Shaoran Ren

CO2-triggered gelation for mobility control and channeling blocking during CO2 flooding processes

CO2 flooding is regarded as an important method for enhanced oil recovery (EOR) and greenhouse gas control. However, the heterogeneity prevalently distributed in reservoirs inhibits the performance of this technology. The sweep efficiency can be significantly reduced especially in the presence of “thief zones”. Hence, gas channeling blocking and mobility control are important technical issues for the success of CO2 injection. Normally, crosslinked gels have the potential to block gas channels, but the gelation time control poses challenges to this method. In this study, a new method for selectively blocking CO2 channeling is proposed, which is based on a type of CO2-sensitive gel system (modified polyacrylamide-methenamine-resorcinol gel system) to form gel in situ. A CO2-sensitive gel system is when gelation or solidification will be triggered by CO2 in the reservoir to block gas channels. The CO2-sensitivity of the gel system was demonstrated in parallel bottle tests of gel in N2 and CO2 atmospheres. Sand pack flow experiments were conducted to investigate the shutoff capacity of the gel system under different conditions. The injectivity of the gel system was studied via viscosity measurements. The results indicate that this gel system was sensitive to CO2 and had good performance of channeling blocking in porous media. Advantageous viscosity-temperature characteristics were achieved in this work. The effectiveness for EOR in heterogeneous formations based on this gel system was demonstrated using displacement tests conducted in double sand packs. The experimental results can provide guidelines for the deployment of the CO2-sensitive gel system for field applications.

Gas hydrate risks and prevention for deep water drilling and completion: A case study of well QDN-X in Qiongdongnan Basin, South China Sea

Abstract Taking a deep-water exploration well of natural gas located in the Qiongdongnan Basin in the South China Sea as an example, the hydrate risks of the well under operational conditions during drilling and testing processes were analyzed, and the corresponding hydrate prevention solutions were presented and verified by lab experiments and field application. Based on the predicted gas hydrate equilibrium curves and the calculated wellbore pressure-temperature fields, the hydrate risks were analyzed. The maximum sub-cooling temperature is 6.5 °C during normal drilling with a small hydrate stability zone in the wellbore; when the drilling or testing stops, the hydrate stability zone in the wellbore becomes larger and the maximum sub-cooling temperatures are 19 °C and 23 °C respectively; the maximum sub-cooling temperature at the beginning of testing is no more than that when testing stops; when the tested production rate of natural gas increases, the hydrate stability zone in the wellbore decreases or even disappears if the gas rate is more than 25×10 4 m 3 /d. The designed hydrate prevention solutions include: adding sodium chloride and ethylene glycol into drilling fluid during normal drilling and when drilling stops; adding calcium chloride/potassium formate and ethylene glycol into testing fluid; applying downhole methyl alcohol injection when the production rate of natural gas is lower than 25×10 4 m 3 /d; filling the testing string with testing fluid when the test shuts down for a long time. Lab experiments and field operations have indicated that all the designed solutions can meet the requirements of hydrate prevention.

Numerical simulation of water and sand blowouts when penetrating through shallow water flow formations in deep water drilling

In this study, we applied a two-phase flow model to simulate water and sand blowout processes when penetrating shallow water flow (SWF) formations during deepwater drilling. We define ‘sand’ as a pseudo-component with high density and viscosity, which can begin to flow with water when a critical pressure difference is attained. We calculated the water and sand blowout rates and analyzed the influencing factors from them, including overpressure of the SWF formation, as well as its zone size, porosity and permeability, and drilling speed (penetration rate). The obtained data can be used for the quantitative assessment of the potential severity of SWF hazards. The results indicate that overpressure of the SWF formation and its zone size have significant effects on SWF blowout. A 10% increase in the SWF formation overpressure can result in a more than 90% increase in the cumulative water blowout and a 150% increase in the sand blowout when a typical SWF sediment is drilled. Along with the conventional methods of well flow and pressure control, chemical plugging, and the application of multi-layer casing, water and sand blowouts can be effectively reduced by increasing the penetration rate. As such, increasing the penetration rate can be a useful measure for controlling SWF hazards during deepwater drilling.

Formation water evaporation induced salt precipitation and its effect on gas production in high temperature natural gas reservoirs

Abstract To study the pattern of formation water evaporation and salt precipitation, based on the oil-gas-water three phase thermodynamic equilibrium, the principle of salt dissolution/precipitation, and results of formation water evaporation and salt precipitation experiment, a comprehensive salt precipitation model considering formation water evaporation, precipitation of NaCl in water, and reservoir porosity and permeability variations was established to analyze the salt precipitation and its influence factors during the development of high temperature gas reservoir, and some methods preventing and removing salt precipitation were proposed. The study results show that salt precipitation usually occurs in production well area during development of gas reservoir. When the initial formation water saturation is less than the irreducible water saturation, the concentration of precipitated salt from production well area will be lower, and the influence of salt precipitation on reservoir can be ignored. When initial formation water saturation is higher than irreducible water saturation, the flowing formation water constantly carries NaCl to the well bore, leading to massive precipitation of NaCl in the production well area, damaging or even plugging the reservoir completely, and shortening the development life cycle of gas reservoir at last. The increase of reservoir temperature, formation water salinity and reservoir porosity will intensify reservoir damage caused by salt precipitation. But the increase of production rate and reservoir permeability will reduce reservoir damage caused by salt precipitation. The results of this study can guide the prevention and removal of salt precipitation, enhancement of gas reservoir productive capacity and secondary development of high temperature gas reservoir.

CO2 geological storage into a lateral aquifer of an offshore gas field in the South China Sea: storage safety and project design

The DF1-1 gas field, located in the western South China Sea, contains a high concentration of CO2, thus there is great concern about the need to reduce the CO2 emissions. Many options have been considered in recent years to dispose of the CO2 separated from the natural gas stream on the Hainan Island. In this study, the feasibility of CO2 storage in the lateral saline aquifer of the DF1-1 gas field is assessed, including aquifer selection and geological assessment, CO2 migration and storage safety, project design, and economic analysis. Six offshore aquifers have been investigated for CO2 geological storage. The lateral aquifer of the DF1-1 gas field has been selected as the best target for CO2 injection and storage because of its proven sealing ability, and the large storage capacity of the combined aquifer and hydrocarbon reservoir geological structure. The separated CO2 will be dehydrated on the Hainan Island and transported by a long-distance subsea pipeline in supercritical or liquid state to the central platform of the DF1-1 gas field for pressure adjustment. The CO2 will then be injected into the lateral aquifer via a subsea well-head through a horizontal well. Reservoir simulations suggest that the injected CO2 will migrate slowly upwards in the aquifer without disturbing the natural gas production. The scoping economic analysis shows that the unit storage cost of the project is approximately US

Displacement mechanisms of air injection for IOR in low permeability light oil reservoirs

26-31/ton CO2 with the subsea pipeline as the main contributor to capital expenditure (CAPEX), and the dehydration system as the main factor of operating expenditure (OPEX).

Low-Temperature Oxidation of Oil Components in an Air Injection Process for Improved Oil Recovery

Air injection into light oil reservoirs has been proven to be a valuable improved oil recovery (IOR) process and is being successfully implemented worldwide in many oilfields. It specially offers unique technical and economic opportunities for tertiary or secondary oil recovery in light oil reservoirs with low permeability in which conventional water injection techniques have been unsuccessful and/or uneconomical. This paper provides a comprehensive overview on the oxidation and IOR process of air injection into low permeability light oil reservoir based on detailed analysis of some field projects and the results of laboratory testing and reservoir simulation of a typical light oil reservoir, the Q131 Block. The reaction mechanisms of low temperature oxidation (LTO) and high temperature oxidation (HTO or in-situ combustion) are particularly addressed in this study. Air flooding displacement efficiency experiment was carried out without water injection, and an oil recovery of more than 40% of hydrocarbon pore volume (HCPV) was observed. A series of high-pressure oxidation experiments using the typical light oil were conducted in the temperature range of 98°C to 180°C. The results showed high oxidation and carbon dioxide (CO2) conversion rates, which are both favourable in terms of oxygen consumption. A conceptual full field compositional reservoir simulation model of the targeted low permeability block was also used to examine the reaction schemes, thermal effect of LTO reactions and IOR mechanisms. [Received: March 22, 2014; Accepted: February 7, 2016]