Dry Gas Zone Research Articles

Multiphase flow analysis of complex wellbore–fracture–cave connections in condensate gas reservoirs

The significant heterogeneity of fracture-caved gas reservoirs and the phase transition behavior with pressure depletion pose great challenges for flow behavior analysis and property estimation. Therefore, the objective of this paper is to develop robust and novel pressure transient analysis models for condensate-gas flow under pressure depletion in fracture-caved gas reservoirs. To characterize the complex connections between wellbore, fracture region, and caves, four conceptual models of wellbore–fracture–cave distributions are determined. The fracture region is considered as a dynamic three-zone (dry gas zone, condensate-gas two-phase zone, and transition zone) to characterize the phase transition during pressure depletion, while a variable storage concept is introduced to describe the phase transition in the wellbore and caves. The results indicate that six typical flow stages can be observed from the type curves: constant wellbore storage flow, variable wellbore storage flow, fracture linear flow (FLS), constant cave storage flow, variable cave storage flow, and transition flow. Moreover, the phase transition behavior in the fracture region is reflected in the changes of one-half slope straight lines during the FLS period, while the phase transition behavior in the wellbore and caves is reflected in the pressure derivative curve as a positive upward bending of the straight line with unit slope at later stage. The property estimation in the fracture-caved gas reservoirs (i.e., length and permeability of the fracture region, the storage coefficient of wellbore and cave) by matching with the actual pressure monitoring data provides a better understanding of the geological evidence.

Effects of synthetic maturation on phenanthrenes and dibenzothiophenes over a maturity range of 0.6 to 4.7% EASY%Ro

As the exploration target of the shale gas industry is shifting to more deeply buried strata, it is of great application value to study the distribution of molecular maturity ratios in the late dry gas zone and the mechanisms behind them for a robust thermal maturity evaluation. This study investigates the continuous molecular evolution of parent and alkylated phenanthrenes (P, A-Ps), anthracenes (An, A-An), and dibenzothiophenes (DBT, A-DBTs) during the synthetic maturation (Gold tube hydrous pyrolysis) from 0.6% to 4.7% EASY%Ro of two marine shales. The two untreated samples show different elemental composition, bulk geochemistry, and molecular geochemistry characteristics. The distribution sequence of classes with different degrees of alkylation indicates that higher reaction energy is needed for the demethylation of compounds with a lower degree of alkylation. However, the occurrence of trimethyl- and dimethyl-classes of A-Ps and A-DBTs at 550 °C (EASY%Ro: 4.4%) and 600 °C (EASY%Ro: 4.7%) is proposed to result from the breakdown of pyrobitumen at high pyrolysis temperature. The inclusion of An with P when calculating maturity ratios has an influence on their correlation with EASY%Ro at very high maturity. Common molecular thermal ratios including MPI-1, MPI-3, MPDF, MPR, and DMPR were calculated and compared with previous works. All proxies show general trends of firstly increasing and then decreasing along with thermal evolution. The separate trends in the molecular thermal evolution of the two source rocks could be attributed to the difference in organic matter composition and sedimentary facies. Two new thermal molecular maturity ratios applicable in the late gas window, i.e. 2+3-MDBT/4-MDBT and (2,4,6-TMDBT + 1,4,6-TMDBT)/(3,4,6-TMDBT + 2,6,7-TMDBT) are proposed based on the sensitivity of 2+3-MDBT, 2,4,6-TMDBT and 1,4,6-TMDBT isomers towards high maturity.

Chemical and isotopic evolution of flowback fluids from the Utica Gas Shale Play, Eastern Ohio USA

Hydraulic fracturing flowback fluids were collected from two Utica/Point Pleasant well pads in eastern Ohio. One site was in the wet gas zone (UPPW), while the site ∼50 km south consisted of four wells on the same pad in the dry gas zone (UPPS). Samples of input fluids also were collected before and during hydraulic fracturing. Flowback fluids are Na-Ca-Cl brines with total dissolved salt (TDS) concentrations that increase over several months from ∼100 to 200 g/L. The slightly higher TDS of the dry gas fluids are in part due to recycled flowback used as input fluids, and in part due to lower volume of water used in hydraulic fracturing. Concentrations of most major ions (Ca2+, Mg2+, Na+, Sr2+, Fe, Mn, Cl−, Br−) are similar for the five wells sampled, although small but systematic changes occur in the major element ratios over time.Most notably, an increase in the Sr/Cl ratio corresponds to an increase in the 87Sr/86Sr ratio in the fluids, suggesting interactions with a more radiogenic Sr source in the subsurface. Dissolved Ba concentrations and Ra activities were different between the two sites, reflecting a high SO42− fluid used at the UPPW site, and water-rock reactions occurring during hydraulic fracturing at the UPPS site.Water oxygen (δ18O) and hydrogen (δD) isotopes for input fluids used in the UPPW4 well and fresh water used for the UPPS wells fall on the Global Meteoric waterline (GMWL). Flowback fluids from both sites are relatively enriched in δ18O and δD compared to the input, but do not appear to follow a simple mixing trend, suggesting reaction and isotopic exchange with carbonates and fractionation due to imbibition in the rock. Cl isotopes, δ37Cl in the FP fluids varied from ∼ −0.43 to +0.13‰, the largest variation was observed in the earlier stages of flowback, while in the later stages δ37Cl exhibited a small but systematic increase over time, suggesting diffusion control of isotopic composition.Some of the trace species measured (dissolved Fe, Mn, thiosulfate and organic acids) do not follow the same trends as the major ions, suggesting contributions from input fluids, or microbially mediated reactions are exerting control on their concentrations. Input water chemistry exerts an important control on the Sr and Ba concentrations in flowback water. High SO42− in the input fluids used for hydraulically fracturing the wet gas well leads to precipitation of barite-celestite in flowback fluids.

Geochemical Considerations from the Carboniferous Unconventional Petroleum System of SW Iberia

The Baixo Alentejo Flysch Group (BAFG) is an important stratigraphic unit that covers over half of the South Portuguese Zone (SPZ) depositional area, and it is composed by three main tectono-stratigraphic units: the Mértola, Mira, and Brejeira formations. All of these formations contain significant thicknesses of black shales and have several wide areas with 0.81 wt.%, 0.91 wt.%, and 0.72 wt.% average total organic carbon (TOC) (respectively) and thermal maturation values within gas zones (overmature). This paper is considering new data from classical methods of organic geochemistry characterization, such as TOC, Rock–Eval pyrolysis, and organic petrography, to evaluate the unconventional petroleum system from the SPZ. A total of 53 samples were collected. From the stratigraphical point of view, TOC values seem to have a random distribution. The Rock–Eval parameters point out high thermal maturation compatible with gas window (overmature zone). The samples are dominated by gas-prone extremely hydrogen-depleted type III/IV kerogen, which no longer has the potential to generate and expel hydrocarbons. The petrographic analyses positioned the thermal evolution of these samples into the end of catagenesis to metagenesis (wet to dry gas zone), with values predominantly higher than 2 %Ro (dry gas zone). The presence of thermogenic hydrocarbon fluids characterized by previous papers indicate that the BAFG from SPZ represents a senile unconventional petroleum system, working nowadays basically as a gas reservoir.

Source rock potential assessment of the Paleocene coal and coaly shale in the Attock-Cherat Range of Pakistan

In this study the hydrocarbon generation potential of the coal and coaly shale samples collected from coal mines in Attock-Cherat Range of Pakistan is optically and analytically evaluated. These samples, representing the Paleocene Hangu Formation, are analyzed across a range of thermal maturity stages to understand their hydrocarbon generation potential. The visual examination of maceral type and values of vitrinite reflectance have been considered while interpreting the geochemical results for the coal and associated sediments from the Paleocene Hangu Formation. The maceral group is dominated by vitrinite, mainly collodetrinite, followed by inertinite and liptinite, and suggests Type III kerogen for the samples. The geochemical parameters suggest that the samples are post mature, however, the vitrinite reflectance measurements show late mature conditions for a gas-prone generation. The overall petrographical and geochemical data suggest that the coal and coaly shale appear to occupy the gas window and fall in the dry gas zone. Based on the maceral types and Rock–Eval data, an anoxic to terrestrial environment is inferred for the deposition of the coal and associated sediments. The vitrinite reflectance, Rock–Eval pyrolysis, and the type and frequency of macerals show that the coal is of good quality, i.e., medium to high volatile bituminous and hard brown coal, mature, and is lying in the gas window. Oxygen index is continuously low throughout the analyzed interval, which further supports that the coal is of good quality.

Petroleum System Modelling of the Akri-Bijeel Oil Field, Northern Iraq: Insights From 1-Dimensional Basin Modelling

The petroleum system of the Akri-Bijeel oil field shows that the Palaeogene formations such as the Kolosh Formation seem to be immature. However, the Jurassic–Lower Cretaceous source rocks such as those from the Chia Gara, Naokelekan, and Sargelu formations are thermally mature and within the main oil window because their vitrinite reflectance (Ro%) values are >0.55%. The Triassic Kurra Chine and Geli Khana formations are thought to be in the high maturity stage with Ro values ≥1.3% and within the wet and dry gas windows, whereas the older formations are either within the dry gas zone or completely generated hydrocarbon stage and depleted after the hydrocarbons were expelled with subsequent migration to the reservoir rock of the structural traps.

Impact of thermal maturity on the concomitant evolution of the ultrafine structure and porosity of marine mudstones organic matter; contributions of electronic imaging and new spectroscopic investigations

This study aims to better understand the evolution of the organic matter (OM) ultrafine structure (designating the nanoscopic structure of the OM/macerals) and porosity with increasing thermal maturity of mudstones source-rocks. To this end, the particulate fractions of kerogen from organic-rich Kimmeridge clay mudstones were isolated by acidic treatment before and after laboratory thermal maturation. The evolution of the composition, the chemical structure and the porosity of kerogen from the immature stage (Ro = 0.42%) to the dry gas zone (Ro = 2.12%) were documented using a combination of elemental analysis, vitrinite reflectance measurements, Scanning Electron Microscopy (SEM) and Transmission Electron Microscopy (TEM), Raman spectroscopy and Small Angle X-Ray Scattering (SAXS). The evolution of the porosity of OM was then compared to the evolution of the pore volume of the total rock measured by nitrogen adsorption. The results show that the progressive densification, reorganization and aromatization of the amorphous kerogen particles into a more ordered, but heterogeneous carbon-rich residue is responsible for significant variations in the kerogen porosity with increasing maturity. Contrary to the previous observations on these Kimmeridge clay mudstones, the variations that occur during the peak of oil generation (Ro of ca. 0.90%) mark the onset of the OM-hosted pores development. There appears to be a natural close relationship between the evolution of OM porosity and total pore volume of organic-rich mudstones during gas generation. Indeed, a similar alternation of pore collapse and pore development is observed in response to gas generation. The development and the evolution of pores in these organic-rich mudstones seems thus mainly driven by the evolution of the chemical structure and the composition of OM during thermal maturation. In the dry gas zone, the porosity and the specific surface area of the kerogen are significant (19% and 57.1 m2.g−2 respectively). This highlights the importance of the OM content, type and composition in the porosity and gas storage capacities of mudstone reservoirs, increasingly discussed in the available literature in recent years.

Lower Paleozoic oil and gas shale in the Baltic-Podlasie-Lublin Basin (central and eastern Europe) – a review

In the Baltic-Podlasie-Lublin Basin, four potential lower Paleozoic shale reservoirs are identified: the Piaśnica, Sasino and Jantar formations, as well as the Mingajny shale. These units were diachronously deposited during the starved stages of Caledonian foredeep basin development, in the course of rising or high eustatic sea level. Across most of the basin, the shale formations analysed are saturated with light oil and condensate, and they are buried to depths of 2300–3500 m. The shale reservoirs reach the wet gas window at burial depths of 2800–4000 m, while dry gas accumulations occur at depths exceeding 3500–5000 m, except in the Bilgoraj-Narol Zone. The shale analysed might be generally classified as a moderate to low quality, and locally high quality, unconventional reservoir. Within the shale net pay zones, the average TOC content is 2–5 wt.% TOC. The exceptions are the Piaśnica Formation, for which this is 5–12 wt.%, and the Mingajny shale, which is TOC-lean (1.4–1.7 wt.%). The thickness of the shale net pay intervals in the most favourable locations, mainly on the Łeba Elevation, generally reaches 20 m, and locally exceeds 35 m. The shale reservoirs are saturated with hydrocarbons of good quality. Their permeability is low to moderate, often in the range of 150–200 mD, while total porosity average per borehole is commonly exceeds 6 %, reaching up to 10% at maximum, which might be considered as moderate to good. The clay minerals content is moderate to high (30–50%), and geomechanical characteristics of the shale formations are intermediate between brittle and ductile. No overpressure occurs in the basin, except for a dry gas zone in the SW Baltic Basin. In the Bilgoraj-Narol Zone, and to a lesser degree also in the Lublin region, pronounced tectonic deformation significantly limits shale gas/oil potential. Among 66 exploration boreholes drilled in the basin so far, only 5 were lateral boreholes with representative production test results. Hydrocarbon flow from the best boreholes was low to moderate, equal to 11.2 to 15.6 thousand m3/day for gas, and 157 bbl/day (~21.4 ton/day) for oil. There is, however, high potential to improve production flow rates, connected with the fracturing of two net pay intervals at one time, as well as with significant technological progress in the exploitation of shale basins during the last 5 years. Commercially viable production might be achieved for a single borehole with estimated ultimate recovery exceeding 30–50 thousand tons of oil, or 60–90 million m3 of gas.

Preservation of lateral pressure disequilibrium during the uplift of shale reservoirs

A pressure gradient increase from normal pressure in oil zones to overpressure in dry gas zones indicates a lateral disequilibrium of pore pressure in many shale reservoirs. In this work, conditions for the preservation of the lateral pressure disequilibrium during uplift and erosion are investigated. Numerical simulations were conducted by coupling pressure–volume–temperature (PVT) and fluid dynamic calculations. Results show that temperature decrease and pore volume expansion during erosion tends to increase the pressure gradient in the gas or condensate zone and tends to decrease the pressure gradient in the black oil zone; therefore, the PVT effect tends to enhance lateral pressure disequilibrium during erosion. Low permeability is crucial for the preservation of the lateral pressure disequilibrium. The persistence of disequilibrium over geological time (tens of millions of years) requires extremely small vertical permeability (sub-picodarcy range) and horizontal permeability (10 nd or even lower). The horizontal permeability is 10–100 times smaller than laboratory measurements on shale plugs, indicating a discontinuity of laminations and fractures within a shale formation.

Influence of Gas and Oil State on Oil Mobility and Sweet-Spot Distribution in Tight Oil Reservoirs from the Perspective of Capillary Force

Summary The coexisting free gas, solution gas, and oil in a tight oil reservoir, constrained by the capillary force of the micrometer/nanometer pore/pore-throat system, are of crucial importance to the sweet spot of a tight oil reservoir. Equations of modified total capillary force for the liquid phase are proposed to indicate the tight oil mobility in situ, and are derived from the Kelvin capillary force equation, the Peng-Robinson (PR) equation of state (EOS) (Robinson et al. 1977), and the Van-Laar (VL) equation (Renon and Prausnitz 1968). In addition, relationships between the vapor/liquid state, phase-flow state for production, and gas/oil ratio (GOR) are established in correspondence with the production data of North American and Chinese (Yanchang) tight oil plays. The following conclusions can be drawn. We proposed a modified total capillary force function to indicate the tight oil mobility in situ, using the PR EOS method and the EOS+λ (VL equation) method. We identified five phase stages according to the gas volume ratio ( yi) in situ: the single-phase oil flow stage, the multiphase transient-flow stage, the multiphase stable-flow stage, the multiphase supercritical-flow stage, and the single-phase gas flow stage. Tight oils are more mobile in three stages: near the critical point of yi-critical(1), such as in the Yanchang and Bakken tight oils; at the transition zone between oil and wet-gas zones before yi-critical(2), such as in the Eagle Ford tight oil; and between the yi-critical(2) and yi-critical(3) in a gas-condensate state, which is at the transition zone between wet-gas and dry-gas zones.

Effect of organic matter composition on source rock porosity during confined anhydrous thermal maturation: Example of Kimmeridge-clay mudstones

To investigate how slight differences in the total particulate organic matter (OM) assemblage and maceral types of marine mudstones influence the development and the evolution of OM porosity throughout the same formation, laboratory gold-tube anhydrous confined thermal maturation was applied on low-mature organic-rich marine Kimmeridge clay mudstones (Yorkshire, UK). Organic petrography (palynofacies and maceral analysis), SEM observations, global and molecular geochemical characterization and low-pressure nitrogen adsorption measurements were performed to examine, to our knowledge for the first time, the role of the OM composition and properties on the evolution of porosity during thermal maturation. Evidence from organic petrography and geochemical analyses showed that organic-rich Kimmeridge clay samples containing a higher relative proportion of brown amorphous organic matter (AOM), known to be derived essentially from the cell walls of microalgae, exhibit a different pore evolution compared to samples containing a higher proportion of oil-prone orange AOM derived primarily from preservation by natural sulfurization of phytoplanktonic organic components naturally rich in lipidic compounds. OM conversion of orange AOM-rich samples has led to the production of higher amounts of low viscous oil and abundant gaseous hydrocarbon that are more favorable to the formation of abundant but small OM micropores and mesopores in the condensate/wet gas zone and less abundant large modified mineral pores in the dry gas zone. The secondary cracking of the heavier oil produced by brown-AOM-rich OM has led to the formation of a greater quantity of CO2 and an abundant organic-rich residue more favorable to the formation of larger mesopores. Moreover, the more abundant thick laminar bituminite macerals forming a continuous ductile network particularly prone to compaction and the higher amounts of oil/bitumen generated during their conversion may have led to a higher pore collapse after oil/gas generation and migration, responsible for the destruction of part of the secondary pore network observed on some samples. Despite their slightly lower oil-prone potential, brown AOM-rich samples have thus developed larger mesopores during thermal maturation, resulting in higher pore volumes in the dry gas zone. Thus, the ability of marine mudstones to develop pores during maturation do not increase proportionally with the OM oil prone quality. These results show that variations in the individual particulate OM assemblage of a similar type II kerogen can significantly influence the amount of oil and gas generated during thermal maturation throughout the same formation, resulting in different pore evolution models. This reveals the importance of clearly identifying the composition of the original particulate OM assemblage to better predict the amount of bitumen, oil and gas generated during thermal maturation and the associated pore development.

Petroleum geochemistry, burial history and shale gas potential of the Goldwyer Formation - Canning Basin, Western Australia

Several organic-rich shale horizons in the Canning Basin, Western Australia, acted as source rocks for conventional oil and gas fields. The aim of this study is to investigate one of its units, the Goldwyer Formation (Ordovician in age, as the Utica Shale in USA) as a potential shale gas play. Geochemical analysis such as Rock-Eval pyrolysis and total organic carbon (TOC) estimation, as well as thermal and burial history modelling were used. The organic matter is mixed type II/III kerogen and the total organic carbon (TOC) values range between 0.16 and 4.8 wt%. Tmax values between 335°C and 471°C and vitrinite reflectance values between 0.71 and 1.3 Ro% point to the main oil to wet and dry thermogenic gas zones, with a trend of increasing maturity in the west-central part of the basin. The results of this study show that the Goldwyer shale may be considered as potential shale-gas play. [Received: September 3, 2016; Accepted: March 2, 2017]

Petroleum geochemistry, burial history and shale gas potential of the Goldwyer Formation - Canning Basin, Western Australia

Several organic-rich shale horizons in the Canning Basin, Western Australia, acted as source rocks for conventional oil and gas fields. The aim of this study is to investigate one of its units, the Goldwyer Formation (Ordovician in age, as the Utica Shale in USA) as a potential shale gas play. Geochemical analysis such as Rock-Eval pyrolysis and total organic carbon (TOC) estimation, as well as thermal and burial history modelling were used. The organic matter is mixed type II/III kerogen and the total organic carbon (TOC) values range between 0.16 and 4.8 wt%. Tmax values between 335°C and 471°C and vitrinite reflectance values between 0.71 and 1.3 Ro% point to the main oil to wet and dry thermogenic gas zones, with a trend of increasing maturity in the west-central part of the basin. The results of this study show that the Goldwyer shale may be considered as potential shale-gas play. [Received: September 3, 2016; Accepted: March 2, 2017]

Nowa metoda interpretacji danych odbudowy ciśnienia głowicowego w odwiertach gazowych udostępniających złoże o niskiej lub umiarkowanej przepuszczalności

Nowa metoda interpretacji danych odbudowy ciśnienia głowicowego w odwiertach gazowych udostępniających złoże o niskiej lub umiarkowanej przepuszczalności

Do all fractions of organic matter contribute equally in shale porosity? A case study from Upper Ordovician Utica Shale, southern Quebec, Canada

In many unconventional hydrocarbon systems, organic matter (OM) substantially contributes to total porosity of the rock that led to a positive correlation between total organic carbon (TOC) and porosity. While organic porosity is an important reservoir property of unconventional hydrocarbon systems, TOC of these rocks consists of different macerals or petrographic fractions. These TOC fractions can be geochemically divided and quantified by the revised, extended slow heating (ESH) Rock-Eval analysis. This study discusses the contribution of different fractions of OM on porosity variation in the mature to overmature Utica Shale in southern Quebec, using ESH Rock-Eval analysis, helium pycnometery, scanning electron microscopy (SEM), and X-ray diffraction (XRD) mineralogy. Selected samples from three wells at depths of ∼400, 700, and 2000 m, covering a range of thermal maturity from late peak oil window (VRoeqv. ∼1%) to dry gas zone (VRoeqv. ∼2.1%) were analyzed in this study. The predominant OM constituents are solid bitumen, chitinozoans, and minor graptolites with mean TOC of 1.1 ± 0.4 wt. %. The mean porosity for oil and gas window samples decreases with depth from 3.9 ± 0.9 to 2.6 ± 0.5%, respectively. The SEM images reveal that organic porosity is limited to pores developed in solid bitumen, while regardless of thermal maturity, chitinozoans have a non-porous structure throughout the oil to dry gas window. This observation suggests that the impact of thermal maturity on porosity is different for different OM fractions (i.e., macerals), leading to different contribution of OM fractions to total porosity. The latter conclusion is further supported by the improved correlation observed between the solid bitumen fraction and porosity compared to TOC-porosity correlation for oil window samples. Our entire data set suggests that OM (i.e., bitumen fraction), especially in the dry gas window, is not the major controlling factor on the total porosity in the Utica Shale, whereas, intergranular porosity has the dominant control on total porosity. This observation suggests that the hydrocarbon storage potential may largely reside in inorganic pores rather than organic pores in the analyzed intervals of the Utica Shale. The decrease in total porosity observed from shallower samples (i.e., oil window) to deeper samples (i.e., dry gas window) also suggests that intergranular porosity is the dominant porosity component, which decreases with burial.

The organic petrology of graptolites and maturity assessment of the Wufeng–Longmaxi Formations from Chongqing, China: Insights from reflectance cross-plot analysis

The Wufeng–Longmaxi Formations (Ordovician-Silurian) contain abundant graptolite-bearing shales, which have proven to be one of the most successful shale gas exploration targets in China and can provide an opportunity to study the organic petrology of graptolites. Organic petrology analysis has been conducted on these organic-rich shales in order to depict the shape of graptolite reflectance indicating surface (GRIS) and their organic maturity. Granular and non-granular graptolites have been observed in the studied sediments, and non-granular graptolites were the major graptolite species. The strong positive correlation between the maximum reflectance (Rmax) and bireflectance of graptolites indicates that the graptolites display stronger anisotropy with maturation. A linear coalification path of graptolite fragments was observed in the studied sediments. A remarkable decrease in the minimum reflectance (Rmin) values of graptolites was observed when Rmax exceeds 6%. The samples with lower thermal maturity (Rmax≤2%) tend to be biaxial neutral, whereas higher rank samples display biaxial negative characteristics. The GRIS shape becomes more oblate with maturation. The Wufeng–Longmaxi shales from the southeastern Chongqing and Wuxi areas of the Chongqing municipality, China, are post mature and in the dry gas zone, whereas samples from the Chengkou area of the Chongqing municipality, China, are still in the oil window. Their different burial and thermal histories controlled their thermal maturity.

Crude oil and condensate in the Ordovician–Silurian formations of the Eastern European: The Western Black Sea Basin

ABSTRACTThe Lower Paleozoic sediments of Eastern Europe extend from Poland to the Black Sea Coasts. The Lower Ordovician Bakacak Formation and Middle Ordovician–Silurian Karadere, Ketencikdere, and Fındıklı formations of the Western Black Sea Basin contain mudstones and black shales with sandstone and limestone intervals. The mudstones of the Lower Ordovician do not display any potential. But some intervals of the Middle Ordovician–Silurian black shales have potential for unconventional exploration because total organic carbon (TOC) of organic matter contents ranges from 0.11% to 1.94%. Hydrogen index (HI) values of the Karadere, Ketencikdere, and Fındıklı formations are ranging 0–139 mg oil/g TOC. Vitrinite reflection equivalent (Roe) estimation from HI shows that the shales locate within the oil, wet gas-condensate, and dry gas zone. In-situ oil and condensate volumes of the black shales have been calculated between 0 and 2812 mg HC/g TOC. These volumes indicate presence of potentially producible hydrocarbon in the some intervals of the Middle Ordovician–Silurian shales. Mineralogical properties of the Karadere, Ketencikdere, and Fındıklı formations are suitable for hydraulic fracturing because the shales are dominated by quartz/carbonate. Quartz ratio ranges from 12% to 91% with an average 53%. Total calcite/dolomite content is an average of 13/0.5%. Total clay mineral chance between 0% and 39% with an average of 21%.

Petroleum System Modeling of Jabal Kand Oil Field, Northern Iraq

The petroleum system of Jabal Kand Oil Field shows that the formations such as Tertiary Kolosh, Cretaceous Shiranish, and Jurassic Sargelu are immature and have not generated any oil Ro 0.55%. Other formations such as Gele Khana and other Triassic formations are with high maturity with Ro≥ 1.3% and are within wet and dry gas window while older formations are either within dry gas zone or completely generated hydrocarbon and depleted after hydrocarbon was expelled and migrated to reservoir rock of structure traps.

Source Rock Assessment of Naokelekan Formation in Iraqi Kurdistan

The Callovian-Kimeridgian Naokelekan Formation is a heterogeneous sequence consisting principally of bituminous shales with bituminous limestone and dolomitic limestones. It is 48 m thick maximally in some parts of the area. One hundred forty four rock and cutting samples from six outcrops and eight boreholes in different parts of Iraqi Kurdistan have been studied using the Rock-Eval technique with the primary purpose of assessing their potentiality as promising source rocks for petroleum. The outcomes of the Rock-Eval study for examined samples shows that TOC ranges from 0.4 to 18.8 wt. % and types II and III kerogens are the main components of organic matter.Qualitative evaluations are also done by textural microscopy used in assessing amorphous organic matter for palynofacies. The organic matters are mature that have thermal alteration index of 2.6-3.2 by Pearson's scale with palynomorphs of dark orange and light brown colors and Tmax ranges between 434 to 493ºC. Thus the Naokelekan Formation can be considered as a source rock for generation and expulsion of oil and/or gas that has been charged largely oil fields in the area.Maturity increases toward the northeastern part of the studied area. Furthermore, the study revealed that Naokelekan Formation is within dry gas and/or late oil zone in the eastern part, early oil window in the central part and immature in the western part of the studied area.

Energy Intensity and Greenhouse Gas Emissions from Oil Production in the Eagle Ford Shale

A rapid increase in horizontal drilling and hydraulic fracturing in shale and “tight” formations that began around 2000 has resulted in record increases in oil and natural gas production in the U.S. This study examines energy consumption and greenhouse gas (GHG) emissions from crude oil and natural gas produced from ∼8,200 wells in the Eagle Ford Shale in southern Texas from 2009 to 2013. Our system boundary includes processes from primary exploration wells to the refinery entrance gate (henceforth well-to-refinery or WTR). The Eagle Ford includes four distinct production zones—black oil (BO), volatile oil (VO), condensate (C), and dry gas (G) zones—with average monthly gas-to-liquids ratios (thousand cubic feet per barrel—Mcf/bbl) varying from 0.91 in the BO zone to 13.9 in the G zone. Total energy consumed in drilling, extracting, processing, and operating an Eagle Ford well is ∼1.5% of the energy content of the produced crude and gas in the BO and VO zones, compared with 2.2% in the C and G zones. On a...