An Experimental Investigation of the Impact of Diffusion Osmosis and Chemical Osmosis on the Stability of Shales

Abstract

Wellbore instability in shales is the most challenging and costly issue in drilling operations. Wellbore instability in shales can be attributed to many factors, some of which have been well studied and documented. However, the physicochemical and mechanical properties alterations in shales that eventually lead to wellbore failure have been largely ignored. Water and ion movements in and out of shales play a major role in the alteration of the physicochemical and mechanical properties of shales, thus leading to wellbore instability problems and possible hole collapse. Water and ions can move in and out of shales by many mechanisms, including, but not limited to, diffusion osmosis, chemical osmosis, convective flow, and capillary suction.

This work presents experimental data analyzing the impact of chemical osmosis and diffusion osmosis on water and ion movements when shale interacts with drilling fluids. The adopted experimental work minimized the effect of convective flow and capillary suction. Results show that water movement is not only controlled by chemical osmosis (water activity) as previously thought but is also influenced by diffusion osmosis. This insight provides information and guidelines to optimize drilling fluids to effectively control and mitigate wellbore instability when drilling through troublesome shale.     

Geostatistical Simulation Study of Porosity and Hydrocarbon Saturation Values in the Vicinity of Adiyaman,Turkey

Abstract

The Cretaceous Mardin Group sequence in the Adiyaman region displays a “continental platform type” petroleum system. The main lithologies within the sequence are shales, mudstones, and carbonates. Most dolomitic and bioclastic wackestones of the Karababa-C member and dolomites of the Derdere Formation have hydrocarbon reservoir characteristics, whereas shales and some carbonates of the Derdere and Karababa-A member have mature hydrocarbon source-rock properties. To determine the porosity and hydrocarbon saturation value vs. depth and areal extends, geostatistical simulation for the three dimensional evaluation of the study area were constructed and the variogram functions were calculated and then three dimensional variograms which were obtained from the porosity and hydrocarbon saturation values were modelled spherically. According to the simulation results, the porosity values in the Karababa-C member decrease with increasing depth. The amount of hydrocarbon saturation tends to decrease with increasing depth, as well and the decrease ratio is 7.2%. The suitability of the model parameters were validated with back-kriging technique.     

Source rock assessment of the Lower Cretaceous Ulus Formation of NW Turkey: implication to petroleum exploration

Abstract

The Ulus Basin of the Western Black Sea of Turkey contains Upper Jurassic–Recent sediments. Mudstone-marl and turbiditic shales of the Lower Cretaceous Ulus Formation have moderate source rock potential because total organic carbon (TOC) contents range from 0.34% to 1.18%. HI values are between 20 and 259. T-max values have been measured between 438 and 457?°C. Thus, maturity of the shales of the Ulus Formation is ranging from early mature-to mature. The formation was produced oil and wet gas-condensate. The Ulus Basin has several reservoirs, seals and traps. Although three exploration wells were drilled by Turkish Petroleum Company, the wells were abandoned as dry because of not reach to reservoirs.     

CHEMICAL COMPOSITION OF SHALE OIL I. DEPENDENCE ON OIL SHALE ORIGIN

ABSTRACT

Shale oils obtained by nitrogen retorting of North Carolina, Cleveland, Ohio, Colorado, Rundle, Stuart, and Condor oil shales have been chemically characterized by g.c.-m.s. techniques. After species identification, chemical compositions of the shale oils have been related to the geological origins of the parent shales. Based on the characteristics observed in the chromatograms, eight semi-quantitative parameters have been used to describe the chromatograms. Six of these parameters describe the relative abundance and distribution of straight chain alkanes and alkenes in the chromatograms. The other two parameters represent the abundance, relative to the total amount of volatiles in the oil, of alkylbenzenes and alkylphenols.     

Wellbore Instability and Countermeasures in Offshore Bedding Shale Formations

Abstract

The properties of bedding shales are different from that of normal formations. Strength anisotropy is their outstanding feature. Experimental study and theoretical analysis show that this kind of anisotropy of bedding shales is the main reason of wellbore instability. W-2nd section shales in WZ12-1N oilfield are in typical bedding formation, and there were some problems such as severe borehole collapse and pipe sticking in drilling. Bedding shale formation was assumed to be a transversely isotropic material, and a collapse pressure calculating method was established. The calculation result of directional drilling collapse pressure in W-2nd bedding shales shows that if hole deviation exceeds a certain critical value, collapse pressure will increase sharply. This result was used in mud density design and well trajectory optimization, which solved the wellbore instability problems of the W-2nd formation. This research method has reference value to solve problems of wellbore instability and improve drilling efficiency in other similar regions.     

Organic Geochemical Evaluations of Bituminous Rock and Coals in Miocene Himmetoglu Basin (Bolu,Turkey)

Abstract

The studied area is a lake basin located in Bolu basin in Turkey. In the basin, from Upper Cretaceous to Upper Miocene 3,000-m thickness sediments were deposited. Upper Miocene Himmetoglu formation consisted of sandstone, claystone, and marl. To the middle level of the formation are located coal, bituminous limestone, and bituminous shales. In the basin, there are two coal beds whose thicknesses range from 1 to 13 m. The coals are easily breakable and black in color. In the coal beds exists some bituminous limestone and bituminous shales, and their thicknesses are between 5 and 45 cm. The amount of organic matter of the bituminous rocks from the Upper Miocene Himmetoglu formation are between 6.83 and 56.34 wt%, and the amount of organic matter of the bituminous limestone from the formation are between 13.58 and 57.16 wt%. These values indicate that these rocks have very good source potential. According to hydrogen index (HI), S ₂/S ₃, HI-T _max, and HI-OI (oxygen index) parameters, kerogen types of the bituminous rocks and coals belonging to Upper Miocene Himmetoglu formation are Type I, Type II, and Type III. In accordance with HI, S ₂/S ₃, HI-T _max, and HI-OI parameters, the bituminous rocks and coals from the Upper Miocene Himmetoglu formation are mostly immature.     

COMPARATIVE STUDY BETWEEN THE KINETICS OF RETORTING OF OHIO ANO COLORADO SHALE

ABSTRACT

A comparative study between the kinetics of oil generation from Ohio and Colorado shales has been done. To facilitate comparison and to eliminate systematic errors, the same retorting system was used to study the kinetics of both Ohio and Colorado shales. Temperatures ranging to 923° K and nitrogen and carbon dioxide as sweep gases were used for this study. Both the isothermal and non-isothermal retorting techniques were employed for the kinetic measurement and the results obtained compared favorably with each other. The pyrolysis of Ohio shale was also found to comply with first order kinetics within the limits of experimental error. The study gave an apparent activation energy of 149.1 ± 2.8 KJ/mol for Ohio shale (25 cm³/kg) and 182.5 ± 3.5 KJ/mol for Colorado shale (110 cm³/kg).     

Application of Light Hydrocarbon (C7+) and Biomarker Analyses in Characterizing Oil from Wells in the North and North Central Sinai,Egypt

Abstract

Seven representative oil show samples from wells in the north and north central Sinai have been characterized by means of a variety of organic geochemical techniques (C₇ hydrocarbon and biomarker analyses), to illustrate origin, differences, and similarity among oils. These oils were obtained from Cretaceous and Jurassic reservoirs. The C₇ oil correlation star diagram (OCSD) suggests closely related oils, derived mainly from similar source rocks, while the C₇ oil transformation star diagram (OTSD) and C₇ light hydrocarbon analyses indicate a minor degree of transformation of some oils, as Misri-1, Halal-1, and Nakhl-1 oils were subjected to evaporative fractionation. Moreover, the studied oils show no sign of water washing and biodegradation. Molecular characteristics suggest pre-Tertiary shales and carbonate source rocks, deposited under a saline oxic environment, rich in terrigeneous organic sources with significant bacterial and algal input. Since the studied oils are of mixed marine and terrestrial origin, C₇ signature of these oils is not representative of their origin and should be supported by other geochemical evidence (e.g., biomarkers) to predict their origin.     

Calculation of the Amounts of Hydrocarbons Generated from the Lower Antalya Nappes,Western Taurus Region: The Importance of the Fractional Conversion (f) Value

Abstract

Applying the corrected Hydrogen Index values obtained from S ₂ vs. TOC graph in conjuction with the results of Rock-Eval pyrolysis and mass balance calculations provide estimations of the original hydrocarbon generative capacity and the amounts of hydrocarbons generated. For calculations and a comparison between three different approaches were applied to 27 organic-rich samples collected from the Dereköy Formation shales which are mainly characterized by oil-prone Type-II kerogen that is in different thermal maturity levels. Such calculations indicate that (1) the results of the calculated amounts of original hydrocarbons are mostly over 100,000 ppm, (2) the results of the hydrocarbon generative capacities from two methods which include fractional conversion value are in accordance, and, are over 5000 ppm, and (3) when the fractional conversion values are low (ranging from essentially zero to 0.5%), indicating thermally immature stage, the calculation results of three methods are almost similar.     

BIOMARKER GEOCHEMISTRY OF CRUDE OILS AND NEOGENE BITUMINOUS SHALES IN THE YENIKÖY AREA,EREĞLI‐ULUKIȘLA BASIN,CENTRAL ANATOLIA,TURKEY

In the Ere?li‐Uluk??la Basin, southern Turkey, crude oil shows have been observed in the subsurface in the shale‐dominated non‐marine Upper Miocene – Pliocene succession. Based on analyses of samples from four boreholes, the shales’ organic matter content, thermal maturity and depositional characteristics are discussed in this study. Geochemical correlations are established between shale extracts and a crude oil sampled from the shale succession. The shales have moderate to high hydrogen index (HI) and very low oxygen index (OI) values. Pyrolysis data show that the shales contain both Types I and II kerogen, and n‐alkane and biomarker distributions indicate that organic matter is dominated by algal material. Very high C₂₆/C₂₅ and C₂₄/C₂₃, and low C₂₂/C₂₁ tricyclic terpane ratios and C₃₁ R/C₃₀ hopane, C₂₉/(C₂₈+C₂₉) MA and DBT/P ratios in shale extracts indicate that deposition occurred in a lacustrine setting. High gammacerane and C₃₅ homohopane concentrations and low diasterane/sterane ratios with a very low Pr/Ph ratio suggest that both the shales and the source rocks for the oil were deposited in a highly anoxic environment in which the water column may have been thermally stratified. Although the shales analysed have very low T_max values, the production index is quite high which suggests that the shales are early‐mature to mature. Biomarker ratios including C₃₂ 22S/(22R+22S) homohopanes, C₂₉ 20S/(20R+20S) and ββ(ββ+αα) steranes, moretane/hopane, TA(I)/TA(I+II) and MPI‐3 all suggest that the shales are within the oil window. Heavy components of free hydrocarbons (S₁) within the shales may have been recorded as part of the Rock‐Eval S₂ peak resulting in the low T_max values. The oil and shale extracts analysed are similar according to their sterane and triterpane distributions, suggesting that the oil was generated by the shales. However burial depths of the Upper Miocene – Pliocene shale succession are not sufficient for thermal maturation to have occurred. It is inferred that intense volcanism during the Pliocene – Pleistocene may have played an important role in local maturation of the shale succession.     

ORGANIC-RICH SHALES IN THE UPPER TRIASSIC ZANGXIAHE FORMATION,NORTHERN QIANGTANG DEPRESSION,NORTHERN TIBET: DEPOSITIONAL ENVIRONMENT AND HYDROCARBON GENERATION POTENTIAL

This study reports on the organic geochemical characteristics of high-TOC shales in the Upper Triassic Zangxiahe Formation from a study area in the north of the Northern Qiangtang Depression, northern Tibet. A total of fifty outcrop samples from the Duoseliangzi, Zangxiahe South and Zangxiahe East locations were studied to evaluate the organic matter content of the shales and their thermal maturity and depositional environment, and to assess their hydrocarbon generation potential. Zangxiahe Formation shales from the Duoseliangzi profile have moderate to good source rock potential with TOC contents of up to 3.4 wt.% (average 1.2 wt.%) and potential yield (S₁+S₂) of up to 1.11 mg HC/g rock. Vitrinite reflectance (R_o) and T_max values show that the organic matter is highly mature, corresponding to the condensate/wet gas generation stage. The shales contain mostly Types II and I kerogen mixed with minor Type III, and have relatively high S/C ratios, high contents of amorphous sapropelinite, low Pr/Ph ratios, high values of the C₃₅ homohopane index (up to 3.58%), abundant gammacerane content, and a predominance of C₂₇ steranes. These parameters indicate a saline, shallow-marine depositional setting with an anoxic, stratified water column. The source of organic matter was mainly aquatic OM (algal/bacterial) with subordinate terrigenous OM. Zangxiahe Formation shale samples from the Zangxiahe East and Zangxiahe South locations have relatively low TOC contents (0.2 to 0.8 wt.%) with Type II kerogen, suggesting poor to medium hydrocarbon generation potential. R_o and T_max values indicate that organic matter from these locations is overmature. The discovery of organic-rich Upper Triassic shales with source rock potential in the north of the Northern Qiangtang Depression will be of significance for oil and gas exploration elsewhere in the Qiangtang Basin. Future exploration should focus on locations such as Bandaohu to the SE of the study area where the organic-rich shales are well developed, and where structural traps have been recorded together with potential reservoir rocks and thick mudstones which could act as seals.     

Petroleum Source Rock Characteristics of the Lower Tertiary Formations in the Ereğli-Ulukışla Basin,Southern Central Anatolia,Turkey

Abstract

Potential source rocks in the Ere?li-Uluk??la basin include Campanian-Maastrichtian limestones and marls, Upper Paleocene-Lower Eocene deep-marine shales, and Middle-Upper Eocene continental slope deposits, including shales and sandstones. Organic geochemical analyses and palynofacies observations show that the organic components in Upper Paleocene-Upper Eocene sediments are mainly coaly and woody, with minor herbaceous and algal-amorphous-like organic matter, indicating that they are terrigenous (mainly Type III and Type IV kerogen). The organic carbon content of these rocks ranges from 0.04 to 0.73%, and they have marginal source rock quality for oil generation. A plot of HI versus T-max values implies that the Upper Paleocene-Lower Eocene samples are in the early stage of oil generation, while the Middle-Upper Eocene samples are thermally immature. The pristane/phytane ratio for Tertiary samples corresponds to a transition from anoxic to oxic depositional conditions.     

Mass Spectrometry of Metalloporphyrins in Egyptian Oil Shales from Red Sea Area

Abstract

Metalloporphyrins, extracted from asphaltene and maltene fractions of some Egyptian oil shales (Abu-Shegeili, El-Beida, El-Nakheil, and Abu-Tundub in the Red Sea area) by means of adsorption column chromatography and TLC, were subjected to mass spectrometry in order to elucidate the structure of different types of VO, Ni, or Fe porphyrins. Metalloporphyrins were not detected in maltene or asphaltene fractions of Abu-Shegeili oil shale. The mass spectra appeared as a truncated series of mass numbers, which is characteristic of geo-porphyrins in sediments or oil shales. The data indicated that the five types of porphyrins (Etio, DPEP, BEtio, BDPEP, and THBD) with carbon numbers ranging from C₂₀ to C₅₀ were present in considerable detection levels. Based on mass spectrometric data, the major components of metalloporphyrins (VO, Ni, or Fe) were identified and their chemical structures were suggested. The occurrence and distribution of VO, Ni, and Fe porphyrins were interpreted from a geochemical point of view, particularly maturation levels and oil-gas potentials of kerogens.     

Whole-Rock,Clay Mineral Contents and Matrix Effect on the Cenomanian/Turonian Petroleum Source Rocks in the Lower Antalya Nappe,Western Taurus Region of Turkey

Abstract

Whole-rock analyses by x-ray powder diffraction and Rock-Eval pyrolysis studies were carried out on the Cenomanian/Turonian Dereköy formation shales from four sample sites in the Lower Antalya Nappe in the western Taurus region (SW Turkey) to determine rock-forming mineral assemblages, their abundance in bulk composition, and clay matrix effect on hydrocarbon yield during Rock-Eval pyrolysis. These studies indicate that the rock-forming minerals are mostly quartz (3–68%), clay minerals (32–81%) including smectite and illite, and rare to common calcite (0–39%), feldspar (0–5%) and mica (0–11%). High total organic carbon (TOC) contents (up to 42 wt%) and corrected hydrogen indices between 538 and 642 (mg HC/g TOC) correspond to marine organic matter (Type II kerogen) and excellent oil-prone hydrocarbon source rocks. Strong positive correlation (R ² = 0.84 to 0.96) between hydrocarbon yield (S ₂) and TOC content implies that the positive values of x and y-intercepts are relatively high, with values ranging between 1–13.117 mg pyrolysable hydrocarbon in 1 g of rock. These results mean that the clay matrix is the main agent of adsorbtion, and high amounts of hydrocarbon retention must be present.     

Source Rock Characteristics,Thermal History,and Oil Generation of the Upper Cretaceous Island Arc Sequences from Northeastern Turkey

Abstract

The Upper Cretaceous eastern Pontide island arc sequence in northeastern Turkey is composed mainly of volcanic and volcaniclastic rocks and rarely of sediments. In this study, source rock characteristics and hydrocarbon potentials of shale and claystone sequences at Zigana, Çatak, and Hacimehmet areas of the volcanic island arc were investigated. According to pyrolysis data, Zigana, Çatak, and Hacimehmet sequences show poor source rock character and they mostly contain residual organic matter and type III kerogen. In addition, shales have low potential yield and hydrogen index values. In the burial diagram drawn on the basis of Lopatin method, Σ TTI values of the Zigana, Çatak, and Hacimehmet sequences are calculated as 93,222, 1,124 and 1, respectively. This diagram indicates that Zigana and Çatak sequences are out of oil generation zone while Hacimehmet sequence has not reached oil generation zone. T _max values measured from pyrolysis data generally show over mature character for the Zigana and Çatak sequences and immature character for the Hacimehmet sequence. T _max values are consistent with burial diagram. Irregularities and deviations observed particularly in Zigana and Çatak sequences may be explained with thermal effect of Late Cretaceous volcanism.     

SOURCE ROCK POTENTIAL AND ORGANIC GEOCHEMISTRY OF CENOMANIAN-TURONIAN BLACK SHALES,WESTERN TAURUS,SW TURKEY

The depositional environment and hydrocarbon source rock potential of Cenomanian-Turonian black shales of the Dereköy and Ballik Formations in SW Turkey were investigated by organic geochemical methods. In detail, 33 samples from three section of the Dereköy Formation, and 15 samples from one section of the Ballik Formation were analysed for elemental (TOC, Rock -Eval pyrolysis), C₁₅₊-lipid and biomarker compositions. Based on maximum pyrolysis degradation temperatures of not more than 420°C, all the shale samples are classified as immature, corresponding to a vitrinite reflectance of less than 0.45% R_r and a lignite to sub-bituminous coal stage. This is confirmed by relatively high isoprenoid to n-alkane ratios as well as by high biomarker contents. According to this maturity stage, and both total organic carbon contents of 6–41% and hydrogen indices of 255–708 mg HC/g TOC, the Cenomanian-Turonian black shales exhibit fair to excellent source rock potential with mixed Type II and Type I kerogen. Relatively high isoprenoid to n-alkane ratios may indicate at least partial (bio-) degradation/evaporation/waterwashing and selective modification of the lipid composition due to the nature of the outcrop. However, very similar unimodal n-alkane distributions in the gas chromatograms of four selected shale samples, with a predominance in the C₁₆ to C₁₇ region, clearly point to a significant contribution of algal and/or bacterial type organic matter with low terrigenous organic input. C₂₇, C₂₈ and C₂₉ steranes in shales from both formations have similar distributions (C₂₉>C₂₇>C₂₈). High C₃₁ R homohopane / C₃₀ hopane ratios indicate a marine depositional environment. This is confirmed by the presence of gammacerane in all the black shales investigated which in general indicates salinity. Pregnanes in one sample (BA-6) may point to hypersaline conditions.     

Investigation of Organic Carbon and Trace Metal Enrichments of Rocks at the Paleocene-Eocene Boundary,NW Turkey

Abstract

In this study, organic geochemical and biogeochemical investigations were conducted on various deposit types at the Paleocene-Eocene boundary in the Bolu and Ankara (Ozanköy) regions in northwest Turkey. Investigations yield that clayey and carbonaceous rocks in the Bolu and Ankara regions have high organic carbon (Corg) and Ni, As, Se, Au, W, and Mo contents. Variation range, range difference, and averages of these two parameters in the rocks were computed. In addition, enrichment factors of the elements in the fields were determined with respect to their abundance in the earth crust and shales. The average Corg content in the Bolu and Ankara regions is about 7.51 wt%. However, in various bitumen layers this value ranges from 10–40 wt%. The main source of OM in deposits is sapropelic or algal amorphous Type I kerogen and also Type II kerogen consisting of plant materials such as spore pollen, and leaf cuticle. Enrichment factors of Ni, As, Se, Au, W, and Mo with respect to their abundance in the earth crust are 2.93, 35.73, 144.5, 15.0, 15.25, and 3.2, respectively. Corg and element accumulation levels indicate a periodical property and the presence of a positive correlation among them. Enriched element contents are mostly attributed to an OM-dependent biogenic accumulation level. In addition, diagenetic element exchange and the element exchange particularly between seawater and bituminous material are very effective. Results of this study yielded that bitumoid-rich Bolu and Ankara regions can also be evaluated for their energy and metal sources.     

CHEMICAL COMPOSITION OF OIL SHALE II. DEPENDENCE ON THE EXTRACTION PROCESS

ABSTRACT

Eastern and Western U.S. and Australian oil shales were retorted in a fixed-bed, bench-scale retorter, using nitrogen and carbon dioxide as sweep gases. The resulting shale oils were chemically characterized by GC/MS techniques. Shale oils extracted by nitrogen and carbon dioxide retorting processes were found to have different chemical compositions, even when applied to the same oil shale samples. The extraction process dependent nature of shale oils is fully assessed in this paper and the information may be used for comparison among various extraction processes as well as for choosing appropriate upgrading processes for the crude shale oils.     

Hydrocarbon Source Rock Assessments of the Late Jurassic Black Shales (Tokmar Formation) in the Central Taurus Region of Turkey

Abstract

The hydrocarbon source rock potential and the thermal maturity of the Late Jurassic Tokmar Formation in the Bo?untu area of the central Taurus region have been investigated. Tokmar Formation includes organic matter–rich dark grey shales alternating with carbonates that were deposited under dysoxic to anoxic marine conditions prevailed in the Late Jurassic. A total of 14 samples have been analyzed by Leco and Rock-Eval pyrolysis for determination of their hydrocarbon source rock characteristics and organic maturity. The total organic carbon content of the samples range from 0.26 to 1.53 wt%. The actual Rock-Eval pyrolytic yields (S₁ + S₂ peak values) are between 0.25 and 3.63 mg HC/g rock. The calculated hydrogen index and oxygen index values imply that the main organic matter types are Type II and Type III kerogens. T_max versus hydrogen index values indicate that the Bo?untu samples are thermally mature and took place in the oil generation window.     

COMPARISON OF OILS PRODUCED FROM KENTUCKY OIL SHALES BY FLUID BED AND FISCHER ASSAY RETORTING

ABSTRACT

Physical properties and chemical composition of oils produced from a master sample of the Ohio Shale by bench scale fluid bed and Fischer Assay retorting are compared. The fluid bed oil was found to have a higher nitrogen content, lower H/C ratio, more heteroaromatic and heavy hydrocarbons, higher alkene/alkane ratios, a higher naphthalene/(C₁₁ + C₁₂) ratio and a higher aromatic carbon content than the Fischer Assay oil. Since vapor phase cracking is the major source of oil loss during fluid bed retorting with coking being near zero, these results are in agreement with correlations developed for western U.S. shales. Additionally, there is evidence to suggest that under fluid bed conditions, raw shale aromatic carbon is converted to oil.