Fault Closures Research Articles

The role of temperature‐enhanced fault closure in promoting postinjection pressure diffusion and seismicity in enhanced geothermal systems

AbstractPost shut‐in seismic events in enhanced geothermal systems (EGSs) occur predominantly at the outer rim of the co‐injection seismic cloud. The concept of postinjection fracture and fault closure near the injection well has been proposed and validated as a mechanism for enhancing post shut‐in pressure diffusion that promotes seismic hazard. This phenomenon is primarily attributed to the poro‐elastic closure of fractures resulting from the reduction of wellbore pressure after injection termination. However, the thermal effects in EGSs, mainly including heat transfer and thermal stress, may not be trivial and their role in postinjection fault closure and pressure evolution needs to be explored. In this study, we performed numerical simulations to analyze the relative importance of poro‐elasticity, heat transfer, and thermo‐elasticity in promoting postinjection fault closure and pressure diffusion. The numerical model was first validated against analytical solutions in terms of fluid pressure diffusion and against heated flow‐through experiments in terms of thermal processes. We then quantified and distinguished the contribution of each individual mechanism by comparing four different shut‐in scenarios simulated under different coupled conditions. Our results highlight the importance of poro‐elastic fault closure in promoting postinjection pressure buildup and seismicity, and suggest that heat transfer can further augment the fault closure‐induced pressure increase and thus potentially intensify the postinjection seismic hazard, with minimal contribution from thermo‐elasticity.

Correlation and K-means clustering based small current ground fault line selection algorithm

The existing small current grounding line selecting technique has consequences by transition resistance, fault closure angles, and the fault location, and there is a problem of low selection accuracy, which is addressed by proposing a line-choosing algorithm that employs a combination of transient zero-sequential current (TZSC) waveform correlation and K-means clustering. First, to obtain the correlation coefficient matrix, the correlation analysis is performed for each line of the zero-sequence currents transient measurement values; second, to address the issue of the difficulties in manually setting the threshold, we apply the K-mean cluster analysis algorithm to group the row vectors of the correlation coefficients matrices; and finally, we output the label of the cluster to realize the fault line selection. Simulation and real-world fault data validate the method, showing that it is independent of transition resistance, fault closure angles, and fault location. It can achieve precise and dependable line selectivity.

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.

3D structural modelling and fluid identification in parts of Niger Delta Basin, southern Nigeria

Integrated 3D seismic and well log interpretations were used to assess structures and define reservoir fluid in some parts of the Niger Delta Basin. This method of characterizing structures and delineating fluid types has been proven to generate reliable interpretations of reservoir geometry and structures which serves as inputs during flow modelling and reservoir simulations. The study is aimed at defining 3D structural architecture and differentiating reservoir fluid across reservoirs in parts of Niger Delta, due to the difficult associated in building structural grid in complex reservoir situations for reservoir modelling and simulation, in spite of the enormous growth in grid generation. The structural styles in the field show intricate network of gravity-driven growth fault systems such as synthetic and antithetic listric faults, back-to-back faults within the ridges of mobile shale beneath the depo-belt and a variety of trapping mechanisms such as fault closures and rollover structures. These fault systems influence the dynamics of reservoir fluid providing preferential pathways that mobilize hydrocarbon up-dip. Localized variability in sedimentary succession and structural styles evident in the litho-facies logs and reservoir fluid distribution across the entire field were also identified. This work provides a relatively simple and reliable workflow for 3D structural modelling and reservoir fluid identification.

Application of 3D Seismic Attribute Analyses for Hydrocarbon Prospectivity in Uzot-Field, Onshore Niger Delta Basin, Nigeria

3D seismic interpretative study was carried out across the Uzot-field in the western Coastal Swamp Depobelt of the onshore Niger Delta Basin, Nigeria, with the aim to identify possible hydrocarbon leads and prospects away from the drilled zone, utilizing seismic amplitude attributes. The method employed in this study involved systematic picking of faults and mapping of horizons/reservoir tops across seismic volume and extraction of seismic attributes. Structural analysis indicates the presence of down-to-basin footwall and hanging wall faults associated with rollover anticlines and horst-block (back-to-back fault). Generated time and depth structural maps from three reservoir intervals (D3100, D5000, and D9000) revealed the presence of fault dependent closure across the field. Analyses of relevant seismic attributes such as root-mean-square (RMS) amplitude, maximum amplitude, average energy amplitude, average magnitude amplitude, maximum magnitude attribute, and standard deviation amplitude, which were applied on reservoir tops, revealed sections with bright spot anomalies. These amplitude anomalies served as direct hydrocarbon indicators (DHIs), unravelling the presence and possible hydrocarbon prospective zones. In addition, structural top maps show that booming amplitude is seen within the vicinity of fault closures, an indication that these hydrocarbon prospects are structurally controlled. Results from this study have shown that, away from currently producing zone at the central part of the field, additional leads and prospects exist, which could be further evaluated for hydrocarbon production.

Seismic structural analysis of the miocene section in Zaafarana offshore area, North Gulf of Suez, Egypt

ABSTRACTThirty 2D seismic lines interpreted, with help of velocity well, and time-depth trace conversion, to construct the depth structural maps of Zaafarana area. This is to characterise the different stratigraphic tops of the Zaafarana area. The 2D seismic lines in Zaafarana area investigated and reviewed to select the best quality set.The depth contour maps and structure of three different reflectors Top Kareem, Top Rudeis and Top Nukhul formations in this area were constructed and detected.These depth structural maps indicate that the Miocene Formations in the Zaafarana Field affected by elongated fault block dipping 5–15°, to the cast-southeast. It lies downthrown and adjacent to a major down to basin, east-dipping and clysmic fault system. At the level of the Miocene reservoir section, the structure is more indicative of a large, northwest trending and compactional anticline. It is a four-way dip closure to the south-north and probable fault closures, to northeast, northwest, and southwest side of the structure.The central portion of the structure is relatively unfaulted based upon the current seismic interpretation, it is enhancing sweep efficiency within the reservoirs.

Impact of structural setting on hydrocarbon trapping mechanism of onshore Niger Delta basin, Nigeria, using seismic attribute analysis

The evaluation of hydrocarbon trapping system in an onshore Niger Delta basin, Nigeria was studied using well log and seismic data. This is very important in estimation of production cost and assessment of viable reservoir units in petroleum industry. It is the main aim in reservoir characterization, in order to estimate the geometry and trapping mechanism of any particular field under investigation. These were achieved through the integration of 3D seismic and well log data that was acquired from an Onshore Niger Delta basin, Nigeria. From the well logs, three reservoir units was identified namely RS1, RS2, RS3 and these were mapped based on the curve signatures of the geophysical logs. These identified hydrocarbon bearing intervals were mapped on the seismic section using checkshot dataset for time to depth conversion. Four horizons and a total of thirteen fault traces were mapped within the region, with two characterized building structural faults of F2 and F3 features. Fault F4 and F7 are antithetic fault that trends north east to south west and the trapping mechanisms for the region are both a four way closure and fault assisted closure, as the trap is an up dip fault closure against the up thrown side of fault F8. Amplitude, variance and coherence attributes shows the faulting structure of hydrocarbon migration channels and path ways, through which hydrocarbon migration and accumulation occurs within the region. A significant level of contribution was achieved with the variance attributes showing a better resolution of an instant fault detection or identification compared to other attributes studied within the field of interest. The identified hydrocarbon bearing units lies within the same depth across the entire wells. This proved that the region has exhibits little or no tectonic deformation. The presence of structural features such as antithetic and synthetic is responsible for the hydrocarbon entrapment within the region. A detailed analysis of the study location revealed highly faulted region that exhibits a typical Niger Delta tectonic settings.

Improved reservoir characterisation using fuzzy logic platform: an integrated petrophysical, seismic structural and poststack inversion study

There is a tendency for applying different integrated geophysical approaches for better hydrocarbon reservoir characterisation and interpretation. In this study, petrophysical properties, seismic structural and poststack seismic inversion results are integrated using the fuzzy logic AND operator to characterise the Tensleep Sandstone Formation (TSF) at Powder River Basin (PRB), Wyoming, USA. TSF is deposited in a coastal plain setting during the Pennsylvanian era, and contains cross-bedded sandstone of Aeolian origin as a major lithology with alternative sabkha dolomite/carbonates. Wireline logging datasets from 17 wells are used for the detailed petrophysical evaluation. Three units of the TSF (A-sandstone, B-dolomite and B-sandstone) are targeted and their major rock properties estimated (i.e. shale/clay volume, Vsh; porosity, φEff; permeability, K; fluid saturations, Sw and SH; and bulk volume water, BVW). The B-sandstone zone, with its petrophysical properties of 5–20% effective porosity, 0.10–250 mD permeability and hydrocarbon potential up to 72%, is considered the best reservoir zone among the three studied units. Distributions of the most important petrophysical parameters of the B-sandstone reservoir (Vsh, φEff, K, Sw) are generated as GIS thematic layers.The two-dimensional (2D) and three-dimensional (3D) seismic structural interpretations revealed that the hydrocarbons are entrapped in an anticlinal structure bounded with fault closures at the west of the study area. Poststack acoustic impedance (PSAI) inversion is performed on 3D seismic data to extract the inverted acoustic impedance (AI) cube. Two attribute slices (inverted AI and seismic amplitude) were extracted at the top of the B-sandstone unit as GIS thematic layers. The reservoir properties and inverted seismic attributes were then integrated using fuzzy AND operator. Finally, a fuzzy reservoir quality map was produced, and a prospective reservoir area with best reservoir characteristics is proposed for future exploration. The current study showed that integration of petrophysical, seismic structural and poststack inversion under a fuzzy logic platform can be used as an effective tool for interpreting multiple reservoir zones.

Petrophysical evaluation and volumetric estimation within Central swamp depobelt, Niger Delta, using 3-D seismic and well logs

Estimation of hydrocarbon volume is a critical issue for the economic aspect of the petroleum industry. It is very key in production to estimate reserves and after considerable production, to determine the efficiency of recovery and also as a basis for advanced studies such as reservoir simulations. The petrophysical parameters and hydrocarbon volume within the Central swamp depobelt in the Niger Delta has been evaluated from seismic and well logs data. Two reservoirs, GA and GB were delineated from the logs. The lithologies are sand and shale sequences. The trapping system were interpreted from seismic sections as anticlinal and fault closures. Two horizons and several faults were mapped from the seismic sections. The faults mapped are mainly synthetic and antithetic, characteristic of the Niger Delta. The seismic to well tie shows a fairly good match. The average porosity and permeability estimated for reservoir GA are 20% and 1338md respectively. Similarly, the estimated average porosity and permeability for reservoir GB are 21% and 1392md respectively. The results show that the oil bearing zones in the reservoirs are porous and highly permeable. There was no gas present in either of the reservoirs. The estimated initial hydrocarbon in place for reservoirs GA and GB are 57.84MMSTB and 48.43MMSTB respectively. The results of the research shows that the field has a decent hydrocarbon potential and can be economically produced from.

Impact of faults and compartmentalisation on geological carbon storage estimates in highly faulted basins

Faults have extensively been studied for hydrocarbon exploration and production; however, previous studies on fault behaviour for geological carbon storage have focused on sealing capacity or reactivation potential during injection or post-injection phases. Little is known on the impact of faults for estimating storage capacity in highly faulted basins. A geological conceptual model of a representative compartment was designed to identify the key drivers of storage capacity estimates in highly faulted basins. An uncertainty quantification framework was then designed upon this model to address the impact of geological uncertainties such as fault permeability, reservoir injectivity, compartment geometry and closure on the compartment storage capacity. Pressure-limited storage capacity was estimated from numerical simulation of CO2 injection under the constraints of maximum bottom hole pressure and fault reactivation pressure. Interpretation of the simulation results highlights that (1) two injection regimes are observed: borehole- or fault-controlled, (2) storage capacity can vary more than an order of magnitude, (3) fault and reservoir permeability can be regarded as the most influential properties with respect to storage capacity, (4) compartment geometry mainly influences the injection regime controlling the storage capacity and (5) the large sensitivity of storage capacity to the type of enclosure and fault permeability indicates that pressure build-up at the fault is often the deciding factor for CO2 storage capacity.

English

A structural evaluation of a post stack time migrated (PSTM) 3D seismic data over an X–Field in the eastern Niger Delta has been attempted. The objective of the study is to structurally evaluate the field with a view to identifying structural features such as faults, map geologic horizons and analyze reflection characteristics that might be a good lead to probable hydrocarbon accumulations. Results revealed that six growth faults (F1, F2, F3, F4, F5, and F6) and three seismic horizons (HI, H2 and H3) were delineated on the seismic section.  F1, F2, F4, F5 and F6   are synthetic, while F3 is antithetic growth faults. The synthetic faults trend northeast-southwest and dips southwestward, while the antithetic fault trend northwest-southeast and dips southeastward. The seismic horizons are fault truncated with hanging wall/footwall fault assisted closures characterized by distinctive high amplitude reflection events. The horizons have good reflection continuity, moderate to strong reflection strength and medium to high amplitudes. These suggests wide spread and uniform deposition of clastic sediments with thick sand facies and inter-bedding shales, which is the characteristic of a hydrocarbon reservoir in the Niger Delta basin. The potential for hydrocarbons is high in this prospect field based on our preliminary study, which could be explored.   Key words: Growth faults, seismic horizons, fault closures, post stack time migrated (PSTM) 3D seismic data.

Mesozoic tectonostratigraphic evolution of the North Carnarvon Basin unlocked using regional 3D seismic

Interpretation of regional scale merged 3D seismic data sets covering the North Carnarvon Basin has for the first time enabled a detailed description of Mesozoic stratigraphic and structural features on a basin scale. Isoproportional slicing of the data enables direct interpretation of Triassic depositional environments, including contrasting low-stand and high-stand fluvial channel complexes, marginal marine clastic systems and reef complexes. Channels vary dramatically between sinuous-straight single channels within low net:gross floodplain successions, to broad channel belts within relatively high net:gross fluvial successions. The latter can be traced from the inboard part of the basin to the outer areas of the Exmouth Plateau. 3D visualisation and interpretation has demonstrated the huge variety of structural styles that are present, including basement-involved extensional faults, detached listric fault complexes, polygonal faults, and regional scale vertical strike-slip faults with flower structures. Fault trends include north–south, north–northeast to south–southwest, and northeast–southwest, with deformation events occurring mainly between the Rhaetian and Valanginian. Extensional and compressional deformation has created multiple horsts, three-way fault closures, fold belts and associated four-way anticlinal traps. Wrench tectonics may also explain pock-mark trains with the interpreted transfer of over-pressure from Triassic to Early Cretaceous levels. The use of regional scale merged 3D seismic data sets is now shedding light on tectonostratigraphic features on a basin scale that were previously unrecognised or enigmatic on 2D seismic or local 3D seismic data sets.

The Waitsia Field, onshore North Perth Basin, Western Australia

The Waitsia Field represents a new commercial play for the onshore north Perth Basin with potential to deliver substantial reserves and production to the domestic gas market. The discovery was made in 2014 by deepening of the Senecio–3 appraisal well to evaluate secondary reservoir targets. The well successfully delineated the extent of the primary target in the Upper Permian Dongara and Wagina sandstones of the Senecio gas field but also encountered a combination of good-quality and tight gas pay in the underlying Lower Permian Kingia and High Cliff sandstones. The drilling of the Waitsia–1 and Waitsia–2 wells in 2015, and testing of Senecio-3 and Waitsia-1, confirmed the discovery of a large gas field with excellent flow characteristics. Wireline log and pressure data define a gross gas column in excess of 350 m trapped within a low-side fault closure that extends across 50 km2. The occurrence of good-quality reservoir in the depth interval 3,000–3,800 m is diagenetically controlled with clay rims inhibiting quartz cementation and preserving excellent primary porosity. Development planning for Waitsia has commenced with the likelihood of an early production start-up utilising existing wells and gas processing facilities before ramp-up to full-field development. The dry gas will require minimal processing, and access to market is facilitated by the Dampier–Bunbury and Parmelia gas pipelines that pass directly above the field. The Waitsia Field is believed to be the largest conventional Australian onshore discovery for more than 30 years and provides impetus and incentive for continued exploration in mature and frontier basins. The presence of good-quality reservoir and effective fault seal was unexpected and emphasise the need to consider multiple geological scenarios and to test unorthodox ideas with the drill bit.

Structural and hydrogeologic evolution of the Putumayo basin and adjacent fold-thrust belt, Colombia

This multidisciplinary study evaluates the structural and hydrogeologic evolution of Cretaceous-age reservoirs in the Putumayo basin, Colombia. We focused on the Eastern Cordillera fold-thrust belt along the southern Garzon Massif. Many important hydrocarbon accumulations occurred regionally along the proximal foreland basin and frontal fold-thrust belt defining the eastern margin of the northern Andes. To understand why recent Putumayo basin and adjacent thrust belt exploration has resulted in a wide range of oil quality and limited economic discoveries, we reconstructed the structural evolution, timing of oil migration, and timing of groundwater infiltration by (1) assessing regional trends in formation water, oil, and reservoir properties; (2) quantifying the timing of hydrocarbon generation and migration relative to trap formation using (a) two-dimensional (2-D) and three-dimensional seismic data to define and constrain a restorable balanced cross section from the Upper Magdalena Valley to the Putumayo foreland and (b) coupled one-dimensional thermal basin modeling; (3) evaluating the potential roles of Mesozoic extensional faulting and Paleogene shortening in the generation and preservation of structural traps; and (4) assessing groundwater influx from the modern foothills into the reservoir using a 2-D numerical groundwater flow model. We suggest that four-way closure is limited in the study area, where most foreland-verging structures create three-way fault closures that do not effectively trap light hydrocarbons. In addition, east-dipping structures and a relatively large reservoir outcrop area provide water infiltration pathways. Groundwater modeling suggests reservoirs were water washed by 2–200 million pore volumes since Andean uplift. Finally, average reservoir temperatures are <80°C (<176°F), which further facilitated biodegradation.

English

The structural trapping mechanism and petrophysical attributes of Afam field, offshore Niger Delta was evaluated using 3D seismic reflection data and composite well logs data. The structure maps and seismic sections show that the anticlinal structure at the centre of the field, which is tied to the crest of the rollover structure assisted by faults, is the principal structure responsible for the hydrocarbon entrapment in the field. Distinctive fault closures are the dominant structural plays in the field. Structural highs, fault assisted closures comprising two-way closure and four-way dip closed structures are evident on the depth structure maps. Petrophysical analysis of four mapped reservoir sand horizons quantitatively revealed water saturation ranging from 3.07 to 12.02% in Well1 and 7.25 to 19.32% in Well 5; hydrocarbon saturation with range 87.98 to 96.93% (well 1), 80.68 to 92.75% (well 5). The porosity and permeability values of the reservoirs within the field proved them to be quite prolific with the porosity ranging from 24.5 to 31% (well 1), 21.25 to 28.25% (well 5) and permeability range of 2606.91 to 11,777.71 mD (well 1), 1050 to 6502.20 mD (well 5). Key words: Niger Delta, trapping mechanism, petrophysical analysis, structural highs, fault assisted closures.

English

A three-dimensional seismic reflection survey carried out in Odo Field in the central swamp of the Niger Delta Basin has been interpreted with respect to exploration for hydrocarbons. The Odo Field is marked by a large southwest heading listric growth fault with numerous synthetic and antithetic faults. The two picked seismic events, horizons 1 and 2 indicate four closures each, which are hydrocarbon bearing. The faults in the field thus support hydrocarbon accumulations which are seen to be mainly fault/dip closures. The expectations calculated for the observed fault closures suggest that several in-field appraisal prospects exist. The seismic attributes (amplitude maps) furthermore suggest that horizon 1 is mainly gas bearing. Key words: Field, faults, Niger Delta, seismic, hydrocarbon

STRUCTURES AND HYDROCARBON PROSPECTS IN EMI FIELD, OFFSHORE NIGER DELTA

The Niger Delta is ranked among the world’s major hprovinces in the world. Oil and gas in t he Niger Delta are mainly trapped in sandstones and unconsolidated sands in t he Agbada formation and the structural traps are no t easy to map precisely because they are very slight, not obvious and very complicated. The main aim was to determine the stru ctures and hydrocarbon prospects in Emi-field, off shore Niger Delta using seismic data integrated with well logs. Four (4) h orizons namely L1, L2, L3 and L4 were selected and structural maps drawn for each of the horizons. Fault closures of high quality hydro carbon prospects were identified and delineated. The integration of seism ic data with well logs greatly improved the extent of accuracy and exactness of structural maps in hydrocarbon prospects and its de velopment in Emi Field. --------------------------------------------------- --------------------***---------------------------- The Niger Delta is ranked among the world’s major hydrocarbon provinces in the world. It is the most important in the West African continental margin. Oil and gas in the Niger Delta are primarily produced from sandstones and unconsolidated sands mainly in the Agbada formation. The goal of oil and gas exploration is to identify and delineate structural traps suitable for profitably exploitabl e accumulations and delineate the extent of discoveri es in field appraisals and development. These traps are very sl ight, not obvious and very complicated and are therefore not easy to map precisely. Major improvements in seismic and well logs have made it possible to map such structural arrang ements with high degree of accuracy and exactness. Seismic profiles provide almost a continuous latera l view of the subsurface by defining its geometry and providi ng an estimate of the acoustic impedance which is related to the formation densities and velocities. However, vertical details are limited due to length y duration of the individual seismic wavelets and the occurren ce of overlapping wavelets from closely spaced reflectors . Well logs are limited in their definition of lateral variatio n of subsurface parameters. Thus, the extent of accuracy in mapping complicated structural plays would be improved greatly by combining seismic data with well logs ([1]; [2]; [3 ]). In addition, the risk associated with finding oil and gas in very slight, not obvious and complicated structural plac es will be reduced tremendously since such integration will he lp to discern differences between poor and rich reservoir s and also greatly improve the extent of accuracy and exactnes s of the structural maps in hydrocarbon prospects and its de velopment. In this research, 3-D seismic reflection data were integrated with well logs so as to characterize the subsurface geometry and also determine the structures and hydrocarbon p rospects of the field. 1.1 Location and Geological Setting of the Field

The Puguang gas field: New giant discovery in the mature Sichuan Basin, southwest China

The giant Puguang gas field, with a proven original in-place gas volume of 350 109 m3 (12.36 TCFG), was discovered in 2003 in the eastern Sichuan fold-thrust belt of the mature Sichuan Basin, southwest China. The field is a combination structural-stratigraphic trap closed by lateral depositional change and fault closure. The trap evolved from a paleo-oil reservoir originating in the Triassic–Jurassic. The entrapment of thermal gas, which was derived from Lower–middle Silurian and Permian source rocks, occurred during deep burial in the Jurassic–Cretaceous. Tertiary–Quaternary compression transformed the paleotrap into the present gas reservoir. Gas is contained in the Lower Triassic Feixianguan and the Upper Permian Changxing reservoirs, which consist predominantly of dolomitized oolites deposited in shelf and platform-margin shoal and backreef environments. Reservoir quality is characterized by porosity of 1–29% and permeability of 0.01–9664 md, with buried depth greater than 5000 m (16,400 ft). The discovery of the Puguang field exemplifies the successful application of a new play concept and new technology in a mature basin. The discovery resulted from a shift in exploration strategy from structures to stratigraphic traps in reef and shoal dolomites and benefited from advanced high-resolution seismic techniques. The discovery will not only broaden the exploration scope in the Sichuan Basin, but also provide an excellent analog for exploration in other fold-thrust belts worldwide.

Fault-seal analysis South Marsh Island 36 field, Gulf of Mexico

SMI 36 is a predominantly gas field on the Gulf of Mexico shelf. The principal trap is updip fault closure in the hanging wall of a large down-to-the-north normal fault. A second normal fault, the intrareservoir fault, separates the reservoir into two compartments. Juxtaposition (Allan) diagrams of the stratigraphy projected onto this intrareservoir fault surface show several intervals of sand-on-sand juxtaposition. In the lowermost part of the section, the MA sand in the footwall is juxtaposed against the LN and LP sands in the hanging wall. Differential fluid contacts and pressures in these sands across this fault suggest that the fault is sealing. We hypothesize shale gouge as the mechanism for fault seal. Estimates of shale percent along the fault plane between the sand intervals range between 40 and 80%. Mud weights and limited reservoir pressure data show that the deep section is overpressured with a water pressure differential as much as 600 psi (4.13 106 Pa) across the fault. The cross-fault differences in the aquifer pressure partially seal the hydrocarbons in the hanging wall. The hydrocarbons in the footwall reservoir support a capillary pressure as much as 80 psi (5.51 105 Pa) for a shale gouge of 45%. Production pressure profiles record a cross-fault pressure difference of 3000 psi (2.06 107 Pa) across the fault before pressure support between the reservoirs suggesting seal “breakdown.”

MICROSTRUCTURAL AND GEOMECHANICAL CHARACTERISATION OF FAULT ROCKS FROM THE CARNARVON AND OTWAY BASINS

The results of natural and laboratory-induced fault behaviour from wells in the Otway Basin are compared with sample material from a producing Carnarvon Basin field where rocks from a fault zone have been cored. Capillary pressure, microstructural and juxtaposition data obtained from these fault rocks indicate a capability to hold back gas columns in excess of 100 m, yet many fault closures are found to contain only palaeo-columns. Trap failure is usually attributed to reactivation of trap-bounding faults, often during Miocene-Recent times in these basins. Faults susceptible to reactivation can be predicted by geomechanical methods involving the determination of the in-situ stress field and the orientation and dip of faults with respect to that stress field. Failure envelopes of fault rocks have been determined to estimate reactivation potential in the present day in-situ stress field. This approach works well where fault rocks are weaker than the host reservoir sandstone, but may not be applicable where fault rocks are stronger. In fields where the latter is the case, intact hydrocarbon columns are present, irrespective of whether faults are optimally oriented for reactivation. This indicates that the assumptions of zero cohesive strength and constant friction coefficient for predicting the reactivation potential of fault rocks may not be completely reliable.