Using calibrated shale gouge ratio to estimate hydrocarbon column heights

Bretan, P.; Yielding, Graham; Jones, Helen

doi:10.1306/08010201128

Cited by 115 publications

(127 citation statements)

References 26 publications

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“…Thereby, the SGR analysis is applied to get the percentage of shale volume information between sand-sand juxtaposition. The SGR presents the shale percentage inside sand-sand juxtaposition, which is calculated from shale volume in a reservoir layer and throw of the fault movement [18][19][20]. This means that the percentage of SGR strongly controls the character of faults in terms of sealing or leaking.…”

Section: The Application Of Fsa For Reservoir Compartment Assessmentmentioning

confidence: 99%

Reservoir Compartment Assessment: A Case Study of Bangko and Bekasap Formation, Central Sumatra Basin Indonesia

Haris¹,

Anindya

Indra³

et al. 2018

GEOMATE

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ABSTRACT:The reservoir compartment assessment for a case study of the Agur field, Central Sumatra Basin has been successfully carried out by using fault seal analysis (FSA). The objective of this paper is to asses subsurface fault properties in term of the fault sealing that was defining the hydrocarbon reservoir compartment. In this work, the FSA was performed by integrating juxtaposition, shale gouge ratio (SGR) and transmissibility analysis over fault plane that was identified within reservoir layers on the Bangko and Bekasap formation. The juxtaposition seal is intended to assess how the reservoir layer is juxtaposed across the fault plane over either reservoir or non-reservoir layer. The SGR analysis is applied to estimate the shale content in the fault plane, which is caused by the fault movement of sequence stratigraphy. The last analysis of transmissibility is carried out to calculate the capacity of a reservoir to drain the hydrocarbon through a fault plane. Faults architecture (throw, heave, and orientation) and the reservoir layer target were identified based on 3D seismic and well log data interpretation. The FSA is applied to nine faults that formed nine reservoir compartments within three reservoir layers, which are obtained from 3D seismic and well log interpretation. The fault characteristics were classified and the fault seal distribution map was produced to identify the reservoir connectivity among the faults. The FSA results show that nine identified compartments in the first reservoir layer are clustered into five compartments. In addition, the FSA clustered nine identified compartments in the second reservoir layer into four compartments. In contrast, nine compartments in the third reservoir layer were connected each other that are clustered into one compartment. These results are useful not only for evaluating future hydrocarbon traps but also for future field development.

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Section: The Application Of Fsa For Reservoir Compartment Assessmentmentioning

confidence: 99%

Reservoir Compartment Assessment: A Case Study of Bangko and Bekasap Formation, Central Sumatra Basin Indonesia

Haris¹,

Anindya

Indra³

et al. 2018

GEOMATE

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“…Faults can separate reservoirs into compartments, particularly when a fault offset juxtaposes sandstone against shale or a significant amount of fault gouge within the fault zone during faulting. The industry's knowledge of sealing potential of faults in the Niger Delta is mainly based on information about normal faults (Bretan et al 2003). In general, the maximum seal capacity of a fault is directly proportional to the shale gouge ratio (SGR) and is inversely proportional to the net-to-gross (NTG) ratio of the faulted section (Smith 1980;Yielding et al 1997;Bretan et al 2003).…”

Section: Introductionmentioning

confidence: 99%

“…The industry's knowledge of sealing potential of faults in the Niger Delta is mainly based on information about normal faults (Bretan et al 2003). In general, the maximum seal capacity of a fault is directly proportional to the shale gouge ratio (SGR) and is inversely proportional to the net-to-gross (NTG) ratio of the faulted section (Smith 1980;Yielding et al 1997;Bretan et al 2003). Stratigraphic compartmentalizations are caused by stratigraphic heterogeneities and can be classified into microscopic (pore/grain-scale), mesoscopic (well-scale), and macroscopic (interwell-scale) heterogeneities (Krause et al 1987) based on the types and scales of the heterogeneities.…”

Section: Introductionmentioning

confidence: 99%

Evaluation of reservoir compartmentalization and property trends using static modelling and sequence stratigraphy

Ejeke

Anakwuba

Preye³

et al. 2016

J Petrol Explor Prod Technol

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In the context of harder-to-find reserves and rise in development costs, it is vital that reservoir heterogeneities and compartmentalization be accurately predicted ahead of the drill bit. There are many situations where unexpected compartmentalization negatively impacts reservoir development. This paper used an integration of 3D seismic, well logs, and biostratigraphic data analysis to evaluate compartmentalization in a low well density reservoir (Z-2), onshore Niger Delta. The aim was to identify areas of bypassed hydrocarbon accumulations during production due to compartmentalization. Structural modelling of the Z-2 reservoir identified three intra-reservoir faults that could lead to possible compartmentalization of the reservoir. Z-2 reservoir was interpreted as early transgressive systems tract normal regressive sediments based on sequence stratigraphic techniques used in the modelling. Z-2 reservoir is bounded below and above by layers of shale about 180-200 ft thick, which provides a good seal for the reservoir. Sequential Gaussian simulation algorithm was used to distribute the modelled petrophysical properties in the static model. Modelled porosity, permeability, and NTG ranges are 5-30 %, 1-10,000 mD, and 0.10-0.98, respectively, through all layers. Z-2 reservoir was divided into two flow units separated by approximately 12-ft-thick shale unit, which could act as a barrier to flow between the zones. Fault analysis was done using Shell structural and fault analysis plug-in in Petrel to determine the shale gauge ratio, fault permeability, and fault zone thickness of the relevant intra-reservoir faults. Fault juxtaposition analysis shows sand-on-sand juxtaposition at the fault tips. Further analysis shows that fault thickness is within the gas crossflow range of (0-0.6 ft) and shale gouge ratio for all three faults falls within the ranges of 0-100 % with a significantly higher percentage of the areas below 35 % in fault 3. Fault 1 will not allow gas crossflow, while \20 % of the juxtaposed areas in fault 2 are within the range to permit gas crossflow. Fault 3 which has a low SGR and high permeability relative to the other faults is not interpreted to be sealing. Fault zone permeability for parts of fault 1 is \1 mD while parts of faults 2 and 3 are [1 mD. The Z-2 reservoir stands the risk of being compartmentalized into two hydrocarbon accumulations ('X' and 'Y') during production. The total GIIP for Z-2 is 1668 Bscf and with the present well positions and configurations; the production of about 20 % of the GIIP is at risk of being bypassed. Future wells should be planned to appraise 'X' and 'Y' accumulations.

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“…The second aspect is that the remaining oil at the fault edges is affected by fault sealing (Yielding 2002), apart from its relevance to the injection-recovery relationship, such as water channeling and oil leakage occurring frequently at footwall and hanging wall of faults. Thus, quantitative evaluation of fault sealing is the core of research into remaining oil at fault edges (Bretan et al 2003;Fu et al 2010;Liu et al 2014). In this paper, the Putaohua oil layer of the Xingbei Oilfield in the Daqing Placanticline was selected for the study of faults and remaining oil.…”

Section: Introductionmentioning

confidence: 99%

Characteristics of fault zones and their control on remaining oil distribution at the fault edge: a case study from the northern Xingshugang Anticline in the Daqing Oilfield, China

Xiao

Meng

et al. 2016

Pet. Sci.

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Most major oil zones in the Daqing Oilfield have reached a later, high water cut stage, but oil recovery is still only approximately 35 %, and 50 % of reserves remain to be recovered. The remaining oil is primarily distributed at the edge of faults, in poor sand bodies, and in insufficiently injected and produced areas. Therefore, the edge of faults is a major target for remaining oil enrichment and potential tapping. Based on the dynamic change of production from development wells determined by the injection-recovery relationship at the edge of faults, we analyzed the control of structural features of faults on remaining oil enrichment at the edge. Our results show that the macroscopic structural features and their geometric relationship with sand bodies controlled remaining oil enrichment zones like the edges of NNE-striking faults, the footwalls of antithetic faults, the hard linkage segments (two faults had linked together with each other to form a bigger through-going fault), the tips of faults, and the oblique anticlines of soft linkages. Fault edges formed two types of forward microamplitude structures: (1) the tilted uplift of footwalls controlled by inverse fault sections and (2) the hanging-wall horizontal anticlines controlled by synthetic fault points. The remaining oil distribution was controlled by microamplitude structures. Consequently, such zones as the tilted uplift of the footwall of the NNW-striking antithetic faults with a fault throw larger than 40 m, the hard linkage segments, the tips of faults, and the oblique anticlines of soft linkage were favorable for tapping the remaining oil potential. Multi-target directional drilling was used for remaining oil development at fault edges. Reasonable fault spacing was determined on the basis of fault combinations and width of the shattered zone. Well core and log data revealed that the width of the shattered zone on the side of the fault core was less than 15 m in general; therefore, the distance from a fault to the development target should be larger than 15 m. Vertically segmented growth faults should take the separation of the lateral overlap of faults into account. Therefore, the safe distance of remaining oil well deployment at the fault edge should be larger than the sum of the width of shattered zone in faults and the separation of growth faults by vertical segmentation.

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Using calibrated shale gouge ratio to estimate hydrocarbon column heights

Cited by 115 publications

References 26 publications

Reservoir Compartment Assessment: A Case Study of Bangko and Bekasap Formation, Central Sumatra Basin Indonesia

Reservoir Compartment Assessment: A Case Study of Bangko and Bekasap Formation, Central Sumatra Basin Indonesia

Evaluation of reservoir compartmentalization and property trends using static modelling and sequence stratigraphy

Characteristics of fault zones and their control on remaining oil distribution at the fault edge: a case study from the northern Xingshugang Anticline in the Daqing Oilfield, China

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