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Background: Understanding the biomass accumulation and growth rate of the forages to feed the animal throughout the year is critical for improved earnings and long-term livestock production. This was found in forage maize (Zea mays), forage millet (Echinochloa utilis), elephant grass (Pennisetum purpureum) and Gamba grass (Andropogon gayanus). The experiment was place at Federal University Oye Ekiti in Ekiti State, Nigeria, in latitude N 07° 48.308, longitude E 005° 29.573 and elevation 548.4 meters above sea level, with an annual rainfall of 1778 mm. Methods: Planting four rows in a complete randomized design (CRD with four replications) was used to test the forage crops. Before planting, the soil in the experimental field had 49.96% organic matter and 33.59% after the crops were harvested. During the growth season, Pennisetum purpereum had the maximum plant height and sward height. Result: The Zea mays plant had the maximum leaf breadth (5.44 cm at 8 weeks) and the most leaves. Zea mays had the largest biomass accumulation (BC) of 113.80% after 8 weeks, followed by Andropogon gayanus with 67.15 per cent, Pennisetum purpureum with 56.24 per cent and Echinochloa utilis with 51.63%. Although there were no significant differences p£0.05 in the crude protein levels of the different species, samples from the latest cuts (8th week) had the greatest crude protein content (11.88% in Andropogon gayanus). Crude protein levels were shown to rise in lockstep with grass growth. Although there was no significant difference between the grass species, the crude fibre content of the three grass species was discovered to vary with the growth phase. The greatest fibre content of 13.58% in Zea mays was reported during the 6th week, which might be attributable to lignin encrustation in grasses that were harvested late. All of the plant samples of crops showed the same irregular pattern in crude fiber, moisture content and fat content, with no significant variance.

The use of gas injection and storage approach in enhanced oil recovery (EOR) is receiving increasing attention as an efficient solution to mitigate the effects of anthropogenic greenhouse gas emissions in the atmosphere, improve production by means of increasing static reservoir pressure, and allow optimized utilization of produced hydrocarbons as a function of actual consumption. During gas injection a geological trap (i.e. active or abandoned reservoir) is used to store excess gas that can be eventually produced for future utilization. This process generates changes in pore pressure within the rock's porous space, affecting simultaneously the state of stress inside the reservoir and in its surroundings. These changes of the state of stress can be at the origin of instability mechanisms associated with fracturing inside and outside the reservoir and of reactivation of existing discontinuities (faults and fractures). If reactivation occurs within the caprock, this could lead to possible reservoir sealing failure and thus leakage of the stored gas at surface. Therefore, deformation of caprock and fault integrity must be assessed to properly manage containment performance and leakage-related risks. Given the intrinsic 3D nature of the problem, to ascertain the feasibility of injecting and/or re-injecting natural gas back into producing formations, it is essential to perform numerical simulations to capture the link between concomitant pressurization and /or depletion. The modelling is done with a 3D reservoir simulator and in-situ stresses changes are obtained by means of a 3D coupled reservoir geomechanics simulator. A feasibility study of gas injection and storage in a producing reservoir was performed using coupled geomechanics modeling within an E&P software platform. The process started from single-well geomechanics analysis and then passed through 3D structural characterization and properties modeling, in-situ preproduction stress modeling, dynamic simulation, and, finally, injection modeling. Analyses were carried out using injection pressure modeled dynamically in an industry-standard reservoir simulator. This allowed various injection scenarios to be explored, providing a 4D characterization at various time steps in the future of the state of stress within the reservoir and its surroundings. Results highlighted the main risks, which are related to loss of sealing for the caprock and reactivation of induced faults, as well as uncertainties associated with input parameters.

Improving production and ultimate recovery (UR) from pressure-depleted reservoirs overlain with gas-cap poses considerable risks and challenges that include complex structure, uncertainties in current reservoir fluid distribution and insufficient reservoir energy to produce formation fluids. Both gas cap expansion and solution gas liberation, as a result of decline in static pressure, causes the GOC to migrate downstructure. In addition, the extent and uniformity of OWC movement upstructure would depend on aquifer strength, heterogeneity and mobility ratio at the depleted insitu conditions. Unfavourable mobility ratio further escalates the uncertainty in saturation distribution from the standpoint of determining optimum infill wells locations. The paper will review the case history of two formations in OML-XYZ where declining trend in production performance was reversed by combining power water injection (PWI), gas lift (GL) and optimum placement of infill wells that maximises production and UR. Downhole pressure recordings have demonstrated continuous and steady rise in reservoir pressure since commencement of PWI that has translated to higher oil production. Well surveillance reveals positive response to PWI and GL from decreasing GOR, stable or increasing FTHP. In addition, infill wells are planned to recover reserves that would be bypassed by existing producers even after providing pressure support and continuous GL gas supply. The paper will present steps taken to mitigate the risks stemming from complex structure and uncertainty in current fluid distribution.

The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with a measured matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996. Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline (WL) formation testers for the following reasons: Severe depletion and well deviation causing differential stickingHigh temperatures (150 to 195° C) at the limit of tool electronicsLow permeabilityFractures and breakouts that can impact seal success This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data, and influence on seal success with probe vs. packer elements, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects. While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Pre-run wireline petrophysical data were gathered to characterize the Petrophysical properties of the reservoir and to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation and to confirm the stratigraphic dipping of the structure. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts. This novel approach resulted in 100% seal success, >50% improvement. Four days of rig time were saved, and the required data were obtained.

The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with a measured matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996. Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline (WL) formation testers for the following reasons: Severe depletion and well deviation causing differential sticking High temperatures (150 to 195° C) at the limit of tool electronics Low permeability Fractures and breakouts that can impact seal success This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data, and influence on seal success with probe vs packer elements, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects. While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Pre-run wireline petrophysical data were gathered to characterize the Petrophysic of the reservoir and to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation and to confirm the stratigraphyc dipping of the structure. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts. This novel approach resulted in 100% seal success, >50% improvement. Four days of rig time were saved, and the required data were obtained.