ALBERT

Description: The influence of moisture, temperature, coal rank, and differential enthalpy on the methane (CH4) and carbon dioxide (CO2) sorption capacity of coals of different rank has been investigated by using high-pressure sorption isotherms at 303, 318, and 333 K (CH4) and 318, 333, and 348 K (CO2), respectively. The variation of sorption capacity was studied as a function of burial depth of coal seams using the corresponding Langmuir parameters in combination with a geothermal gradient of 0.03 K/m and a normal hydrostatic pressure gradient. Taking the gas content corresponding to 100% gas saturation at maximum burial depth as a reference value, the theoretical CH4 saturation after the uplift of the coal seam was computed as a function of depth. According to these calculations, the change in sorption capacity caused by changing pressure, temperature conditions during uplift will lead consistently to high saturation values. Therefore, the commonly observed undersaturation of coal seams is most likely related to dismigration (losses into adjacent formations and atmosphere). Finally, we attempt to identify sweet spots for CO2-enhanced coalbed methane (CO2-ECBM) production. The CO2-ECBM is expected to become less effective with increasing depth because the CO2-to-CH4 sorption capacity ratio decreases with increasing temperature and pressure. Furthermore, CO2-ECBM efficiency will decrease with increasing maturity because of the highest sorption capacity ratio and affinity difference between CO2 and CH4 for low mature coals.

Description: The shale beds of the Khabour and Akkas Formations (Ordovician-Silurian) in Akkas field of western Iraq have been studied to determine their hydrocarbon-generation potential. The total organic carbon (TOC) values of the Khabour Formation were generally low and associated with low S2 and hydrogen index (HI) values indicating that this formation is not a hydrocarbon source, although this could reflect advanced thermal maturity. The gray-green shales of the upper part of the Akkas Formation also have low TOC and S2 values. On the other hand, the TOC, S2, and HI values of the black shales of the lower part of the Akkas Formation were high. The values indicate that the gray-green shales of the upper part of the Akkas Formation are not petroleum sources, whereas the black shales of the lower part can be regarded as potential hydrocarbon source rocks. Organic petrology studies reveal that marine amorphous organic matter is predominant, and no significant differences were observed between Khabour and Akkas samples in terms of organic-matter type. Molecular geochemical data also indicate that the kerogen of the two formations is of similar origin. The normal alkane distribution is unimodal, with a maximum at C16-C18, indicating marine algal organic matter. Rock-Eval Tmax and biomarker data indicate that the organic matter of the black shales of the lower part of the Akkas Formation is early mature, whereas the Khabour Formation is highly mature in the Akkas field.

Description: In the South Oman salt basin (SOSB), diapirs of infra-Cambrian Ara Salt enclose isolated, commonly overpressured carbonate reservoirs. Hydrocarbon-impregnated black rock salt shows that it has repeatedly lost and then regained its sealing capacity. The black staining is caused by intragranular microcracks and grain boundaries filled with solid bitumen formed by the alteration of oil. The same samples show evidence for crystal plastic deformation and dynamic recrystallization. Subgrain-size piezometry indicates a maximum differential paleostress of less than 2 MPa. Under such low shear stress, laboratory-calibrated dilatancy criteria indicate that oil can only enter the rock salt at near-zero effective stresses, where fluid pressures are very close to lithostatic. In our model, the oil pressure in the carbonate reservoirs increases until it is equal to the fluid pressure in the low but interconnected porosity of the Ara Salt plus the capillary entry pressure. When this condition is met, oil is expelled into the rock salt, which dilates and increases its permeability by many orders of magnitude. Sealing capacity is lost, and fluid flow will continue until the fluid pressure drops below the minimal principal stress, at which point rock salt will reseal to maintain the fluid pressure at lithostatic values. Johannes Schoenherr received his diploma from the Technical University of Darmstadt, Germany, with main emphasis in structural geology. Johannes is currently a Ph.D. student at Rheinisch-Westfälische Technische Hochschule (RWTH) Aachen University, Germany. His research is focused on the diagenesis and organic geochemistry of intrasalt carbonates and evaporites from the South Oman salt basin. His further interests are in microtectonics involving the geomechanics of rock salt. Janos L. Urai is currently a professor of structural geology, tectonics, and geomechanics at RWTH Aachen University and program director of the Department of Applied Geoscience, Oman-German University of Technology in Muscat, Oman. He is interested in basic and applied aspects of rock deformation in the presence of fluids at a wide range of scales in hydrocarbon reservoirs. Peter A. Kukla graduated in geology from Wuerzburg University, Germany, and Witwatersrand University, South Africa (Ph.D.). His professional career included positions at Witwatersrand University (1986–1990), Shell International E&P (1991–2000), and at RWTH Aachen University (since 2000) as full professor of geology and head of the department and director of the Geological Institute, with research focus on applied sedimentology, reservoir geology, and quantitative geodynamics. Ralf Littke is a professor of geology and geochemistry of petroleum and coal at RWTH Aachen University, Germany. Ralf's current research topics include dynamics of sedimentary basins, with special emphasis on temperature and pressure history; generation of hydrocarbon gases and nonhydrocarbon gases as well as petroleum; transport and accumulation of methane and carbon dioxide; and development of new tools in petroleum system modeling. Zsolt Schléder received his M.Sc. degree from the Eötvös University, Budapest, Hungary, in 2001 and his Ph.D. from the RWTH Aachen University, Germany, in 2006. He is currently working at Midland Valley Exploration, Ltd., as a structural geologist. His research efforts are focused on deformation and recrystallization mechanisms in rock salt. His current interest is in two- and three-dimensional structural restoration technology. Jean-Michel Larroque has a Ph.D. in structural geology from Montpellier University (France) and joined the Shell structural geology team in 1988. He had assignments in the United Kingdom, Germany, and Oman as South Oman Exploration team leader. Previously, he was Shell Exploration chief geoscientist for the Middle East and the Caspian. He is now exploration manager for Shell Syria. Mark J. Newall is a senior exploration geologist in Frontier Exploration in Shell, Egypt. He has a Ph.D. from Liverpool University (1990) and, since joining Shell, has worked as an explorationist in Holland, Malaysia, and Oman, before moving to Cairo in 2005. He is currently exploring for gas in the Nile delta. Nadia Al-Abry holds a Ph.D. (2002) from the University of Edinburgh. Nadia joined Petroleum Development Oman in October 2002 and since then has been working on the Precambrian intrasalt Ara carbonate stringers first as an exploration team geologist and seismic interpreter and then as a production geologist. Her research interests are in the tectonic evolution of basins and its influence on sedimentation and reservoir architecture. Hisham A. Al-Siyabi holds an M.S. degree (1994) and a Ph.D. (1998) from the Colorado School of Mines. Hisham joined Petroleum Development Oman in 1999 and, since 2001, has worked as a geologist and seismic interpreter exclusively on the terminal Proterozoic intrasalt Ara stringers. In 2005, Hisham joined Shell Exploration and Production Company in the United States as an exploration geologist. Zuwena Rawahi is a senior carbonate geologist in Petroleum Development Oman and has been working on the Precambrian stringer play on the South Oman exploration team for the last 3 years. Prior to that, she worked for 7 years on the Shuaiba Formation. Her main interest is related to carbonate sedimentology and diagenesis.

Description: Paleozoic and Mesozoic outcrop and core samples (Remina Dekese and Remina Samba wells) covering various stratigraphic intervals from the central Congo Basin were analyzed for total organic carbon (Corg), total inorganic carbon (Cinorg), and total sulfur content. Rock-Eval analysis and vitrinite reflectance (Ro) measurements were performed on the basis of the Corg content. Fifteen samples were chosen for molecular organic geochemistry. Nonaromatic hydrocarbons (HCs) were analyzed by gas chromatography (GC)–flame ionization detection and GC–mass spectrometry. Samples of the Alolo shales from the Aruwimi Group (Lindi Supergroup, late Neoproterozoic to early Paleozoic) are in general very poor in Corg (most samples 〈0.5%) and contain a high amount of degraded organic matter (OM). All samples of this group revealed a type III to IV kerogen and cannot be considered as a potential source rock. Permian–Carboniferous sediments from the Lukuga Group (Dekese well and outcrop samples) contain moderate contents of organic carbon (〈2%). The T max values (heating temperature at which the top peak of S2 occurs) indicate early mature OM, partly also a higher level of maturity because of Ro (0.6–0.7%) and production index values (S1/S1 + S2 〈 0.2). All samples contain hydrogen-poor type III to IV kerogen with low HC generation potential, only having a very minor gas generation potential. The kinds of OM, as well as the biological markers, indicate a terrestrial-dominated depositional environment. Organic geochemical investigations on Upper Jurassic (Stanleyville Group) to Lower Cretaceous (Loia Group) samples from the Samba well and outcrops in the northeastern part of the Congo Basin reveal moderate to high contents of organic carbon (as much as 25%). The kerogen has very high hydrogen index (HI) values reflecting type I kerogen of excellent quality in the Stanleyville Group (as much as 900 mg HC/g Corg) and type I to II kerogen in the overlying Loia Group (as much as 900 mg HC/g Corg). Outcrop samples from the Stanleyville Group have variable partly high Corg contents and are also characterized by very high HI values (as much as 900 mg HC/g Corg). The samples studied are too immature for petroleum generation. Based on biomarker analysis, an aquatic anoxic depositional environment can be assumed for the Stanleyville Group, whereas a lacustrine deposition is likely for the samples of the Loia Group. Based on the geologic knowledge of the area, deposition under lacustrine conditions is most likely also for the Stanleyville Group. Both the Stanleyville and Loia groups can be regarded as excellent petroleum source rocks and could be part of a petroleum system if sufficient burial and maturation have occurred. The presence of resedimented vitrinite particles in the Lukuga Group of the Dekese well with a slightly higher maturation rank than the autochthonous vitrinites suggests that 3000–4000 m (9840–13,120 ft) of Carboniferous to Devonian sediment has been eroded from the eastern margin of the Congo Basin. Finally, Ro data were used to create one-dimensional models for the Dekese and Samba wells, giving an overview of the burial, thermal, and maturity histories of the area.

Description: Conventional basin and petroleum systems modeling uses the vertical backstripping approach to describe the structural evolution of a basin. In structurally complex regions, this is not sufficient. If lateral rock movement and faulting are inputs, the basin and petroleum systems modeling should be performed using structurally restored models. This requires a specific methodology to simulate rock stress, pore pressure, and compaction, followed by the modeling of the thermal history and the petroleum systems. We demonstrate the strength of this approach in a case study from the Monagas fold and thrust belt (Eastern Venezuela Basin). The different petroleum systems have been evaluated through geologic time within a pressure and temperature framework. Particular emphasis has been given to investigating structural dependencies of the petroleum systems such as the relationship between thrusting and hydrocarbon generation, dynamic structure-related migration pathways, and the general impact of deformation. We also focus on seal integrity through geologic time by using two independent methods: forward rock stress simulation and fault activity analysis. We describe the uncertainty that is introduced by replacing backstripped paleogeometry with structural restoration, and discuss decompaction adequacy. We have built two end-member scenarios using structural restoration, one assuming hydrostatic decompaction, and one neglecting it. We have quantified the impact through geologic time of both scenarios by analyzing important parameters such as rock matrix mass balance, source rock burial depth, temperature, and transformation ratio.

Description: In order to investigate in more detail the relation between the size of diffusing molecules and their diffusion coefficients (and geometric factors), diffusion experiments with gases of different size and tritiated water (HTO) have been performed on different clayey samples (Boom Clay, Eigenbilzen Sands, Opalinus Clay, Callovo-Oxfordian Clay, and bentonite with different dry densities). We observed that, for unreactive gases in clayey materials, the effective diffusion coefficient varies with the size of the diffusing molecule and this variation can be described by an exponential or a power law function. The variation of the geometric factor can also be described by an exponential function. The observed experimental relations can be used to estimate diffusion coefficients; by measuring experimentally in clay the effective diffusion coefficient of two unreactive dissolved gases with a different size, the diffusion coefficients of other dissolved gases (with a size in between the two measured gases) can be estimated by using the fitted exponential relationship.