The aim of this investigation is to develop a comprehensive understanding of an enhanced oil recovery (EOR) candidate reservoir based in an unconventional sandstone dominated environment. The unique geology, owing to its proximity to an inland, endorheic basin, alongside its complex stratigraphic geometry incorporating extensive folding and faulting as well as a laterally extensive unconformity. The study leans heavily on the forefront of reservoir characterizations. Reservoir characterization is crucial in providing an outline of the sub-surface and helps visualize the hydrocarbon system in-place. Our study area is the deeper consolidated units. This section was analyzed in detail to understand the petrophysical and fluid properties. The properties of the rock formation(s) of interest were identified from mineralogical content based on XRD analysis and SEM analysis to develop an interlink between the results. A compilation of the results plays a key role in determining reservoir quality and fluid properties which heavily influences important variables such as porosity, permeability, capillary pressure, relative permeability, wettability, interfacial tension, and fluid compositions. The clay mineralogy affects the penetration rate and the diagenetic overprint either enhances or deliberates fluid flow. The novelty of this integrated study lays the foundation for a thorough and bespoke screening EOR study, which is currently under development for an offshore candidate field. Preliminary screenings were also conducted through core flooding with representative outcrops. An understanding of the integration of the various reservoirs and fluid properties is essential in determining the characteristics of the entirety of the candidate reservoir. Incorporating these complex zones in an integrated reservoir characterization study is fundamental in achieving successful EOR deployment and optimizes oil production.

This investigation presents laboratory and field deployment results that demonstrate the potential candidacy utilizing Nano and bio-technologies to create superior chemicals for novel applications to increase oil recovery from both onshore and offshore reservoirs. Nano-technology is gaining momentum as a tool to improve performance in multiple industries, and has shown significant potential to enhance hydrocarbon production. The laboratory analysis and specifically designed coreflood results indicate there are beneficial interactions at liquid-nano solid interface that increase oil mobility. This will increase the surface activity of chemical surfactants and thereby make them the dominant agents to mobilize and recover oil from oil-bearing reservoirs. Advances in biotechnology offer another rich resource of knowledge for surface active materials that are renewable and more environmental-friendly. In addition, our studies also demonstrate that bio-surfactants are well-suited to provide superior performances in enhancing oil recovery. Nano-particles and biosurfactants may be included with synthetic surfactants to create novel and more efficient surface active agents for enhanced oil recovery. These formulations can promote better flow back of the injected stimulation fluids and additional mobilization to extract more oil from the matrix and micro-fractures. Laboratory experiments demonstrate that the specialized surfactant formulations created, interact with mixed or oil-wet low permeability formations to produce additional oil. Furthermore, this investigation also compares the total production on a candidate field with respect to typical water flood and the novel formulated surfactant approach. For each surfactant treatment, the overall designed injected fluid volume is 1500 m3 (~ 396,000 gallons) with 4 gpt (gallon per thousand unit) of surfactant concentration. Results indicate improved oil production with longer exposure time of the key surfactants within the reservoir. Enhanced surface wetting and super-low interfacial tension (IFT) at lower chemical concentrations are recognized to be the main mechanisms. The novel surfactant also shows stronger sustainability and endurance in keeping rock surface wettability over traditional surfactant system up to 5 times for an 8 PV wash. Furthermore, this can assist to identify and initiate the optimization of the identified mechanisms for potential applications within other compatible reservoirs. A number of successful field applications of EOR with special formulated nano and bio-based surfactant formulation are discussed in this paper. This unique study bridges the gap between the field realized results and lab optimization to enhance feasibility as a function of time and cost.

The sedimentology, petrography and reservoir potential of Pliocene sandstones within the Upper Red Series in the offshore LAM field, Western Turkmenistan, have been examined. Depositional settings are interpreted within the framework of the Red Series palaeoenvironments across the entire Turkmen sector of the Apsheron-Prebalkhan uplift zone, including its onshore extension to the east.Examination of 81 m of core from three separate intervals suggests that the Red Series in the LAM field is the product of a fluvial-dominated delta system with associated floodplain deposits, periodically flooded by the saline waters of the South Caspian Lake. Relatively thick sandstones, up to around 5 m thick, are interpreted as channel and pointbar deposits of a meandering river system, with thinner and finer-grained sandstones and siltstones inferred to be crevasse-splay and interdistributary floodplain deposits. Floodplain mudstones display signs of desiccation, soil formation, plant rootlets and occasional thin layers of anhydrite. Intervals with marine trace-fossil assemblages record incursions of saline-lake waters. Conglomeratic layers at the base of thicker mudstone intervals may be associated with abrupt transgressions of the lake. The best reservoir qualities are associated with the fluvial channel and point-bar sandstones. Crevasse-splay and other overbank sandstones are of poorer quality, while intercalated floodplain to lacustrine claystone/siltstone units may constitute local seals.Eighteen sandstone plug samples from the cored intervals were examined in thin-section and by XRD and SEM to assess how mineralogy, grain size and diagenesis affect reservoir quality. The samples consist predominantly of lithic arkoses and feldspathic litharenites; higher porosities, and therefore better reservoir potential, are associated with the feldspathic litharenites. Primary controls on porosity include compaction, clay-matrix content and calcite cementation. XRD data reveal the presence of illite, illite-smectite and chlorite. The presence

<p>The Cretaceous Dunvegan Formation in the Western Canada Sedimentary Basin is a well-characterized source-to sink system that extends for about 1000 km from proximal gravelly alluvial systems in the Liard Basin, Northwest Territories, to well-developed sandy deltaic and prodelta muddy shelf systems in Alberta. The mud to sand transition has been well-documented and the sandy deltas have been shown to be fed by tributive incised valley systems driven by cycles of high frequency sea-level change. These incised valleys in turn pass landward into the conglomerate alluvial systems, but the nature of these conglomerates and the controls on the gravel-sand transition have not been well examined.</p> <p>Dunvegan conglomerates in outcrops in the Liard Basin are moderately-sorted and well- rounded reaching up to small cobbles in size. These have previously been interpreted as alluvial fans; however, our investigations show a domination of sharp to scoured based meters-thick fining upward facies successions consisting of dune- and bar- scale cross stratification. The conglomeratic units comprise highly amalgamated channel belt deposits that form cliff exposures that are about 70 m high. There is an absence of debris flows or of sedimentary structures characteristic of supercritical flows, and we thus interpret these as likely deposited by meters-deep lower-gradient gravel-bed streams, rather than steep-gradient, sheet-flood dominated alluvial fans.</p> <p>Trunk channels in the sink area, farther to the southeast are associated with incised valleys and have a mean bankfull depth of 10-15 m, carry medium sand (< 200 microns) with slopes estimated to be on the order of 6x 10<sup>-5</sup>. Source to sink calculations indicate a back-water length of around 200 kilometers. Based on paleogeographic reconstructions, the conglomerates appear to have been deposited 300 to 500 km from the mapped deltaic shorelines, indicating that the gravel sand transition is not related to the back water and is likely not controlled by sea-level changes, thought to be important in generating the incised valleys in the sink area. </p> <p>The conglomerates appear to be confined within the Liard Basin, which is bounded to the east by the Bovie Fault, expressed as a major kilometer-throw normal fault. The Bovie structure was long-lived and may have been active throughout Dunvegan time. Hence, excess accommodation, driven by movement on the Bovie Fault may have prevented gravel from escaping into the more distal parts of the Western Canada Sedimentary basin.  </p> <p>This is in contrast to other clastic wedges in the Cretaceous Interior Seaway, such as the Frontier and Cardium formations, that contain conglomeratic shoreline and shelf deposits and may indicate steeper gradient S2S systems.</p> <p>Tectonics and climate in the Dunvegan drainage basin may not have been linked to processes downstream because of the Bovie Fault. Despite clear evidence of downstream sea-level controls in the Dunvegan sink, it does not appear that these signals were able to propagate upstream.</p>