Abstract The Salina del Fraile in northwest Argentina is a Pliocene to Recent pull-apart basin developed at a releasing stepover along the NNE-SSW-trending El Fraile sinistral strike-slip fault. The basin is 35 km long and 12 km wide with a characteristic rhomboidal shape and is starved of synkinematic sediments thus providing unique 3D exposures. Prominent basin side-wall fault systems form scarps 700 m high and large tilted fault blocks form a terraced system along the southwest basin sidewall. A short-cut, basin-floor fault transects the pull-apart basin connecting the northwest strand of the El Fraile Fault to the southeast strand. An anticlinal positive flower structure in the northwest of the basin is a relict of early, segmented, fault growth typical of strike-slip fault evolution. Extension faults in the basin floor indicate a NE-SW intrabasinal extension direction during the Pliocene to Recent. The pull-apart basin accommodates an estimated 7.7 km of sinistral displacement along the El Fraile fault system. The morphology and fault architecture of the Salina del Fraile pull-apart can be directly compared to scaled sandbox models of strike-slip pull-apart basins. This first detailed analysis of the Salina del Fraile pull-apart basin provides a model for 3D architecture and evolution of similar pull-apart basins, and may serve as a template for the interpretation of other pull-apart systems.

Abstract Shallow core boring transects on West Caicos record the late Pleistocene evolution of the leeward margin of Caicos Platform. Throughout the Pleistocene and Holocene, this leeward margin progressively evolved from an open margin to one blocked by emergent topography, resulting in a dramatic shift in depositional facies. A leeward-margin barrier reef formed behind the protection of emergent oolitic grainstone ridges that persisted through the last two Pleistocene and the Holocene interglacial sea-level high stands. Soil crusts separate depositional sequences and define emergent periods. The youngest Pleistocene interglacial produced a classic shallowing upwards barrier reef that built up to a reef flat about 4 meters above present sea level. Pleistocene and Holocene reef sequences are each capped by oolitic grainstones that were spread across the reefs by longshore currents that also promoted beachspit accretion from ooid sources to the north and south. Ooid smothering of reef sequences occurred during the later part of each sea-level high stand. Older Pleistocene units are increasingly recrystallized and cemented, but the youngest retains most of the depositional mineralogy and has little marine or freshwater cement. Where not protected by preexisting emergent topography, the Pleistocene leeward margin sequence comprises repeated shallowing-upwards, burrowed to layered oolitic grainstone sequences. These grainstones retain much of their depositional mineralogy and are only weakly cemented. Well-cemented soil crusts formed during sea-level low stands, separate these oolitic sequences, and form permeability barriers that are responsible for ponding brines derived from overlying Holocene salinas. These brines promoted dolomitization of Holocene storm-derived grainstones below the salinas.

ABSTRACT The Talos Energy Zama-1SON, the first private-sector exploration well operated in Mexico in 78 years, was drilled in May–July 2017 in Block 7, 50 km (30 mi) offshore Tabasco in 166 m (545 ft) of water. The Zama structure was identified before the leasing round using two three-dimensional narrow-azimuth seismic data sets. The structure consists of an upthrown fault block with three-way closure on a salt structure’s flank in the eastern Salina del Istmo basin. A 344-m (1129-ft) gross sandstone reservoir interval was penetrated, containing 29.6° API oil. The estimated reserves make Zama one of the most significant offshore discoveries globally in several years. An array of tools and techniques was used to define, drill, and evaluate the Zama prospect. These include (1) structural and stratigraphic analysis to frame the prospect in proper context; (2) predrill amplitude versus offset analysis calibrated to seismic data using existing well control; (3) petrophysical analysis using x-ray diffraction (XRD) mineralogy and image logs; (4) forward modeling for predrill stratigraphic control and reservoir thickness; (5) a full suite of logging while drilling (LWD) and wireline logs (including elemental spectroscopy, formation pressure testing, and fluid sampling); and (6) combined biostratigraphic and petrologic (XRD and x-ray fluorescence [XRF] analyses performed on cuttings while drilling, drill stem test (DST)/pressure, volume, temperature (PVT) analysis, and whole-core analysis. The reservoir section is dominated by amalgamated, coarse-to-very fine-grained, highly feldspathic, unconsolidated, poorly sorted sandstones with low clay content. Structural mapping and biostratigraphy suggest sediment may have been fed into an evolving late Miocene offshore basin from a narrow shelf and proximal alluvial fan complex in a very active geologic setting before being deposited in a deep-water environment as a submarine channel lobe complex. The base of the reservoir section coincides with a significant middle Miocene unconformity related to salt tectonics. Pressure gradient data confirmed only one hydrostatic system in the reservoir, and a pressurized fluid sample was acquired. Subsequent appraisal drilling included whole cores in two wells covering the entire reservoir interval and DST analysis to define the reservoir qualities and extent.

ABSTRACT Area 1 is located in the Campeche Bay, offshore Gulf of Mexico at a distance from shore ranging from 2 km to 8 km and in water depths from 20 m to 40 m. Eni was awarded Area 1 in 2015, as part of the Mexico Ronda 1-Licitación 2 launched by the Comisión Nacional de Hidrocarburos (CNH). It consists of three separate blocks that include the Amoca, Miztón, and Tecoalli oil fields, previously discovered by Pemex in 2003, 2013, and 2009, respectively. Area 1 is situated in the Sureste Basin, in the southern sector of the Gulf of Mexico, one of the most prolific hydrocarbon provinces in the world. The geology of the basin is strictly linked to the sedimentary and tectonic evolution of the whole Gulf of Mexico. The tectonic deformation of the Sureste Basin is dominated by salt movements, which started in the Upper Jurassic with a major phase in the Upper Tertiary, together with the main regional uplift events related to the Laramide (Paleogene) and Chiapanecan (Middle Miocene) orogeny. The main contribution to the hydrocarbon charge comes from the organic-rich Tithonian shale-to-marly deposits, representing the main source rock of the Gulf of Mexico. In the Sureste Basin, reservoirs are present both within Upper Jurassic–Cretaceous carbonates and in Miocene-Pliocene clastic sequences. However, in Area 1 reservoirs are limited to Tertiary clastics, because the Mesozoic carbonates are quite deep and are expected to be in unfavorable, very tight lithological facies. In general, the Tertiary clastic section could be subdivided into two mega sequences separated by the Middle Miocene unconformity. In Area 1 the most important Tertiary reservoirs are associated with the prograding, and generally coarsening-upward, platform-slope-basin turbidite and deltaic systems, overlying the Middle Miocene unconformity. Top seals consist essentially of intraformational shale packages. In the past 60 years, approximately 50 onshore fields have been discovered in Salina del Istmo, the westernmost part of the Sureste Basin, within the Neogene geological plays, the same where Area 1 discoveries were made, with a cumulative production of more than 2 BBOE. Starting from 2003, the exploration activity moved also to the offshore sector, where some discoveries have been made both by Pemex and by international operators, most notably the Zama discovery in 2017. Area 1 exploration and delineation phase was characterized by several challenges, from both a geological and geophysical point of view. Three separate structures in a complex depositional and structural setting, in addition to multiple reservoirs with a wide range of oil gravity, were indeed a challenge to tackle. Legacy seismic data consisting of two different surveys, OBC and streamer, resulted in inhomogeneous seismic response with imaging issues, especially in the deeper sequences. In 2016–2017 Eni reprocessed the two surveys by merging them and producing new PSDM 3-D volumes. The in-house reprocessed volumes considerably improved the seismic imaging and allowed to build up a more reliable geological and structural model of the area. Seismic amplitudes showed up in sequences previously characterized by a poor seismic response and significantly de-risked untested plays that were the targets of the exploration campaign, opening up the prospectivity of the deeper levels of the Cinco Presidentes Formation and also of the shallower Orca 2 Formation. A rigorous use of seismic attributes and amplitude versus offset (AVO) analysis was also key in defining the exploration strategy. All the five exploration and appraisal wells were drilled in the fields’ sweet spots previously unseen on legacy seismic data and characterized by stacked amplitude anomalies mostly associated to a class III AVO response. In the Amoca Field, the exploration and appraisal wells not only confirmed previously discovered resources but also opened up new plays in deeper stratigraphic sections or in undrilled areas. The Amoca-3DEL well encountered 358 m of net oil pay of which 206 m in new reservoirs not investigated by the Amoca-1 discovery well. All the new Amoca wells indicate the presence of an extremely efficient petroleum system, because most of the encountered sandstone reservoirs were found oil bearing. In Miztón, a seismic amplitude and AVO-driven exploration approach also proved successful. The Miztón-2DEL well, drilled in the western sector of the structure, found 184 m net oil pay in four reservoirs, with an 80% increase compared to the total net oil pay encountered by the Mitzón-1 discovery well (102 m net oil pay). The same approach led to positive results also in Tecoalli, where the Tecoalli-2DEL well, besides confirming the presence of the Orca 2 oil-bearing reservoir, also encountered 27 m of net oil pay in the deeper and previously undrilled Cinco Presidentes Formation. To summarize, in 2017–2018 Eni ran a successful exploration and appraisal campaign in Area 1 drilling five exploration and appraisal wells and carrying out four production tests that resulted in a significant increase of the estimated hydrocarbon in place of the Amoca, Miztón, and Tecoalli fields. At the end of this campaign, the total hydrocarbons initially in place (HIIP) raised from the pre-bid estimate of 880 MBOE (million barrels oil equivalent) to 2.1 BBOE (billion barrels oil equivalent). Following the conclusion of the initial contractual period, Eni submitted the Area 1 Development Plan to the Comisión Nacional de Hidrocarburos that approved it on July 31, 2018. The Area 1 development drilling campaign started in the first quarter of 2019, and first oil was produced from the Miztón Field on June 30, 2019, only two-and-a-half years after the spud-in of the first exploration and appraisal well drilled by Eni.