Abstract Sand injectites are described as an increasingly common occurrence in hydrocarbon reservoirs, in particular in deep-water clastic systems, where they are known to influence reserves distribution and recovery. Seismically detectable injected sand bodies constitute targets for exploration and development wells, and subseismic sand bodies provide excellent intrareservoir flow units that create fieldwide vertical communication through depositionally extensive, low-permeability units. Because sand injectites form permeable conduits in otherwise low-permeability units, they facilitate the expulsion of basinal fluids; hence, they act both as a seal risk as well as mitigating timing and rate of hydrocarbon migration. Injected sand bodies form intrusive traps, which are distinct from structural or stratigraphic traps. Reservoir quality is typically excellent, with a high level of connectivity between sand bodies of all sizes. In a production context, sand injections enhance sweep efficiency but may cause more rapid-than-expected water breakthrough if wells are placed too near injectite complexes. Despite experience from the North Sea, recognition of sand injectites and their significance in hydrocarbon basins globally are at an early stage.

Abstract Postdepositional remobilization and injection of sand are important processes in deep-water clastic systems. Features resulting from these processes are particularly well documented in the Paleogene of the central and northern North Sea, where large-scale sandstone intrusions significantly affect reservoir geometries and fluid-flow properties of sand and mudstone intervals throughout large areas. Large-scale sandstone intrusions seen in seismic data from the Paleogene of the North Sea can be grouped into three main categories based on their size, morphology, and relation to their parent sand body: Type 1: Winglike sandstone intrusions are seen as discordant seismic anomalies that emanate from the sides and sometimes from the crests of steep-sided concordant sand bodies, which may be of depositional or intrusive origin. The intrusions may be as much as 50 m (164 ft) thick, and crosscut some 100–250 m (330–820 ft) of compacted mudstone section at angles between 10 and 35°. Winglike intrusions may form regardless of preexisting structures, but commonly exploit polygonal fault systems in the encasing mudstones. Type 2: Conical sandstone intrusions are seen as conical amplitude anomalies that emanate some 50–300 m (164–1000 ft) upward from distinct apexes located a few meters to more than 1 km (0.6 mi) above the likely parent sand body. The intrusions may be as much as 60 m (196 ft) thick and are discordant to bedding along most of their extent, with dips ranging from 15 to 40°. The nature of the feeder system is conjectural, but may comprise subvertical zones of weakness such as blowout pipes or polygonal fault planes, whereas the intrusions themselves do not appear to be controlled by preexisting fault systems. Type 3: Crestal intrusion complexes comprise networks of intrusions above more massive parent sand bodies. These intrusions are either too thin or too geometrically complex to be well imaged by seismic data. Despite the small scale of their component intrusions, crestal intrusion complexes may be volumetrically important. Large-scale sandstone intrusions commonly terminate at unconformities such as base Balder (uppermost Paleocene), top Frigg (lower Eocene), or base Oligocene, where they may have extruded onto the paleo-sea-floor. Because sandstone intrusions are commonly highly porous and permeable, they are important as reservoirs and as efficient plumbing systems in thick mudstone sequences. Because the intrusions occur in unusual stratigraphic positions not predicted by standard sedimentary facies models, they may constitute drilling hazards by hosting shallow gas accumulations or by acting as sinks to dense and overpressured drilling fluids. Predrill prediction of the occurrence of large-scale sandstone intrusions based on seismic data and predictive models is thus vital to successful exploration of deep-water clastic plays.

Abstract An integrated three-dimensional seismic, well, and core study indicates the development of a series of slope channel and fan-depositional systems in the Upper Cretaceous interval of the Malø slope, Norwegian margin. Because of their sand content and occurrence in a mud-dominated succession, the slope-depositional systems manifest as high-amplitude reflection packages on seismic reflection data. The Upper Cretaceous depositional systems are flanked and overlain by two types of amplitude anomalies that display unusual geometries in cross section and plan view. The first type of anomaly is bedding discordant and crosscuts overlying reflections, dips 10–20°, is as much as 100 ms high, and is typically developed at the margins of the slope systems. The second type of amplitude anomaly is bedding concordant, as much as 400 m (1312 ft) long in cross section, and is developed either halfway up or at the upper tips of the bedding discordant anomalies. In three dimensions, the steeply dipping anomalies developed at the margins of the slope-depositional systems form winglike structures that are elongate along the lengths of the slope-depositional systems. Based on their close spatial relationship to the Upper Cretaceous slope-depositional systems and inferred sand content, the bedding-discordant and bedding-concordant amplitude anomalies are interpreted as clastic dikes and sills, respectively, sourced from the Upper Cretaceous slope systems. Although the mechanism that caused initial overpressuring of the sand bodies is unclear, it is speculated that a combination of the migration of basinal fluids into the sealed depositional sand bodies and rapid burial of the sand bodies in low-permeability mudstones may have contributed. The development of the largest clastic dikes at the margins of the depositional systems suggests that differential compaction and forced folding adjacent to the buried depositional systems triggered remobilization and injection and the subsequent geometry and distribution of clastic injection features. The postdepositional remobilization and injection of clastic slope systems as exemplified in this study have important implications for hydrocarbon exploration and production in slope systems because this process has caused marked changes in primary reservoir geometry and has resulted in the development of clastic intrusions that are large enough to represent stand-alone exploration targets.

Abstract Three-dimensional seismic data from the continental margin offshore Israel (eastern Mediterranean) show several large-scale mounded structures interpreted to be clastic intrusions. The structures are confined to the Zanclean (early Pliocene) and lower Gelasian (late Pliocene) intervals and restricted to an area of 40 × 20 km (24 × 12 mi) along the Afiq submarine canyon, a former depositional fairway of Oligocene age. Most of the features are circular to oval in plan view, range from 0.5 to 2 km (0.3 to 1.2 mi) in diameter at their base, and are flanked by kilometer-scale depressions interpreted as regions of sediment depletion. In cross section, the mounds are as much as 400 m (1300 ft) in height and have flank dips of as much as 20–25°. The largest structures may reach as much as approximately 0.75 km 3 (0.17 mi 3 ) in volume and represent economic hydrocarbon reservoirs. Well data and direct hydrocarbon indicators show that the mounds are predominantly composed of gas-saturated sandstones along their flanks and crests, whereas their center is heterolithic. Petrophysical interpretation indicates the presence of chaotic and remobilized sediments in the core of the structures. The relationships of the mounds to the overburden exhibit both depositional and deformational geometries (e.g., onlap, forced folding). The proposed model for their formation is hydraulic jacking up of the overburden by forceful vertical and lateral intrusion of clastic sediments during shallow burial. Several episodes of intrusion alternated with the deposition of fine-grained clastic sediment during the Zanclean and early Gelasian to create the complex structures presented in this chapter. The suggested model has implications for the understanding of the trapping mechanism and reservoir properties of the mounded structures and needs to be incorporated in exploration and production strategies.

Abstract A large-scale sand injection complex, the Hamsun prospect, was the specific target of exploration well 24/9-7, drilled in 2004 offshore Norway. The well and subsequent sidetracks proved, as predicted, the presence of high-reservoir-quality sand injection facies. An oil column in excess of 100 m (330 ft) was demonstrated with a small associated gas cap. To our knowledge, this is the first deliberate exploration well to successfully target an injection complex.

Abstract The Cecilie field is located at the mouth of the Paleocene Siri Canyon near the Danish Central Graben. The field comprises a stratified succession of lower to upper Paleocene deep-marine sandstones and hemipelagic mudstones. Part of the field is occupied by a remarkable mounded structure, circular in planform and approximately 600 m (1968 ft) in diameter. Continuous coring through the mound and in the surrounding undisturbed sections provides significant data for the interpretation of this mounded feature. The Cecilie Mound gained its present shape by differential compaction over a dome-shaped injection of sand. In cores, the domeshaped injection is seen to have eroded and removed 25–30 m (82–98 ft) of the original stratigraphy preserved only outside the mound. Excavation of this attic chamber resembles magmatic stoping and occurred primarily by sand injection, splitting the overlying, semiconsolidated mudstones, so that clasts were spalled off. This resulted in the formation of common mudstone-clast conglomerates, which, along with flow structures formed by density segregation of the glauconitic sands, are important for the differentiation of injected and in-situ depositional sandstones. The close relationship of the Cecilie Mound to deep-seated faults in the Chalk Group indicates that initial fluidization occurred in response to the reactivation of the graben faults, breaching the overburden and releasing the overpressured pore waters of the Paleocene sands. Mounded injections like the Cecilie Mound have the potential to form hydrocarbon traps, and during production, the crosscutting nature of the mounded injection has ensured good vertical and lateral hydraulic communication in the otherwise depositionally stratified reservoirs.

Abstract This chapter describes three-dimensional (3-D) stochastic modeling of the Jotun field, which was initially undertaken in 1998 and updated after the first four wells came on production. The Jotun field contains both differential compaction traps (Elli and Elli South four-way dip closures) and a stratigraphic pinch-out trap (Tau West). It produces from the distal parts of the Paleocene Heimdal Formation sand-rich submarine-fan system. A predrill (1997) deterministic oil-in-place geological model was history matched so that simulated pressure drop resulting from Heimdal field gas production matched the observed pressure drop in the Jotun appraisal wells, with aquifer size and conductivity as the main history-matching parameters. With a development plan strategy of four producers on Elli, two on Elli South, and five producers on Tau West (all highly deviated or horizontal), the predicted aquifer support was such that predrilling water injectors for pressure support was unnecessary. This saved the considerable capital expenditure of three water injectors. Predicted hydrocarbon recovery was influenced by vertical sweep efficiency, dependent on vertical permeability (kv)/horizontal permeability (kh), controlled, in turn, by the architecture of the interlayer shales. Reservoir heterogeneity was introduced in the 1998 model as architectural facies bodies in a 3-D object-based (Roxar STORM software) stochastic geological model. This captured and integrated the core-scale features in a seismic-scale stratigraphic and structural framework, using rules from outcrop analogs to fill in the missing scale. Subsurface realizations reflected different geological possibilities while preserving their influence in the upscaled dynamic simulation models. One of the major uncertainties in the geological modeling was considered to be the extent of faulting, sandstone injection, and slumping as features, which disrupt shale continuity at core scale and which might greatly increase vertical communication and, hence, recovery. If such features are not common, significant volumes of oil could be trapped beneath laterally continuous shale barriers. Different scenarios of geometry, properties, and distribution were used to investigate the significance of such features on the expected ultimate reserves of the field. Both the large aquifer support and a high level of connectivity between the separate structures were confirmed by the first four producers brought on stream.

Abstract The Balder field comprises seven structurally and stratigraphically trapped oil accumulations, in three separate stratigraphic intervals of Paleocene to early Eocene age. The reservoirs are deep-water gravity-flow-deposited sands, draped and sealed by hemipelagic mud and volcanic tuff. Strong initial reservoir compartmentalization has been significantly modified by postdepositional sand remobilization and sand injection. Sand injections were first recognized in 1969, in core from one of the early exploration wells. At the time, they were not thought to be significant. More than 150 sand injections have subsequently been identified in cores from the exploration, appraisal, and development drilling programs. This led to the realization that they were not just isolated occurrences but a common phenomenon that could impact production. In addition to the cores, sand injections are now recognized and mapped using seismic and well-log correlations, aided by principles derived from outcrop observation. Initial geologic and reservoir modeling of the Balder field consisted of separate models for each of the seven main accumulations. This was partially caused by the complexity of sand distribution and an incomplete understanding of how individual sand bodies might be interconnected. It was also caused by limitations in available software for building and simulating models of high complexity. The field went on production in September 1999. In early 2000, when the first phase of infill drilling was considered and more efficient tools for geologic and reservoir modeling were available, the decision was taken to build a full-field model. To better understand how to incorporate the sand injections, outcrop analogs were studied to develop models for injection dimensions, orientations, and distribution patterns. Following the outcrop work, a detailed reexamination of the Balder core, log, and seismic data was undertaken, cataloging all evidence for sand injections in the field. Strict criteria were developed for recognizing sand injections of all scales. Full-field geologic and reservoir models have now been built for the field, incorporating both the depositional and injected sand bodies. Because of resolution limitations, particularly with the smaller and more steeply inclined sand injections, parts of the model are nonunique. Ongoing production history matching has led to model modifications, which continue to adhere to the core, well-log, and seismic constraints, but now yield improved matches to individual well performances and gas-water breakthrough histories. This has been an iterative process, which is expected to continue throughout the life of the field. The full-field model is now being used to predict future production milestones and help identify optimum locations for potential infill drilling and well workovers.

Abstract The numerous sandstone injections found associated with the Gryphon field in the United Kingdom North Sea are mostly small-scale intrusions less than 30 cm (12 in.) thick. The largest intrusions identified in core and wire-line-log data from the Gryphon field are approximately 8 m (26 ft) thick, but these large features are uncommon. The intrusions form two main populations of interconnected steeply dipping dikes (≥60°) and sills (≤20°), with a lesser number of intrusions with moderate dips. Although small, centimeter-scale injections dominate the intrusion population, these small intrusions cluster around thicker dikes and sills (>20-30 cm [>8–11.8 in.] thick) that are localized at the margins and above the field. Sandstone injections are found as much as 170 m (557 ft) vertically above the main Gryphon reservoir sandstone and several hundred meters laterally from the parent sandstone body. Greater numbers of dikes exist in the first approximately 80 m (262 ft) above a top reservoir datum, and at higher levels, sills are more numerous. A well-by-well analysis of the intrusion distributions shows that they cluster at different heights above the top reservoir; injections are not equally spaced. Examination of the total cumulative thickness of intrusions measured in the recovered core and intrusion thickness interpreted from wire-line logs beyond the extent of the core suggests that there may be twice the volume of injected sand on the field flanks, margins, and off-field positions than over the center of the main reservoir sandstone. Integration of the observations from core and wire-line logs allows a new model for the sandstone injection complexes on Gryphon to be developed. This model suggests that a complex hierarchy of intrusion scale exists, with thin intrusions branching off the main intrusive network. The dip distribution of the injection population is influenced by the depth relative to the main reservoir sandstone, and the spatial distribution of the intrusion shows that this network is best developed around the margins of the field. Correlation of core and wire-line-log interpretations with seismic data indicates that a seismically identifiable discordant facies is most likely composed of localized interconnected networks of sandstone dikes and sills (an injection complex) in connection with the main reservoir and is not necessarily a single, simple intrusion made up of 100% intruded sand.

Abstract Evidence is presented for the widespread presence of sand injectites in mudstone- prone units in the deep-water sandstones of the Ty formation (Paleocene). Pressure communication throughout the field during production demonstrates that the laterally extensive shale layers in the reservoir are not barriers to cross-flow. Centimeter- scale sand injections are recognized in core, and sedimentary features commonly associated with meter-scale sand injectites are also identified. These remobilized sandstones are interpreted to facilitate fieldwide cross-flow, possibly augmented by subseismic- resolution faulting. Evidence for fault-induced or erosional dissection of the mudstone units is lacking. These injection features are similar in scale and appearance to sand injectites known from other reservoirs.

Abstract Alba is a heavy oil (19 –20° API) field discovered in 1984 and brought on production in 1994. The oil is reservoired within middle Eocene turbiditic sands deposited within hemipelagic background argillaceous sediments. Alba sands have been subjected to postdepositional remobilization and sand injection on a field- wide scale. Sand geometries are highly complex. Prediction of sand-shale lithology from the Alba field four-component Ocean Bottom Cable seismic data set is refined through detailed horizontal and vertical well-seismic integration. Reservoir sands are subdivided into remobilized or injected and depositional facies in all wells by recognition in cores and/or logging-while-drilling response and by elastic impedance seismic character. An abundance of multiple horizontal well sidetrack data (commonly in the same vertical plane) in the Alba field allows the construction of facies cross sections against a seismic impedance data backdrop with some confidence. A new, threedimensional (3-D) geomodeling software is used that can directly include these facies cross sections as constraints on geomodeling, in addition to conventional well and seismic data constraints. This allows a degree of geological interpretation to be imposed and supported with outcrop analogs within the uncertainties of the available data. Numerous equiprobable 3-D cellular geomodel possibilities are created that differentiate remobilized or injected reservoir facies from depositional reservoir facies. The impacts of facies variability on production profiles are tested in a streamline reservoir simulator at the geological model scale.

Abstract Large-scale injection complexes, which border many Paleogene deep-water sandstone accumulations in the North Sea, are modeled as emplaced in a single phase by sand fluidization into preexisting fractures and as extruding on the sea floor. The energy involved in the emplacement of the large-scale dikes and extrusions is at least in the order of 10 13 J and is mainly expended when lifting the large mass (3.1 × 10 11 kg) of granular material and fluid. Minor amounts of energy are dissipated as frictional effects. The flow velocity at the exit point on the sea floor is calculated to be initially turbulent, in the order of a few tenths of meters per second and to decrease with time. Evaluation of the dynamic properties of the process allows the assessment of the possible triggering mechanisms and supports the function of an initial liquefaction of the parent sand body. Earthquakes that could release the large amount of energy required for the liquefaction and injection of these complexes during burial are untypical of thermally subsiding basins like the Paleogene North Sea. Hence, the large pore-fluid overpressure, which is required for this process, is possibly supplied by fluid influx.

Abstract The Upper Jurassic Hareelv Formation in Jameson Land, East Greenland is one of the world’s finest outcrop examples of a giant sand-injection complex. The contrast between the black, organic-rich hemipelagic mudstones and the injected light yellow sandstones is striking and allows easy recognition of geometries both in close-up and from a distance. The formation is 200–400 m (660–1310 ft) thick, and in the lower part (Katedralen Member), the sandstone/mudstone ratio is roughly 1:1, increasing to about 9:1 in the upper part (Sjsllandselv Member). All sands in the upper Oxfordian–Volgian Katedralen Member have undergone postburial remobilization and injection into the surrounding mudstones, and virtually all primary sedimentary structures have been obliterated. It is thus not possible to provide detailed interpretations of the primary depositional processes. On the basis of sand-body geometry and comparison with the undisturbed underlying Olympen and overlying Raukelv formations, the depositional system is interpreted as comprising slope gullies and laterally extensive base-of-slope lobes. The sandstones occur as thick, virtually structureless bodies, which may be laterally extensive or form mounded or pod-shaped masses. Smaller dikes and sills are ubiquitous, and their geometries range from orthogonal or polygonal to extremely irregular, reflecting injection into mudstones with various degrees of consolidation. Mudstone slabs and fragments of all sizes occur in the sandstones and may easily be mistaken for clasts transported in concentrated gravity flows. They are formed, however, by excavation and rip-down of the mudstone during forceful injection of fluidized sand. Vertical or lateral organizational trends of sandstone bodies are not observed, and no clear indications exist if intrusion of dikes and sills were upward, downward, or lateral with respect to the larger sandstone bodies. The mudstones above large convex- upward sandstone bodies seem, however, to be relatively undisturbed by dikes and sills. Close inspection of some thick, laterally extensive sandstone bodies show that they contain subhorizontal mudstone leaves or layers, indicating long-distance lateral injection and splitting of the injected mudstone package. The thick convex-upward sandstone bodies were, however, clearly intruded vertically upward into the mudstones. No evidence is present for sand extrusion on the sea floor, and remobilization and injection clearly were postburial, probably under a cover of tens to perhaps hundreds of meters. Several generations of injection can be demonstrated based on crosscutting relationships of dikes and sills and the presence of both straight and strongly ptygmatically folded dikes at the same levels. Similar injections are unknown from both older and younger formations in Jameson Land. The Hareelv Formation was deposited during the climax of the most important Mesozoic rift event in East Greenland, and the pervasive remobilization of all sands in the formation is interpreted as caused mainly by cyclic loading triggered by seismic shocks. Additional factors may have included slope shear stress, buildup of pore pressure caused by sediment loading, upward movement of pore waters expelled from the compacting muds, and possibly biogenic and thermogenic gas. The well-exposed Hareelv Formation is an excellent analog for subsurface hydrocarbon reservoirs, which have been modified by remobilization and injection of sands. It provides one of the best field examples known, illustrating the degree to which a sediment can be altered and all primary features destroyed by remobilization, fluidization, and injection.

Abstract The Yellow Bank creek complex (YBCC) is a large, upper Miocene injectite complex, one of numerous injectites northwest of Santa Cruz, California. The feeder for these injectites is the Santa Margarita Sandstone, a shelfal sandstone unit that is also the reservoir rock in several exhumed oil fields. The impermeable cap rock for these oil fields, the Santa Cruz Mudstone, was breached by sand injectites, some of which reached the sea floor. Located near the edge of one of these oil fields, the YBCC is a dike-sill complex that shows evidence for multiple phases of injection by fluidized sand that was initially gas or water saturated and later possibly oil bearing. Vertical injection of a large sand dike along a fracture was followed by lateral injection of a sill from the dike along bedding planes in the Santa Cruz Mudstone. Flow differentiation during injection of fluidized sand into the sill formed centimeter-scale layering in its lower part. Subsequent emplacement of oil into this sand may have occurred by injection and by seepage that displaced pore water, producing sand masses that became preferentially cemented by dolomite. Some evidence suggests that the injection and cementation occurred at relatively shallow burial depths beneath the sea floor, with the injection resulting from a combination of possible seismic shaking and migration of overpressured fluids from more deeply buried parts of the Santa Margarita Sandstone. A pervasive lamination marked by limonite staining developed following uplift and subaerial exposure of the complex, possibly in a groundwater environment.

Abstract Shaly formations are the focus of many research programs and consortia sponsored by petroleum companies and/or waste management organizations; given that they act as seals for oil- or gas-bearing reservoirs or as host rock for underground waste disposals, their integrity (e.g., the possible presence of water-bearing fractures) is a critical factor in risk assessment. To model their rheological properties through time, the observed clastic injectites are used as markers of their mechanical evolution. Aptian–Albian marly formations of the Vocontian Basin (southeast France) are the basis of this study; massive turbidite systems associated with large-scale clastic injectite networks have been described in exceptional outcrops. Field data have permitted the identification of early fracturing in the host formation; the injection of sand is an early event, contemporaneous with the deposition of massive sand bodies. The paleocom-paction curve has been calculated, and the porosity evolution of the sediments has been restored from sea floor to about 500 m (1640 ft) burial. Then, the original configuration of dikes can be reconstituted. Boundary conditions of various numerical modeling have been derived from this extensive reliable data set. Numerical static simulations of the behavior of marly formations are presented, testing the possible function of heterogeneous lithology, bedrock geometry, or loading by sudden massive sand deposition; they indicate that early fracturing is physically possible in the presented scenarios. The next step will be to simulate in dynamic conditions the opening and filling of some of these cracks by hydrofracturing. We dedicate this chapter to the memory of our colleague and friend, Stephen T. Horseman.

Abstract Hardly detected with logs and recognized with difficulty on cores, clastic injectites (sills and dikes) can be troublemakers in oil-field development. Moreover, they provide a precious record of early fracturation. To predict their geometry, extension, and relationship to their feeders, field analysis of selected analog outcrops is conducted to propose some simple rules. In southeast France, the Aptian–Albian formation provides exceptional outcrops (Bevons, Rosans, and Nyons) where it is possible to characterize large sets of injectites: dikes and sills are associated in the same metric-to-kilometric network. The injection occurred per ascensum (more frequently) or per descensum, during or after the sand deposition. Specific geometric-based field methods have been developed to analyze the geometry based on the best conditions. A three-dimensional (3-D) model of the Rosans area injectite network has been built through gOcad ™ tool using outcrop analysis and an original, very high-resolution twodimensional seismic acquisition (0.6 km 2 ; 0.23 mi 2 ). This field analysis, the seismic survey, and the 3-D modeling provide some keys to consider possible occurrences of injectites and associated facies related to a turbiditic channel fill. We dedicate this article to the memory of our colleagues and friends G. P. Allen and D. Claude.

Abstract Apaleoseep system consisting of hundreds of sand injectites and authigenic carbonate structures crops out in the Panoche and Tumey Hills, central California. This paleoseep system developed on the western margin of the Great Valley forearc basin and is contained within the uppermost, early Paleocene part of the dominantly siliciclastic Moreno Formation. It is 20 km (12 mi) long and is distributed over more than 700 m (2296 ft) of stratigraphic section. Injectites appear in the lower 600 m (1968 ft), thinning upward from 3 m (9.8 ft) to less than 1 cm (0.4 in.), and cooccur with the paleoseep carbonate structures in the uppermost 200 m (660 ft) of section. The paleoseep slab, mound, and concretionary carbonates are 13 C depleted (to −46‰ Vienna Peedee belemnite) and commonly contain pipelike structures and the remains of chemosynthetic macroinvertebrates, including tube worms and lucinid bivalves. Their diverse morphologies likely reflect different rates and styles of fluid flow, but most show a similar paragenesis beginning with biologic colonization and pervasive micrite authigenesis and concluding with sparite precipitation in vugs and conduits. The close stratigraphic and compositional associations of paleoseep carbonate structures with injectites suggest that they were contemporaneous, and that injectites controlled the location of the seeps. Variations in abundance, morphology, and geochemistry of the authigenic carbonates, fossils, and injectites across the outcrop area indicate considerable variability in seep venting rates locally, regionally, and throughout the nearly 2-Ma duration of the seep system. Thus, the Panoche and Tumey Hills locality offers a four-dimensional view of the nature and evolution of a large, injectite- driven, cold seep in a forearc setting.