No abstract

In situ heat generation is one of the promising techniques to enhance hydrocarbon production, by removing the condensate damage from the near-wellbore region, and improve gas mobility. This technology is performed by injecting two thermochemical solutions that will react at reservoir conditions and generate heat and pressure. The use of thermochemical fluids will reduce the injection cost to within 60% compared to the solvent injection. During thermochemical treatment, a considerable alteration in the fluid phase behavior will take place. This paper presents a novel technique and the first application of using thermochemicals to eliminate gas condensation. Experimental measurements and computer modeling group (CMG) modeling were performed to investigate the effect of injecting thermochemical fluids on the gas condensate behavior. A new reactor was fabricated to study the reaction kinetics of thermochemical materials. Thereafter, the influence of thermochemical treatments on removing the condensate, reducing the capillary forces, and improving the gas production was studied. Also, the impact of energizing the condensate region with nitrogen that was generated by thermochemical reaction was emphasized. Finally, the propagation depth of the generated heat from thermochemical reaction was determined as a function of injection time. The obtained results showed that injecting thermochemical fluids will increase the reservoir temperature and pressure beyond the dew point curve. At reservoir conditions, a pressure of 1300 psi could be achieved from the thermochemical reaction. The generated pressure is higher than the dew point pressure; therefore, the condensate liquid will be converted into the gaseous phase. Calculations of capillary forces revealed that thermochemical treatment reduced capillary forces by 25–36%. An exponential relationship was observed between the injection time and the radius of heat propagation. Increasing the injection time will increase the radius of the heated area exponentially. The heat propagation model can be used to determine the injection time required to heat the condensate region inside the reservoir.

The recovery of unconventional oil such as heavy oil is receiving great interest as the world oil demand is increasing along with relatively high oil prices. Producing such high viscosity oil is complex and challenging, which usually require thermal techniques. Thermal recovery methods are widely used to recover the heavy oil and bitumen basically by thermally reducing oil viscosity, improving the mobility ratio and enhancing the heavy oil displacement. In response to the recent effort of leveraging heavy oil and tar plays in Saudi Arabia, Saudi Aramco has launched a new thermochemical research program to tackle challenges associated with lowering oil viscosity to improve well productivity and the overall reservoir depletion efficiency. One of the promising new technologies is enabling in-situ steam generation by chemical reaction (EXO-Clean) to mobilize the low API crude oil or tar reserves. In this paper a new steam flooding methodology will be introduced and compared with existing technologies. Steam will be generated in-situ by chemical reactions, which will have better efficiency and lower cost compared to conventional steam injection methods. Simulation study, lab experiments, and field treatment showed great promises of the technology. The developed EXO-Clean treatment relates to in-situ steam generation to maximize heat delivery efficiency of steam into the reservoir and to minimize heat losses due to under and/or over burdens and non-producing areas. The treatment consists of injecting exothermic reaction-components that react downhole and generate in-situ steam and nitrogen gas. The generated in-situ steam and gas can be applied to recover deep heavy oil, and tight oil reservoirs, which cannot be recovered with traditional steam injection methods.

Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution to mitigate the condensate damage around the borehole in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. In addition, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal. In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 h of mixing and injection. In addition, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used. The results of this study showed that the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure. These micro-fractures reduced the capillary forces that hold the condensate and enhanced the rock relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.

No abstract

Thermogravimetric analysis (TGA) provides useful information, which can be used in thermal processing and conversion kinetic modeling of materials, including hydrocarbons. In the present study, a series of TGA experiments were conducted in the presence of air (combustion) and under inert conditions (pyrolysis) using nitrogen gas with the focus of obtaining quantitative information to compare thermal decomposition characteristics of the two processes. The analysis was performed at different gas injection rates (10–50 mL/min) and heating rates (10–30 °C/min) under non-isothermal conditions from 30 to 600 °C. It was observed that the gas injection rates did not have significant impact on the thermal decomposition of the tar sample. However, increasing the heating rate shifted the peak temperatures of the reactions to higher temperatures. In addition, the combustion process generally has a higher conversion and peak rate of conversion than the pyrolysis process. Moreover, the activation energy, E a (kJ mol–1), obtained for the combustion process was observed to be higher than those of the pyrolysis.

No abstract

Unconventional reservoirs have shown tremendous potential for energy supply for long-term applications. However, great challenges are associated with hydrocarbon production from these reservoirs. Recently, injection of thermochemical fluids has been introduced as a new environmentally friendly and cost-effective chemical for improving hydrocarbon production. This research aims to improve gas production from gas condensate reservoirs using environmentally friendly chemicals. Further, the impact of thermochemical treatment on changing the pore size distribution is studied. Several experiments were conducted, including chemical injection, routine core analysis, and nuclear magnetic resonance (NMR) measurements. The impact of thermochemical treatment in sustaining gas production from a tight gas reservoir was quantified. This study demonstrates that thermochemical treatment can create different types of fractures (single or multistaged fractures) based on the injection method. Thermochemical treatment can increase absolute permeability up to 500%, reduce capillary pressure by 57%, remove the accumulated liquids, and improve gas relative permeability by a factor of 1.2. The findings of this study can help to design a better thermochemical treatment for improving gas recovery. This study showed that thermochemical treatment is an effective method for sustaining gas production from tight gas reservoirs.