Seismic reservoir characterization of gas-sand deposits in the Kutei basin, Indonesia

Kutei Basin has the second largest hydrocarbon reserve in Indonesia. In addition to the Miocene inversion related structural traps, slope-fan and channel stratigraphic traps are also important traps in this basin. To guide stratigraphic traps explorations in the basin, the seismic stratigraphy, attributes, and AI inversion methods are integrated to identify and map the reservoir seismic facies, porosity, and pore-fluid. Well data indicates that the studied reservoirs are filled by gas. Seismic data shows that there are two main gas-sand reservoirs corresponding to strong amplitude anomaly. Seismic stratigraphy analysis, guided by seismic attributes, shows that these gas-sand reservoirs were deposited in the channel and local fan facies. The AI inversion is applied to identify and map the porosity and pore-fluid of these two sand reservoirs. Future well locations are identified by integrating the facies, porosity, and pore-fluid maps.

TECTONIC AND EROSION FEATURES, AND THEIR INFLUENCE ON ZONAL DISTRIBUTION OF THE UPPER TRIASSIC AND THE LOWER CRETACEOUS SEDIMENTS IN THE EUPHRATES GRABEN AREA, SYRIA

We have investigated the tectonic and erosion features of the Upper Triassic (Mulussa F Formation) and Lower Cretaceous (Rutbah Formation) sediments in the Euphrates graben area and analysed their influence on changes in the thickness and zonal distribution patterns of these sediments. In this study, the geological modeling software of Petrel Schlumberger is used to model the regional geological structure and stratigraphy from the available geological and geophysical data.The Upper Triassic and Lower Cretaceous sediments (in total, almost 800 m thick) are the major hydrocarbon reservoirs in the Euphrates graben, which contain approximately 80 to 90 % of the total hydrocarbon reserve in this area. These sedimentary zones experienced variable changes in thickness and zonal distribution due to erosion processes caused by the two major regional unconformities, the Base Upper Cretaceous (BKU) and Base Lower Cretaceous (BKL) unconformities. The maximum thickness of the Upper Triassic sediments amounts to 480 m in the central parts of the Euphrates graben and along the NW-SE trend, i.e. in the dip direction of the Upper Triassic Mulussa F Formation. Towards the NE flank of the graben near the Khleissia uplift and the SW flank near to the Rutbah uplift, the thickness of the Upper Triassic sediments is gradually decreased due to their partial or total erosion caused by the BKL unconformity, and also due to a less space for sediment accumulation near the uplifts. The thickness of the Lower Cretaceous sediments increases in the northern, NW and NE flanks of the graben. Their maximum thickness is about 320 m. The BKL unconformity is the major cause of erosion of the Lower Cretaceous sediments along the southern, SE and SW flanks of the graben. In the Jora and Palmyra areas towards the NW flank of the Euphrates graben, the Upper Triassic and Lower Cretaceous sediments show no changes in thickness. In these areas, there was more space for sediment accumulation, and the sediments were less influenced by the BKL and BKU unconformities and thus less eroded.

Reducing Uncertainties in Hydrocarbon Volumetric Estimation: A Case Study of Fuba Field, Onshore Niger Delta

Reducing uncertainties to the barest minimum before reserve estimation aids in making a better decision regarding field development. This study analyses uncertainty in hydrocarbon reserve estimation in Fuba Field using both scenario-based deterministic and stochastic methods. Two hydrocarbon reservoirs (A and I) were selected and mapped. Depth structure maps revealed fault supported collapsed crestal closures for both reservoirs. Uncertainty analysis was conducted using low case (P90), base case (P50), and the high case (P50) reservoir properties. On average, porosity, NTG and Sw are 31%, 89%, 10%, and 24%, 84%, 23% for A and I reservoirs. Hydrocarbon volumes recorded for the high case, base case, and low case using a deterministic versus stochastic approach are 30.52 MMSTB, 12.46 MMSTB, 4.57 MMSTB, and 18.52 MMSTB, 13.59 MMSTB, and 9.40 MMSTB for reservoir A, 58.87 MMSTB, 10.94 MMSTB, 1.51 MMSTB, and 25.56 MMSTB, 14.59 MMSTB and 7.63 MMSTB for reservoir I. While the base case was similar for both methods (stochastic and deterministic), there is a huge difference in the low and high-case hydrocarbon volumes recorded in both methods. This change could be attributed to the reservoir bulk volume with (>85%) with little contribution from oil saturation and porosity. Cross plot analysis confirms that bulk volume is the main control of the estimated stock tank original oil in place (STOIIP). Hence, a slight alteration in bulk volume will significantly affect the estimated STOIIP. It is recommended that bulk volume be given most attention when conducting reservoir simulation as this will increase simulation time, reduce simulation cost, and provide more accurate simulation results.

Localisation of Ancient Migration Pathways inside a Fractured Metamorphic Hydrocarbon Reservoir in South-East Hungary

Numerous fractured hydrocarbon reservoirs exist in the metamorphic basement of the Pannonian Basin in Hungary. Many decades of experience in production have proven that these reservoirs are highly compartmentalised, resulting in a complex mosaic of permeable and impermeable domains situated next to each other. Consequently, in most fields, only a small amount of the total hydrocarbon reserve can be extracted. This paper aims to locate the potential migration pathways inside the most productive basement reservoir of the Pannonian Basin, using a multiscale approach. To achieve this, evaluation well-log data, DFN modelling and a composition analysis of fluid trapped in a vein-filling zeolite phase are combined. Data on a single well are presented as an example. The results of the three approaches indicate the presence of two highly fractured intervals separated by a barely fractured amphibolite. The two zones are probably part of the communicating fracture system inside the single metamorphic mass. The gas analysis further specifies the migrated fluids and indicates hydrocarbons of a composition similar to that of the recently produced oil. Consequently, we conclude that the two zones do not only form an ancient migration pathway but are also members of a more recent hydrocarbon system.

Localisation of Ancient Migration Pathways inside a Fractured Metamorphic Hydrocarbon Reservoir in South-East Hungary

Numerous fractured hydrocarbon reservoirs exist in the metamorphic basement of the Pannonian Basin in Hungary. Many decades of experience in production have proven that these reservoirs are highly compartmentalised, resulting in a complex mosaic of permeable and impermeable domains situated next to each other. Consequently, in most fields, only a small amount of the total hydrocarbon reserve can be extracted. This paper aims to locate the potential migration pathways inside the most productive basement reservoir of the Pannonian Basin, using a multiscale approach. To achieve this, evaluation well-log data, DFN modelling and a composition analysis of fluid trapped in a vein-filling zeolite phase are combined. Data on a single well are presented as an example. The results of the three approaches indicate the presence of two highly fractured intervals separated by a barely fractured amphibolite. The two zones are probably part of the communicating fracture system inside the single metamorphic mass. The gas analysis further specifies the migrated fluids and indicates hydrocarbons of a composition similar to that of the recently produced oil. Consequently, we conclude that the two zones do not only form an ancient migration pathway but are also members of a more recent hydrocarbon system.

Paleoкarst, hydrothermal karst and karst reservoirs of the Franian reefs of the Rybkinsky group

More than 20 isolated reefs of the Rybkinsky group were discovered in 2015-2018 in the eastern part of the Rubezhinsky Trough, west of the Sol-Iletsky Arch (Orenburg region; southern part of Volga-Ural Oil and Gas Province), thanks to the use of seismic surveys 3D and exploration drilling. The interval of the stratigraphic distribution of the reefs encompasses Domanikian, Rechitskian and Voronezhian Horizons (=Regional Stages) of the Franian Stage of Upper Devonian. The reefs are cased and overlapped by carbonate-terrigene-clay deposits of the Kolganian Formation that form the seal. High-amplitude oil fields (up to 150 m high) are related to the bodies of reefs. Reefs developed under conditions of significant changes in sea level caused by both eustatic fluctuations and regional tectonics. Actual data on features of surface and deep karst in different reefs of the Rybkinsky group are given. Three karst epochs are allocated: 1) late Domanikian; 2) late Rechitskian; 3) late Voronezhian. Evidences of the post-franian hydrothermal karst in the reefs are presented. Reservoirs formed as a result of karst are characterized by high complexity of pore space. Reef reservoirs have a scale permeability effect that is necessary to consider in hydrocarbon reserve calculations.

PETROPHYSICAL EVALUATION OF RESERVOIRS FOR HYDROCARBON RESERVE ESTIMATION IN EASTERN CENTRAL SWAMP DEPOBELT, NIGER DELTA

Petrophysical properties were evaluated in five wells in eastern Central Swamp Depobelt, Niger Delta using well logs. Analyses by Kingdom Suite software reveal that reservoirs’ thicknesses ranged between 24.5ft in SNG in Afam 16 to 200.5ft in SNB in Obeakpu 005. Volume of shale varies within and across all the wells with values <30% of the total thicknesses. Relative permeability to water (Krw) ranges from 0.00 to >1.00 across the wells. Reservoirs SNE and SNF in Afam 16 have average Krw of 0.00 implying 100% water-free hydrocarbon production. SNC reservoir in Afam 15 and Afam 16 has average Krw >1 implying 100% water production. The relative permeability to oil (Kro) is very high in reservoirs with high hydrocarbon saturation. SNH in Korokoro 006 has average hydrocarbon saturation of 85.70% and Kro of 0.89. SNB in Obeakpu 005 has average absolute permeability of 62,086.9mD. Reservoirs SNB, SNC and SND contain no producible hydrocarbon in Afam 15 but contain producible hydrocarbon in Afam 16, Korokoro 003 and Obeakpu 005 wells. Reservoirs SNE, SNF, SNG and SNH in Afam 15, Afam 16, Korokoro 003 and Korokoro 006 contain producible hydrocarbon with the exception of SNF in Korokoro 003. Afam 15 and Afam 16 are mainly gas-producing with estimated gas-in-place ranging from 72,630.27cu.ft/acre in SNB in Afam 15 to 1,534,667.86cu.ft/acre in SNH in Afam 16 while Korokoro 003, Korokoro 006 and Obeakpu 005 are mainly oil-producing with estimated oil-in-place ranging from 47,590.26bbl/acre in SNB in Korokoro 003 and 387,754.83bbl/acre in SNB in Obeakpu 005.

Finding the Sweet Spot of Sustainability in the Energy Sector

Energy security and sustainability have become two of the most critical and fundamentally interdependent issues of our time. Canada is a key player in the global energy industry and home to a major oil sands hydrocarbon reserve which, after 50 years of massive investments and technological advancements, has evolved from a “fringe” oil supply to one of strategic importance in global energy security. However, the resource is in its early stages of development, and efforts to fully exploit it have been hampered by a range of factors, including strong opposition from various stakeholder groups. This Chapter provides a framework for a systems-based approach to managing the oil sands that integrates stakeholder management and domain-based collaboration theory.