Reservoir Operation

Employing water injection is a widely utilized method to sustain continual oil recovery from reservoirs. This involves maintaining reservoir pressure, managing the oil rim, and facilitating the movement of oil from injection wells to production wells. Given that many water injection facilities still heavily depend on manual operation, automating the injection process emerges as a crucial strategy.

Being able to calculate and predict the inflow performance from a well is critical in designing any form of artificial lift. The production/lift capability of whatever form of artificial lift chosen should closely match the current and future inflow performance of the well for the economics of the investment to be the highest.

Inflow performance estimation is also required to ensure that production is being optimized. When used with the outflow performance of the lift method, NODAL analysis can be performed to evaluate the entire production system for production enhancements.

In mature oil fields, the success of gel treatment results depends on the ability of the gel to reduce the high permeable formation without damaging to low permeable formation. Formation damage refers to the extent of damage reservoir rocks face from various drilling techniques and/or chemical treatment during well completion. A dynamic filtration test was used to investigate this effect using distinct core samples, brine concentrations and preformed particle gels.

Environmental concerns and increasing costs are creating a need for a polymer that will allow the use of a high salt, high hardness water in the making of a viscosified frac fluid. Any new polymer would also need to tick the boxes for cost, rheology, HS&E characteristics as well as breaking in the reservoir. Past development efforts have focused on improving organic-based polymers. A new approach was taken and a shift was made to the use of silica-based polymer.

Multiphase flow is found in various places both in nature and in practice, however, multiphase flow is prevalent in the petroleum production industry. This phenomenon brings about a major problem of pressure loss in piping systems and results in a loss in production. Multiphase flow has been studied for years however, with the increase in unconventional engineering methods, there is now a greater need for the study of multiphase flow.

Darcy and non-Darcy flow through packing particles is an important study to determine the flow rate and pressure drop through porous media. Darcy is formed with a low liquid flow rate while non-Darcy flow is formed with a high flow rate. The objective of this experiment is to determine the flow performance through packing particles. In this study, a syringe piston pump is used to inject the water through various packing particles. The solution contained different salt concentration mixed with desalinated water.

Water block after hydraulic fracturing is one of the major challenges in shale oil recovery which affects the optimal production from the reservoir. The water blockage represents a higher water saturation near the matrix-fracture interface, which decreases the hydrocarbon relative permeability. The removal of water blockage in the field is typically carried out by soaking the well (i.e., shut-in) after hydraulic fracturing.

Because the flow regimes and drainage geometry of horizontal well are different from those of vertical wells, there is a need to develop a distinct analytical Productivity Index (PI) solution for horizontal well.  There have been several researches in the early 1990's  developing the solutions; however, each solution generates different PI values.  The degree of disparity depends on how conservative or optimistic the input values are, which possibly results in the reduction in confidence level when applying these analytical methods.

The fault effects on the build-up pressure distribution of oil wells were investigated by using numerical and analytical approaches. The limitations and benefits of analytical and numerical solutions of the build-up test were listed in the research. The effects of reservoir boundaries on well responses by using analytical solutions were analyzed. Schlumberger software package “ECLIPSE” was used for the numerical simulation, where the model was discretized to 200 by 200 by 5 grid blocks with the length of each side of the grid block as 75 feet horizontally and 7.5 feet vertically.

The study optimizes the effect of the non-ionic surfactant and slugs of low concentration HCl on the near fracture face matrix permeability of Eagle Ford and Marcellus shale by considering different scenarios for the fracturing treatment design. Constant rate flooding apparatus was used to measure the samples base permeability and the permeability after flooding with either slickwater fluid or slickwater with nonionic surfactant or with 3 wt% HCl at 200 oF. The permeability was measured using 3 wt% KCl and at atmospheric temperature.