Lower Shale Research Articles

Influence of the Emeishan basalt eruption on shale gas enrichment: A case study of shale from Wufeng-Longmaxi formations in northern Yunnan and Guizhou provinces

The eruption or invasion of the Emeishan basalt has a systematic impact on the maturity of shale organic matters, hydrocarbon-generation evolution, reservoir physical properties and gas-bearing properties of shale, which is directly related to the preservation and accumulation of shale gas. By taking four typical shale gas wells in northern Yunnan and Guizhou provinces of China as examples, the influence of the basalt eruption on shale gas enrichment of Wufeng-Longmaxi formations is analyzed. The results show that: The shale near the basalt eruption area reached the late stage of over-mature ahead of time, with the equivalent Ro greater than 3.0%. Close to the basalt eruption zone, the porosity and permeability are significantly reduced. The low shale gas content and high N2 component are related to the abnormal thermal effect of the basalt and the acceleration of hydrocarbon-generation process. N2 content indicates the shale gas preservation conditions. Near the basalt eruption area, the formation temperature increases, the liquid hydrocarbon wet gas is formed early, the peak-period of gas-generation moves forward greatly, the shale gas experiences more tectonic movements and prolonged preservation periods. In conclusion, the eruption or invasion of the Emeishan basalt is unfavorable for the shale gas enrichment of Wufeng-Longmaxi formations, while the large amount of discharged shale oil and gas in the early stage is favorable for the conventional natural gas accumulation of overlying strata. It is suggested that the exploration should be focused on conventional gas and supplemented by shale gas in area with large basalt distribution.

Hartha Formation divisions Based on Well Logs Analysis in Majnoon Oil Field, Southern Iraq

This study aims to evaluate reservoir characteristics of Hartha Formation in Majnoon oil field based on well logs data for three wells (Mj-1, Mj-3 and Mj-11). Log interpretation was carried out by using a full set of logs to calculate main petrophysical properties such as effective porosity and water saturation, as well as to find the volume of shale. The evaluation of the formation included computer processes interpretation (CPI) using Interactive Petrophysics (IP) software. Based on the results of CPI, Hartha Formation is divided into five reservoir units (A1, A2, A3, B1, B2), deposited in a ramp setting. Facies associations is added to well logs interpretation of Hartha Formation, and was inferred by a microfacies analysis of thin sections from core and cutting samples. The CPI shows that the A2 is the main oil- bearing unit, which is characterized by good reservoir properties, as indicated by high effective porosity, low water saturation, and low shale volume. Less important units include A1 and A3, because they have low petrophysical properties compared to the unit A2.

Geochemical signatures of manganese ores around Barbil, Noamundi-Koira basin, Singhbhum Craton, Eastern India

ABSTRACT Palaeoproterozoic Noamundi – Koira Basin (NKB), on the western margin of the >3.0 Ga old Singhbhum Granitoid Complex, forms a horseshoe-shaped synclinorium. Volcanic rocks belonging to Bonai volcanic suite (BVS) occur outside and all-around the NKB that consists of three distinct but conformable stratigraphic units viz; Lower Shale Formation, Middle Banded Hematite Quartzite (BHQ) and/or Banded Hematite Jasper (BHJ) and Upper Shale Formation. The layered, lensoid, lateritoid, and vein type Mn-ore bodies are associated with the Upper Shale Formation. Compositions of the Mn ores widely variable values, SiO2 (1.00%- 16.40%), Al2O3 (1.62%-17.20%), Fe2O3 (10.55%-63.28%), MnO (31.75% −75.72%), Ni (25–260 ppm), Co (78–350 ppm), Zn (82–509 ppm) and Cr (13–187 ppm) clearly reflect their submarine hydrothermal source. Litho-stratigraphic considerations also lead to suggest that BHJ/BHQ and Mn-ore deposits of NKB are genetically related to the BVS. It is suggested that manganese and iron ores were deposited in a (? Forearc) basin associated with the mature island arc or active continental margin setting. FeO and MnO were added to the basin by hydrothermal solutes produced during the Bonai volcanism. BHQ/BHJ precipitation took place under a low redox potential while Mn-ore deposition is a consequence of the high redox potential.

An integrated scheme of coal-assisted oil shale efficient pyrolysis and high-value conversion of pyrolysis oil

Shale oil produced from oil shale pyrolysis is regarded as an important alternative to crude oil. There is the conventional oil shale pyrolysis technology represented by Fushun-type, which suffers from low utilization efficiency of oil shale and low shale oil production. The development of the indirectly heated moving bed technology can solve these problems. However, this new technology requires extra heat for oil shale pyrolysis which means low pyrolysis efficiency and it also suffers from the production of low quality shale oil. The driving force for the efficient pyrolysis of oil shale and high-value conversion of shale oil calls for the involvement of high-value fuel to supply heat for pyrolysis and hydrogen source for shale oil upgradation. Coal is produced in the process of oil shale mining. A new process of coal-assisted oil shale refinery is therefore proposed in this study. Coal is used for gasification to produce syngas. Part of the syngas is used as fuel to supply additional heat for oil shale pyrolysis and the remaining syngas is used to produce hydrogen, which is then used for shale oil hydrogenation to increase the quality of shale oil. Results show that the energy efficiency of the new process is increased by 5%–24% and has a 53%–75% increase of the return on investment, comparing to those of the conventional Fushun-type technology.

Synthesis of an amphoteric polymer as a high‐temperature‐resistant shale stabilizer in water‐based drilling fluids

AbstractTo meet the increasing requirement of stabilizing shale under high‐temperature situation with the use of water‐based drilling fluids (WBDFs), the high‐performance shale stabilizer is an urgent need. In this study, an amphoteric copolymer of AM/DMDAAC/NVP (APC) was synthesized by acrylamide (AM), dimethyl diallyl ammonium chloride (DMDAAC), and N‐vinylpyrrolidone (NVP) and used as a high temperature‐resistant shale stabilizer. The Fourier transform infrared spectroscopy and nuclear magnetic resonance spectroscopy confirmed the successful synthesis of APC. The inhibitive performance of APC was systematically evaluated and compared with three other commonly used shale stabilizers, including the anionic potassium polyacrylamide (KPAM), cationic poly dimethyl diallyl ammonium chloride (PD), and amphoteric polymer FA367. The results demonstrated that APC displayed excellent performance on the linear swelling test, hot‐rolling recovery experiment, and shale immersion test. Furthermore, APC combined the advantages of high shale recovery percentages of PD and maintaining shale pellet integrity of KPAM, avoiding the drawbacks of enormous filtration volume of PD and low shale recovery percentages of KPAM. These great properties indicated that APC would be suitable as a shale stabilizer in WBDF to drill high‐temperature shale formation.

低熟富有机质泥页岩热模拟排出油饱和烃地球化学特征

低熟富有机质泥页岩热模拟排出油饱和烃地球化学特征

Investigation of the factors causing the coalbed methane production differences in Shizhuangnan Block, Southern Qinshui Basin, North China

The geology and engineering characteristics are investigated in the Zaoyuan area of the Shizhuangnan Block, Southern Qinshui Basin to determine variations in the water/gas production not only amongst regions, but wells within the same region. Using geophysical logging, hydraulic fracturing and production data, it appears that a roof/floor with low shale content may be the cause of excessive water production when a coal reservoir predominantly develops horizontal fractures due to hydraulic fracturing. Maintaining a slowly bottom hole pressure decline rate before gas production and stable after producing gas is favourable for the extension of the pressure drop funnel. This is also more likely to help wells have high gas production over their lifetime. Whether or not a coal reservoir depressurises fully is crucial for gas production in both north and south regions. [Received: October 19, 2017; Accepted: July 5, 2018]

Mass flow rate prediction of shale gas considering gas diffusion and water film evaporation

The difference between organic and inorganic matters in shale matrix has significantly influence on the transport capacity of shale gas and the total production of shale gas further. Previous studies have demonstrated that the organic pores are hydrophobic and the inorganic pores are hydrophilic. Therefore, the water film can be adsorbed on the walls of the inorganic pores. However, the evaporation of water film in inorganic pore is often overlooked due to the analytical challenge and the effect of the water film evaporation on gas transport capacity is rarely discussed. Thus, it is important to accurately predict mass flow rate of the shale gas through a single nanopore whether it is organic or inorganic. In this article, the mass flow rate prediction model of the organic pore is developed firstly, which considers the interactions of slip flow, gas adsorbed at pore walls, surface diffusion for adsorbed gas and gas diffusing from the kerogen which contains dissolved shale gas in organic pores at nanoscale. This model is then used to investigate the influences of initial pressure, pressure gradient, and thickness of kerogen on the gas mass flow rate. For inorganic pores, the mass flow rate prediction model is developed secondly and the interactions of water film and the evaporation of water film have been considered. The influence of evaporation, initial humidity, water–methane diffusivity is investigated on the gas mass flow rate. Results show that diffusion from kerogen plays an important role in the transport capacity of shale gas. Both higher pressure gradient and thicker kerogen can contribute to higher gas mass flow rate and higher diffusion from kerogen. Higher initial pressure and thicker kerogen can contribute to the lower shale gas desorption. The thicker kerogen can contribute to the higher surface diffusion. The evaporation in inorganic pore should not be ignored, because it impacts gas mass flow rate and can contribute to the higher flow rate. Experimental data was compared with our prediction model, which proves the correctness and validity of our model.

PRODUCTIVITY PREDICTION OF FRACTURED HORIZONTAL WELLS WITH LOW PERMEABILITY FLOW CHARACTERISTICS

Horizontal well and large-scale fracturing are revolutionary technologies in petroleum industry. The technologies bring obvious economic benefits to exploiting unconventional oil and gas reservoirs with low permeability, ultra-low permeability and shale gas. With the increasingly extensive application of these technologies, other correlated technologies have also gained great development. However, low-permeability reservoirs exhibit complicated features and horizontal well fractures have complex shape. The existing methods for the productivity prediction of fractured horizontal well in low-permeability reservoirs rarely consider the influencing factors in a comprehensive manner. In this paper, a horizontal well seepage model of casing fracturing completion was established according to the superposition principle of low-permeability reservoir and the relationship between potential and pressure, by which model the seepage characteristics of low-permeability reservoirs could be fully described. Based on the established new seepage model, a new targeted model with coupling seepage and wellbore flow was established for the productivity prediction of low-permeability fractured horizontal well. Finally, the new targeted model was verified through field experiment. The experimental results confirmed the reliability of productivity prediction by the proposed model. Sensitivity analysis was then performed on the parameters in the proposed model.

Evaluation of Nubia sandstone reservoir as inferred from well logging data interpretation for Rabeh East-25 well, Southwest Gulf of suez, Egypt

The present study interprets well log responses obtained from the Nubia sandstone in the Rabeh East-25 Well, Southwest Gulf of Suez in Egypt. The reservoir characterization of the Nubia sandstone reservoir demonstrates that it has excellent potential for hydrocarbon production. Based on the qualitative interpretation of available well log data, the examined well through the Nubia sandstone succession has been subdivided into four zones. The hydrocarbon-bearing zones include zone II, a shaly reservoir occurs between depths of 5610 and 5631 ft, and zone IV, characterized by a clean sandstone reservoir is located between depths of 5656 and 5685 ft. When both zones are combined, the net pay thickness of the Nubia sandstone reservoir in the studied well reaches 60 ft. The petrophysical parameters of the oil-bearing zones were calculated to determine their reservoir properties, including their fluid saturation, shale volume, porosity, bulk volume of water and permeability values. The shaly sandstones in zone II have low water saturation (17–47%), low shale volume (0–50%), high total porosity (18–23%) and high effective porosity (8–23%) values. However, the clean sandstones in zone IV display lower water saturation (8–38%), high total porosity (17–22%) and high effective porosity (14–22%) values. Both zones exhibit high permeability values (usually above 50 MD), and their values of the Movable Oil Index are lower than 0.7reflecting the movability of the preserved oil. The constructed Buckles plots for the two zones indicate that the points which follow 0.04 and 0.05 BVW hyperbolas in zone II and points track 0.02, 0.03 and 0.035 BVW hyperbolas in zone IV will produce oil without water. The relative permeability to oil is usually less than 1.0, and the relative permeability to water is less than 0.01. Additionally, the water contents accompanying production are relatively low, i.e., they vary between 0 and 20%, thus reflecting the good reservoir quality of both zones.

Factors controlling the reservoir accumulation of Triassic Chang 6 Member in Jiyuan-Wuqi area, Ordos Basin, NW China

Abstract In the Triassic Yanchang Formation, Jiyuan-Wuqi area, Ordos Basin, the Chang 6 reservoir is contacted to the Chang 7 high-quality source rock, but the oil pools are unevenly distributed, and complex in oil and water distribution. Through cores observation and fracture statistics, combined with comprehensive analyses of physical property, mercury injection, logging and geochemical data, and comparisons of the sandbodies scales, reservoir physical properties, argillaceous laminae and fractures between source and reservoir in the eastern and western oil-bearing areas and in the central water producing area, it is found that the hydrocarbon accumulation patterns are different in the eastern, central and western areas, and the characteristics of hydrocarbon migration under the background of double-provenance were sorted out. The study results show that the crude oil in the eastern area has different Pr/Ph and sterane distribution from that in the western area. The oil and gas primarily migrated vertically. The high-quality source rocks and favorable source-reservoir-cap combinations lay the foundation for large-scale oil and gas accumulations. Vertically, the oil and gas enrichment is controlled by the scale of sandbody and the difference of physical properties, while on the plane, it is controlled by the connectivity of sandbodies, the argillaceous laminae between source rock and reservoir, the reservoir physical property and the fractures. The sandbodies of oil-rich zones in the eastern and western areas have large thickness, low shale content, good physical properties, weak heterogeneity, few argillaceous laminae and abundant fractures, all of which are favorable for the vertical migration and accumulation of oil and gas. In contrast, in the middle area with converging provenances, the reservoirs, composed of thin sandbodies, features rapid variation in lithology and physical properties, strong heterogeneity, poor continuity of sandbodies, abundant argillaceous laminae between source rock and reservoir, and few fractures, makes it difficult for the oil and gas to migrate vertically, and results in low oil enrichment degree ultimately. For the exploration of continental multiple-provenance tight reservoirs, not only the good-property source rocks and reservoirs, but more importantly the source-reservoir contact relationship and the effect of fractures on the hydrocarbon migration and accumulation should be considered.

A Modified Approach for Volumetric Evaluation of Shaly Sand Formations from Conventional Well Logs: A Case Study from the Talhar Shale, Pakistan

In potential shale-gas basins, due to limited data availability, volumetric evaluation of shaly sand formations is a challenging task for researchers, as well as for exploration and production companies, with the use of conventional well logs. This paper is intended to provide a better understanding of volumetric evaluation in unconventional shaly sand formations. Petrophysical parameters derived from conventional well logs play a significant role in the volumetric estimation of shale. The assessment was performed using numerical equations, well log indexes, and cross-plot analysis. Deep and shallow resistivity logs overlap with each other; this phenomenon indicates that the Talhar Shale in Pakistan can be considered to be an unconventional formation. The average values of shale volume, total porosity, effective porosity, and matrix volume are 29, 16, 12, and 59%, respectively. The Talhar Shale is dominantly characterized by intergranular porosity. It has been observed that at low shale volumes (10–20%), porosities (total and effective), and resistivity measurements (deep, shallow, and microlaterolog), well log signatures have close contents with the shale volume. In contrast, for the remainder of the shale volume, there is significant separation of log signatures. Well log indexes indicate significant responses in 10–20% shale volume zones.

Optimum development options and strategies for water injection development of carbonate reservoirs in the Middle East

Abstract Through the research on several carbonate reservoirs developed in the Middle East, the basic characteristics of different types of carbonate reservoirs are determined, and a set of high-efficiency water injection development options and strategies are presented. Hidden baffles and barriers exist in carbonate reservoirs in the Middle East, so the reservoirs could be divided into different separated development units based on the baffles and barriers characteristics. Flexible and diverse profile control techniques such as high angle wells and simple and applicative zonal water injection have been introduced to improve the control and development degree of reservoirs. Three principal water injection development methods suitable for different carbonate reservoirs in the Middle East are proposed, including the combination of crestal gas injection and peripheral water injection, bottom interval injection and top interval production (buoyancy underpinning), and “weak point and strong plane” area well pattern. Based on the characteristics of very low shale content, fast and far pressure transmission in the Middle East carbonate reservoirs, a large well-spacing flood pattern is recommended, and reasonable development strategies have been made such as moderate water injection rate and maintaining reasonable production pressure drawdown and voidage replacement ratio, so as to maximize the recovery of reservoirs in the none or low water cut period.

Exploitation of fractured shale oil resources by cyclic CO2 injection

With shale oil reservoir pressure depletion and recovery of hydrocarbons from formations, the fracture apertures and conductivity are subject to reduction due to the interaction between stress effects and proppants. Suppose most of the proppants were concentrated in dominant fractures rather than sparsely allocated in the fracture network, the fracture conductivity would be less influenced by the induced stress effect. However, the merit of uniformly distributed proppants in the fracture network is that it increases the contact area for the injection gas with the shale matrix. In this paper, we address the question whether we should exploit or confine the fracture complexity for CO2-EOR in shale oil reservoirs. Two proppant transport scenarios were simulated in this paper: Case 1—the proppant is uniformly distributed in the complex fracture system, propagating a partially propped or un-propped fracture network; Case 2—the proppant primarily settles in simple planar fractures. A series of sensitivity studies of the fracture conductivity were performed to investigate the conductivity requirements in order to more efficiently produce from the shale reservoirs. Our simulation results in this paper show the potential of CO2 huff-n-puff to improve oil recovery in shale oil reservoirs. Simulation results indicate that the ultra-low permeability shales require an interconnected fracture network to maximize shale oil recovery in a reasonable time period. The well productivity of a fracture network with a conductivity of 4 mD ft achieves a better performance than that of planar fractures with an infinite conductivity. However, when the conductivity of fracture networks is inadequate, the planar fracture treatment design maybe a favorable choice. The available literature provides limited information on the relationship between fracture treatment design and the applicability of CO2 huff-n-puff in very low permeability shale formations. Very limited field test or laboratory data are available on the investigation of conductivity requirements for cyclic CO2 injection in shale oil reservoirs. In the context of CO2 huff-n-puff EOR, the effect of fracture complexity on well productivity was examined by simulation approaches.

Seismic Stratigraphic and Petrophysical Characterization of Reservoirs of the Agbada Formation in the Vicinity of ‘Well M’, Offshore Eastern Niger Delta Basin, Nigeria

Two dimensional seismic and composite well logs from well M in the eastern offshore Niger delta basin were used to carry out a seismic stratigraphic and petrophysical characterization of reservoirs of the Agbada Formation. Three seismic sequences have been delineated within a time window of 600 ms-2200 ms showing depositional environments that have prograded from the delta platform in seismic sequence one (S1) down to the wave dominated prodelta /slope in seismic sequences three (S3). Five seismic facies (F1, F2, F3, F4, and F5) have been mapped within the study area with F2, the hydrocarbon habitat, consisting of deltaic distributary channel fills. The deposits of F2 were formed during aggradation to progradation of the delta and are considered to be High stand system tracts (HST) reservoirs. Twenty reservoirs zones (A-T) were identified with porosity ranging from 0.192 to 0.423 and permeability from 5.078 to 12,397.895 md, indicating very good porosity and permeability as a result of the low shale volume (0.031-0.148). The values for the bulk volume water are constant or nearly constant throughout the reservoirs and the reservoirs are said to be at irreducible water saturation implying the reservoir can produce water free hydrocarbon hence they are very good hydrocarbon reservoirs. The reservoirs qualities of well M are good and some of the reservoirs are petroliferous. Therefore, Well M could serve as a control well in hydrocarbon exploration in the offshore depobelt.

Ichnostratigraphy of the Ediacaran-Cambrian boundary: new insights on lower Cambrian biozonations from the Soltanieh Formation of northern Iran

AbstractStrata in the Central Alborz Mountains, northern Iran, are interpreted to show continuous sedimentation from Ediacaran through Cambrian times. The Soltanieh Formation consists of five members: Lower Dolomite, Lower Shale, Middle Dolomite, Upper Shale and Upper Dolomite members. The clastic units (Lower and Upper Shale members) represent sedimentation in distal marine settings, ranging from the shelf to offshore, and contain abundant trace fossils of biostratigraphic utility. Four ichnozones have been recognized. Ichnozone 1, containingHelminthoidichnites tenuis,Helminthopsis tenuis, andCochlichnus anguineus, is early Fortunian based on small shelly fossils, and is interpreted as a distal expression of theTreptichnus pedumzone. Ichnozone 2, comprising the first occurrence ofT.pedum, is middle Fortunian, and is best regarded as the upper half of theTreptichnus pedumZone. Ichnozone 3 is late Fortunian–Cambrian Age 2, characterized by a sudden change in abundance and complexity of trace fossils. Main elements in this ichnozone includeCruziana problematica,Curvolithusisp., Phycodesisp.,Treptichnus pedum,Treptichnus pollardi, andTreptichnusisp. Ichnozone 4 is of Cambrian Age 2–Age 3 and marked by the first appearances ofPsammichnites gigas,Rusophycus avalonensis, andDidymaulichnus miettensis. Integration of trace fossils with small shelly fossils suggests that the Ediacaran–Cambrian boundary should be placed at the base of the Soltanieh Formation or within the Lower Dolomite Member. The delayed appearance ofT.pedumand the low ichnodiversity in the Lower Shale and lower interval of the Upper Shale reflect limited colonization of settings below storm wave base during the early Fortunian.

DETECTION OF HYDROCARBON, BY USING ADVANCED WELL LOG TOOLS FOR KAFR EL-SHEIKH FORMATION AT SAPPHIRE FIELD, OFFSHORE NILE DELTA, EGYPT

The present work is devoted to study the geologic setting, reservoir characterization and hydrocarbon detection with conventional and advanced well log methods for Kafr El-Sheikh Formation at Sapphire field, Offshore Nile Delta, Egypt. The used wells are Sapphire-Da, Db, Dc, De, Dh and Dq. By using open hole logging tools, advanced logging tool like Modular dynamic tester (MDT), Mud log during drilling and conventional core that analyzed carefully, to detect the clean sandstone and thin bedded sandstone of the study Location. These basic well log tools (Gamma Ray, Resistivity, Density and Neutron) reflectclean sandstone reservoir with good way, but can’t detectthin bedded sandstone reservoir, as a result of their low vertical resolution, this may miss several intervals charged with hydrocarbons during perforation and production from the field.So, we should run advanced tool like the Modular Dynamic Tester (MDT) and analyze conventional core, if found, and the hydrocarbons in Mud log to detect these missed intervals. Also by using the conventional cores and mud logging while drilling. The results had showed clean sandstone and thin bedded sandstone reservoirsthroughthe advanced well log tools, which identify more than 68% deep water reserve didn’t use beforethis should be takeninto consideration in the future wells, workover wells, excellent distribution of facies in both the static and dynamic models, to increase the hydrocarbon production and life time of producible wells. . The optimum location for forthcoming wells is south west of the field, because it has the best petrophysical parameters. It has high porosity, hydrocarbon saturation, and net to gross, in addition to low shale volume.

Geochemistry of cretaceous rocks, Pakistan: I. Biomarker approach to assess thermal maturity of OM

ABSTRACTThe sediment samples from cretaceous sequences, Lower Indus basin, were analyzed using diagnostic biomarkers to predict the thermal maturity of organic matter. The sediments were tested for aliphatic biomarkers ratios, i.e. homohopanes and steranes isomerization ratios and carbon preference indices. These biomarker maturity parameters reveal that the Lower Goru (including its members Upper shale, Lower shale, and Talhar shale) and Sembar Formations in the Lower Indus Basin of Cretaceous age have reached the maturity level equivalent to the main zone of hydrocarbons generation, whereas Parh and Upper Goru Formations are immature and far from oil window. Geochemical analyses carried out stresses that hydrocarbons derived from the Sembar and Lower Goru Formations (particularly deeper Members) are within the zone of peak oil generation.

Geochemical characterization of cretaceous sediments—Sindh Basin, Pakistan

ABSTRACTThis study includes geochemical characterization of source rock samples from the Upper shale, Lower shale, Talhar shale units of Sembar Formation and Badin shale, Turk shale units of Lower Goru Formation. Fourteen (14) sediment samples have been obtained from various wells located in Badin area of Lower Indus Basin and were analyzed to evaluate thermal history, depositional settings and generative potential. The bitumens obtained by soxhlet extraction were fractionated into saturates, aromatics, NSOs and asphaltenes/resins by column chromatography on silica gel. Saturated fractions isolated by column chromatography were analyzed by Gas Chromatography-Flame Ionization Detector. TOC determined by wet combustion titration method revealed fair to good source rock potential. Pr/Ph ratios and hydrocarbons distributions show anoxic to oxic depositional environment. The TAR ratio, nC31/nC19 ratio, and odd carbon number predominance suggest land plant organic matter input. The values of CPI, OEP and Bit/TOC suggest that these Cretaceous sequences of Sembar and Lower Goru formation are of intermediate maturity and lie within the onset of oil genesis zone.

Variation in outcomes and leakage potential across Clean Power Plan compliance designs

This paper presents results from a “modeler's choice” suite of runs that model the US Environmental Protection Agency's proposed Clean Power Plan (CPP) regulating carbon dioxide emissions from existing power plants under Section 111d of the Clean Air Act more closely than does the core EMF 31 Technology Performance Standard (TPS) case. While the TPS case imposed a national emissions rate standard for the power sector, the CPP imposes its budgets at the state level and provides states a great deal of flexibility in designing their implementation approaches. States may convert their CPP rate targets to a mass basis, and they may join with other states in multi-state trading plans. Under the proposed rule, EPA also left open the question of how new gas units were to be treated under the CPP. This design flexibility leads to a range of possible outcomes when it comes to the impacts of the proposed CPP on emissions, policy costs, electricity generation patterns, and gas markets. We analyzed 40 CPP scenarios in the Framework for Analysis of Climate-Energy-Technology Systems (FACETS), permuting these three design dimensions along with energy efficiency and low shale resource scenarios.Many designs have significantly higher emissions than EPA's original June 2014 design, while others deliver greater emissions reductions. In particular, the EMF TPS is closest to one of the more stringent possible designs. We observed substantial potential for emissions leakage when generation is able to move from covered to uncovered sources or from lower to higher rate states. Movement of generation is stimulated by the very different incentives that are set up across states by the differences in state rates. We discuss the features in each design that drive emissions impacts along with measures that can be taken to mitigate leakage risks. Since the EMF 31 study was completed, EPA has released the final CPP rule, which differs from the proposed rule in many important respects. We discuss the impact of those changes on the leakage potential observed here.Policy impacts on the gas market are found to be highly sensitive to the levels of energy efficiency (EE) achieved. Without EE, the CPP boosts gas production and increases prices by stimulating a shift from coal to gas. However, when the EE levels projected by EPA are achieved as part of state compliance approaches, gas production and price fall below no-policy levels by the mid-2020s.