Investigation of air injection to enhanced oil recovery from medium oil reservoir of Upper Indus basin of Pakistan

Previously, air injection is exclusively used in light oil reservoirs; however, laboratory research has shown that air injection can also be very efficient for medium and heavy oil recovery. Due to the low cost of air injection and its indefinite availability, it has an economic advantage over other Enhanced Oil Recovery methods. This study is carried out in an experiment conducted on air injection into medium oil reservoirs. To better understand the air injection procedure for enhancing oil recovery from the X field\u27s medium oil (26.12 °API) of Pakistan reservoir, 14 runs were performed. The effects of air flux, porous media, temperature, and pressure on oxidation reaction rates were explored and measured. The consumption of oxygen at a rate of 90% was determined. At a moderate pressure of 7300 kPa, a significant oil recovery of around 81% of the original oil in place was observed. Increased air flux and low permeability can have a more significant effect on medium oil recovery. The technique produced flue gases that were exceptionally low in carbon oxides, with a typical gas composition of 12% CO2, 6% CO, and unreacted oxygen. This research will contribute to a better knowledge of the air injection method and allow for the optimum performance for a specified reservoir. In the Enhanced oil recovery, a less costly process using this method will be inspiring due to recovering oil in this region

CO2 storage capacity estimation under geological uncertainty using 3-D geological modeling of unconventional reservoir rocks in Shahejie Formation, block Nv32, China

Underground CO2 storage is a promising technology for mitigating climate change. In this vein, the subsurface condition was inherited a lot of uncertainties that prevent the success of the CO2 storage project. Therefore, this study aims to build the 3D model under geological uncertainties for enhancing CO2 storage capacity in the Shahejie Formation (Es1), Nv32 block, China. The well logs, seismic data, and geological data were used for the construction of 3-D petrophysical models. The target study area model focused on four units (Es1 × 1, Es1 × 2, Es1 × 3, and Es1 × 4) in the Shahejie Formation. Well logs were utilized to predict petrophysical properties; the lithofacies indicated that the Shahejie Formation units are sandstone, shale, and limestone. Also, the petrophysical interpretation demonstrated that the $$Es1$$ E s 1 reservoir exhibited high percentage porosity, permeability, and medium to high net-to-gross ratios. The static model showed that there are lateral heterogeneities in the reservoir properties and lithofacies; optimal reservoir rocks exist in Es1 × 4, Es1 × 3, and Es1 × 2 units. Moreover, the pore volume of the Es1 unit was estimated from petrophysical property models, ranging between 0.554369 and 10.03771 × 106 sm3, with a total volumetric value of 20.0819 × 106 sm3 for the four reservoir units. Then, the 100–400 realizations were generated for the pore volume uncertainties assessment. In consequence, 200 realizations were determined as an optimal solution for capturing geological uncertainties. The estimation of CO2 storage capacity in the Es1 formation ranged from 15.6 to 207.9 × 109 t. This result suggests the potential of CO2 geological storage in the Shahejie Formation, China

A Study on the Mechanism of Urea-assisted Steam Flooding in Heavy Oil Reservoirs

The Biqian-10 block, located in Henan Oilfield of Sinopic, contains many thin and interbedded reservoirs, which have been operated by cyclic steam stimulation for 20 years or more. Therefore, it is a challenge to implement the conventional steam flooding. In order to improve the recovery of steam flooding, urea was used to assist steam flooding. Urea can decompose into CO2 and NH3, which are beneficial to enhance oil recovery (EOR). For the sake of exactly quantifying the mechanism of urea assisted steam flooding (UASF), the UASF model was built according to the experimental results. The simulation results show that CO2 is the key point for EOR, and its pressurization function is more effective than the decrease in oil viscosity by dissolving CO2. The emulsification of crude oil for NH3 is weak in interfacial tension tests; thus the effect of emulsification can be ignored in the simulation. The UASF can improve the recovery by about 17.4%, which is 6.8% higher than steam flooding.</span

Scientific justification of the perforation methods for Famennian deposits in the southeast of the Perm Region based on geomechanical modelling

The article presents the results of analysing geological structure of the Famennian deposits (Devonian) in the Perm Region. Numerical modelling of the distribution of inhomogeneous stress field near the well was performed for the two considered types of perforation. With regard for the geometry of the forming perforation channels, numerical finite element models of near-wellbore zones were created considering slotted and cumulative perforation. It is ascertained that in the course of slotted perforation, conditions are created for a significant restoration of effective stresses and, as a result, restoration of reservoir rock permeability. Stress recovery area lies near the well within a radius equal to the length of the slots, and depends on the drawdown, with its increase, the area decreases. From the assessment of failure areas, it was found that in case of slotted perforation, the reservoir in near-wellbore zone remains stable, and failure zones can appear only at drawdowns of 10 MPa and more. The opposite situation was recorded for cumulative perforation; failure zones near the holes appear even at a drawdown of 2 MPa. In general, the analysis of results of numerical simulation of the stress state for two simulated types of perforation suggests that slotted perforation is more efficient than cumulative perforation. At the same time, the final conclusion could be drawn after determining the patterns of changes in permeability of the considered rocks under the influence of changing effective stresses and performing calculations of well flow rates after making the considered types of perforation channels

RESEARCH ON CO2 FLOODING FOR IMPROVED OIL RECOVERY IN WATER FLOODING ABANDONED RESERVOIRS

CO2 injection is an effective technique for improved oil recovery in light oil reservoirs, especially for water flooding abandoned reservoirs. In this study, the lower part of Es1 reservoirs in Pucheng oilfield was introduced as the target reservoir. By studying the minimum miscible pressure in CO2 flooding, the reservoir could achieve miscible flooding. Long core displacement experiments proved that water alternating CO2 flooding could significantly improve the recovery. For the reservoir characteristics, anti-corrosion technology in the process of injection was researched, and the H-20 inhibitor was screened. A channeling blocking agent in combination with the delayed expansion of gel particles and cross-linked copolymer was used to control the gas fluidity. The Pu 1-1 well groups were optimized to conduct a field trial. The cumulative injected liquid CO2 was 19219.95 ton, 0.248 PV and the cumulative increasing oil was 4520.9 t. The predicted recovery will increase by 8.3%. The successful implementation of the project can provide technical attempt for completion of energy to succeed and energy-saving emission reduction targets.</span

Assessment of CO2 EOR and its geo-storage potential in mature oil reservoirs, Shengli Oilfield, China

Most oil reservoirs in the Shengli Oilfield area have entered middle and late development stages after nearly 40-years of production, and they are suitable for applying CO2 EOR and carbon storage techniques. This study is aimed at assessing the potential of CO2 EOR and storage in three large oil fields in the region based on the data of 183 mature oil reservoirs. The assessments include a regional geology assessment, storage site screening, reservoir screening for CO2 EOR and EOR potential and storage capacity calculations. Many mature oil reservoirs are close to the main CO2 sources and have good geographical and geological conditions for CO2 storage. Of 41 reservoirs, 18 are suitable both for EOR and storage while 23 reservoirs were found suitable for storage as depleted oil reservoirs. The total EOR potential could be 999.72×104 t and the CO2 storage potential could reach 9,553.92×104 t. The overall incremental oil recovery rate could be 5.76%. The greater OOIP the oil reservoir has, the greater potential for CO2 EOR and storage it will have, and the more suitable for large-scale storage projects it will be. Those oil reservoirs suitable for CO2 EOR with large OOIP will be the preferred sites for CO2 storage. Many nearly depleted oil reservoirs with large OOIP can be considered as main sites for CO2 storage in the near future. Key words: Carbon dioxide, CO2 EOR, geological storage, geo-storage potential, Shengli Oilfiel

Experimental study on scaling and adhesion characteristics in water-producing gas wellbore

A water-producing gas well in deep water encounters problems of high cost and substantial operational difficulties in scale prevention and descaling. To determine the characteristics of wellbore scaling and its influencing factors, it is important to accurately predict the scaling risk in deepwater gas wells so that anti-scale measures can be optimized. In this study, a high-temperature and high-pressure reactor and aslim metal tube at atmospheric pressure were used to simulate the scaling process of formation water in a gas wellbore under static and flowing conditions. The amount of scaling, distribution of scaling particles, and wellbore blockage risk were investigated. The results show that: (1) Carbonate scaling in formation water occurs at high temperature and low pressure. The scaling ion concentration, CO2 partial pressure, gas phase proportion, and MEG content are the main factors affecting the scaling amount. Only a part of the scaling particles attaches to the tube wall. The remainder will disperse in water, and can be produced out or stranded in the wellbore, depending on the hydrodynamic conditions in the wellbore. The scaling particles easily precipitate and block in horizontal and inclined well sections. (2) The adhesion of scaling particles on the tube wall is severely affected by the scaling tendency of the formation water. As the scaling tendency of water increases, the scaling ions tend to transfer to the tube wall and scale on the tube wall. However, when the scaling tendency is sufficiently high, more scaling particles will be produced in water because of the limited mass transfer speed. (3) The production of gas and water has an important influence on wellbore scaling, output, and distribution. A large water rate results in a large amount of scaling, but the scaling particles in the wellbore are distributed widely and are easy to produce, which causes a small blockage risk in the wellbore. In comparison, gas production has little influence on the amount of scaling, but it can make the scaling particles deposit more intensively in the wellbore and increase the risk of blockage. The knowledge gained in this study can provide baseline information for the accurate prediction of scaling and plugging risk in gas wellbores