This study investigates the contribution of fluid saturation variation to the time-lapse velocity response by performing fluid substitution modeling. The methodology is exemplified by the time-lapse seismic monitoring of carbon dioxide at Farnsworth field unit (FWU). In order to evaluate the fluid distribution in a matured oil reservoir, the Southwest Regional Partnership (SWP) acquired multiple vertical seismic profile (VSP) surveys at different times during the CO 2 -water alternatinggas (WAG) injection period. In this work, we present a thorough methodology for computing the elastic response of the saturated rock for different fluid saturations using a site-specific petro-elastic model (PEM). The output from the PEM was combined with results from a fluid compositional model to compute the seismic velocities at times corresponding to each VSP survey. To produce a calibrated simulated response, the measured time-lapse seismic velocities were integrated into the numerical simulation model. The mismatches between the predicted and measured time-lapse velocities were minimized through an iterative calibration process using a trained artificial neural network proxy (ANN) coupled with a particle swarm optimizer (PSO). Our study indicates that the hybrid optimization workflow can effectively perform the history matching. With an accurate prediction of the hydrodynamic properties, the migration of CO 2 within the subsurface was modeled by predicting the spatial velocity distribution for a radius of 305 m around the injection well. The technology demonstrated and the expertise gained from this study can guide similar CO 2 -WAG projects.
The properties of Protein enzyme biosurfactant, a green-enzyme, water-based inert-enzyme generated from the DNA of microbes that eat oil was studied to ascertain its applicability in EOR processes. A light crude oil of 0.908 g/cc at 22°C density and 53.87 cp viscosity was used in this study with a kinematic viscosity which was variable between 90.654 mm2/s to 13.7544 mm2/s between temperatures of 22.5 °C to 70 °C with a measured surface tension of about 35 mN/m. The bio-surfactant yielded a CMC value of 0.02 wt.% which is comparable to reported CMC values of other surfactants. The least IFT value measured was 4.0 mN/m, which is very high for a very efficient and effective residual oil recovery (an ultralow IFT of about 0.01mN/m is required of which was achievable by Rhamnolipid a bio-surfactant studied alongside Protein Enzyme in this work). Ionic (0.083M to 3.0M) and temperature (23 to 70 °C) effects did not have much influence on the activities of bio-surfactant, thus quite stable within such conditions. The protein-enzyme has the ability to form a Winsor type III emulsion and stable over the period of time studied. Adsorption was noticed especially with higher bio-surfactant concentrations but tends to be stable over time.
This study investigates the impacts of geomechanical and geochemical changes on carbon storage in a partially depleted oil reservoir, using results from four different coupled simulation models. Models were used to examine the relative importance of storage mechanisms, and how changing reservoir parameters might affect these mechanisms through time. The study uses data from a Morrowan sandstone reservoir in the Farnsworth Unit (FWU), Ochiltree County, Texas which is currently undergoing CO 2 enhanced oil recovery (EOR). Partially depleted oil reservoirs such as the FWU offer attractive carbon utilization and/or storage targets because of existing infrastructure and economic benefits from incremental oil recovery as well as tax credits. However, prediction of storage capacity or long-term fluid migration in these fields can be difficult because of the wide variation in formation fluids and operational histories that may have undergone. CO 2 injection can cause complex geomechanical and geochemical responses in a reservoir as a result of interplay between dynamic changes in pore pressure, reservoir temperature, fluid composition, and interactions between formation fluids, CO 2 , and reservoir rock. Thus, multiple coupled numerical simulation models must be developed and used to more precisely understand what CO 2 storage mechanisms are most significant, as well as the long-term fate of the stored CO 2 . Our study used results from hydrodynamic, coupled hydro-geomechanical, coupled hydro-geochemical, and coupled hydro-geomechanical-geochemical models to examine how changes in geomechanical and geochemical properties can impact the injectivity or storage capacity of CO 2 . Models simulated historical field operations and then forward-modeled a water-alternate-gas (WAG) operation for 20 years, followed by a 1000-year post-injection monitoring. The work demonstrates that in this specific reservoir, geomechanical impacts
A post-drill pore pressure and fracture gradient analyses were conducted on a field in the Tano Basin of Ghana with the primary objective of predicting as accurately as possible the pore pressure, fracture pressure and the overburden pressure from the well logs data of two wells. The wells were drilled offshore in water depths of about 95.4 m and 124.4 m.
Eaton's method coupled with depth-dependent Normal Compaction Trendlines (NCT) and Mathews and Kelly method were used in determining the pore pressure and fracture gradient. The results indicate that average pore pressure gradient, fracture pressure gradient and overburden pressure gradient for the first well are 1.423 psi/m (8.34ppg), 3.514psi/m (20.6ppg) and 4.299psi/m (25.2ppg) respectively whiles values for the second well are 1.423psi/m (8.34ppg), 3.85psi/m (21ppg) and 4.299psi/m (25.2ppg) respectively. These values were predicted to be required to maintain the stability of the wells using accurate mud weight.
Reliable assessment of the petrophysical properties of hydrocarbon-bearing reservoirs is essential for the estimation of hydrocarbon reserves, identification of good production zones, and assessing the need for hydro-fracturing jobs. The K-Field although discovered in the 1970s is yet to be developed.
In this study, well logs from the wells drilled in this field were analysed with the primary objective of determining the petrophysical properties of the reservoir zones using various estimation models. From the log readings, the reservoir sands containing hydrocarbons in the field are found to be located at the Mid Turonian (90Ma)-Intra Upper Albian (96.5Ma) and Intra Upper Albian (98Ma). The porosity was determined using the density log and crossplots. Archie and Simandoux correlations were utilized in the determination of the water saturation. Permeability was estimated using Timur, Tixer and Coates correlations.
The findings after the petrophysical evaluation indicate that the wells entered formations with good reservoir quality in terms of porosity, which ranges from 16.12% to 20.97%. In relation to hydrocarbon saturation and permeability, two of the wells gave better results suggesting that they were drilled through the productive part of the reservoir. Nonetheless, the average permeability of the reservoir is estimated to be very low. This suggests that in the field development planning, well stimulation methods should be incorporated to aid the ability of the reservoir rocks to transmit fluids into the production wells.
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