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This paper investigates the time series properties of three Beyond-Gross Domestic Product (BGDP) measures in Canada, namely, gross national disposable income (GNDI), human development index (HDI), and index of economic freedom (IEF), along with Gross Domestic Product (GDP). GDP is the most used metric for measuring economic growth and is susceptible to influence by numerous factors beyond the value of production measured by GDP. BGDP measures have been suggested in the literature as alternative indicators that can capture economic progress in a more holistic way (Kimmerer, 2020). This paper generates and evaluates the descriptive statistics of GDP and BGDP indicators. To evaluate the potential existence of a long run relationship between GDP and BGDP indices, we performed Augmented Dickey Fuller stationarity and Johansen cointegration tests. The results demonstrate that per capita GDP is cointegrated with the BGDP indicators. Furthermore, this study shows for the first time in the literature that BGDP measures are cointegrated when paired with each other. The paper contributes to the literature by highlighting the time series properties of BGDP indicators in Canada. This insight facilitates understanding the behavior of BGDP measures, thereby further enhancing the use of these measures for econometric studies and policy making. Keywords: Economic growth, Beyond-GDP measures, Disposable income, Human development, Economic freedom, Cointegration.

In the current low commodity price environment, several operators have chosen to return to their mature fields to re-fracture the reservoirs to improve overall recovery of reserves. Although modelling remains challenging, re-fracturing treatments have been successfully executed on multiple wells worldwide. This study compares three different approaches to model re-fracturing in tight sands as a means of reducing the overall uncertainty. Multi-domain integration was utilised in which geomechanical data was coupled with petrophysical analysis to build a three-dimensional (3D) hydraulic fracture model. Fracture pressure history matching was performed and the model was validated using calibration data available from microseismic analysis and extended leakoff tests. Production history matching was performed to validate the reservoir simulation model and estimate the resulting depletion around the wellbore. Geomechanical properties and the resulting minimum in-situ horizontal stress were re-calculated incorporating the results of depletion using three different approaches: Pore Pressure Model, Scale Model and Non-Scale Model. Finally, the hydraulic fracture models were re-constructed using the revised geomechanical properties to simulate re-fracturing using various pumping treatments. The fracture geometries obtained from re-fracture simulations were dependent on the model used for re-computation of geomechanical properties post-production as well as the fluid volume pumped. These properties were also validated using laboratory testing. Comparison of the three approaches indicated consistent geometries when small volumes of fluid or typical ‘Plug and Perf’ designs were pumped. Upon pumping larger volumes or typical ‘Sliding Sleeve’ treatments, major differences were observed using the three approaches indicating larger uncertainty and warranting the use of the more rigorous Non-Scale Model. Validated models are important tools for designing hydraulic fracturing treatments to avoid risks of sub-optimisation of fracture designs or undesirable bashing of offset parent wells. Good understanding of re-fracture models helps oil companies make informed decisions regarding their completion programme, hence improving overall hydrocarbon recovery. Modelling of re-fracture treatments continue to pose a challenge for engineers due to added subsurface static and dynamic complexities. This study presents basic guidelines to follow for modelling, with results verified from laboratory testing.

OBAGI is an onshore oil field located on OML58, 85 km north-west of Port-Harcourt, Nigeria. It is composed of 26 stacked reservoir levels with an estimated total OOIP of 1.2 Gbbls. It was discovered in 1964 and has been producing since 1966 through 123 wells and 257 completions. 21 layers have been developed. With a global recovery to-date of 50% and an average producing water-cut of 75%, OBAGI can be considered as a mature oil field. Current activities are driven by two main objectives:to sustain short term production level, andto identify potential remaining resources for additional developments Appropriate monitoring and global static/dynamic review are the key factors to achieve these objectives. The short term objective is to maintain production by optimizing the injection capacity. Difficulties to model reservoir performance have resulted in implementation of an intensive monitoring program. This is to limit water production and to maintain/increase water injection capacity. For the long term, it is believed that potential resources not accessible with current wells could effectively double the remaining reserves. For this purpose, complementary developments have to be proposed to target clearly identified attic oil or by-passed regions. A pragmatic approach was adopted based on 2G model review, material balance study and fluid contact updates (with regular saturation survey campaigns) to identify additional reserves potential. The progress of the study is presented for one of the layers of the field. Introduction OBAGI is an oil field located onshore Nigeria (Figure 1) and discovered in 1964. The OOIP has been estimated to 1.2 Gbbls, split in 26 stacked reservoir levels (Figure 2). Oil production started in 1966 and the maximum of 70,000 bopd was reached in 1983. Both oil and gas productions are currently valorised thanks to Obite Gas Plant start-up in 1999 (also located on OML58). Therefore, although Obagi is mainly an oil field, 5 gas caps are also considered for future production. All produced water is reinjected into the field to minimise environmental impact and support the reservoir pressure.

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