, according to peer-reviewed studies and effective field testing.

Keywords: enhanced oil recovery, gas injection, shale oil, transport mechanism, unconventional reserve

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Authors: Tawfig Alghbaili

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LP3D Field is located near the center of the Sirt Basin in the Marada Trough approximately 215 km south Marsa Al Braga City. The Marada Trough is bounded on the west by a major fault, which forms the edge of the Beda Platform, while on the east, a bounding fault marks the edge of the Zelten Platform. The main reservoir in the LP3D Field is Upper Paleocene Beda Formation. The Beda Formation is mainly limestone interbedded with shale. The reservoir average thickness is 117.5 feet. To develop a better understanding of the characterization and distribution of the Beda reservoir, quantitative seismic data interpretation has been done, and also, well logs data were analyzed. Six reflectors corresponding to the tops of the Beda, Hagfa Shale, Gir, Kheir Shale, Khalifa Shale, and Zelten Formations were picked and mapped. Special work was done on fault interpretation part because of the complexities of the faults at the structure area. Different attribute analyses were done to build up more understanding of structures lateral extension and to view a clear image of the fault blocks. Time to depth conversion was computed using velocity modeling generated from check shot and sonic data. The simplified stratigraphic cross-section was drawn through the wells A1, A2, A3, and A4-LP3D. The distribution and the thickness variations of the Beda reservoir along the study area had been demonstrating. Petrophysical analysis of wireline logging also was done and Cross plots of some petrophysical parameters are generated to evaluate the lithology of reservoir interval. Structure and Stratigraphic Framework was designed and run to generate different model like faults, facies, and petrophysical models and calculate the reservoir volumetric. This study concluded that the depth structure map of the Beda formation shows the main structure in the area of study, which is north to south faulted anticline. Based on the Beda reservoir models, volumetric for the base case has been calculated and it has STOIIP of 41MMSTB and Recoverable oil of 10MMSTB. Seismic attributes confirm the structure trend and build a better understanding of the fault system in the area.

Keywords: LP3D Field, Beda Formation, reservoir models, Seismic attributes

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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: 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: Ahmed M. Al-Mutarreb, Shiferaw R. Jufar

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Global shale gas resource assessment is still in its preliminary stage in most of the countries including the development of shale gas reservoirs in Malaysia. This project presents the main geochemical and mineral characteristics of few Malaysian’s shale samples which contribute on evaluating shale gas reserve world resource evaluations. Three shale samples from the western part of Peninsular Malaysia (Batu-Caja, Kuala Lumpur, and Johor Baru shale formations) were collected for this study. Total organic carbon wt.%, thermal maturity, kerogen type, mineralogy and adsorption/desorption characteristics are measured at Universiti Teknologi PETRONAS laboratories. Two samples show good potential in TOC results exhibited > 2wt.% exceeding the minimum values of Shale gas potential, while the third revealed < 1.5wt. Mineralogical compositions for the three samples are within the acceptable range percentage% of quartz and clays compared to shale plays in USA. This research’s results are promising and recommend to continue exploring and assessing unconventional shale gas reserves values in these areas.

Keywords: shale gas characterizations, geochemical properties, Malaysia, shale gas reserve

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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: Hadayat Ullah, Pervez Khalid, Saad Ahmed Mashwani, Zaheer Abbasi, Mubashir Mehmood, Muhammad Jahangir, Ehsan ul Haq

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The aim of the study is to explore subsurface structures through data that is acquired from the seismic survey to delineate the characteristics of the reservoir through petrophysical analysis. Ghazij Shale of Eocene age is regional seal rock in this field. In this research work, 3D property models of subsurface were prepared by applying Petrel software to identify various lithologies and reservoir fluids distribution throughout the field. The 3D static modeling shows a better distribution of the discrete and continuous properties in the field. This model helped to understand the reservoir properties and enhance production by selecting the best location for future drilling. A complete workflow is proposed for formation evaluation, electrofacies modeling, and structural interpretation of the subsurface geology. Based on the wireline logs, it is interpreted that the thickness of the Pab Sandstone varies from 250 m to 350 m in the entire study area. The sandstone is massive with high porosity and intercalated layers of shales. Faulted anticlinal structures are present in the study area, which are favorable for the accumulation of hydrocarbon. 3D structural models and various seismic attribute models were prepared to analyze the reservoir character of this clastic reservoir. Based on wireline logs and seismic data, clean sand, shaly sand, and shale are marked as dominant facies in the study area. However, clean sand facies are more favorable to act as a potential net pay zone.

Keywords: cretaceous, pab sandstone, petrophysics, electrofacies, hydrocarbon

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Authors: Abrar Al-Mutairi, Talal Al-Bazali

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In this study, changes in capillary entry pressure of shale, as it interacts with CO₂, under different temperatures (25 °C to 250 °C) have been investigated. The combined impact of temperature and petrophysical properties (water content, water activity, permeability and porosity) of shale was also addressed. Results showed that the capillary entry pressure of shale when it interacted with CO₂ was highly affected by temperature. In general, increasing the temperature decreased capillary entry pressure of shale. We believe that pore dilation, where pore throat size expands due to the application of heat, may have caused this decrease in capillary entry pressure of shale. However, in some cases we found that at higher temperature some shale samples showed that the temperature activated clay swelling may have caused an apparent decrease in pore throat radii of shale which translates into higher capillary entry pressure of shale. Also, our results showed that there is no distinct relationship between shale’s water content, water activity, permeability, and porosity on the capillary entry pressure of shale samples as it interacted with CO₂ at different temperatures.

Keywords: heat, threshold pressure, CO₂ sequestration, shale

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Authors: Xianglu Tang, Zhenxue Jiang, Zhuo Li

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Characterization of shale multi scale heterogeneity is an important part to evaluate size and space distribution of shale gas reservoirs in sedimentary basins. The origin of shale heterogeneity has always been a hot research topic for it determines shale micro characteristics description and macro quality reservoir prediction. Shale multi scale heterogeneity was discussed based on thin section observation, FIB-SEM, QEMSCAN, TOC, XRD, mercury intrusion porosimetry (MIP), and nitrogen adsorption analysis from 30 core samples in Silurian Longmaxi formation. Results show that shale heterogeneity can be characterized by pore structure and mineral composition. The heterogeneity of shale pore is showed by different size pores at nm-μm scale. Macropores (pore diameter > 50 nm) have a large percentage of pore volume than mesopores (pore diameter between 2~ 50 nm) and micropores (pore diameter < 2nm). However, they have a low specific surface area than mesopores and micropores. Fractal dimensions of the pores from nitrogen adsorption data are higher than 2.7, what are higher than 2.8 from MIP data, showing extremely complex pore structure. This complexity in pore structure is mainly due to the organic matter and clay minerals with complex pore network structures, and diagenesis makes it more complicated. The heterogeneity of shale minerals is showed by mineral grains, lamina, and different lithology at nm-km scale under the continuous changing horizon. Through analyzing the change of mineral composition at each scale, random arrangement of mineral equal proportion, seasonal climate changes, large changes of sedimentary environment, and provenance supply are considered to be the main reasons that cause shale minerals heterogeneity from microcosmic to macroscopic. Due to scale effect, the change of shale multi scale heterogeneity is a discontinuous process, and there is a transformation boundary between homogeneous and in homogeneous. Therefore, a shale multi scale heterogeneity changing model is established by defining four types of homogeneous unit at different scales, which can be used to guide the prediction of shale gas distribution from micro scale to macro scale.

Keywords: heterogeneity, homogeneous unit, multiscale, shale

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Authors: Hillary Mwongyera

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The Semliki basin has become a frontier for petroleum exploration in recent years. Exploration efforts have resulted into extensive seismic data acquisition and drilling of three wells namely; Turaco 1, Turaco 2 and Turaco 3. A petrophysical analysis of the Turaco 1 well was carried out to identify two reservoir zones on which AVO modeling was performed. A combination of seismic modeling and rock physics modeling was applied during reservoir characterization and monitoring to determine variations of seismic responses with amplitude characteristics. AVO intercept gradient analysis applied on AVO synthetic CDP gathers classified AVO anomalies associated with both reservoir zones as Class 1 AVO anomalies. Fluid replacement modeling was carried out on both reservoir zones using homogeneous mixing and patchy saturation patterns to determine effects of fluid substitution on rock property interactions. For both homogeneous mixing and saturation patterns, density (ρ) showed an increasing trend with increasing brine substitution while Shear wave velocity (Vs) decreased with increasing brine substitution. A study of compressional wave velocity (Vp) with increasing brine substitution for both homogeneous mixing and patchy saturation gave quite interesting results. During patchy saturation, Vp increased with increasing brine substitution. During homogeneous mixing however, Vp showed a slightly decreasing trend with increasing brine substitution but increased tremendously towards and at full brine saturation. A sensitivity analysis carried out showed that density was a very sensitive rock property responding to brine saturation except at full brine saturation during homogeneous mixing where Vp showed greater sensitivity with brine saturation. Rock physics modeling was performed to predict diagnostics of reservoir quality using an inverse deterministic approach which showed low shale content and a high degree of shale stiffness within reservoir zones.

Keywords: Amplitude Versus Offset (AVO), fluid replacement modelling, reservoir characterization, AVO attributes, rock physics modelling, reservoir monitoring

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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: Mohamed Mehdi Kadri

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The prediction of hot shale interval in Silurian formation in a well drilled vertically in Ahnet basin Is by logging Data (Resistivity, Gamma Ray, Sonic) with the calculation of total organic carbon (TOC) using ∆ log R Method. The aim of this paper is to present Physico-chemical Properties of Hot Shale using IR spectroscopy and gas chromatography-mass spectrometry analysis; this mixture of measurements, evaluation and characterization show that the hot shale interval located in the lower of Silurian, the molecules adsorbed at the surface of shale sheet are significantly different from petroleum hydrocarbons this result are also supported with gas-liquid chromatography showed that the study extract is a hydroxypropyl.

Keywords: physic-chemical analysis, reservoirs characterization, sweet window evaluation, Silurian shale, Ahnet basin

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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: M. K. Kim, C. H. Shin, W. G. Park

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Recently, natural gas resources are issued due to alternative and eco-friendly energy policies, and development of even unconventional gas resources including tight gas, coal bed methane and shale gas is being rapidly expanded from North America all over the world. For developing these gas reservoirs, it is necessary to investigate reservoir characteristics by using reservoir simulation. In reservoir simulation, calculation of permeability of fractured zone is very important to predict the gas production. However, it is difficult to accurately calculate the permeability by using conventional methods which use analytic solution for laminar flow. The flow in gas reservoirs exhibits complex flow behavior such as slip around the wall roughness effect and turbulence because the size of the apertures of fractures is ranged over various scales from nano-scale to centi-scale. Therefore, it is required to apply new reservoir flow analysis methods which can accurately consider complex gas flow owing to the geometric characteristics and distributions of various pores and flow paths within gas reservoirs. Hence, in this study, the flow characteristics and the relation between each characteristic variable was investigated and multi-effect was quantified when the fractures are compounded for devising a new calculation model of permeability of fractured zone in gas reservoirs by using CFD.

Keywords: fractured zone, gas reservoir, permeability, CFD

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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: Vaishali Sharma, Anirbid Sircar

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Energy is one of the most eminent and fundamental strategic commodity, scarcity of which may poses great impact on the functioning of the entire commodity. According to the present study, the estimated reserves of gas in India as on 31.03.2015 stood at 1427.15 BCM. It is expected that the gas demand is set to grow significantly at a CAGR of 7% from 226.7 MMSCMD in 2012-13 to 713.5 MMSCMD in 2009-30. To bridge the gap between the demand and supply of energy, the interest towards the exploration and exploitation of unconventional resources like – Shale gas, Coal bed methane, Gas hydrates, tight gas etc has immensed. Nowadays, Shale gas prospects are emerging rapidly as a promising energy source globally. The United States of America (USA) has 240 TCF of proved reserves of shale gas and presently contributed more than 17% of total gas production. As compared to USA, shale gas production in India is at nascent stage. A resource potential of around 2000 TCF is estimated and according to preliminary data analysis, basins like Gondwana, Cambay, Krishna – Godavari, Cauvery, Assam-Arakan, Rajasthan, Vindhyan, and Bengal are the most promising shale gas basins. In the present study, the careful evaluation of Cambay Shale (Indian Shale) properties like geological age, lithology, depth, organically rich thickness, TOC, thermal maturity, porosity, permeability, clay content, quartz content, Kerogen type, Hydrocarbon window etc. has been done. And then the detailed comparison of Indian shale with USA shale will be discussed. This study investigates qualitative and quantitative nature of potential shale basins which will be helpful from exploration and exploitation point of view.

Keywords: shale, shale gas, energy source, lithology

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Authors: Elijah Acquah-Andoh

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The UK has had its fair share of the shale gas revolutionary waves blowing across the global oil and gas industry at present. Although, its exploitation is widely agreed to have been delayed, shale gas was looked upon favorably by the UK Parliament when they recognized it as genuine energy source and granted licenses to industry to search and extract the resource. This, although a significant progress by industry, there yet remains another test the UK fracking resource must pass in order to render shale gas extraction feasible – it must be economically extractible and sustainably so. Developing unconventional resources is much more expensive and risky, and for shale gas wells, producing in commercial volumes is conditional upon drilling horizontal wells and hydraulic fracturing, techniques which increase CAPEX. Meanwhile, investment in shale gas development projects is sensitive to gas price and technical and geological risks. Using a Two-Factor Model, the economics of the Bowland shale wells were analyzed and the operational conditions under which fracking is profitable in the UK was characterized. We find that there is a great degree of flexibility about Opex spending; hence Opex does not pose much threat to the fracking industry in the UK. However, we discover Bowland shale gas wells fail to add value at gas price of $8/ Mmbtu. A minimum gas price of $12/Mmbtu at Opex of no more than $2/ Mcf and no more than $14.95M Capex are required to create value within the present petroleum tax regime, in the UK fracking industry.

Keywords: capex, economical, investment, profitability, shale gas development, sustainable

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Authors: Ghulam Sohail, Christopher Hawkes

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Pakistan has been facing a growing energy crisis for the last decade, and the government is seeking new horizons for increasing oil and gas production to reduce the gap between supply and demand. Recent developments in technologies to produce natural gas from shales at economical rates has unlocked new horizons for hydrocarbon exploration and development throughout the world. Operating companies in the U.S.A. and Canada have been particularly successful at producing shale gas, so comparing against the properties of shale gas reservoirs in these countries is used for an initial assessment of prospective shale gas reservoirs in other parts of the world. In this study, selected source rocks of Pakistan are evaluated for their shale gas potential using analogs selected from various North American shales for which data have been published. Published data for Pakistani shales were compiled, then assessed and supplemented through consultation with industry professionals. Pakistani formations reviewed are the Datta (shaly sandstone), Hangu (sandy shale), Patala (sandy shale), Ranikot (shaly sandstone), Sembar (sandy shale) and Lower Goru (shaly sandstone) formations, all of which are known source rocks in the Indus Basin. For this study, available geological, geochemical, petrophysical and elastic parameters have been investigated and are correlated specifically with the eight most active shale gas plays of the U.S.A., while data for other North American shale gas plays are used for general discussion on prospective Pakistani shales. The results show that the geological and geochemical parameters of all the Pakistani shales reviewed in this work are promising regarding their shale gas. However, more petrophysical and geomechanical data are required before conclusions on economic production from these shales can be made with confidence.

Keywords: Canada shale gas, Indus Basin, Pakistani shales, U.S.A shale gas

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Authors: Ayman Mutahar Alrassas, Shaoran Ren, Renyuan Ren, Hung Vo Thanh, Mohammed Hail Hakimi, Zhenliang Guan

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The significant effect of CO₂ on global climate and the environment has gained more concern worldwide. Enhance oil recovery (EOR) associated with sequestration of CO₂ particularly into the depleted oil reservoir is considered the viable approach under financial limitations since it improves the oil recovery from the existing oil reservoir and boosts the relation between global-scale of CO₂ capture and geological sequestration. Consequently, practical measurements are required to attain large-scale CO₂ emission reduction. This paper presents an integrated modeling workflow to construct an accurate 3D reservoir geological model to estimate the storage capacity of CO₂ under geological uncertainty in an unconventional oil reservoir of the Paleogene Shahejie Formation (Es1) in the block Nv32, Shenvsi oilfield, China. In this regard, geophysical data, including well logs of twenty-two well locations and seismic data, were combined with geological and engineering data and used to construct a 3D reservoir geological modeling. The geological modeling focused on four tight reservoir units of the Shahejie Formation (Es1-x1, Es1-x2, Es1-x3, and Es1-x4). The validated 3D reservoir models were subsequently used to calculate the theoretical CO₂ storage capacity in the block Nv32, Shenvsi oilfield. Well logs were utilized to predict petrophysical properties such as porosity and permeability, and lithofacies and indicate that the Es1 reservoir units are mainly sandstone, shale, and limestone with a proportion of 38.09%, 32.42%, and 29.49, respectively. Well log-based petrophysical results also show that the Es1 reservoir units generally exhibit 2–36% porosity, 0.017 mD to 974.8 mD permeability, and moderate to good net to gross ratios. These estimated values of porosity, permeability, lithofacies, and net to gross were up-scaled and distributed laterally using Sequential Gaussian Simulation (SGS) and Simulation Sequential Indicator (SIS) methods to generate 3D reservoir geological models. The reservoir geological models show there are lateral heterogeneities of the reservoir properties and lithofacies, and the best reservoir rocks exist in the Es1-x4, Es1-x3, and Es1-x2 units, respectively. In addition, the reservoir volumetric of the Es1 units in block Nv32 was also estimated based on the petrophysical property models and fund to be between 0.554368

Keywords: CO₂ storage capacity, 3D geological model, geological uncertainty, unconventional oil reservoir, block Nv32

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Authors: Safwat E. Musa, Nuha E. Mohamed, Nuha A. Bagi

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In this study, several crossplots of the P-impedance with the lithology logs (gamma ray, neutron porosity, deep resistivity, water saturation and Vp/Vs curves) were made in three available wells, which were drilled in central part of the Blue Nile basin in depths varies from 1460 m to 1600 m. These crossplots were successful to discriminate between sand and shale when using P-Impedance values, and between the wet sand and the pay sand when using both P-impedance and Vp/Vs together. Also, some impedance sections were converted to porosity sections using linear formula to characterize the reservoir in terms of porosity. The used crossplots were created on log resolution, while the seismic resolution can identify only the reservoir, unless a 3D seismic angle stacks were available; then it would be easier to identify the pay sand with great confidence; through high resolution seismic inversion and geostatistical approach when using P-impedance and Vp/Vs volumes.

Keywords: basin, Blue Nile, inversion, seismic

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Authors: Nader Mohamed

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The Late Cretaceous deposits are well developed through-out Egypt. This is due to a ‎transgression phase associated with the subsidence caused by the neo-Tethyan rift event that ‎took place across the northern margin of Africa, resulting in a period of dominantly marine ‎deposits in the Gulf of Suez. The Late Cretaceous Nezzazat Group represents the Cenomanian, ‎Turonian and clastic sediments of the Lower Senonian. The Nezzazat Group has been divided ‎into four formations namely, from base to top, the Raha Formation, the Abu Qada Formation, ‎the Wata Formation and the Matulla Formation. The Cenomanian Raha and the Lower Senonian ‎Matulla formations are the most important clastic sequence in the Nezzazat Group because they ‎provide the highest net reservoir thickness and the highest net/gross ratio. This study emphasis ‎on Matulla formation located in the eastern part of the Gulf of Suez. The three stratigraphic ‎surface sections (Wadi Sudr, Wadi Matulla and Gabal Nezzazat) which represent the exposed ‎Coniacian-Santonian sediments in Sinai are used for correlating Matulla sediments of Ras ‎Budran field. Cutting description, petrographic examination, log behaviors, biostratigraphy with ‎outcrops are used to identify the reservoir characteristics, lithology, facies environment logs and ‎subdivide the Matulla formation into three units. The lower unit is believed to be the main ‎reservoir where it consists mainly of sands with shale and sandy carbonates, while the other ‎units are mainly carbonate with some streaks of shale and sand. Reservoir modeling is an ‎effective technique that assists in reservoir management as decisions concerning development ‎and depletion of hydrocarbon reserves, So It was essential to model the Matulla reservoir as ‎accurately as possible in order to better evaluate, calculate the reserves and to determine the ‎most effective way of recovering as much of the petroleum economically as possible. All ‎available data on Matulla formation are used to build the reservoir structure model, lithofacies, ‎porosity, permeability and water saturation models which are the main parameters that describe ‎the reservoirs and provide information on effective evaluation of the need to develop the oil ‎potentiality of the reservoir. This study has shown the effectiveness of; 1) the integration of ‎geological data to evaluate and subdivide Matulla formation into three units. 2) Lithology and ‎facies environment interpretation which helped in defining the nature of deposition of Matulla ‎formation. 3) The 3D reservoir modeling technology as a tool for adequate understanding of the ‎spatial distribution of property and in addition evaluating the unlocked new reservoir areas of ‎Matulla formation which have to be drilled to investigate and exploit the un-drained oil. 4) This ‎study led to adding a new room of production and additional reserves to Ras Budran field. ‎

Keywords: geology, oil and gas, geoscience, sequence stratigraphy

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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: Axel Priambodo, Dwiharso Nugroho

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Studies conducted to map the reservoir properties based on facies architecture in which to determine the distribution of the petrophysical properties and calculate hydrocarbon reserves in study interval. Facies Architecture analysis begins with stratigraphic correlation that indicates the area is divided into different system tracts. The analysis of distribution patterns and compiling core analysis with facies architecture model show that there are three estuarine facies appear. Formation evaluation begins with shale volume calculation using Asquith-Krygowski and Volan Triangle Method. Proceed to the calculation of the total and effective porosity using the Bateman-Konen and Volan Triangle Method. After getting the value of the porosity calculation was continued to determine the effective water saturation and non-effective by including parameters of water resistivity and resistivity clay. The results of the research show that the Facies Architecture on the field in divided into three main facies which are Estuarine Channel, Estuarine Sand Bar, and Tidal Flat. The petrophysics analysis are done by comparing different methods also shows that the Volan Triangle Method does not give a better result of the Volume Shale than the Gamma Ray Method, but on the other hand, the Volan Triangle Methode is better on calculating porosity compared to the Bateman-Konen Method. The effective porosity distributions are affected by the distribution of the facies. Estuarine Sand Bar has a low porosity number and Estuarine Channel has a higher number of the porosity. The effective water saturation is controlled by structure where on the closure zone the water saturation is lower than the area beneath it. It caused by the hydrocarbon accumulation on the closure zone.

Keywords: petrophysics, geology, petroleum, reservoir

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Authors: Xin Li, Zhenxue Jiang, Zhuo Li

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Generally, shale gas is trapped within shale systems with low porosity and ultralow permeability as free and adsorbing states. Its production is controlled by properties, in terms of occurrence phases, gas contents, and percolation characteristics. These properties are all influenced by porous features. In this paper, porosity differences of marine shales were explored between Lower Cambrian shale and Lower Silurian shale of Sichuan Basin, South China. Both the two shales were marine shales with abundant oil-prone kerogen and rich siliceous minerals. Whereas Lower Cambrian shale (3.56% Ro) possessed a higher thermal degree than that of Lower Silurian shale (2.31% Ro). Samples were measured by a combination of organic-chemistry geology measurement, organic matter (OM) isolation, X-ray diffraction (XRD), N2 adsorption, and focused ion beam milling and scanning electron microscopy (FIB-SEM). Lower Cambrian shale presented relatively low pore properties, with averaging 0.008ml/g pore volume (PV), averaging 7.99m²/g pore surface area (PSA) and averaging 5.94nm average pore diameter (APD). Lower Silurian shale showed as relatively high pore properties, with averaging 0.015ml/g PV, averaging 10.53m²/g PSA and averaging 18.60nm APD. Additionally, fractal analysis indicated that the two shales presented discrepant pore morphologies, mainly caused by differences in the combination of pore types between the two shales. More specifically, OM-hosted pores with pin-hole shape and dissolved pores with dead-end openings were the main types in Lower Cambrian shale, while OM-hosted pore with a cellular structure was the main type in Lower Silurian shale. Moreover, porous characteristics of isolated OM suggested that OM of Lower Silurian shale was more capable than that of Lower Cambrian shale in the aspect of pore contribution. PV of isolated OM in Lower Silurian shale was almost 6.6 times higher than that in Lower Cambrian shale, and PSA of isolated OM in Lower Silurian shale was almost 4.3 times higher than that in Lower Cambrian shale. However, no apparent differences existed among samples with various matrix compositions. At late diagenetic or metamorphic epoch, extensive diagenesis overprints the effects of minerals on pore properties and OM plays the dominant role in pore developments. Hence, differences of porous features between the two marine shales highlight the effect of diagenetic degree on OM-hosted pore development. Consequently, distinctive pore characteristics may be caused by the different degrees of diagenetic evolution, even with similar matrix basics.

Keywords: marine shale, lower Cambrian, lower Silurian, om isolation, pore properties, om-hosted pore

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Authors: A. A. Embaby, A. Abu Halawa, M. Ramadan

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In Kingdom of Saudi Arabia, there are several areas where expansive soil exists in the form of variable-thicknesses layers in the developed regions. Severe distress to infrastructures can be caused by the development of heave and swelling pressure in this kind of expansive shale. Among the various techniques for expansive soil mitigation, the removal and replacement technique is very popular for lightly loaded structures and shallow foundations. This paper presents the result of an experimental study conducted for evaluating the effect of type and thickness of the cushion soils on mitigation of swelling characteristics of expanded shale. Seven undisturbed shale samples collected from Al Qadsiyah district, which is located in the Tabuk town north Kingdom of Saudi Arabia, are treated with two types of cushion coarse-grained sediments (CCS); sand and gravel. Each type is represented with three thicknesses, 22%, 33% and 44% in relation to the depth of the active zone. The test results indicated that the replacement of expansive shale by CCS reduces the swelling potential and pressure. It is found that the reduction in swelling depends on the type and thickness of CCS. The treatment by removing the original expansive shale and replacing it by cushion sand with 44% thickness reduced the swelling potential and pressure of about 53.29% and 62.78 %, respectively.

Keywords: cushion coarse-grained sediments (CCS), expansive soil, Saudi Arabia, swelling pressure, Tabuk Shale

Procedia PDF Downloads 283

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: 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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