Zhang, Hao (Missouri University of Science & Tech) | Bai, Baojun (Missouri University of Science & Tech) | Song, Kai (Missouri University of Science and Technology) | Elgmati, Malek Mohamed (Missouri University of Science & Tech)
Shale gas reservoir developments have steadily increased over the past few years throughout North America. A significant amount of the produced gas in shales is stored in complex submicron pore structures. The absence of an intensive hydraulic flow unit (HFU) model for these shale gas source rocks makes the prediction of economic gas productivity and hydraulic fracturing risky. Therefore, understanding of pore size distribution, permeability, pore connectivity, and other petrophysical properties is crucial for accurate performance prediction and effective reservoir management. This study utilizes the dual-beam (SEM-FIB) instrument for shale gas tomography. The reconstructed 3D sub-micron pore model provides insights into the petrophysical properties of shale gas, including pore size distribution and porosity. These properties were used to define the shale gas hydraulic unit and permeability. The identified flow units were able to fit into existing flow unit models for unconventional reservoirs. The comparison between the proposed method and mercury injection capillary measurements (MICP) revealed similar data range however MICP method tends to slightly overestimate the flow unit. Flow simulation based on 3D Stokes equation using image segmentation was performed and consistent permeability value was found compared to the estimation in SEM-FIB tomography. However, the permeability simulation results tend to underestimate the permeability value in reality. A case example from Utica shale illustrated the use of this approach.
Manipulating the injected brine composition can favorably alter the reservoir wetting state; this hypothesis has been validated in sandstone reservoirs by several scientists. A total of 214 coreflooding experiments were conducted to evaluate low salinity waterflooding (LSWF) secondary recovery and 188 experiments were conducted to evaluate tertiary recovery, for sandstone reservoirs. Although the incremental recovery potential in carbonate reservoirs is greater than in sandstones, only a few imbibition and coreflooding experiments have been conducted. The simulator and recovery mechanisms presented by Aladasani et al. (2012) are used and their suitability and validity to low salinity waterflooding in carbonate reservoirs has been confirmed. This has been achieved by comparing simulated LSWF secondary and tertiary recoveries with published coreflooding experiments. Furthermore, the prediction profiler in JMP was used to examine incremental recovery for the following variables: (a) acid number and interfacial tension (IFT) sensitivities, and (b) 2nd stage injected brine and 3rd stage injected brine anion contents. In weak water-wet conditions, the incremental recovery is driven by low capillary pressures, and the underlining recovery mechanism is the increase in oil relative permeability. Therefore, wettability modification is ideal when achieved by shifting the wetting state from oil-wet or water-wet to a maintained intermediate wetting condition irrespective of the injected brine salinity dilution. If the wettability is shifted to a strong water-wet system, then it would be more favorable to use brine with anions to shift the wettability back to an intermediate wetting state. IFT has a bigger impact on LSWF in carbonate reservoirs; however, contact angle is more significant to the final oil recovery. Future work should consider studying the impact of cationic and anionic ions on coreflooding recovery separately and using cores with different initial wetting states, preferably strong oil-wet cores.
Numerous core-flooding experiments have shown that Low-Salinity Water Flooding (LSWF) could improve oil recovery in sandstone reservoirs. However, LSWF recovery mechanisms remain highly contentious primarily because of the absence of crucial boundary conditions. The objective of this paper is to conduct a
parametric study using statistical analysis and simulation to measure the sensitivities of LSWF recovery mechanisms in sandstone reservoirs. The summary of 411 coreflooding experiments discussed in this paper highlights the extent and consistency in reporting boundary conditions, which has two implications for statistical analysis: (1) Even though statistical correlations of the residual oil saturation to chlorite (0.7891) and kaolinite (0.4399) contents, as well as the wettability index (0.3890), are comparably strong, the majority of dataset entries are missing, and a prediction model cannot be generated; (2) If a prediction model is generated without clay content values and a wettability index, even though LSWF emphasizes wettability modification by virtue of oil aging time and the strong influence of brine cation and divalent ion concentrations on Sor, the prediction model's regression curve and confidence level are poor. Reservoir simulations conducted to examine LSWF recovery sensitivities conclude that LSWF recovery mechanisms are governed based on the initial and final wetting states. In strong water-wet conditions, the increase in oil relative permeability is the underlying recovery mechanism. In weak water-wet conditions, the incremental recovery of LSWF is driven by low capillary pressures. In weak oil-wet conditions, the primary LSWF recovery mechanism is the increase in oil relative permeability, and the secondary mechanism is the change of the non-wetting phase to oil. In strong oil-wet conditions, the underlining LSWF recovery mechanism is the increase in oil relative permeability. In all cases, an appreciable decrease in interfacial tension (IFT) is realized at the breakthrough recovery however that is rapidly overshadowed by the increase in oil relative permeability and decrease in contact angle.
The use of miscible carbon dioxide (CO2) flooding has increased significantly in the past decade. What makes CO2 unique is its low miscibility pressure, which extends the candidacy of CO2 to reservoirs with lower API gravity, shallower depths and lower fracture pressure gradients compared to reservoirs in which miscible nitrogen or miscible hydrocarbon flooding might be used. Furthermore, the financial incentives associated with the removal of a greenhouse gas offset development costs and operating expenditures. Therefore, this paper focuses primarily on selection criteria for CO2 Enhanced Oil Recovery (EOR) and the dispersion modeling of highpressure CO2 release, as these are critical in offsetting capital investments and managing legal liabilities.
The available EOR selection criteria, which are based on reported EOR projects were developed initially by Taber in 1983 and then updated by Taber et al. in 1996 and again by Aladasani & Bai in 2010. Recent publications by Aladasani & Bai (2011) regarding discussions surrounding EOR selection criteria focus on dataset distribution to refine EOR candidacy selection. The work presented in this paper further develops the tools with which to screen miscible CO2 for EOR applications by offering detailed distributions and correlations of reservoir properties reported in miscible CO2 projects, as well as a prediction model for miscible CO2 recovery. The screening tools presented in this paper are intended as a new detailed and systematic approach to selecting miscible CO2 flooding and to developing EOR as a whole.
The increase in Carbon Sequestration Projects (CSP) and CO2 EOR projects has resulted in the expansion of the CO2 pipeline network in the United States (US). An overview of the CO2 network in the US, the transit pipeline incident history in North America and Europe, and the scope of pipeline risk studies are presented. Finally, recent developments in CO2 consequence modeling inform the dispersion modeling of critical CO2 releases, highlighting the toxicity risk of H2S in anthropogenic CO2 streams.
Technology Focus - No abstract available.