No abstract

A reliable future development plan of an oilfield would require that all of the elements in the petroleum system are modeled in an integrated manner if a timely response, a more realistic economical evaluation, and risk analysis are needed for better decisions making. The main goal for future development of Tomoporo field is to change the traditional focus (petroleum system elements by separated) by enabling to multidisciplinary team members to take advantage of their expertises within a collaborative environment based on interaction among petroleum system components. The Tomoporo field's hydrocarbon reserves have been largely developed in offshore, but barely in onshore. It has been planned to increase production twice through new producing wells in onshore area which presents several limitations for handling production. Also a plan for pressure support, and improved oil recovery have been considered by implementing a waterflooding project. This paper shows an innovative integrated asset methodology, applied for forecasting scenarios where reservoir, surface network, geographic location aspects, economy, risk, and uncertainty analysis were considered. The evaluation of forecasting scenarios was performed by implementing an integrated asset modeling (IAM) where all of simulation scenarios were coupled with a surface network model. Such network modeling included itself three integration levels to address complexity of surface facility needed for future offshore-onshore field development. In addition, an innovative link from reservoir-surface network models to the economic model was developed for a fully assisted asset modeling, resulting in faster and more reliable scenarios evaluation. The IAM for Tomoporo field provided valuable information for all team members of the production stream, maximizing benefits from decision making based on a fully coupled asset model. This integrated approach determined that greater recovery factor and less reservoir pressure drop are achieved if an onshore flow station is added for new onshore wells in spite of existing capabilities in offshore surface facilities. The IAM approach triggered warnings about future needs (investment, expenses), and also to be alert in minimizing bottlenecks in order to ensure no violation of surface capacity constraints. In addition, it allowed to define operating limits of water injection plants, enabling that optimum operation conditions are set, and the added value of the Tomoporo field development be maximized.

This paper offers an innovative method to test various scenarios for toe-to-heel air injection wells, to meet the demands for new technology and methods using in-situ combustion coupled with steam injection. It presents research conducted over the last few years on the numerical simulation of the toe-to-heel air injection enhanced heavy oil recovery process. Reservoir simulations were used to evaluate multiple variables and scenarios, leveraging the integrated workflow capabilities of software while maximizing the effective time for performance analysis. Included are discussions of the workflow process, a description of base model details, well array testing results (i.e., four patterns combining horizontal and vertical wells), a comparison of injection air rate in the toe-to-heel air injection process versus a conventional in-situ combustion method, and sensitivities in oxygen concentration and injection rate, which led to increased recovery through the application of toe-to-heel air injection technology. The effects of heterogeneities on the development of the toe-to-heel air injection process are also examined, along with multisegmented well model benefits demonstrated in the reservoir simulation software tool (ECLIPSE). Additionally, coke deposition during combustion was simulated, showing that toe-to-heel air injection does not affect the fluid flow dynamics process. Based on our research study, this analysis of the best scenario for toe-to-heel air injection well placement efficiently produces nonconventional hydrocarbon accumulations by delivering increased process control on the combustion front.

Previous research demonstrates listeners dynamically adjust phonetic categories in line with lexical context. While listeners show flexibility in adapting speech categories, recalibration may be constrained when variability can be attributed externally. It has been hypothesized that when listeners causally attribute atypical speech input to an external factor, phonetic recalibration is attenuated. The current study investigated this theory directly by examining the influence of face masks, an external factor that affects both visual and articulatory cues, on the magnitude of phonetic recalibration. Across four experiments, listeners completed a lexical decision exposure phase in which they heard an ambiguous sound in either /s/-biasing or /ʃ/-biasing lexical contexts, while simultaneously viewing a speaker with a mask off, mask on the chin, or mask over the mouth. Following exposure, all listeners completed an auditory phonetic categorization test along an /s/ - /ʃ/ continuum. In Experiment 1 (when no face mask was present during exposure trials), Experiment 2 (when the face mask was on the chin), Experiment 3 (when the face mask was on the mouth during ambiguous items), and Experiment 4 (when the face mask was on the mouth during the entire exposure phase), listeners showed a robust and equivalent phonetic recalibration effect. Recalibration manifested as greater proportion /ʃ/ responses for listeners in the /ʃ/-biased exposure group, relative to listeners in the /s/-biased exposure group. Results support the notion that listeners do not causally attribute face masks with speech idiosyncrasies, which may reflect a general speech learning adjustment during the COVID-19 pandemic.

Dual-viscosity fluid is a fracturing fluid that has been recently introduced to cover a wide range of fracturing applications varying, from a non-delayed to delayed fluid system for treatments in low to moderate to high temperatures, respectively. Reducing the impact of the pressure effect of traditional borate cross-linked systems, the system crosslinker is compact and delivers a relatively high concentration of crosslinker per unit volume; it is also compatible with current metering pumps, covering a range of treatment rates compared to the current fluid system, and this can simplify logistics on location. The North Bahariya oil fields are onshore fields located in the Western Desert of Egypt and operated by Sahara Oil and Gas Company (SOG). The fields contain proven oil reserves in two sandstone packages at relatively shallow drilling depths (6,500 ft. subsea) in the Abu Roash "G" member (A/R G) of Cenomanian (Cretaceous) age. These sandstones comprise the main reservoirs in the field. During the last 4 years, the introduction of various techniques has led to a fourfold increase in the production from these fields. This success story is mainly the result of using the new hydraulic fracturing methods such as channel fracturing technique and continuous improvement of the fracturing treatments. SOG has been at the forefront in applying novel technologies to optimize the fracturing fluid treatment by using the dual-viscosity fracturing fluid to improve the wells potential. This technology has been implemented in Abrar field. As seen in case studies, very positive results have been seen in both zones of the A/R G formation in terms of improvement in the well performance. Experiences in Abrar field illustrate how to optimize the production rate in a marginal field by optimizing the hydraulic fracturing treatment fluid and how to build on this success for subsequent fields while pushing the innovation envelope further.