AAPG Bulletin 

About: AAPG Bulletin is an academic journal published by American Association of Petroleum Geologists. The journal publishes majorly in the area(s): Sedimentary rock & Sedimentary depositional environment. It has an ISSN identifier of 0149-1423. Over the lifetime, 18026 publications have been published receiving 373500 citations. The journal is also known as: American Association of Petroleum Geologists bulletin & A.A.P.G. bulletin.

Unconventional shale-gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment

Abstract: Shale-gas resource plays can be distinguished by gas type and system characteristics. The Newark East gas field, located in the Fort Worth Basin, Texas, is defined by thermogenic gas production from low-porosity and low-permeability Barnett Shale. The Barnett Shale gas system, a self-contained source-reservoir system, has generated large amounts of gas in the key productive areas because of various characteristics and processes, including (1) excellent original organic richness and generation potential; (2) primary and secondary cracking of kerogen and retained oil, respectively; (3) retention of oil for cracking to gas by adsorption; (4) porosity resulting from organic matter decomposition; and (5) brittle mineralogical composition. The calculated total gas in place (GIP) based on estimated ultimate recovery that is based on production profiles and operator estimates is about 204 bcf/section (5.78 × 10 9 m 3 /1.73 × 10 4 m 3 ). We estimate that the Barnett Shale has a total generation potential of about 609 bbl of oil equivalent/ac-ft or the equivalent of 3657 mcf/ac-ft (84.0 m 3 /m 3 ). Assuming a thickness of 350 ft (107 m) and only sufficient hydrogen for partial cracking of retained oil to gas, a total generation potential of 820 bcf/section is estimated. Of this potential, approximately 60% was expelled, and the balance was retained for secondary cracking of oil to gas, if sufficient thermal maturity was reached. Gas storage capacity of the Barnett Shale at typical reservoir pressure, volume, and temperature conditions and 6% porosity shows a maximum storage capacity of 540 mcf/ac-ft or 159 scf/ton.

Guidelines for Evaluating Petroleum Source Rock Using Programmed Pyrolysis

Abstract: Rock-Eval pyrolysis is used to rapidly evaluate the petroleum-generative potential and thermal maturity of rocks. Accurate conclusions require programs every 30-60 ft (9-18 m), understanding of interpretive pitfalls, and supporting data, such as visual kerogen, vitrinite reflectance, and elemental analyses. The generative potential of coals is commonly overestimated by pyrolysis and is best determined by elemental analysis and organic petrography. Most coals show high S2/S3 (>5) and low HI values (< 300 mg HC/g TOC). Migrated oil and mud additives, which alter Rock-Eval data, can sometimes be removed by special processing. For immature rocks, bimodal S2 peaks and PI values over 0.2 indicate contamination. Pyrolysis downgrades organic-poor, clay-rich rocks, which show lower HI and higher Tmax values than isolated kerogen because of adsorption of pyrolyzate on the clays. Tmax values for small S2 peaks (< 0.2 mg HC/g TOC) are unreliable. Tmax is affected by maturation, organic matter type, contamination, and the mineral matrix. S3 is sensitive to inorganic and adsorbed carbon dioxide, and to instrumentation problems. Acidification of carbonate-rich samples and proper maintenance improves S3 measurement. Constant sample weights (100 mg) are recommended. Below a threshold weight, Tmax increases by up to 10°C, and other parameters decrease. Organic-rich samples, which overload the detector, can be diluted with carbonate. Detector linearity is determined by pyrolyzing various weights of an organic-rich rock.

Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores

Abstract: Matrix-related pore networks in mudrocks are composed of nanometer- to micrometer-size pores. In shale-gas systems, these pores, along with natural fractures, form the flow-path (permeability) network that allows flow of gas from the mudrock to induced fractures during production. A pore classification consisting of three major matrix-related pore types is presented that can be used to quantify matrix-related pores and relate them to pore networks. Two pore types are associated with the mineral matrix; the third pore type is associated with organic matter (OM). Fracture pores are not controlled by individual matrix particles and are not part of this classification. Pores associated with mineral particles can be subdivided into interparticle (interP) pores that are found between particles and crystals and intraparticle (intraP) pores that are located within particles. Organic-matter pores are intraP pores located within OM. Interparticle mineral pores have a higher probability of being part of an effective pore network than intraP mineral pores because they are more likely to be interconnected. Although they are intraP, OM pores are also likely to be part of an interconnected network because of the interconnectivity of OM particles. In unlithifed near-surface muds, pores consist of interP and intraP pores, and as the muds are buried, they compact and lithify. During the compaction process, a large number of interP and intraP pores are destroyed, especially in ductile grain-rich muds. Compaction can decrease the pore volume up to 88% by several kilometers of burial. At the onset of hydrocarbon thermal maturation, OM pores are created in kerogen. At depth, dissolution of chemically unstable particles can create additional moldic intraP pores.

Fractured shale-gas systems

Abstract: The first commercial United States natural gas production (1821) came from an organic-rich Devonian shale in the Appalachian basin. Understanding the geological and geochemical nature of organic shale formations and improving their gas producibility have subsequently been the challenge of millions of dollars worth of research since the 1970s. Shale-gas systems essentially are continuous-type biogenic (predominant), thermogenic, or combined biogenic-thermogenic gas accumulations characterized by widespread gas saturation, subtle trapping mechanisms, seals of variable lithology, and relatively short hydrocarbon migration distances. Shale gas may be stored as free gas in natural fractures and intergranular porosity, as gas sorbed onto kerogen and clay-particle surfaces, or as gas dissolved in kerogen and bitumen. Five United States shale formations that presently produce gas commercially exhibit an unexpectedly wide variation in the values of five key parameters: thermal maturity (expressed as vitrinite reflectance), sorbed-gas fraction, reservoir thickness, total organic carbon content, and volume of gas in place. The degree of natural fracture development in an otherwise low-matrix-permeability shale reservoir is a controlling factor in gas producibility. To date, unstimulated commercial production has been achievable in only a small proportion of shale wells, those that intercept natural fracture networks. In most other cases, a successful shale-gas well requires hydraulic stimulation. Together, the Devonian Antrim Shale of the Michigan basin and Devonian Ohio Shale of the Appalachian basin accounted for about 84% of the total 380 bcf of shale gas produced in 1999. However, annual gas production is steadily increasing from three other major organic shale formations that subsequently have been explored and developed: the Devonian New Albany Shale in the Illinois basin, the Mississippian Barnett Shale in the Fort Worth basin, and the Cretaceous Lewis Shale in the San Juan basin. In the basins for which estimates have been made, shale-gas resources are substantial, with in-place volumes of 497‐783 tcf. The estimated technically recoverable resource (exclusive of the Lewis Shale) ranges from 31 to 76 tcf. In both cases, the Ohio Shale accounts for the largest share.

Structural History and Tectonics of Iran: A Review

Abstract: The structural development of the Iranian ranges has certain peculiarities which contradict the conventional geosynclinal theory of mountain building. Early orogenic movements resulted in the consolidation of the Precambrian basement and the formation of a vast Iranian platform considered to be an extension of the Arabian shield. Only epeirogenic movements affected the region during the Paleozoic, which is represented by typical platform deposits. However, most of Iran went through all stages of a complete Alpine orogeny in spite of the prevailing platform character in preorogenic time. Important trends in the Alpine structural plan clearly were inherited from Precambrian structures. Precursory Alpine movements in Mesozoic time were strongest in Central Iran, although this region and the closely related Alborz (Elburz) Mountain area generally retained their epicontinental character, allowing for only a rudimentary geosynclinal development. More clearly geosynclinal conditions developed in peripheral fold belts: the Zagros, the Kopet Dagh, and the East Iranian ranges. Strong folding and thrusting during the Alpine orogeny proper in Late Cretaceous-Tertiary time affected most of Iran except the rigid Lut block in the eastern part of the country. The conventional tripartite division of Iran into an extensive median mass and two bordering ranges of geosynclinal origin (Zagros, Alborz) cannot be maintained. The writer replaces this oversimplified interpretation by recognizing the existence of more structural zones which differ in structural development and present tectonic style.