3D geomodeling of the Lower Cretaceous oil reservoir, Masila oil field, Yemen

Oil was first discovered in the Masila area of Yemen in the late 1990s, with about 90% of the reserves found in the Lower Qishn Clastic Member of the Qishn Formation. The porosity determinations of the Lower Qishn Clastic are relatively high and the permeability ranges from 103 to 374?md. This paper tries to evaluate the hydrocarbons in the porous zones encountered in the Lower Cretaceous formations, which were penetrated by the eight wells in the study area. The water saturation shows low values, while the hydrocarbon saturation is in a reverse relation, i.e., the hydrocarbon increases where the water saturation decreases. Different cross-plots such as Rho-PHIN, Rho-DTN, and M-N were used in lithological identification for the two studied formations (Saar and Qishn) in the studied wells. Formation evaluation and presentation forms of the obtained petrophysical parameters have frequently proven that the formations have high hydrocarbon saturation in this area and contain many pay zones. On of the main targets of this paper is to build a detailed 3D geological modeling of the Lower Cretaceous Sequence conducted through an integrated study.     

Stratigraphy,deposition, and structural framework of the cretaceous (review) and 3D geological model of the lower cretaceous reservoirs,Masila oil field,Yemen

The Masila area is located in the Hadhramaut region in east central Yemen. Oil was first discovered in the area in late 1990 with commerciality being declared in late 1991. Oil production began in July 1993. By the end of December 1999, the daily production rate was set at 210,000 stock tank barrels/day (STB/D) of very low gas–oil ratio (GOR) oil under partial to full water drive. About 90% of the reserves are found in the Lower Qishn Clastics Member of the Qishn Formation. This paper focuses on the detailed 3D geological modeling of the Lower Cretaceous Sequence conducted through an integrated study. There are three critical areas in the process of modeling reservoirs that involve geological and geophysical modeling, reservoir characterization, and reservoir flow modeling. This paper presents methodologies found useful during the modeling of these reservoirs including field case histories for the Lower Cretaceous reservoir in the Masila oilfield.     

Diagenesis and reservoir quality analysis in the Lower Cretaceous Qishn sandstones from Masila oilfields in the Sayun–Masila Basin,eastern Yemen

Lower Cretaceous sandstones of the Qishn Formation have been studied by integrating sedimentological, petrological and petrophysical analyses from wells in the Masila oilfields of eastern Yemen. These analyses were used to define the origin, type of diagenesis and its relation to reservoir quality. The sandstones of the Qishn Formation are predominately quartz arenite to subarkose arenite with sublitharenite and quartz wackes displaying a range of porosities, averaging 22.33%. Permeability is likewise variable with an average of 2844.2 mD. Cementation coupled with compaction had an important effect on porosity destruction after sedimentation and burial. The widespread occurrence of early calcite cement suggests that the sandstones of the Qishn Formation lost significant primary porosity at an early stage of its diagenetic history. In addition to poikilotopic calcite, several different cements including kaolinite, illite, chlorite and minor illite–smectite occur as pore‐filling and pore‐lining cements, which were either accompanied by or followed the development of the early calcite cement. Secondary porosity development occurred due to partial to complete dissolution of early calcite cements and feldspar grains. The new data presented in this paper suggest the reservoir quality of Qishn sandstones is strongly linked to their diagenetic history; hence, the reservoir quality is reduced by clay minerals, calcite and silica cements but is enhanced by the dissolution of the unstable grains, in addition to partial or complete dissolution of calcite cements and unstable grains. Copyright © 2015 John Wiley & Sons, Ltd.     

Characteristics of the tight sand reservoirs in the delta front in the Xu-2 Member of the Upper Triassic Xujiahe Formation (Hechuan area of the central Sichuan Basin,SW China)

The Xu-2 Member of the Upper Triassic Xujiahe Formation (Hechuan area, southwestern China) is an important potential sedimentary sequence for gas exploration in the central Sichuan Basin. Thus, we performed a comprehensive study of drilling parameters, sedimentary cores, well logging, and core test data and combined our results with previous research and the geological background of the basin. We found that the Hechuan area was a delta front that included underwater distributary channels, interchannels, and mouth and distal bars during deposition of the Xu-2 Member. The sand body genetic types were divided into three categories based on where they developed: an underwater distributary channel, a mouth bar, or a distal bar. The lithology of the Xu-2 reservoirs is mainly feldspathic litharenite, lithic arkose, subarkose, litharenite, and sublitharenite. Residual intergranular pores and intergranular dissolution pores are the major pore types in the reservoirs. Reservoirs with porosities of 0.18–15.84% and permeabilities of 0.001–8.72?×?10^?3 μm² showed a correlation coefficient of 0.7592. The reservoir throats are mainly tubular and constricted. Overall, the sedimentary environment and diagenesis are the major controlling factors for reservoir formation in the study area. The reservoir zones with relatively high porosity and permeability mainly developed in a delta front with underwater distributary channels and mouth bars. Chlorite growth preserved the primary pores during early diagenesis stage B, and intergranular dissolution pores resulted from contact with organic acids derived from source rocks during middle diagenesis stage A₁. Compaction and cementation significantly decreased porosity during middle diagenesis stage A₂. These important factors influenced reservoir quality.     

Well log analysis and hydrocarbon potential of the Sa'ar–Nayfa reservoir,Hiswah Oilfield,eastern Yemen

Sa'ar–Nayfa reservoir is mainly made up of carbonate sediments with bands of shale that contain a substantial amount of proven oil in the Hiswah Oilfield, Sayun–Masila Basin, eastern Yemen. Several vertical wells have been drilled and penetrated these sequences. This study is concerned on the petrophysical evaluation and well log analysis of the Lower Cretaceous of 11 wells at the Hiswah Oilfield, Hadramawt Governorate, eastern Yemen. Computer-assisted log analyses were used to evaluate the petrophysical parameters such as shale volume, total porosity, effective porosity, water saturation, hydrocarbon saturation, flushed zone saturation and reservoir and pay flags. Cross-plots of the petrophysical parameters versus depth were illustrated. The Lower Cretaceous Sa'ar–Nayfa reservoir reflects that the matrix components are mainly carbonates and shales. Moreover, the lithological-geologic model reflected that these shales are strongly affecting the porosity and, consequently, the fluid saturation in the Sa'ar–Nayfa reservoir. In this study, the thickness of the Sa'ar–Nayfa reservoir increases from central toward north-eastern and north-western parts within the Hiswah Oilfield. The porosities analyses of the investigation of the Sa'ar–Nayfa reservoir for the 11 studied wells concluded that the average total porosity ranges from 5.4 % to 16.8 % while the effective porosity ranges from 5.2 % to 14.8 %. Water saturation of the Sa'ar–Nayfa reservoir ranges from 6.9 % to 75.8 %. On the other hand, hydrocarbon saturation matches with water saturation in a reverse relationship. Sa'ar–Nayfa reservoir is interpreted as good quality reservoir rocks with high average effective porosity reaching to 20 % and high hydrocarbon saturation exceeding 93 %. The Sa'ar–Nayfa reservoir reveals promising reservoir characteristics especially the upper reservoir unit, which should be taken into consideration during future development of the oilfields area. The hydrocarbon saturation map of the Sa'ar–Nayfa reservoir shows a regular pattern of distribution with a general increasing to the northeast, northwest and east directions while decreasing southwest wards, recording the maximum value of 93.1 % at the Hiswah-21 well.     

Increased hydrocarbon recovery and CO2 management, a Croatian example

Enhanced oil recovery based on CO₂ injection is expected to increase recovery from Croatian oil fields. Large quantities of CO₂ are generated during hydrocarbon processing produced from gas and gas condensate fields situated in the north-western part of Croatia. First CO₂ injection project will be implemented on the Ivani? Oil Field. Numerical modelling based on Upper Miocene sandstone core samples testing results have shown the decrease of oil viscosity during CO₂ injection. Some of the characteristics of the testing samples are porosity 21.5–23.6 %, permeability 14–80 × 10^?15 m² and initial water saturation 28–38.5 %. Water alternating foam (WAF) and water alternating gas (WAG) simulations have provided satisfactory results. The WAF injection process has provided better results, but due to the process sensitivity and costs WAG is recommended for future application. During the pilot project 16 × 10⁶ m³ CO₂ and 5 × 10⁴ m³ of water were injected. Additional amounts of hydrocarbons (4,440 m³ of oil and 2.26 × 10⁶ m³ of gas) were produced which confirmed injection of CO₂ as a successful tertiary oil recovery mechanism in Upper Miocene sandstone reservoirs in the Croatian part of the Pannonian Basin System.     

Chemical Weathering of Pleistocene Glacial Outwash Sediments: A Comparison of Contemporary and Long-term Rates for Soils and Groundwaters

Pore water solutes increase to depths of up to six meters in unsaturated 10 kyr-old glacial outwash sediments in the Trout Lake Basin of northern Wisconsin, USA. After correction for evapotranspiration, these increases reflect weathering gradients produced from plagioclase, calc-magnesium pyroxenes, and amphiboles. In spite of relatively abundant K-feldspar, solute K and Rb reflect negative gradients produced by nutrient plant uptake and cycling. Weathering rates are calculated from solute gradients (b _solute), hydraulic fluxes (q _h ), volumetric BET surface areas (S _v ), and mineral-specific stoichiometric coefficients (β) such that $ R_{\text{solute}} = \frac{{q_{h} }}{{b_{\text{solute}} \beta {\kern 1pt} {\kern 1pt} S_{v} }} $ Average plagioclase weathering rates (R _plag = 1.6–3.1 × 10^?15 mol m^?2 s^?1) bracket rates calculated for other Quaternary glaciated landscapes. Deeper soil pore waters are as chemically concentrated as underlying groundwaters which, based on hydrologic analyses, have traveled distances up to several kilometers over transient times of hundreds of years. Pore water recharge essentially sets solute compositions close to thermodynamic saturation, thus limiting additional weathering potential along these ground water flow paths. Solid-state elemental and mineral gradients, unlike solute gradients, are essentially invariant with soil depth, reflecting low weathering intensities produced over the relatively short geologic time since sediment deposition. A spreadsheet calculator reproduces modest mass loses from such profiles and indicates that present-day weathering is kinetically and not saturation/transport controlled.     

Petrophysical parameters and modelling of the Eocene reservoirs in the Qadirpur area,Central Indus Basin,Pakistan: implications from well log analysis

The Eocene rock units of the Qadirpur field, Central Indus Basin (Pakistan), are investigated petrophysically for their detailed reservoir characterization. The different petrophysical parameters determined include the following: true resistivity, shale volume, total porosity, effective porosity, density and neutron porosity, water and hydrocarbon saturation, bulk volume of water, lithology, gas effect, P-wave velocity, movable hydrocarbon index and irreducible water saturation and integrated with different cross-plots. The Eocene reservoirs are excellent with high effective porosity (2–32 %) and hydrocarbon saturation (10–93 %). Among these, the Sui Upper Limestone is an overall a poor reservoir; however, it has some hydrocarbon-rich intervals with high effective porosity and better net pay. All the net pay zones identified show low and variable shale volume (5–30 %). The secondary porosity has added to the total and effective porosities in these reservoirs. The main contributors to the porosity are the chalky, intercrystalline and vuggy/fracture types. The thickness of the reservoirs zones ranges from 4.5 to 62 m. These reservoirs are gas-producing carbonates with almost irreducible water saturation (0.002–0.01) and are likely to produce water-free hydrocarbons. The lower values of moveable hydrocarbon index (0.07–0.9) show that the hydrocarbons are moveable spontaneously to the well bore. The proposed correlation model shows that the reservoirs have an inclined geometry and are a part of an anticlinal trap.     

The stress regime in a Rotliegend reservoir of the Northeast German Basin

In-situ stresses have significant impact, either positive or negative, on the short and long term behaviour of fractured reservoirs. The knowledge of the stress conditions are therefore important for planning and utilization of man-made geothermal reservoirs. The geothermal field Groß Schönebeck (40 km north of Berlin/Germany) belongs to the key sites in the northeastern German Basin. We present a stress state determination for this Lower Permian (Rotliegend) reservoir by an integrated approach of 3D structural modelling, 3D fault mapping, stress ratio definition based on frictional constraints, and slip-tendency analysis. The results indicate stress ratios of the minimum horizontal stress S _hmin being equal or increasing 0.55 times the amount of the vertical stress S _V (S _hmin ≥ 0.55S _V ) and of the maximum horizontal stress S _Hmax ≤ 0.78–1.00S _V in stress regimes from normal to strike slip faulting. Thus, acting stresses in the 4,100-m deep reservoir are S _V  = 100 MPa, S _hmin = 55 MPa and S _Hmax = 78?100 MPa. Values from hydraulic fracturing support these results. Various fault sets of the reservoir are characterized in terms of their potential to conduct geothermal fluids based on their slip and dilatation tendency. This combined approach can be adopted to any other geothermal site investigation.     

Kinetics of urease mediated calcite precipitation and permeability reduction of porous media evidenced by magnetic resonance imaging

The enzyme urease drives the hydrolysis of urea leading to the release of ammonium ions and bicarbonate; in the presence of calcium, the rise in pH leads to increased calcium carbonate saturation and the subsequent precipitation of calcite. Although such alkalinizing ureolysis is widespread in nature, most studies have focussed on bacteria (i.e. indigenous communities or urease-active Sporosarcina pasteurii) for calcite precipitation technologies. In this study, urease-active jack bean meal (from the legume Canavalia ensiformis) was used to drive calcite precipitation. The rates of ureolysis (k _urea ), determined from measured NH₄ ⁺, enabled a direct comparison to microbial ureolysis rates reported in literature. It is also demonstrated that a simple single reaction model approach can simulate calcite precipitation very effectively (3–6 % normalised root-mean-square deviation). To investigate the reduction of permeability in porous media, jack bean meal (0.5 g L^?1) and solutions (400 mM urea and CaCl₂) were simultaneously pumped into a borosilicate bead column. One-dimensional magnetic resonance profiling techniques were used, non-invasively, for the first time to quantify the porosity changes following calcite precipitation. In addition, two-dimensional slice selective magnetic resonance images (resolution of ~0.5 × 1.0 mm) revealed that the exact location of calcite deposition was within the first 10 mm of the column. Column sacrifice and acid digestion also confirmed that 91.5 % of calcite was located within the first 14 mm of the column. These results have important implications for the design of future calcite precipitation technologies and present a possible alternative to the well known bacterial approaches.     

Gas generation and expulsion characteristics of Middle–Upper Triassic source rocks,eastern Kuqa Depression,Tarim Basin,China: implications for shale gas resource potential

Frontier exploration in the Kuqa Depression, western China, has identified the continuous tight-sand gas accumulation in the Lower Cretaceous and Lower Jurassic as a major unconventional gas pool. However, assessment of the shale gas resource in the Kuqa Depression is new. The shale succession in the Middle–Upper Triassic comprises the Taliqike Formation (T₃t), the Huangshanjie Formation (T₃h) and the middle–upper Karamay Formation (T_2–3k), with an average accumulated thickness of 260 m. The high-quality shale is dominated by type III kerogen with high maturity and an average original total organic carbon (TOC) of about 2.68 wt%. An improved hydrocarbon generation and expulsion model was applied to this self-contained source–reservoir system to reveal the gas generation and expulsion (intensity, efficiency and volume) characteristics of Middle–Upper Triassic source rocks. The maximum volume of shale gas in the source rocks was obtained by determining the difference between generation and expulsion volumes. The results indicate that source rocks reached the hydrocarbon expulsion threshold of 1.1% VR and the hydrocarbon generation and expulsion reached their peak at 1.0% VR and 1.28% VR, with the maximum rate of 56 mg HC/0.1% TOC and 62.8 mg HC/0.1% TOC, respectively. The volumes of gas generation and expulsion from Middle–Upper Triassic source rocks were 12.02 × 10¹² m³ and 5.98 × 10¹² m³, respectively, with the residual volume of 6.04 × 10¹² m³, giving an average gas expulsion efficiency of 44.38% and retention efficiency of 55.62%. Based on the gas generation and expulsion characteristics, the predicted shale gas potential volume is 6.04 × 10¹² m³, indicating a significant shale gas resource in the Middle–Upper Triassic in the eastern Kuqa Depression.     

Organic geochemical characteristics of crude oils from the Masila Basin, eastern Yemen

The Masila Basin is an important hydrocarbon province in Yemen, but the origin of hydrocarbons and their generation history are not fully understood. In this regard, 10 crude oils from different petroleum reservoir sections in the Masila Basin were characterized by a variety of biomarker and non-biomarker parameters using GC, GC-MS and stable carbon isotope techniques. Oils from the Masila Basin display pristane/phytane (Pr/Ph) ratios ranging from 1.7 to 2.0, low sulfur content, high C₃₅ homohopane index, relatively high C₂₇ sterane concentrations and relatively high tricyclic terpanes suggesting a marine clay source rock that was deposited in mildly anoxic to suboxic conditions with dominantly algal organic matter. C₂₉ 20S/(20S + 20R) steranes and ββ/(ββ + αα) sterane ratios indicate that the Masila oils have reached peak oil window maturity. Another related feature of these oils is the absence of 18α (H)-oleanane, which suggests a source age older than Cretaceous. The carbon isotope compositions are similar to those of the potential source rocks, which range from −25.4‰ to −28.3‰, indicating a marine environment. The new data presented in this paper suggest that the Masila oils constitute one oil family and that the oil originated from the Upper Jurassic Madbi source rock in the basin.     

Diagenetic differences in tight sandstone reservoirs in two delta fronts: an example from the Chang 4 and 5 members of the Yanchang Formation in the Longdong area,Ordos Basin,China

With the intensification of oil and gas exploration, tight sandstone reservoirs have received an increasing amount of attention, particularly with regard to the genesis of tight reservoir rock. The Upper Triassic Yanchang Formation in the Longdong area of the Ordos Basin has developed a typical tight, oil-bearing, clastic reservoir (lithic arkose and feldspathic litharenite, grain size is mainly 0.1~0.3 mm in diameter). During the depositional period of the Chang 4 and 5 members, the two provenance systems of the southwest and northeast developed in the study area. In the southwest, sandstones in the lower part of distributary channels are coarser with fewer quartz overgrowth and ankerite and better reservoir quality (porosity about 12%, permeability about 1 mD). In the northeast, chlorite coating is thicker (>?4 vol%) in the underwater channel sandstones (porosity is about 14%, permeability is about 2 mD) than in the mouth bar sandstones. Sandstones in the upper part of distributary channels are finer with lower permeability (about 0.1 mD). Authigenic ankerite mainly appears around detrital dolomite as an overgrowth. The SiO₂ in the quartz overgrowth most likely came from the transformation of smectite to illite and the dissolution of feldspar. In the northeast, only 2 vol% of chlorite rims significantly inhibited quartz overgrowth, but they probably blocked and delayed the dissolution of feldspars by acids. We present results here that show the diagenetic differences in sand bodies in delta fronts are influenced by sediment size, maturity, and the composition of framework grain; the materials that compose authigenic minerals mainly come from the alteration of sandstones. As a whole, the formation of tight reservoir rocks in the study area is closely related to sedimentary facies, composition of framework grain, cement type and content, and development of dissolution.     

Numerical simulation of carbon dioxide migration in a sandstone aquifer considering the fluid–solid coupling

Very limited investigations have been done on the numerical simulation of carbon dioxide (CO₂) migration in sandstone aquifers taking consideration of the interactions between fluid flow and rock stress. Based on the poroelasticity theory and multiphase flow theory, this study establishes a mathematical model to describe CO₂ migration, coupling the flow and stress fields. Both finite difference method (FDM) and finite element method (FEM) were used to discretize the mathematical model and generate a numerical model. A case study was carried out using the numerical model on the Jiangling sandstone aquifer in the Jianghan basin, China. The rock mechanics parameters of reservoir and overlying strata of Jiangling depression were obtained by triaxial tests. A two-dimensional model was then built to simulate carbon dioxide migration in the sandstone aquifer. The numerical simulation analyzes the carbon dioxide migration distribution rule with and without considering capillary pressure. Time-dependent migration of CO₂ in the sandstone aquifer was analyzed, and the result from the coupled model was compared with that from a traditional non-coupled model. The calculation result indicates a good consistency between the coupled model and the non-coupled model. At the injection point, the CO₂ saturation given by the coupled model is 15.39 % higher than that given by the non-coupled model; while the pore pressure given by the coupled model is 4.8 % lower than that given by the non-coupled model. Therefore, it is necessary to consider the coupling of flow and stress fields while simulating CO₂ migration for CO₂ disposal in sandstone aquifers. The result from the coupled model was also sensitized to several parameters including reservoir permeability, porosity, and CO₂ injection rate. Sensitivity analyses show that CO₂ saturation is increased non-linearly with CO₂ injection rate and decreased non-linearly with reservoir porosity. Pore pressure is decreased non-linearly with reservoir porosity and permeability, and increased non-linearly with CO₂ injection rate. When the capillary pressure was considered, the computed gas saturation of carbon dioxide was increased by 10.75 % and the pore pressure was reduced by 0.615 %.     

Role of degree of saturation in denitrification of unsaturated sand specimens

Nitrate contamination of groundwater arises from anthropogenic activities, such as, fertilizer and animal manure applications and infiltration of wastewater/leachates. During migration of wastewater and leachates, the vadose zone (zone residing above the groundwater table), is considered to facilitate microbial denitrification. Particle voids in vadose zone are deficient in dissolved oxygen as the voids are partially filled by water and the remainder by air. Discontinuities in liquid phase would also restrict oxygen diffusion and therefore facilitate denitrification in the vadose/unsaturated soil zone. The degree of saturation of soil specimen (S _r) quantifies the relative volume of voids filled with air and water. Unsaturated specimens have S _r values ranging between 0 and 100 %. Earlier studies from naturally occurring nitrate losses in groundwater aquifers in Mulbagal town, Kolar District, Karnataka, showed that the sub-surface soils composed of residually derived sandy soil; hence, natural sand was chosen in the laboratory denitrification experiments. With a view to understand the role of vadose zone in denitrification process, experiments are performed with unsaturated sand specimens (S _r = 73–90 %) whose pore water was spiked with nitrate and ethanol solutions. Experimental results revealed 73 % S _r specimen facilitates nitrate reduction to 45 mg/L in relatively short durations of 5.5–7.5 h using the available natural organic matter (0.41 % on mass basis of sand); consequently, ethanol addition did not impact rate of denitrification. However, at higher S _r values of 81 and 90 %, extraneous ethanol addition (C/N = 0.5–3) was needed to accelerate the denitrification rates.     

In situ observation of crystal growth in a basalt melt and the development of crystal size distribution in igneous rocks

The speciation of CO₂ in dacite, phonolite, basaltic andesite, and alkali silicate melt was studied by synchrotron infrared spectroscopy in diamond anvil cells to 1,000 °C and more than 200 kbar. Upon compression to 110 kbar at room temperature, a conversion of molecular CO₂ into a metastable carbonate species was observed for dacite and phonolite glass. Upon heating under high pressure, molecular CO₂ re-appeared. Infrared extinction coefficients of both carbonate and molecular CO₂ decrease with temperature. This effect can be quantitatively modeled as the result of a reduced occupancy of the vibrational ground state. In alkali silicate (NBO/t = 0.98) and basaltic andesite (NBO/t = 0.42) melt, only carbonate was detected up to the highest temperatures studied. For dacite (NBO/t = 0.09) and phonolite melts (NBO/t = 0.14), the equilibrium CO₂ + O^2? = CO₃ ^2? in the melt shifts toward CO₂ with increasing temperature, with ln K = ?4.57 (±1.68) + 5.05 (±1.44) 10³ T ^?1 for dacite melt (ΔH = ?42 kJ mol^?1) and ln K = ?6.13 (±2.41) + 7.82 (±2.41) 10³ T ^?1 for phonolite melt (ΔH = ?65 kJ mol^?1), where K is the molar ratio of carbonate over molecular CO₂ and T is temperature in Kelvin. Together with published data from annealing experiments, these results suggest that ΔS and ΔH are linear functions of NBO/t. Based on this relationship, a general model for CO₂ speciation in silicate melts is developed, with ln K = a + b/T, where T is temperature in Kelvin and a = ?2.69 ? 21.38 (NBO/t), b = 1,480 + 38,810 (NBO/t). The model shows that at temperatures around 1,500 °C, even depolymerized melts such as basalt contain appreciable amounts of molecular CO₂, and therefore, the diffusion coefficient of CO₂ is only slightly dependent on composition at such high temperatures. However, at temperatures close to 1,000 °C, the model predicts a much stronger dependence of CO₂ solubility and speciation on melt composition, in accordance with available solubility data.     

Heat capacity of ferrosilite, Fe2Si2O6

The heat capacity of synthetic ferrosilite, Fe₂Si₂O₆, was measured between 2 and 820 K. The physical properties measurement system (PPMS, Quantum Design^®) was used in the low-temperature region between 2 and 303 K. In the temperature region between 340 and 820 K measurements were performed using differential scanning calorimetry (DSC). The C _p data show two transitions, a sharp λ-type at 38.7 K and a small shoulder near 9 K. The λ-type transition can be related to collinear antiferromagnetic ordering of the Fe²⁺ spin moments and the shoulder at 10 K to a change from a collinear to a canted-spin structure or to a Schottky anomaly related to an electronic transition. The C _p data in the temperature region between 145 and 830 K are described by the polynomial $C_{p} {\left[ {\hbox{J\,mol}^{{ - 1}}\,{\hbox{K}}^{{ - 1}} } \right]} = 371.75 - 3219.2T^{{ - 1/2}} - 15.199 \times 10^{5} T^{{ - 2}} + 2.070 \times 10^{7} T^{{ - 3}} $ The heat content [H ₂₉₈ – H ₀] and the standard molar entropy [S ₂₉₈ – S ₀] are 28.6 ± 0.1 kJ mol^?1 and 186.5 ± 0.5 J mol^?1 K^?1, respectively. The vibrational part of the heat capacitiy was calculated using an elastic Debye temperature of 541 K. The results of the calculations are in good agreement with the maximum theoretical magnetic entropy of 26.8 J mol^?1 K^?1 as calculated from the relationship 2*Rln5.     

Charging time of tight gas in the Upper Paleozoic of the Ordos Basin,central China

The Upper Paleozoic section contains a tight gas sandstone reservoir (of 2.75 × 10¹² m³) in the Ordos Basin, central China. The measured porosities (< 10%) and permeabilities (generally < 1 mD) are the result of significant mechanical and chemical compaction and precipitation of carbonate, quartz and authigenic clay cements. Fluid inclusion geochemistry and kinetic modeling (generation of gaseous components and δ¹³C₁) were integrated to constrain the timing of gas charge into the tight reservoir. The modeling results indicate that the natural gases in the present reservoir are similar to gases liberated from quartz inclusions in both composition and stable carbon isotope values and also similar to gas generated from Upper Paleozoic coal. The similar geochemistry suggests that an important phase of quartz cementation must have occurred after gas emplacement in the reservoirs during regional uplift at the end of the Cretaceous. The latest carbonate cement, postdating quartz cementation, consumed most of the late CO₂ generated from coal at high maturity (R_O > 1.7%) and reduced the reservoir quality dramatically. On the contrary, tight sandstones from non-producing areas have fluid inclusions that were trapped in quartz cements much earlier. These data indicate that natural gas migrated into the Upper Paleozoic reservoir when it still retained high porosity and permeability. The reservoir continued to experience porosity and permeability reduction from continued quartz and carbonate cementation after gas charging due to low gas saturation. Comparison of the relative timing of gas charging with that of sandstone cementation can help to predict areas of risk during tight gas exploration and development.     

Estimating the hydraulic properties of an aquitard from in situ pore pressure measurements

A workflow is described to estimate specific storage (S _s) and hydraulic conductivity (K) from a profile of vibrating wire piezometers embedded into a regional aquitard in Australia. The loading efficiency, compressibility and S _s were estimated from pore pressure response to atmospheric pressure changes, and K was estimated from the earliest part of the measurement record following grouting. Results indicate that S _s and K were, respectively, 8.8?×?10^?6 to 1.2?×?10^?5 m^?1 and 2?×?10^?12 m s^?1 for a claystone/siltstone, and 4.3?×?10^?6 to 9.6?×?10^?6 m^?1 and 1?×?10^?12 to 5?×?10^?12 m s^?1 for a thick mudstone. K estimates from the pore pressure response are within one order of magnitude when compared to direct measurement in a laboratory and inverse modelled flux rates determined from natural tracer profiles. Further analysis of the evolution and longevity of the properties of borehole grout (e.g. thermal and chemical effects) may help refine the estimation of formation hydraulic properties using this workflow. However, the convergence of K values illustrates the benefit of multiple lines of evidence to support aquitard characterization. An additional benefit of in situ pore pressure measurement is the generation of long-term data to constrain groundwater flow models, which provides a link between laboratory scale data and the formation scale.     

Dynamics of carbon fluxes with responses to vegetation,meteorological and terrain factors in the south-eastern Tibetan Plateau

Tibetan Plateau (TP) is the highest and most extensive plateau in the world and has been known as the roof of the world, and it is sensitive to climate change. The researches of CO₂ fluxes (F _C) in the TP region play a significant role in understanding regional and global carbon balance and climate change. Eddy covariance flux measurements were conducted at three sites of south-eastern TP comprising Dali (DL, cropland ecosystem), LinZhi (LZ, alpine meadow ecosystem) and Wenjiang (WJ, cropland ecosystem); amongst those DL and LZ are located in plateau region, while WJ is in plain region. Dynamics of F _C and influences of vegetation, meteorological (air temperature, photosynthetically active radiation, soil temperature and soil water content) and terrain factors (altitude) were analysed on the basis of data taken during 2008. The results showed that, in the cool sub-season (March, April, October and December), carbon sink appeared even in December with fluxes of (?0.021 to ?0.05) mg CO₂ m^?2 s^?1 and carbon source only in October (0.03 ± 0.0048) mg CO₂ m^?2 s^?1 in DL and WJ site. In LZ site, carbon sink was observed in April: (?0.036 ± 0.0023) mg CO₂ m^?2 s^?1 and carbon sources in December and March (0.008–0.010 mg CO₂ m^?2 s^?1). In the hot sub-season (May–August), carbon source was observed only in May with (0.011 ± 0.0022), (0.104 ± 0.0029) and (0.036 ± 0.0017) fluxes in LZ, DL and WJ site, respectively, while carbon sinks with (?0.021 ± 0.0041), (?0.213 ± 0.0007) and (?0.110 ± 0.0015) mg CO₂ m^?2 s^?1 fluxes in LZ, DL, and WJ, respectively. Comparing with plain region (WJ), carbon sinks in plateau region (DL and LZ) lasted for a longer time, and the absorption sum was large and up to (–357.718 ± 0.0054) and (?371.111 ± 0.0039) g C m^?2 year^?1, respectively. The LZ site had the weakest carbon sink with (?178.547 ± 0.0070) g C m^?2 year^?1. Multivariate analysis of covariance showed that altitude (AL) as an independent factor explained 39.5 % of F _C (P < 0.026). F _C had a quadratic relationship with Normalized difference vegetation index (NDVI) (R ² ranges from 0.485 to 0.640 for three sites), an exponential relationship with soil temperature at 5-cm depth (ST ₅) at night time and a quadratic relationship with air temperature (T _a) at day time. Path analysis indicated that photosynthetically active radiation (PAR), sensible heat fluxes (H) and other factors all had direct or indirect effects on F _C in all of the three tested sites around the south-eastern TP.