Dry Gas Zone Research Articles

Effect of thermal maturity on remobilization of molybdenum in black shales

Molybdenum (Mo) concentrations in sedimentary records have been widely used as a method to assess paleo-redox conditions prevailing in the ancient oceans. However, the potential effects of post-depositional processes, such as thermal maturity and burial diagenesis, on Mo concentrations in organic-rich shales have not been addressed, compromising its use as a redox proxy. This study investigates the distribution and speciation of Mo at various thermal maturities in the Upper Ordovician Utica Shale from southern Quebec, Canada. Samples display maturities ranging from the peak oil window (VRo∼1%) to the dry gas zone (VRo∼2%). While our data show a significant correlation between total organic carbon (TOC) and Mo (R2=0.40, n=28, P<0.0003) at lower thermal maturity, this correlation gradually deteriorates with increasing thermal maturity. Intervals within the thermally overmature section of the Utica Shale that contain elevated Mo levels (20–81 ppm) show petrographic and sulfur isotopic evidence of thermochemical sulfate reduction (TSR) along with formation of recrystallized pyrite.X-ray Absorption Fine Structure spectroscopy (XAFS) was used to determine Mo speciation in samples from intervals with elevated Mo contents (>30 ppm). Our results show the presence of two Mo species: molybdenite Mo(IV)S2 (39±5%) and Mo(VI)-Organic Matter (61±5%). This new evidence suggests that at higher thermal maturities, TSR causes sulfate reduction coupled with oxidation of organic matter (OM). This process is associated with H2S generation and pyrite formation and recrystallization. This in turn leads to the remobilization of Mo and co-precipitation of molybdenite with TSR-derived carbonates in the porous intervals. This could lead to alteration of the initial sedimentary signature of Mo in the affected intervals, hence challenging its use as a paleo-redox proxy in overmature black shales.

Critical geological characteristics and gas-bearing controlling factors in Longmaxi shales in southeastern Chongqing, China

The southeastern Chongqing area, one of the highest potential shale gas accumulation areas in China, experienced strong tectonic movements. Due to the tectonic uplift in Himalayan period, the target shale formation is characterized by shallow burial depth and abundant fractures. The Lower Silurian Longmaxi shale was deposited under deep and shallow continental shelf environments with abundant pyrites and graptolite fossils. The lithology of the formation includes black carbonaceous shale, calcareous shale, and siliceous shale. The thickness of the shale varies greatly from 40 to 200 m from southeast to northwest with obvious zonation. Total organic carbon (TOC) content ranges from 1.0 to 4.0% and decreases upward in the formation owing to the change of sedimentary facies. The organic matter reaches dry gas zone. Porosity ranges from 0.5 to 7.9%, and the permeability is measured in the microdarcy to nanodarcy range. Abundant fragile minerals exist in the shales which benefit the hydraulic stimulation. Isothermal adsorption tests show that the sorption gas content in place of the Longmaxi shale ranges from 1.0 to 4.5 m3/t and the gas content in place reaches the standard of commercial exploitation. Factors impacting gas-bearing characteristics were analyzed using a mathematical statistic method, which demonstrates that TOC is the most important factor, especially to the sorption gas content. Meanwhile, clay content, thermal maturity, porosity, and mineral components are also significant factors regarding shale gas-bearing characteristics.

Hydrocarbon potential of Sargelu Formation and oil-source correlation, Iraqi Kurdistan

Sargelu Formation is one of the major petroleum source rocks in Iraq and the Middle East. In an effort to build on the previous work and add new interpretations, this investigates selected outcrops, bore holes, and crude oil samples from different localities in Iraqi Kurdistan. Sargelu Formation has rather uniform lithology with variable thickness throughout Iraqi Kurdistan. The thickness progressively decreases from about 485 m west of the Tigris River in the Mosul area toward north where it is 20–30 m thick and northeastern Iraq where it is about 50 m thick. Results of the studied samples show that the total organic carbon of Sargelu Formation decreases toward the north and northeastern parts of Iraq. The mean of total organic carbon (TOC) wt% is 11.1 in northwestern part in Tawke-15, and it is only 0.5 wt% in eastern part in Hanjeera locality. The organic material is characterized by type II and III kerogens. The thermal maturity increases to the east of the studied area. The organic matter is within the dry gas zone in the eastern part of the study area and is mature and immature in both the western and northwestern parts of the study area. Various diagrams and relationships between bulk properties and biomarkers help recognize different oil families in Iraqi Kurdistan. Four main oil families are recognized: (1) the Upper Jurassic Taq Taq; (2) the Lower Jurassic Tawke; (3) the Upper Jurassic Kirkuk; and (4) the Tertiary Kirkuk. The geochemical parameters suggest carbonate source deposited in reducing environments for the oils. The biomarker parameters show no evidence of molecular contribution from Sargelu Formation to the oils in Taq Taq, but Tawke and Kirkuk oils show a molecular contribution from Sargelu Formation.

Applying classical shale gas evaluation concepts to Germany—Part I: The basin and slope deposits of the Stassfurt Carbonate (Ca2, Zechstein, Upper Permian) in Brandenburg

Organic-rich mudstones of the Stassfurt Carbonate basinal and lower slope facies (Ca2, Zechstein, Upper Permian) occur in the eastern part of the North German Basin (southern Brandenburg, eastern Germany). These source rocks for oil and gas fields have been investigated as a test system for the application of procedures to characterize gas shales. Classic sedimentological investigation methods, including core descriptions and thin section microscopy, were coupled with standardized organic geochemical analysis procedures, such as total organic carbon determination, Rock-Eval pyrolysis, open system pyrolysis-gas chromatography, gas chromatography of aliphatic hydrocarbons, and thermovaporization employing microscale sealed vessels (MSSV). Furthermore, the maceral composition was analyzed and vitrinite reflectance measurements were carried out. Data from these interdisciplinary methods were evaluated to characterize the basinal Stassfurt Carbonate Ca2 utilizing mainly established guidelines for shale gas exploration in North America. The “Stinkschiefer” sediments in southern Brandenburg show a trend of increasing maturity from south to north, favoring the occurrence of gas shales near the basin center. A distinction between basin and lower slope deposits could be made for the investigated suite of samples. The Ca2 basin facies occurs below 3800 m depth. It has reached a minimum thermal maturity of 2.2% R r and is therefore in the dry thermogenic gas zone. In contrast the lower slope deposits occur at depths from 1250 to 3250 m and have oil window maturity, ranging from 0.7% to 1.0% R r. The organic matter is a mixed Type II/III kerogen, the Hydrogen Index ranges from 7 to 105 mg HC/g rock. The low average TOC contents, varying between 0.2 and 0.8 wt%, and its low formation thickness, on average 6 m, are factors limiting the gas shale potential of the Ca2. However, the effective sealing by evaporites below and above the Ca2 may restrict expulsion of generated gas, leading to gas retention within Ca2 black shales.

BURIAL HISTORY RECONSTRUCTION USING LATE DIAGENETIC PRODUCTS IN THE EARLY PERMIAN SILICICLASTICS OF THE FARAGHAN FORMATION, SOUTHERN ZAGROS, IRAN

In spite of the increasing importance to hydrocarbon exploration and production of the Palaeozoic succession in the Zagros area of SW Iran, few burial history and palaeothermal modelling studies of the interval have been carried out. This paper attempts to assess the burial and palaeotemperature history of the Lower Permian Faraghan Formation which is composed of stromatolitic dolomites overlain by mainly cross‐bedded sandstones. The formation grades up into the thick bedded carbonates of the Upper Permian Dalan Formation. The Faraghan and Dalan Formations are major hydrocarbon reservoir units in SW Iran and are time‐equivalents of the Unayzah and Khuff Formations in Saudi Arabia, respectively.The Faraghan Formation consists of shallow‐marine siliciclastics and foreshore deposits, including tidal‐flat and tidal‐channel, estuarine, sabkha, shoreface and offshore facies. In this study, diagenetic constituents are used to evaluate the formation's burial history in the Southern Zagros, an area for which only limited subsurface data is available. A burial history diagram for the formation was constructed for well Finu # 1 using WinBuryTM software. The diagram shows that the formation underwent progressive burial at variable rates between its deposition and the mid‐Tertiary, since when it has undergone rapid uplift.Burial diagenetic products in the Faraghan Formation comprise saddle, ferroan and zoned dolomites, together with dickite, illite/sericite and chlorite minerals. Additional burial‐related features include stylolites and dissolution seams. Isotopic signatures (δ18O versus δ13C) of the ferroan dolomites suggest a burial trend for the formation. Reconstruction of the paragenetic sequence together with the burial history diagram suggests a maximum burial depth of about 5000 m and a wide palaeotemperature range of 80‐160°C. However considering the saddle dolomites as a palaeothermometer, the temperature range narrows to 78 to 138 °C. The burial depth and temperature ranges closely correlate with the main stage of oil generation to the dry gas zone.

Cambrian-Ordovician shales in the Humber Zone: thermal maturation and source rock potential

ABSTRACT Thermal maturation and potential for hydrocarbon generation and pooling are evaluated in the Upper Cambrian Grosses-Roches Formation and the Lower Ordovician Riviere Ouelle Formation of the Humber Zone in Gaspe Peninsula. Five types of organic matter (OM) analyses are used: petrography of rock thin sections and of OM concentrates, reflectance analysis, programmed pyrolysis, and combustion analysis. All analyses indicate that these successions are overmature with respect to hydrocarbon generation, but do not reach the threshold of metamorphism. Source rocks in these formations are in the dry gas zone, and the previously generated oils are now altered into various types of migrabitumen or native coke. A regular increase in maturation is observed in the Riviere Ouelle Formation (Anse du Crapaud member) from the upper condensate zone to near the end of the dry gas zone. No such gradient is observed in the Grosses-Roches Formation. Our results suggest that the upper member of the Grosses-Roches Formation may have had initial fair hydrocarbon potential (some initial TOC values up to about 2 wt%, assuming Type II kerogen) and the D2 unit of the Anse du Crapaud member may have had initial good hydrocarbon potential (some initial TOC values up to about 3 wt%, assuming Type II kerogen). The OM petrographic composition of these fine-grained potential source rocks shows some similarities with those of the Late Ordovician Macasty (Anticosti Island) and Lower Ordovician Green Point (Western Newfoundland) formations. The OM petrographic composition of the A to B2 units of the Anse du Crapaud member suggests former gas storage. No producible hydrocarbons remain. The recognition of Upper Cambrian to Lower Ordovician oil source rocks down-dip of potential Ordovician dolostone reservoir rocks of the Anticosti and St. Lawrence platforms opens a new perspective for hydrocarbon exploration in eastern Quebec. End_Page 213------------------------

THEORY ANALYSIS ON DEEP SEATED GAS AND ITS POTENTIAL STUDY

In recent years, the concept of deep seated gas was commonly mixed up with deep gas in some published articles. In sedimentary, it is better to make the main oil and gas generating zone (oil generating window) as the limit of hydrocarbon generating depth, and the gas that seated in the strata between the depth and sedimentary basement should be named deep seated gas. But to the earth, it is better to name the gas that seated in and under sedimentary crystalline basement as deep gas. Of course, the gas that generated in deeper strata but reserved in shallower strata should also be a important kind of deep seated gas. The generation of deep seated gas relate to the vertical zonation of hydrocarbon generation in earth crust. The theory of oil and gas generating zonation for sedimentary basin have effect on exploration practice in some historical period or in some basins. But with the development of oil and gas geology theory study and exploration practice, the limit of threshold indicate that was made for oil phase disappearing and gas phase appearing in the theory of oil and gas generating zonation was find by scientists. Different basin has different depth for main oil generating zone, so for main gas generating zone (dry gas zone). The sapropeltype organic matter evolution need higher temperature and biger depth and its main gas generating zone is deeper than humictype organic matter's. Evolution of organic matter in main gas generating zone is controlled by many different factors, including some important factors, such as temperature, depth and time. The causes that lead temperature higher are earth dynamics, heat flux in earth deep, and so on. The important geological events taken place before Paleozoic have prepared abundant organic matter and evolution condition for deep seated gas generating. So taken from matter base, there have a great resource potential for deep seated gas. Earth dynamics for oil and gas generating and other new idea offer a new way for deep seated gas study. The resources of hydrocarbon in lithosphere are not used up, but also all resources that have been proved and mined are only a small part of the whole. The main of hydrocarbon resources may be explored in the deep.

Gas-Cap Monitoring in High-Flow-Rate, Low-Porosity Clastic Reservoirs in Colombia Gives Big Economic Returns

Summary Cased-hole neutron logging has been in use for many years and is often used to monitor gas movement in reservoirs behind pipe. This works well in high-porosity reservoirs but is rarely successful in low-porosity reservoirs. In Colombia, there are high-flow-rate reservoirs with significant permeability but low porosity [5 to 6 porosity units (p.u.)]. The challenge was to monitor gas-cap expansion, fluid movement owing to re-injection, and voidage. At the same time, the objective was to identify low gas/oil ratio (GOR) intervals behind pipe for possible recompletion. A number of different examples illustrate both the technique and the economic benefit of the monitoring program. Many of these wells contributed significant additional oil from bypassed zones that were initially thought to be dry gas. In some wells, the instantaneous incremental production was over 10,000 BOPD from a single recompletion. Gas-cap monitoring in very-low-porosity reservoirs in Colombia proved to be not only feasible, but also extremely profitable by differentiating dry-gas zones from low-GOR zones.

Reservoir screening using Iatroscan TLC-FID and identification of palaeo-oil zones, oil–water contacts, tar-mats and residual oil saturations in the Frøy and Rind petroleum accumulations

Combined thin layer chromatography (TLC) and flame ionization detection (FID) of the Iatroscan TLC-FID instrument were used for geochemical screening of 600 core samples from the Elf-operated Frøy Field and Rind Discovery on the Norwegian Continental Shelf. The results allowed a pseudo 3-D characterization of the bitumen distribution in the reservoirs. Calibration of the data to well log-defined oil saturations allowed much more detailed recognition of variation in residual oil saturations (ROS) and helped in determining present and palaeo-oil–water contacts (OWCs). The quantification of bitumen amount and composition between different reservoir units was used to define OWCs. Palaeo-oil zones within present condensate and water zones were identified using an empirical approach to measure bitumen content and composition from live oil zones, condensate zones and dry gas zones, respectively. In this way, the Iatroscan TLC-FID data can be used to reconstruct elements of the filling history of the reservoirs. The application of this technique for identifying compartments, barriers for fluid flow and tar mats is also demonstrated.

Coal rank and burial history of Cretaceous – Tertiary strata in the Grande Cache and Hinton areas, Alberta, Canada: implications for fossil fuel exploration

The present study discusses coal rank and burial histories for Cretaceous–Tertiary coal measures and thermal maturity of associated source rocks. Coal rank ranges from subbituminous to semianthracite. Coalification maps for selected coal zones indicate a broad coalification maximum east of the deformed belt. In the Pocahontas, Brûlé, and Hinton areas, rank levels appear to be elevated locally due to geothermal anomalies. Thermal modelling indicates that the westward decrease of coal rank in Lower Cretaceous strata is related to a westward decrease in the duration of burial beneath Maastrichtian–Eocene foreland-basin deposits. Upper Cretaceous – Tertiary strata were subjected to relatively low geothermal gradients (&lt; 20 °C/km), whereas Lower Cretaceous strata were exposed to much higher gradients (up to 46 °C/km). Tectonic loading in the foothills had only a minor impact on coalification. At Obed Marsh (Alberta Syncline) thermal modelling suggests that deformation in the thrust belt continued for at least a few million years beyond the 60 Ma age recently suggested by fission-track analysis to indicate the end of Laramide deformation. Petroleum source rock intervals of the study area are currently at various stages of thermal maturity (oil generation window to dry gas zone). Coal seams in the Upper Cretaceous – Tertiary coal measures at and near surface have rank levels suitable for combustion, whereas seams in the Lower Cretaceous coal measures are high-quality metallurgical coals. East of the deformed belt the coal measures occur at depths that at the present time are uneconomic for production.

Maturation thermique et histoire de l'enfouissement et de la génération des hydrocarbures du bassin de l'archipel de Mingan et de l'île d'Anticosti, Canada

Carbonate platform sequences of Anticosti Island and the Mingan Archipelago are Early Ordovician to Early Silurian in age. With the exception of the Macasty Formation, the sequences are impoverished in dispersed organic matter, which is chiefly composed of zooclasts. Zooclast reflectances suggest that the Upper Ordovician and Silurian sequences outcropping on Anticosti Island are entirely in the oil window but that the Lower to Middle Ordovician beds of the Mingan Archipelago and their stratigraphic equivalents in the subsurface of most of Anticosti Island belong to the condensate zone. Only the deeper sequences of the southwestern sector of Anticosti Island are in the diagenetic dry-gas zone. The maximum depth of burial of sequences below now-eroded Silurian to Devonian strata increases from 2.3 km on southwestern Anticosti Island to 4.5 km in the Mingan Archipelago. A late upwarp of the Precambrian basement likely allowed deeper erosion of the Paleozoic strata in the vicinity of the Mingan Archipelago than on Anticosti Island. Differential erosion resulted in a southwestern tilting of equal maturation surfaces. The Macasty Formation, the only source rock of the basin (total organic carbon generally &gt; 3.5%, shows a wide range of thermal maturation levels (potential oil window to diagenetic dry gas). It can be inferred from the burial history of Anticosti Island sequences that oil generation began later but continued for a longer period of geologic time in the northeastern part than in the southeastern part of the island. Oil generation was entirely pre-Acadian in the southern and western parts of Anticosti Island, but pre- and post-Acadian in the northern and eastern parts.

An Early Carboniferous (Visean) Lacustrine Oil Shale in Canadian Arctic Archipelago

The Lower Carboniferous (Visean) Emma Fiord Formation in the Canadian Arctic Archipelago is an oil shale of lacustrine origin composed of black carbonaceous shale, siltstone, and marlstone with interbedded sandstone, conglomerate, and oolitic and algal limestones. At Kleybolte Peninsula on Ellesmere Island, the Emma Fiord Formation was deposited on the tectonically active northwestern rim of the Sverdrup basin; it is now thermally overmature and well beyond the dry gas zone of organic maturation (vitrinite reflectance ^approx 5.0). In contrast, the Emma Fiord sequence on Grinnell Peninsula, Devon Island, near the southern edge of the Sverdrup basin, is immature to marginally mature (vitrinite reflectance = 0.26-0.44) and is composed predominantly of liptinite-rich oil sha e. These kerogen-rich rocks contain a high volume of microcrystalline calcite and compositionally are marlstones. The Emma Fiord lake system probably was a closed basin and may have been thermally and chemically stratified (meromictic). Seasonal or continuous high organic productivity by phytoplankton (and bacteria?) in the epilimnion resulted in accumulation of lipid-rich calcareous sediment below an anoxic hypolimnion. The Emma Fiord oil shales on Grinnell Peninsula contain both autochthonous and allochthonous organic material. Two types of oil shales are recognized in this sequence: (1) Alginite-rich oil shales with a clay-carbonate matrix in which liptinite content may be as high as 93% of the organic matter. The hydrogen/oxygen index indicates kerogen of intermediate composition between types I and II. These oil shales are hydrogen rich and oxygen poor. (2) Alginite-poor oil shale with a carbonate matrix, relatively hydrogen poor and oxygen rich. The hydrogen/oxygen index indicates kerogen of intermediate composition between types II and III. The Emma fiord oil shales were deposited in lakes formed immediately prior to or possibly synchronous with the initiation of rifting in the Sverdrup basin. Syntectonic red-bed conglomerates derived from uplifted horst blocks directly overlie the Emma Fiord rocks. A few beds of conglomerate and sandstone in the upper part of the Emma Fiord Formation possibly record the onset of faulting. The formation closely resembles contemporaneous sequences in northern Alaska, Yukon Territory, Greenland, and Spitsbergen. Clearly, similar tectonic and paleoclimatic factors influenced sedimentation over this area in the Early Carboniferous, with the Sverdrup basin locations lying within 10°-15° of the paleoequator.

Hydrocarbon Source Rock Evaluation of Middle Proterozoic Solor Church Formation, North American Mid-Continent Rift System, Rice County, Minnesota

Hydrocarbon source rock evaluation of the Middle Proterozoic Solor Church Formation (Keweenawan Supergroup) as sampled in the Lonsdale 65-1 well, Rice County, Minnesota, shows that: (1) the rocks are organic matter lean (24 of 25 samples have less than 0.8% organic carbon); (2) the organic matter is thermally post-mature, probably near the transition between the wet gas phase of catagenesis and metagenesis (dry gas zone); and (3) the rocks have minimal potential for producing additional hydrocarbons (genetic potential < 0.30 mg HC/g rock). Although no direct evidence exists from which to determine maximum burial depths, the observed thermal maturity of the organic matter requires significantly greater burial depths, a higher geothermal gradient, or both. It is likely, t least on the Saint Croix horst, that thermal maturation of the organic matter in the Solor Church took place relatively early, and that any hydrocarbons generated during this early phase were probably lost prior to deposition of the overlying Middle Proterozoic Fond du Lac Formation (Keweenawan Supergroup).

Gas Storage in the Playa Del Rey Oil Field

Abstract To date, utility company underground storage of gas has generally beenrestricted to depleted dry gas fields. The Playa del Rey project is probablythe first to successfully store gas in a partially depleted oil reservoir withthe recovery of large volumes of gas at high rates as the main objective. Oilrecovery has been a secondary consideration. Problems encountered unusual to those of storage in a dry gas zone were:the removal and retardation of formation of emulsion,the up structuremovement of fluid during withdrawal periods which formed fluid blocks, andreservoir shrinkage resulting from encroachment of edgewater. The solution of these problems as outlined in the paper has resulted inincreasing the withdrawal rate from the original design capacity of 4,000 Mcfper hour to the current 10,000 Mcf per hour. Additional increase is anticipatedas the operations continue. Migration, reservoir performance, operational procedure and a historicalrecord are included to make this a resume of the project from its war-timeinception in 1942 to the first of 1952. Introduction The Playa del Rey underground gas storage project is probably the firstproject in which gas has been stored in a partially depleted oil reservoir, with the recovery of large volumes of gas at high rates as the main objectiveand the recovery of oil a secondary consideration. Problems unusual to those ofstorage in dry gas zones have made this a pioneer endeavor. The total storage capacity of approximately 1,500,000 Mcf of this reservoiris small in comparison with other underground gas storage projects. However, bystudy and experiment the deliverability into transmission lines, operating atpressures in excess of 150 lbs., has been nearly tripled in the past threeyears to the current 10,000 Mcf per hour rate, without the life of compression.It is anticipated this rate will gradually increase as additional fluid isremoved from the formation. Location and History Playa del Rey is located on Santa Monica Bay about two miles south of thebeach community of Venice and 15 miles southwest of the center of the City ofLos Angeles. Fig. 1. T.P. 3669