Digital Rock Physics (DRP) has progressed at a rapid speed since the first pore network models were developed. DRP has now evolved in to a new discipline and essentially involves use of X-ray CT scanning in micro and Nano-CT to capture the 3D network structure of representative reservoir rock types. The proliferation of the technique with powerful computers and robust network modeling means one can rapidly determine various Special Core Analysis (SCAL) properties that form the basis of reservoir characterization parameters: porosity, permeability, formation factor, cementation and saturation exponents, capillary pressure, relative permeability and elastic properties.A comprehensive DRP based validation study was performed on reservoir core plugs which had undergone rigorous Petrophysical SCAL at representative pseudo reservoir conditions. The objective was to assess the use of DRP in determining such data, and quantifying the relevant uncertainties. The plugs were chosen from two super giant carbonate reservoirs in the Middle East. The laboratory tests comprised cementation exponent 'm' at a range of pressures, water-oil capillary pressure (Pc) and electrical resistivity index (RI) tests at reservoir temperature and reservoir overburden pressure using specially designed Porous Plates.Capillary pressure under primary drainage and imbibition conditions, replicating reservoir conditions were established using multi-phase flow simulations on the pore network representation of the 3D rock model. Similarly, the cementation exponent 'm' was calculated using a solution of the Laplace equation with charge conservation; the equations were solved using a random walk algorithm. DRP based primary drainage and imbibition saturation exponents 'n' were also computed for cores samples of different reservoir rock types. The results were then compared to measured SCAL data, and validation criteria established along with possible uncertainties. DRP is extremely promising in generating fairly accurate SCAL parameters very fast from existing cores.
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.
Pore Scale modeling in carbonate reservoir is challenging and important for getting an accurate reservoir characterization, enhanced oil recovery (EOR) and reservoir management. In this case, 3D pore-scale modeling for immiscible and near miscible three phase flow in gas and water alternating gas (WAG) flooding of carbonate reservoir. It is useful to predict and guide SCAL based to access effects on pore-scale and EOR of field scale. A Research has been started in carbonate reservoir with water alternating gas (WAG) injection activity which has various heterogeneity conditions such as: porosity, permeability, relative permeability, cementation, saturation exponent, rock types, fluid types/contacts, interfacial tension, wettability and capillary pressure. Inaccurate to characterize and model of these reservoir properties and fluid will lead to give high uncertainty of reservoir characterization, minimum oil recovery and reservoir management concern. The reliable pore-scale modeling approach is needed by the data integration of various sources such as those from petrophysical, reservoir, geology and geophysical data. Research and utilize of X-ray CT in micro and nano to capture the 3D network structure of representative reservoir rock properties. In prediction and guide SCAL based; investigation the effects (sensitivity) of interfacial tensions, contact angles, wettability and spreading coefficient into miscibility on the oil layers between gas and water in a fully interconnected three-phase flow pore-network model. Utilize thermodynamic criteria for rock properties and oil layers, which affect the oil relative permeability at low oil saturation for accurate prediction of residual oil and maximize oil recovery. In 3D Pore scale modeling workflow; validation with SCAL-lab, up scaling to well logs and field with utilizing logs, formation pressure/sampling/testing and combination with structural data of geology-seismic are necessary in field scale modeling approach. It will provide reliable rock type/properties for a reservoir dynamic model. The special approach needs to be developed and used in simulation model for getting appropriate relative-permeability, rock type/properties and water saturation in Gas and Water Alternating Gas (WAG) flooding of carbonate reservoirs. Thus it can give an accurate and robust of reservoir characterization, maximize oil recovery and reservoir management.
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
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