Shale Smear Research Articles

Evaluation of fault-sealing: a case study on Xiangguosi underground gas storage, SW China

China vigorously implements the dual carbon strategy, and natural gas consumption continues to grow rapidly. It is urgent to improve the natural gas “production, supply, storage, and sales” system and accelerate the construction of underground gas storage (UGS). UGS requires “storage, injection, and extraction”. Faults are the primary factor of “storage”, the evaluation of fault-sealing is crucial for the safe construction and operation of UGS. Existing researches start from the perspective of the hydrocarbon reservoir, develop an evaluation of the basic characteristics of faults, lithological configuration of the fault’s two blocks, analysis of production performance, Shale Smear Factor (SSF), Shale Gouge Ratio (SGR), properties of fault-filling materials, 3D tectonic model, normal pressure on the fault plane, fault shear index, and fault plugging coefficient. This paper systematically analyzes the adaptability of existing methods and proposes an index to evaluate the fault-sealing capability of UGS. Taking the first UGS in SW China—Xiangguosi UGS as a case, using this workflow to evaluate the fault-sealing capability of 5 major faults. It is believed that the evaluation of fault-sealing on Xiangguosi UGS is good. This conclusion supports the design of construction key indicators and is the important basis point of the construction of the “signpost” UGS. It is of guiding significance and provides a reference for the evaluation of fault-sealing for the rebuilding of depleted gas reservoirs to UGSs.

The well log and seismic expression of faults in the Wisting field, Barents Sea

Seismic facies in large fault zones (dam to km throw) can rarely be constrained with well log data. High-resolution seismic data (ca. 3.1 × 3.1 m bins) from the highly faulted Wisting field in the Barents Sea, is compared with log data along a horizontal and a vertical well. The target of both wells is the Lower Jurassic, oil-bearing Stø Fm., which due to Cenozoic uplift and erosion is just ca. 250 m below sea floor. From SW to NE, the horizontal well crosses a horst structure before landing in the Stø Fm. The inner zones of the two normal faults bounding the horst show low acoustic impedance (Aimp) and high porosity. The horst is characterized by a chaotic seismic pattern, partly caused by several faults made visible by seismic attributes. The well logs show large variance within the horst which may be caused by small faults and fractures that were observed during drilling in addition to mud losses. Along the horizontal well path NE of the horst, the Stø Fm. is characterized by strongly varying porosity and Aimp logs, and the seismic horizons around the borehole are offset by several small faults. Farther NE from the horst in the last well interval, the Stø Fm. shows a clean sand with high porosity and a continuous seismic reflector along the well path. The vertical well is between two SW dipping normal faults, and it shows oil only. A gas cloud identified by a flat spot is observed SW of the well, on the footwall of the SW-most fault. The gas cloud has ca. 20% lower Aimp than the oil zone. The two faults exhibit inner fault zones which start at about the Stø Fm. in the hanging wall and are characterized by low Aimp values. The fault blocks do not show these low Aimp values, which means that gas rather than shale smears could be responsible for the low Aimp along the faults. The low Aimp fault zones can be followed up to the upper regional unconformity (URU). The Quaternary above the URU shows a weak fault pattern, which could explain how the gas from the reservoir is conducted through the faults up to the seabed. This emphasizes the importance of faults as fluid conduits in the area.

Impact of structural geometry of tilted fault blocks on hydrocarbon entrapment and deposition of syn-rift clastic reservoirs: Belayim Marine field (Gulf of Suez rift)

Belayim Marine oilfield is representative of the Gulf of Suez fields with hydrocarbon production from pre-rift and syn-rift reservoirs. Detailed subsurface mapping using a complete 3D seismic and borehole dataset throws light on the trapping mechanisms of tilted fault blocks in rift basins where the strike of the tilted block is parallel to the bounding fault. For such one-way tilted fault traps, linkage of rift-parallel and rift-oblique faults at the updip sides of the tilted blocks is necessary for trap integrity of laterally continuous reservoirs like the Nubia Sandstone. For laterally discontinuous reservoirs like tidal sand bars aligned normal or oblique to the block-bounding faults, a combination trap can be laterally closed by lateral change in facies of the reservoir unit along fault strike. Fault sealing of the proved hydrocarbon traps is mainly through juxtaposition. Shale smearing is valid for thick shale units with reasonable fault displacement and shale gouge is a proven sealing mechanism especially in clay-rich units. The ductile nature of syn-rift sediments leads to fault-propagation folding above the main-bounding faults of tilted fault blocks where folding is the trapping mechanism of these syn-rift reservoirs.The structural geometry of tilted fault blocks also controls the distribution of syn-rift reservoirs as the linkage of rift-parallel and rift-oblique faults controls the entry of main valleys transporting syn-rift clastics into the basin. Longitudinal depressions sculptured at the crests of tilted fault blocks represent another location for deposition of syn-rift reservoirs.

3D dynamic fault sealing capacity modelling to improve history matching: a case study in Oligocene reservoir, Tay Ho Field, Blocks A, Cuu Long basin, Offshore

Fault transmissibility multipliers are a simple way of accounting for the effects of faults on fluid flow across fault plans in history matching of production simulation models. Fault transmissibility multipliers can be calculated using parameters such as fault clay, fault smear, thickness, and permeability. In this study, three emperical methods given by Manzocchi et al. (1999), Jolley et al. (2007), and Sperrevik et al. (2002) have been applied to the Oligocene sandstone reservoir, Tay Ho Field. The Oligocene reservoir is a complicated sandstone that was deposited in alluvial-fluvial and lacustrine environments, trapped by both stratigraphic and structural types, sandbody isolated by multi-activated faults. Fault sealing is one of the key factors controlling hydrocarbon accumulations and trap volume and can have a significant influence on reservoir performance during production. Furthermore, the prospective of structural or combination traps in stacked clastic reservoir settings that are typically found in many of the known hydrocarbon provinces in the Cuu Long basin, often critically hinges on the presence of a working fault side seal. Based on a thorough understanding of the key controls on fault seal risk and retention capacity, a consistent methodology to access these factors across a prospect portfolio is essential to achieve a balanced prospect ranking and an accurate assessment of prospect success volumes. In the process workflow built by PVEP Blocks 01/97 & 02/97, the assessment of fault seal capacity and compartmentalization in the Oligocene reservoir have been incorperated by using fault deformation, displacement, juxtaposition, fault zone thickness, shale gouge ratio (SGR), shale smear factor (SSF), clay smear potential (CSP), fault thickness and permeability. In our research, the Sperrevik et al. (2002) method provides the best historical match and most logical geological evidence; thus, it shall be used for dynamic models and further studies.

Study on fault sealing of the Lishui West Sag in the East China Sea Basin

The property of fault sealing is a critical controlling factor for hydrocarbon transportation. To date, the sealing property of the complex fault system in the Lishui West Sag is still not clear, meaning it is essential to study regional hydrocarbon transportation and reservoir formation. In this study, we use an integrated method to quantitatively analyze and characterize several important index parameters that affect the sealing property of the faults in the Lishui West Sag based on regional logs and seismic data. We calculated the shale smear factor (SSF), shale gouge ratio (SGR), and clay smear potential (CSP) to characterize the lateral sealing property of the main faults covered with the giant thick shale cap in the Lishui West Sag. We used the vertical shale smear factor Q to clarify the vertical sealing property of these faults quantitatively as a comparison. The results show that the shale cap has a strong smear ability in the Lishui West Sag, while the active fault could moderate the smear. A high fault activity in this area benefits hydrocarbon transportation at the same time. The lateral sealing property and the vertical sealing property of the main faults in the Lishui West Sag have negative correlations.

Integrated structural, geophysical and remote sensing data for characterizing extensional linked fault systems and related land deformation hazards at Cairo-Suez District, Egypt

A tiered framework has been developed to map and characterize extensional linked fault systems at Cairo-Suez District, Egypt to better understand seismic and land deformation hazards. As a test site, the present tiered approach is applied on the Cairo-Suez District (CSD), Egypt, which is considered as an active seismogenic zone that encompasses complex deformation settings. Tier 1, which involves outcrop observations and structural mapping, reveals four geometries belonging to soft- and hard-linkage transfer zones (TZs). Considering the mapped TZs, the near-surface heterogeneity is characterized using a 2D-electrical resistivity tomography (2D-ERT) technique at “tier 2” applying an advanced inversion scheme (AIS). Inversion results of the 2D-ERT profiles indicate a subsurface continuity of the mapped surface geological and structural features including shale smears of fault zones and shale layer distributions. At “tier 2”, we particularly identify a highly deformed shale bed of 15-m thick, that accommodate fault slips as indicated by internal gouge zones. We further represent all local hazard factors including slope, drainage density, land use/land cover and displacement maps using the “Fuzzy-Shannon Entropy Model”. Overall, our findings show that most of the delineated deformation hazards in the test site are related to hard-linked TZs. At “tier 3”, we ultimately provide our recommendation for regional and site-specific engineering mitigation and to avoid active faults by defining setback-zone buffer (i.e., no build zone) correlated with the local fault activity and near-surface geometry. For Egypt, an economically developing country, this approach represents a major advancement from conventional geologic and geotechnical investigations through introducing a tiered framework for risk-relevant characterization of the extensional linked fault systems to apply adequate procedures/precautions by engineers for urban planning.

Assessment of Fault Sealing in the Gabo Field, Niger Delta, Nigeria

This research assesses the sealing of the fault bounded stratigraphy of the Gabo Field, Niger Delta, Nigeria. Materials used comprises of 3D seismic volume in seg-y, ditch cuttings and well logs. The methods applied are standard fault plane evaluation techniques and they include seismic interpretation, well correlation, XRD analysis, and application of the Yielding et al., (1997) shale gouge ratio (SGR) algorithm for fault seal analysis. The tectonic framework was interpreted in terms of deformational, depositional and post-depositional structures. The order of magnitude of stress is SHmax > σv > Shmin. The juxtaposed strata relationships were analyzed by taking cross sections A-A1 and B-B1 and this showed the structural framework across the field. Cross section A-A1 showed that the depositional and post depositional structures are pinchouts (channel abandonment or switching) and shale smears respectively. The cross section B-B1, showed that the deformational structures are faults F1 and F2 – recognized as closely spaced normal faults and F3 is a syn-depoitional growth fault. The well correlation showed the vertical stratigraphy of the wells are comprised of cyclic succession of sands and shales and the shale thickness increased in intermediate sections. The X-ray diffraction (XRD) analysis of the shales showed that the predominant minerals are kaolinite, rutile, gypsum, albite, microcline and quartz. The rock property analysis showed that the net to gross ranges from 26.28 – 82.0% with an average of 73.7%. The volume of shale ranges from 18 – 73.72% with an average of 63.59%. The bulk density of the shales ranges from 2.379 – 2.692g/cc with an average of 2.46g/cc. The total porosity ranges from 0.159 – 0.317 with an average of 0.167 in the shales and 0.272 in the sand. The effective porosity range from 3.58 – 22.71 with an average of 6.028 in the shale and 20.13 in the reservoir. The drawdown mobility and temperature range is 2.2 – 4124.4mD/cP and 63.3 – 80.1oF respectively, while the average is 569mD/cP and 70.63oF respectively. The estimated pore pressure ranges from 0.4213 – 0.4762psi/ft with an average of 0.47psi/ft in the shales and 0.428 psi/ft in the sand. The fault seal analysis showed that the shale gouge ratio range from 0.2 – 0.7 and the stratigraphic juxtapositions are predominantly sand to sand, sand to shale and shale to shale. The results of this research reduces the fault seal uncertainty in the planning of oilfield development projects and enhanced pressure support for the recovery of bypassed hydrocarbons, most especially in compartmentalized reservoirs. In addition, the results of this research can be applied to similar deltaic successions around the world.

Normal fault transmissibility characteristics under the transition condition of fault conduction and sealing observed in simulation experiments

In rift basins, normal faults conducting and sealing fluids are the main mechanisms for evaluating fault-related reservoirs, and the defined threshold value of fault conduction or sealing is based on statistics. However, fault transmissibility characteristics under a transition condition of fault conduction and sealing have not been clarified. This study used structural deformation and hydrocarbon charging as a foundation to quantitatively characterize fault transmissibility under the transition condition of fault conduction and sealing. This study examined faults occurring in sandstone–mudstone interbeds and used the fault throw and mudstone content as the main variables. The physical simulation results revealed that despite all models exhibiting simple “one-layer” fault architecture with only a fault core, their internal composition undergoes a sequential change from the mudstone drag, mudstone drag and sliding surface to the mudstone breccia and sliding surface. Similarly, when the fault is in the transition condition of fault conduction and sealing under the constraints of mudstone, a normal distribution is observed in terms of the number of oil-bearing layers, oil-bearing length, and oil-bearing area of the lateral fault conduction. However, when the shale smear factor (SSF) is too high, the “one-layer” fault architecture mainly comprises the mudstone breccia and sliding surface, which increases the vertical fault transmission and reduces the lateral fault conduction. Conversely, an excessively small SSF, where the fault zone is a “one-layer” fault architecture comprising mainly the mudstone drag or mudstone drag and sliding surface, will restrict the vertical fault transmission and reduce the lateral fault conduction. When the lateral fault conduction near the inflection point of the normal distribution reaches its threshold, the superposition of mudstone along the fault and the presence of mudstone breccia in the fault zone become critical for decelerating the vertical fault transmission and accelerating the lateral fault conduction. The study of normal fault transmissibility characteristics under the transition condition of fault conduction and sealing provides a solid theoretical foundation for the risk assessment of fault-related hydrocarbon accumulation.

Method for Evaluating Fault Hydraulic Conductive Property and Its Application in Shandong, China.

Coal remains the largest contributor to the energy structure of China. However, coal production is frequently threatened by groundwater inrush accidents caused by hydraulically conductive faults. Despite the threat of such accidents, research on methods for evaluating fault hydraulic conductive property without hydraulic tests has seldom been conducted. Many faults exist in coal mines in Shandong, China. However, due to economic and technical limitations, hydrological tests are rarely performed and can be performed on only a few faults. The hydraulic conductive property of many faults is unknown, which has prevented serious groundwater inrush accidents and casualties from being avoided. Using accessible geological exploration data, we propose a method for evaluating fault hydraulic conductive property in the Jining coalfield, Shandong, China. Mudstone smearing, lithologic contact relations on the fault plane, geostress, water pressure, plastic deformation of mudstone, and the argillaceous content of the fault zone were selected as factors, and six quantitative indicators were proposed: the shale gouge ratio (SGR), lithologic juxtaposition diagram (LJD), fault closure coefficient (FCC), water pressure coefficient (WPC), mudstone deformation coefficient (MDC), and shale smear factor (SSF). The fuzzy analytic hierarchy process (FAHP) was applied to calculate the weights and establish lateral and vertical hydraulic conductive property (L and V) evaluation models for faults. The fault hydraulic conductivities were then classified as weak, medium, or strong. The hydrochemical experiments and the limited number of exposed faults were used for validation. Hence, the evaluation models were considered effective at determining the hydraulic conductive property of faults in the Jining coalfield, China.

Quantitative evaluation of caprock sealing controlled by fault activity and hydrocarbon accumulation response: K gasfield in the Xihu Depression, East China Sea Basin

Caprock-sealing capability affected by fault activity is an important problem that needs to be resolved in hydrocarbon accumulation analysis, especially for rifted basins. In this article, a quantitative model based on the mechanical properties estimated by geophysical logging was first established to characterize the brittle-ductile transition of mudstone caprocks. By establishing a burial depth reconstruction model, the brittle-ductile stage of the mudstone caprock at the termination time of fault activity (TTFA) was restored. Moreover, the caprock juxtaposition thickness (CJT) for brittle rock and the shale smear factor (SSF) for brittle-ductile rock were selected to quantitatively describe the sealing capacity of caprock controlled by faults. These mathematical methods were finally applied to a case study of the K gasfield in the Xihu Depression, East China Sea Basin. Compared with the sealing characterization based on the current mechanical properties, the brittle-ductile reconstruction at the TTFA and matching sealing evaluation better describe the effectiveness of the mudstone caprock. Additionally, the quantified sealing capacity and corresponding hydrocarbon response indicate that a CJT value of 56.1 m and an SSF value of 3.0 can be the threshold for caprock sealing and nonsealing in the study area. As a result, caprock with poor sealing led to vertical hydrocarbon leakage in the structural low zone and structural high zone, while strong sealing caprock located in the structural center zone effectively prevented the upward migration of hydrocarbons, thereby controlling the vertical hydrocarbon distribution in the K gasfield. In general, the evaluation accuracy of caprock sealing predominantly relies on the geological input to the model, especially the fluid pressure, rock mechanical parameters, and caprock and fault interpretation results, and it is also affected by further uncertainties arising from the sealing threshold definition and structural uplift.

Comprehensive evaluation on hydrocarbon-bearing availability of fault traps in a rift basin: A case study of the Qikou sag in the Bohai Bay Basin, China

An evaluation system of hydrocarbon-bearing availability of fault traps was established based on the comprehensive analysis of fault segment growth history, fine reservoir anatomy and geochemistry tracing, with the Qikou sag in the Bohai Bay Basin as target area. The displacement/separation transform and displacement gradient method were used to prove the interpretation reliability of fault traps. The method of maximum throw subtraction was used to recover the history of fault growth and determine the availability of the forming period of fault traps. Based on the quantitative relationship between shale gouge ratio and cross-fault pressure difference of known reservoirs in southern Qikou sag, the critical shale gouge ratio of fault lateral sealing was calculated at 20%, and the quantitative evaluation chart based on the relationship of “fault throw–sand-formation ratio and hydrocarbon column height” was constructed. Based on the results of reservoir fine anatomy and quantitative fluorescence tracing test shale smear factor method is suitable for evaluating the vertical sealing of faults in the caprock of the middle submember of first member of Paleogene Shahejie Formation, and the shale smear factor critical value is 3.5. The juxtaposition thickness method is suitable for evaluating vertical sealing of faults in the caprock of the second member of Paleogene Dongying Formation, and the critical juxtaposition thickness of fault is 70–80 m. By combining four factors, the availability of fault trap interpretation, the availability of the forming period of fault trap, the availability of fault lateral sealing and the availability of fault vertical sealing, the comprehensive evaluation chart on hydrocarbon-bearing availability of fault traps in Qikou sag has been established, which provides a reasonable basis for risk assessment of fault traps.

Stochastic modelling of fault gouge zones: implications for fault seal analysis

Abstract Fault zones are complex, and show considerable variability in both structure and the distribution of associated fault rocks within the fault core: the zone that localizes most strain and displacement. It is the fault-core gouge zone and associated slip surfaces which provide the cross-fault seal when permeable layers are juxtaposed. Predicting the sealing properties of fault gouge zones is difficult but often required when evaluating faults in exploration prospects. A stochastic modelling approach is described to help better understand the compositional controls on fault gouge seal potential. The model is populated with a random assemblage of four fault rock components: shale smears, shaly gouge, cataclastic gouge and low-strain host-rock lenses. Harmonic averaging of permeability and arithmetic averaging of V shale are then used to upscale the properties, and to propose a simple permeability– V shale model for fault rocks. Practical application of the model is discussed by developing an empirical link between standard well-log data and associated fault rock effective permeability. This new approach has the potential to offer a simple well-log-based fault seal model. The utility of the model is demonstrated with a case study, comparing the results to those generated using other published techniques.

Preliminary structural and stratigraphic assessment of an onshore field for CO2 re-injection in the Niger Delta Basin, Nigeria

Detailed preliminary assessment of subsurface is required in potential site for CO2 re-injection in order to ensure safe and viability of the project. Using 3D seismic data analysis and well correlation, a potential site located onshore Niger Delta Basin was assessed for CO2 re-injection. The result indicates multiple reservoir units across the stacked stratigraphy, indicating potential multiple CO2 storage intervals. Well correlation using four wells has further revealed a laterally extensive, thick and sealed potential reservoir located at supercritical depth favorable for geosequestration. Traps are found to be mainly structural consisting of collapsed crest and rollover anticlines. Growth faults are the dominant structural type and the overall structural style within the field is simple with minimal complexity. In the triangle analysis, a potential leak point characterized by thick sand blocks and low potential for shale smearing shows high tendency for CO2 leakage. However, this would only be the case if injected CO2 exceeded the maximum supportable column heights which can be obtained using 3D fault seal modeling to further characterized the basin.

Fault Core Thickness: Insights from Siliciclastic and Carbonate Rocks

Fault core accommodates intense deformation in the form of slip surfaces and fault rocks such as fault gouge, cataclasite, breccia, lenses, shale smear, and diagenetic features. The complexity and variation in fault core geometry and thickness affect fluid flow both along and across the fault. In this study, we have investigated a total of 99 faults in siliciclastic and carbonate rocks. This has resulted in two large datasets that include 871 fault core thickness measurements T in siliciclastic rocks and 693 measurements in carbonates, conducted at regular intervals along fault elevations (fault height) on the outcrop or photos of the outcrop. Many of these measurements have been analyzed with respect to fault displacement measurements D in order to study the relationship between displacement and fault core thickness and to further uncover the fault growth process. We found that the fault type and geometry, displacement, type of fault rocks, lithology, and competency contrasts between faulted layers lead to significant variations in the fault core internal structure and thickness. Analysis of average values of fault core thickness-displacement data of this study and of previously published studies shows that the core thickness-displacement relationship follows an overall power law, in which its exponent and intercept change depending on the lithology of the faulted rocks. In general, small faults in carbonate and siliciclastic rocks (D≤5 m) show comparable T/D ratios, with a slightly higher ratio in carbonate rocks. The outcomes of this study contribute to the understanding of the fault core internal structure and variation in fault core thickness as a result of the interplay between fault displacement and host rock in different lithologies. These outcomes have significant implication for characterizing the sealing and conductivity potential of faulted rocks, which is relevant to different applications such as petroleum exploration and development of existing fields, hydrogeology, geothermal energy storage and extraction, and CO2 sequestration.

Identification of sealing potential through fault seal analysis: a case study of Badin area, Lower Indus Basin, Pakistan

The sealing potential of a fault can be originated from reservoir/nonreservoir rock juxtaposition. The present study focuses on the assessment of the sealing potential of the Lower Goru Formation of Badin area, Lower Indus Basin, Pakistan. The uni-directional force is one of the causes of leakage through the upper reservoirs of Lower Goru Formation, i.e. sand A, B and C and thus made a good seal as sand D. The fault properties associated with sealing capacity and leakage are estimated using algorithms. These algorithms are based on the juxtaposition of the reservoir rock against sealing lithology, deformation and present stage of stress regime within the fault plane relative to leakage. Time and depth contour maps of top of the Lower Goru Formation represent a half-graben structure showing uni-directional force in the area. An Allan-type diagram depicted a sand-sand juxtaposition for sand A and juxtaposition of sand A with sand B, thus eliminating any chances of sealing conditions. A similar diagram confirmed shale-sand juxtaposition for sands C and D. The juxtaposition diagram referred to an increase in shale gouge ratio (SGR) values from sand A to sand D with maximum values at sand D, thus classifying good fault sealing potential at sand D. Therefore, it is confirmed that sealing capacity of the fault (F2) increases from sand A (poor seal) where SGR = 0.44% – 0.9% and shale smear factor (SSF) = 0.23 – 1 to sand D (moderate seal) where SGR = 10% – 44% and SSF = 0.05 – 0.22 which means that sand D is more sealed than any other sand in the study area.

Quantitative determination of the brittle–ductile transition characteristics of caprocks and its geological significance in the Kuqa depression, Tarim Basin, western China

The Tarim Basin is one of the most hydrocarbon-bearing basins in China. It has two sets of gypsum and salt regional caprocks, which have various thicknesses and areal distributions. Such caprocks control large-scale hydrocarbon accumulation and the reservoirs formation in the basin. The estimation of the brittle–ductile transition characteristics of caprocks is one of the fundamental geological problems in petroleum exploration. To tackle this problem, a preliminary experimental method based on the mechanical characteristics of rocks is presented in this paper, which quantitatively forecasts the brittle–ductile transition characteristics of caprocks. The experimental study is based on triaxial tests on different gypsum and mudstones from caprocks of Jidike and Kumugeliemu Formations sheared at different confining stresses. It is shown that during burial, gypsums behave as normally consolidated materials and exhibit ductile responses to load increase. With the increase of depth, gypsum transforms from brittle stage to brittle–ductile or ductile stage. The confining pressure for brittle to brittle–ductile (semibrittle) transition of gypsum is about 18 MPa, and that of brittle–ductile to ductile transition is about 62 MPa. By analyzing the internal structure of fault zones from the caprocks in different brittle–ductile stages, it was observed that faults in brittle gypsum rock deform and form through-going faults, which are filled with soft fault gouge and often act as vertical migration pathways for hydrocarbon. Faults deformed in brittle–ductile caprocks form smears. A shale smear factor (SSF) of 3.5 is the critical value to discriminate between continuous and discontinuous gypsum smears, which can serve as a standard for determining the vertical sealing of the faults in brittle–ductile caprocks. It is generally difficult to cut through faults in ductile gypsum caprocks; this is significant to the sealing of the hydrocarbon vertical migration pathways.

Cataclasis and silt smear on normal faults in weakly lithified turbidites

Fault-seal analysis in sand-shale multilayers emphasises the role of shale smear without explicitly accounting for cataclasis. These processes produce low-permeability fault rock and are examined here for small displacement (0.001–70 m) normal faults displacing weakly lithified turbidites comprising ∼55–80% lithic grains. Late Miocene Mount Messenger Formation (MMF) turbidites from the North Island of New Zealand provide fault rock data over a range of scales from individual grains (∼0.1–350 μm) to the height of coastal cliffs (∼10–20 m). Fault rock and unfaulted source beds has been analysed using thin sections, SEM images, particle-size distribution (PSD) measurements and outcrops of faults mainly in cross section. Cataclasis associated with particle size and macroscopic porosity reduction of protolith sandstones commences at low fault shear strains (<1) and continues as fault displacement accrues. The relationship between particle-size reduction and displacement is non-linear with initial rapid cataclasis facilitated by disaggregation of weak lithic and altered feldspar grains along pre-existing grain defects (e.g., grain boundaries, fractures and altered cleavage planes). Silt smear, by contrast, is not accompanied by significant particle-size reduction and appears to have been achieved by intergrain slip and micro-faulting. Despite the occurrence of silt smear, cataclasis can produce a significant proportion (>50%) of the total fault-rock in sand-silt multilayers. The resulting fault-rock thickness varies by up to three orders of magnitude for a given fault displacement and at short distances (2–10 m) along individual faults. Variations in fault-rock thickness and associated cataclasis have the potential to modify the hydraulic properties of faults and may need to be accounted for in fault-seal analysis.

Insights in Fault Flow Behaviour from Onshore Nigeria Petroleum System Modelling

Faults are complex geological features acting either as permeability barrier, baffle or drain to fluid flow in sedimentary basins. Their role can be crucial for over-pressure building and hydrocarbon migration, therefore they have to be properly integrated in basin modelling. The ArcTem basin simulator included in the TemisFlow software has been specifically designed to improve the modelling of faulted geological settings and to get a numerical representation of fault zones closer to the geological description. Here we present new developments in the simulator to compute fault properties through time as a function of available geological parameters, for single-phase 2D simulations. We have used this new prototype to model pressure evolution on a siliciclastic 2D section located onshore in the Niger Delta. The section is crossed by several normal growth faults which subdivide the basin into several sedimentary units and appear to be lateral limits of strong over-pressured zones. Faults are also thought to play a crucial role in hydrocarbons migration from the deep source rocks to shallow reservoirs. We automatically compute the Shale Gouge Ratio (SGR) along the fault planes through time, as well as the fault displacement velocity. The fault core permeability is then computed as a function of the SGR, including threshold values to account for shale smear formation. Longitudinal fault fluid flow is enhanced during periods of high fault slip velocity. The method allows us to simulate both along-fault drainages during the basin history as well as overpressure building at present-day. The simulated pressures are at first order within the range of observed pressures we had at our disposal.

A geometrical model for shale smear: implications for upscaling in faulted geomodels

A new 1D bed-scale model has been built to help model shale smear in interbedded sand–shale sequences using the shale smear factor (SSF). A smear envelope is generated by mapping each potential shale smear onto the fault plane employing five different shale smear geometries. Graphical outputs then focus on the cumulative length of the resultant smears and the remaining sand–sand juxtaposition windows in the predicted shale smear envelope. The smears are evaluated stochastically with lengths that are a randomized function of the estimated Vclay content of the source shale layers, allowing the smear pattern to change with each realization. A new fragmented smear mode is developed that allows discontinuous smears to be distributed randomly on the fault plane and can be used to modify the smear pattern as fault displacement increases. The model has been tested using well data. Results show that windows in the smear envelope are commonly present, and that their frequency and location are dependent on the smear placement model and sand–shale stacking pattern. Smear fragmentation leads to more windows being preserved. The 1D model can also assess the impact of geocellular upscaling on fault seal analysis. Upscaling reduces cross-fault sand connectivity due to the elimination of thin beds. Shale smear envelopes are also reduced in length as fewer shale beds are involved, even though layers are thicker. A fault may or may not appear more sealing dependent on the layer configuration and net-to-gross ratio (NTG). The model offers results that can inform input to fault seal evaluations and allows the effect of geomodel upscaling to be more closely interrogated.

Effects of fault activities on hydrocarbon migration and accumulation in the Zhu I Depression, Pearl River Mouth Basin, South China Sea

Faults can act as either conduits or barriers for hydrocarbon migration, because they have complicated anisotropic flow properties owing to their complicated three-dimensional structures. This study focuses on the Zhu I Depression, Pearl River Mouth Basin (PRMB), China. In this area, hydrocarbon migration and accumulation occurred over a relatively short period of time and were contemporaneous with fault activation, so the characteristics of hydrocarbon accumulations can be used to deduce the effect of active faults on hydrocarbon migration and accumulation. This study addresses the effect of fault activity on flow properties during hydrocarbon migration through a quantitative and comparative analysis of fault activity vs hydrocarbon accumulation. The fault slip rate and shale smear factor parameters were used to characterise faulting and elucidate its effect on hydrocarbon migration and accumulation. Active faults are generally excellent vertical conduits with strong fault activation resulting in vertical migration of most hydrocarbons and little preservation; traps near faults with fault slip rates greater than 20 m/Ma rarely contain commercial oil and gas accumulations. Faulting can form shale smear, which, if continuous, can act as a barrier to hydrocarbon migration. An active fault can allow hydrocarbon transport from deeper formations and to be trapped by continuous shale smear in shallower strata. Most of the oil and gas in the Zhu I Depression have accumulated near faults with a moderate fault slip rate (<20 m/Ma) and development of continuous shale smear (SSF<4–6).