Assessing the application of miscible CO2 flooding in oil reservoirs: a case study from Pakistan

Miscible carbon dioxide (CO2) flooding has been recognized as a promising approach to enhance the recovery of oil reservoirs. However, depending on the injection strategy and rock/fluid characteristics, efficiency of the miscible CO2flooding varies from reservoir to reservoir. Although, many studies have been carried out to evaluate the performance of the miscible CO2flooding, a specific strategy which can be strictly followed for a hydrocarbon reservoir has not been established yet. The aim of this study is to assess one of Pakistan’s oil reservoirs for miscible CO2flooding by applying a modified screening criterion and numerical modeling. As such, the most recent miscible CO2screening criteria were modified, and a numerical modeling was applied on the prospective reservoir. Based on the results obtained, South oil reservoir (S3) is chosen for a detailed assessment of miscible CO2flooding. It was also found that implementation of CO2water-alternating gas (CO2-WAG) injection at early stages of production can increase the production life of the reservoir

Mechanistic study to investigate the effects of different gas injection scenarios on the rate of asphaltene deposition: An experimental approach

Asphaltene deposition during enhanced oil recovery (EOR) processes is one of the most problematic challenges in the petroleum industry, potentially resulting in flow blockage. Our understanding of the deposition mechanism with emphasis on the rate of the asphaltene deposition is still in its infancy and must be developed through a range of experiments and modelling studies. This study aims to investigate the rate of asphaltene deposition through a visual study under different gas injection scenarios. To visualise the asphaltene deposition, a high-pressure setup was designed and constructed, which enables us to record high-quality images of the deposition process over time. Present research compares the effects of nitrogen (N2), carbon dioxide (CO2) and methane (CH4) on the rate of asphaltene deposition at different pressures. The experimental results in the absence of gas injection revealed that the rate of asphaltene deposition increases at higher pressures. The results showed that the rate of asphaltene deposition in the case of CO2 injection is 1.2 times faster than CH4 injection at 100 bar pressure. However, N2 injection has less effect on the deposition rate. Finally, it has been concluded that the injection of CO2 leads to more asphaltene deposition in comparison with CH4 and N2. Moreover, the experimental results confirmed that gas injection affects the mechanism of asphaltene flocculation and leads to the formation of bigger flocculated asphaltene particles. The findings of this study can help for a better understanding of the mechanism of the asphaltene deposition during different gas-EOR processes

Analysis of EOR Projects and Updated Screening Criteria

Enhanced Oil Recovery (EOR) provides a means to progressively expand hydrocarbon exploitation through scientific advancements. EOR methods have been proved to mobilize, and induce the flow of oil to producing wells in primary, secondary, and tertiary recovery stages. This work involves the construction of an EOR database based on numerous reported EOR projects. The database lists reservoir rock and fluid properties in addition to other project attributes related to oil saturations, incremental recovery, demography, and project start date. The database provides a profile of worldwide EOR trends. This paper also updates the EOR selection criteria published by Taber et al. in 1996 (Society of Petroleum Engineers (SPE) 35385). Finally, this paper illustrates the relationship of EOR project distribution to key reservoir characteristics. The database can be a vital tool for formulating field development plans, ensuring project viability, and clarifying research development priorities

Recent Developments and Updated Screening Criteria of Enhanced Oil Recovery Techniques

This paper reviews recent developments in enhanced oil recovery (EOR) techniques published in SPE conference proceedings for 2007 to 2009. It also updates the EOR criteria developed by Taber et al. in 1996 based on field applications reported in Oil & Gas Journal and at various SPE conferences. It classifies EOR methods into five main categories: gas-based, water-based, thermal, others, and combination technologies. New developments in EOR techniques, chemicals, and mechanisms are summarized to clarify advances in EOR criteria beyond previous limitations. Reservoirs that had previously been ruled out based on specific reservoir conditions are now candidates under updated EOR screening criteria. To demonstrate this potential, this work has established guidelines for the selection and optimization of chemical EOR methods for a specific reservoir

Investigating Low Salinity Waterflooding Recovery Mechanisms in Carbonate Reservoirs

Manipulating the injected brine composition can favorably alter the reservoir wetting state; this hypothesis has been validated in sandstone reservoirs by several scientists. A total of 214 coreflooding experiments were conducted to evaluate low salinity waterflooding (LSWF) secondary recovery and 188 experiments were conducted to evaluate tertiary recovery, for sandstone reservoirs. Although the incremental recovery potential in carbonate reservoirs is greater than in sandstones, only a few imbibition and coreflooding experiments have been conducted. The simulator and recovery mechanisms presented by Aladasani et al. (2012) are used and their suitability and validity to low salinity waterflooding in carbonate reservoirs has been confirmed. This has been achieved by comparing simulated LSWF secondary and tertiary recoveries with published coreflooding experiments. Furthermore, the prediction profiler in JMP was used to examine incremental recovery for the following variables: (a) acid number and interfacial tension (IFT) sensitivities, and (b) 2 nd stage injected brine and 3 rd stage injected brine anion contents. In weak water-wet conditions, the incremental recovery is driven by low capillary pressures, and the underlining recovery mechanism is the increase in oil relative permeability. Therefore, wettability modification is ideal when achieved by shifting the wetting state from oil-wet or water-wet to a maintained intermediate wetting condition irrespective of the injected brine salinity dilution. If the wettability is shifted to a strong water-wet system, then it would be more favorable to use brine with anions to shift the wettability back to an intermediate wetting state. IFT has a bigger impact on LSWF in carbonate reservoirs; however, contact angle is more significant to the final oil recovery. Future work should consider studying the impact of cationic and anionic ions on coreflooding recovery separately and using cores with different initial wetting states, preferably strong oil-wet cores

Investigating Low-Salinity Waterflooding Recovery Mechanisms in Sandstone Reservoirs

Numerous core-flooding experiments have shown that Low-Salinity Water Flooding (LSWF) could improve oil recovery in sandstone reservoirs. However, LSWF recovery mechanisms remain highly contentious primarily because of the absence of crucial boundary conditions. The objective of this paper is to conduct a parametric study using statistical analysis and simulation to measure the sensitivities of LSWF recovery mechanisms in sandstone reservoirs. The summary of 411 coreflooding experiments discussed in this paper highlights the extent and consistency in reporting boundary conditions, which has two implications for statistical analysis: (1) Even though statistical correlations of the residual oil saturation to chlorite (0.7891) and kaolinite (0.4399) contents, as well as the wettability index (0.3890), are comparably strong, the majority of dataset entries are missing, and a prediction model cannot be generated; (2) If a prediction model is generated without clay content values and a wettability index, even though LSWF emphasizes wettability modification by virtue of oil aging time and the strong influence of brine cation and divalent ion concentrations on S or, the prediction model\u27s regression curve and confidence level are poor. Reservoir simulations conducted to examine LSWF recovery sensitivities conclude that LSWF recovery mechanisms are governed based on the initial and final wetting states. In strong water-wet conditions, the increase in oil relative permeability is the underlying recovery mechanism. In weak water-wet conditions, the incremental recovery of LSWF is driven by low capillary pressures. In weak oil-wet conditions, the primary LSWF recovery mechanism is the increase in oil relative permeability, and the secondary mechanism is the change of the non-wetting phase to oil. In strong oil-wet conditions, the underlining LSWF recovery mechanism is the increase in oil relative permeability. In all cases, an appreciable decrease in interfacial tension (IFT) is realized at the breakthrough recovery however that is rapidly overshadowed by the increase in oil relative permeability and decrease in contact angle