Potential of Low-Salinity Waterflooding Technology to Improve Oil Recovery

Low-salinity waterflooding (LSWF) is a potential new method for enhanced oil recovery (EOR) in sandstone and carbonate rock formations. LSWF approach has gained an attention in the oil and gas industry due to its potential advantages over the conventional waterflooding and other chemical EOR technologies. The efficiency of waterflooding process is effected via reservoir and fluid parameters such as formation rock type, porosity, permeability, reservoir fluid saturation and distribution and optimum time of water injection. Combined effect of these factors can define the ultimate recovery of hydrocarbon. The main objective of this chapter is to review the mechanism of LSWF technique in improving oil recovery and the mechanism under which it operates. Various laboratory studies and few field applications of LSWF in recent years have been presented mainly at the lab scale. Also it will explore numerical modeling developments of this EOR approach

Optimization of nano-silica in enhancing the properties of synthetic based drilling fluids for tight gas reservoir conditions

The nano-silica in drilling fluids is commonly used to improve the performance of drilling fluids, mainly water and oil based muds. Tight gas reservoirs are experienced a myriad of problems during drilling. One of the problems is the gas influx into the wellbore because of the abnormal pore pressure, fluid loss due to the fracture pressure and pore pressure is very narrow margin, stuck down hole equipment in the wellbore due to high differential pressure between hydrostatic pressure and pore pressure. Another problem is related to drilling mud and cement. However, not much studies have been done on the effect of nano-silica in invertemulsion drilling fluids. This research paper focuses on how nano-silica influences the performance of invert-emulsion/synthetic based mud in tight gas reservoirs at harsh operation conditions, high pressure high temperature (HPHT). Synthetic based mud has been selected as an ideal drilling fluid to be used in HPHT tight gas reservoirs due to its superior qualities. In order to objectify this study, numerous experiments sets have been carried out in which different concentrations of nano-silica with respect to the fluid loss agent have been added to the synthetic based mud and the resultant performance is carefully studied in order to determine the optimum concentration of nano-silica that will elicit the best performance from synthetic based drilling fluids. The obtained results showed that a maximum concentration of about 40% provides the best performance Nano-silica has also improved the rheological properties of SBM by reducing the plastic viscosity and yield points

Numerical investigation of optimum ions concentration in low salinity waterflooding

     Injecting low saline water is one of the practices used to improve hydrocarbon production that has recently significantly grown due to its advantages over seawater and chemical flooding. Although many theories and mechanisms have been provided on how additional oil recovery has been achieved utilizing low salinity waterflooding, the principle fundamentals of the mechanism(s) are still ambiguous. This article investigates the potential use of low salinity waterflooding (LSWF) to improve oil production from a sandstone formation. A 3D field-scale model was developed using Computer Modeling Group ( generalized equation-of-state model simulator) based on a mature oil field data. The developed model was validated against actual field data where only 8% deviation was observed. Simulation analysis indicated that multi-component ion exchange is a key factor to improve oil production because it alters rock wettability from oil-wet to water-wet. Simulation sensitivity studies showed that low salinity water flooding provided higher oil production than high water salinity flooding. Moreover, simulation showed early breakthrough time of low salinity water injection can provide high oil recovery up to 71%. Therefore, implementing LSWF instantly after first stage production provides recovery gains up to 75%. The determined optimal injected brine composition concentration for Ca2+, Mg2+ and Na+ are 450, 221, and 60 ppm, respectively. During LSWF, a high divalent cations and low monovalent cations’ concentration can be recommended for injected brine and formation aquifer for beneficial wettability alteration. Simulation also showed that reservoir temperature influenced the alteration of ion exchange wettability during LSWF as oil recovery increased with temperature. Therefore, high temperature sandstone reservoirs can be considered as a good candidate for LSWF.Cited as: Ben Mahmud, H., Mahmud, W.M., Arumugam, S. Numerical investigation of optimum lons concentration in low salinity waterflooding. Advances in Geo-Energy Research, 2020, 4(3): 271-285, doi: 10.46690/ager.2020.03.0

Multiphase Transient Flow in Pipes

The development of oil and gas fields in offshore deep waters (more than 1000 m) will become more common in the future. Inevitably, production systems will operate under multiphase flow conditions. The two–phase flow of gas–liquid in pipes with different inclinations has been studied intensively for many years. The reliable prediction of flow pattern, pressure drop, and liquid holdup in a two–phase flow is thereby important.With the increase of computer power and development of modelling software, the investigation of two–phase flows of gas–liquid problems using computational fluid dynamics (CFD) approaches is gradually becoming attractive in the various engineering disciplines. The use of CFD as a modelling tool in multiphase flow simulation has enormously increased in the last decades and is the focus of this thesis. Two basic CFD techniques are utilized to simulate the gas–liquid flow, the Volume of Fluid (VOF) model, and the Eulerian–Eulerian (E–E) model.The purpose of this thesis is to investigate the risk of hydrate formation in a low–spot flowline by assessing the flow pattern and droplet hydrodynamics in gas– dominated restarts using the VOF method, and also to develop and validate a model for gas–liquid two–phase flow in horizontal pipelines using the Eulerian– Eulerian method; the purpose of this is to predict the pressure drop and liquid holdup encountered during two–phase (i.e. gas–oil, gas–water) production at different flow conditions, such as fluid properties, volume fractions of liquid, superficial velocities, and mass fluxes.In the first part of this thesis, the VOF approach was used to simulate the droplet formation and flow pattern at various levels of liquid patched and restart gas superficial velocities. The effect of restart gas superficial velocity on the liquid displacement from the low section of the pipe showed a decrease in the remaining liquid with an increase in gas superficial velocity, and the amount of liquid depends on the fluid properties, such as density and viscosity. Moreover, the flow pattern is also strongly dependent on the restart gas superficial velocity as well as the patched liquid in the low section. A low gas superficial velocity with different patched liquids illustrated no risk of hydrate formation due to the observed flow pattern that is often a stratified flow. However, as the restart gas superficial velocity is increased, regardless of initial liquid patching, hydrate formation is more likely to be observed due to the observed flow pattern, such as annular, churn or dispersed flow.In the second part, the E–E model was employed to establish a computational model to predict the pressure drop and liquid holdup in a horizontal pipeline. Due to the complicated process phenomena of two–phase flow, a new drag coefficient was implemented to model the pressure drop and liquid holdup in the 3D pipe. Different simulations were performed with various superficial velocities of two–phase and liquid volume fractions, and were carried out using RNG k-ε model to account for turbulence. Based on the results from the numerical model and previous experimental study, the currently used E–E model is improved to get more accurate prediction for the pressure drop and liquid holdup in horizontal pipes compared with the existing models of Hart et al. (1989) and Chen et al. (1997).The improved model is validated by previously reported experimental data (Badie et al., 2000). The deviation of pressure drop and liquid holdup obtained throughout the CFD simulation with regard to the experimental data was found to be relatively small at low superficial gas velocities. It was observed that the pressure gradient increased with the system parameters, such as the drop size, liquid and gas superficial velocity and the liquid volume fraction, where the liquid holdup decreased.The developed model provided a basis for studying the pressure drop and liquid holdup in a horizontal pipe. Different parameters have been examined, such as gas and liquid mass flux and liquid volume fraction. Two empirical correlations have been examined (Beggs and Brill (1973), and Mukherjee and Brill (1985)) against the CFD simulation results of pressure drop and liquid holdup, it was noted that they gave better agreement with the air–oil system rather than the air–water system, but shows reasonable agreement over the entire gas mass fluxIn the third part, the coupling of Eulerian–Eulerian multiphase model with the population balance equation (PBE), accounting for droplet coalescence and breakage, is considered. Strengths and weaknesses of each numerical approach for solving PBE have been given in details. The Quadrature Method of Moments (QMOM) is used and particular coalescence and breakup kernels were utilized to demonstrate the droplet size distribution behaviour. Numerical simulations on a two–phase flow in a horizontal pipe, including coalescence and breakage are performed. The QMOM is shown to give the solution of the PBE with reasonable agreement. The numerical data are compared with the experiment data of Simmons and Henratty (2001). The flow variables, such as liquid volume fractions, gas and liquid superficial velocities are employed to examine the droplet size distribution and the potential of the multiphase k–ε with population balance model for predicting the two–phase pressure drop and liquid holdup.The significance of this work is to assist in understanding the risk of hydrate formation in bend pipes at gas–dominated restarts with different patched liquid values. The knowledge gained from this work can be utilized to avoid the hydrate formation operating conditions. The developed of multiphase flow E–E model will provide an accurate prediction for two–phase pressure drop and liquid holdup in a horizontal pipe which will be of benefit to the design of tubing and surface facilities

Sand production: A smart control framework for risk mitigation

Due to the current global oil price, the sand production is considered undesirable product and the control of sand production is considered as one of the main concerns of production engineers. It can damage downhole, subsea equipments and surface production facilities, also increasing the risk of catastrophic failure. As a result of that it costs the producers multiple millions of dollars each year. Therefore, there are many different approaches of sand control designed for different reservoir conditions. Selecting an appropriate technique for preventing formation sand production depends on different reservoir parameters. Therefore, choosing the best sand control method is the result of systematic study. In this paper the sand production factors and their effects are presented where the emphasis is given towards the sand prediction to determine the probability of producing sand from the reservoir, followed by the correct prevention implementation of sand control method. The combination of these two is presented as a smart control framework that can be applied for sand production management

A Review of Fracturing Technologies Utilized in Shale Gas Resources

The modern hydraulic fracturing technique was implemented in the oil and gas industry in the 1940s. Since then, it has been used extensively as a method of stimulation in unconventional reservoirs in order to enhance hydrocarbon recovery. Advances in directional drilling technology in shale reservoirs allowed hydraulic fracturing to become an extensively common practice worldwide. Fracturing technology can be classified according to the type of the fracturing fluid with respect to the well orientation into vertical, inclined, or horizontal well fracturing. Depth, natural fractures, well completion technology, capacity, and formation sensitivity of a shale reservoir all play a role in the selection of fracturing fluid and fracturing orientation. At present, the most commonly used technologies are multi-section fracturing, hydra-jet fracturing, fracture network fracturing, re-fracturing, simultaneous fracturing, and CO2 and N2 fracturing. This chapter briefly reviews the technologies used in shale reservoir fracturing

Characterization and analysis of naturally fractured gas reservoirs based on stimulated reservoir volume and petro-physical parameters

© 2021, The Author(s). Fracture is one of the most important geological phenomena that affect the production of hydrocarbon compounds in broken carbonate reservoirs. However, fracture controlling factors must be combined with well data to achieve accurate fracture modeling. Therefore, structural data, drilling data, well flow diagrams, cores data, wells production data, and dynamic reservoir data have been considered here. Finally, by combining the above-mentioned information and through statistical and mathematical methods, the mechanism of fracture creation, general trends, and dominant fracture patterns are determined. These patterns are directly related to the tectonic regime and the stresses governing the region. For the first time, in this paper, we divided Zubair carbonate gas reservoir into 10 zones based on porosity and water saturation, and shale volume variation. We conclude that just four-zone of these are economic producible. Besides, the dominant lithology of this formation is more than limestone and a small number of thin shale layers. We defined types of cross-sectional petro-physical graphs and confirmed them by the geological graphic diagram prepared at the head

Numerical Investigation of Low-Salinity Waterflooding Capability to Enhanced Oil Recovery

Low-salinity water flooding (LSWF) is one of techniques that can be used to improve oil production and has gained a significant attention in these days because of its advantages over conventional water flooding and chemical flooding. Even though many mechanisms have been recommended on an extra oil recovery achieved using LSWF process, the principle fundamental of the mechanism is still not fully understood. This research paper investigates the potential of oil recovery in an onshore sandstone reservoir using LSWF. A field-scale three–dimensional reservoir model has been developed via CMG’s GEM compositional simulator where the model validated against a real production field data that were in good agreement with a deviation value of 8%. The primary mechanism of LSWF has been identified by providing incremental oil recovery due to a multi-component ion exchange mechanism that causes wettability alteration of reservoir rock from oil-wet to water-wet. The sensitivity study showed that LSWF provides a higher accumulative oil production compared to conventional high salinity water injection with 13.5 and 12 MMSTB. Moreover, the early time of low saline brine injection can provide a maximum oil recovery up to 71%. Therefore, implementing this scenario immediately after the primary recovery, it provides production benefits in both secondary and tertiary method. The oil recover factor increased to 75.5% with the increasing of brine injection rate up to an optimum value of 5320 bbl/d. A reservoir temperature also influenced the ion exchange wettability alteration during LSWF in which as the temperature increasing enhances the oil recovery. Therefore, a high temperature sandstone reservoir will be a potential candidate for LSWF

Investigation of change in different properties of sandstone and dolomite samples during matrix acidizing using chelating agents

Properties of rock, such as effective porosity, permeability and pore size distribution (PSD), are generally referred to as petrophysical properties. These properties are among the most significant for reservoir evaluation. Acid stimulation treatments are usually used in sandstones to mitigate the impact of formation damage, with the aim of restoring or enhancing the natural matrix permeability and consequently boosting the well productivity. Hydrochloric acid (HCl) is commonly used in the preflush stage to remove calcium and other metal ions, preventing the development of calcium fluoride (CaF 2 ) and other silicate precipitates that could block the pore throats, while an acid mixture (HF–HCl combination) is usually preferred as the main stimulation fluid for the removal of quartz and remaining metal ions. However, sometimes the application of these acids can lead to other problems, including fast reactions, corrosion of pipes, environmental hazards, precipitation reactions and formation damage due to the incompatibility of HCl with clay minerals, so chelating agents have been proposed as an alternative for matrix stimulation fluids. In this study, three different chelating agents, ethylenediaminetetraacetic acid (EDTA), N-(2-hydroxyethyl) ethylenediamine-N,N′,N′-triacetic acid (HEDTA) and N-acetyl-l-glutamic acid (GLDA), have been used to stimulate Berea sandstone, Colton tight sandstone and Guelph dolomite samples. Core flood experiments were conducted on 1.5 × 3 (in 2 ) core plugs, at a temperature below 180 °F. A slow injection rate of (1–0.5 cc/min) was chosen for the treatment fluid, promoting the dissolution of ions by increasing the contact time between the fluid and the rock. Furthermore, nuclear magnetic resonance, wettability and micro-computed tomography (CT scan) analyses were employed to evaluate the effect of the acid treatment on formation properties such as porosity, PSD, pore topology, wettability and pore structure. After exposing the samples to HEDTA, large wormholes were detected in their pore network, demonstrating that HEDTA has the highest potential to create new pore spaces when compared to GLDA and EDTA when reacted with both types of samples

An optimization framework for sandstone acidizing using design of experiment (DOE) and mathematical modelling

Fluoroboric acid (HBF4) serve as one of the alternatives for conventional mud acid in the application of sandstone wells stimulation. Various parameters such as formation temperature and acid injection velocity would significantly affect the performance of sandstone acidizing and hence determine the success rate of well stimulation. It is therefore undeniable that a deep understanding of the effects of these major parameters are of paramount importance. However, there is a scarcity of data available in the literature regarding the use of HBF4 in sandstone acidizing in comparison to the use of mud acid. In this work, an optimization framework is developed to study the combined effects of formation temperature and acid injection velocity to the change in porosity and pressure drop. Apart from porosity improvement, a pressure drop across the sandstone core would also give an indication to the acidizing performance. The optimization approach is achieved by using design of experiment (DOE) and response surface methodology, coupled with a mechanistic model for sandstone acidizing. The design of experiment used in this work is central composite design (CCD). Meanwhile, the mechanistic model that simulate a flow in porous media is being developed using COMSOL Multi-physics, which is a computational fluid dynamics (CFD) software that uses finite element method (FEM). In this optimization tool, a range of formation temperature was set between 41˚C and 88˚C, whereas the range of acid injection velocity was set between 1.79×10-5 m/s to 3.78×10-5 m/s. According to the results, the optimum condition studied was found out to be 88˚C and 3.78×10-5 m/s. Under such an operating condition, the favourable maximum porosity enhancement and pressure drop profile were obtained. The maximum porosity and pressure drop were up to 17% and 16.6979 kPa respectively. The porosity enhancement and pressure drop in the sandstone core showed an excellent agreement with the data predicted by the model. In general, this optimization study had proven that response surface methodology (RSM) could be applied to determine the acid performance in sandstone acidizing