EOR in Tight Reservoirs, Technical and Economical Feasibility

Abstract

Field experience indicates that primary depletion of tight oil formations, using multistage fractured horizontal wells, commonly recovers only 5 to 10% of OOIP. The impact of various EOR techniques on recovering additional oil from these formations is still not fully understood. This paper investigates the applicability of feasible EOR methods and determines their technical and economic success over the natural depletion process under different well and fracture designs. Additionally, the study investigates the minimum reservoir permeability required for success. To achieve the objectives, both black oil and compositional simulation models were generated for a Western Canadian tight reservoir containing volatile oil. In addition to primary, the EOR recovery processes that were considered include waterflooding, immiscible-N2 and miscible-CO2 gas flooding. Combinations of these techniques, coupled with the effects of various well and fracture design parameters were technically explored, and economically ranked using a comprehensive economic analysis. Furthermore, the optimal case of each process was subjected to sensitivity on matrix permeability to determine the minimum permeability at which these methods can be applicable. In the EOR scenarios evaluated, the highest cumulative oil produced was associated with the closest well and fracture spacing, and longest fracture half length. With a larger well spacing (in the order of 400 m), the wells were found to be too far apart to offer any benefit from any EOR technique. Additionally, the capital expenditure of tight-oil projects is high and therefore greatly influences the economic success. Several scenarios yielded similar NPV values, however, the IRR performances and CAPEX requirements helped further evaluate and rank the scenarios. For the reservoir model used, waterflood was found to be uneconomical at the initial permeability levels investigated (around 0.3 md) and required a minimum permeability threshold (1 mD) to become profitable. The primary recovery mechanisms in waterflooding are pressure maintenance and areal sweep, which were more pronounced in the N 2flood. This was the best recovery technique based on NPV. However, the best recovery technique based on oil recovery was the miscible-CO2 flood. It offered an increase in oil recovery factor from 11% to 23% over the best natural depletion case, which was a result of increased oil mobility by dissolution of CO2. At lower permeability values (down to 0.03 mD) immiscible-N2 flood became the most effective method via pressure maintenance within the drainage area. For even tighter reservoirs (under 0.03mD), natural depletion remained the best option for this reservoir. This paper provides an elaborate workflow for evaluating and optimizing EOR techniques in tight oil formations through an integrated modeling approach. It helps to identify the most technically and economically proficient techniques under different levels of permeability, well spacing and fracture parameters.

Influence of Heterogeneity and Fracture Conductivity on Supercritical CO2 Miscible Flooding Enhancing Oil Recovery and Gas Channeling in Tight Oil Reservoirs

“…Both laboratory experiments and numerical simulations in Bakken cores have been conducted to investigate CO 2 injection potential in improving oil recovery from tight oil. The results show that the oil recovery factor of CO 2 continuous injection is about 16–25%. ,,, In the past few years, there have been a number of pilot tests for gas injection in North America, including North Dakota and Montana in the United States and Saskatchewan in Canada; however, the pilot tests, in general, show early breakthrough times and relatively low productivity, and the exploitation was not expanded much. Thus, there is the gap between lab work conclusions and field test performance. ,, One reason for the fast breakthrough is that the injection process created induced fractures; thus, the fractured tight reservoir with natural or artificial fractures affects the field test results.…”

“…The results show that the oil recovery factor of CO 2 continuous injection is about 16−25%. 7,9,17,18 In the past few years, there have been a number of pilot tests for gas injection in North America, including North Dakota and Montana in the United States and Saskatchewan in Canada; 19 however, the pilot tests, in general, show early breakthrough times and relatively low productivity, and the exploitation was not expanded much. Thus, there is the gap between lab work conclusions and field test performance.…”

RSM for Modelling the CO2 Effect in the Interfacial Tension Between Brine and Waxy Dulang Crude Oil During LSW-WAG EOR

“…Access to new energy resources from yet to explore hydrocarbon fields are getting more challenging and require significant upfront capital investment. Due to these reasons, recovering oil from existing fields through the Enhanced Oil Recovery (EOR) process is seen as a more feasible alternative as an upfront cost to develop a new field can be obviated [1]. EOR refers to the injection of chemicals, gas or steam as an external agent into the oil reservoir to promote additional oil recovery beyond what is typically realized when the reservoir produced under its natural drive or assisted by waterflooding [2].…”

Investigation of CO2/N2 injection in tight oil reservoirs with confinement effect

“…While, other researchers point that the oil could be produced with a high and stable production rate under the N 2 flooding . Joslin et al have studied various EOR techniques, and the results show that N 2 flooding is the most effective method via pressure maintenance when the permeability value is lower than 0.03 mD. Although several studies have been carried out to investigate the efficiency of N 2 gas injection on tight oil reservoirs, they did not systematically and mechanistically address the feasibility of CO 2 /N 2 injection and comprehensively show microphysical mechanisms in tight oil reservoirs.…”