Factors Affecting Huff-n-Puff Efficiency in Hydraulically-Fractured Tight Reservoirs

Abstract

Evaluation of enhanced liquid recovery from tight or shale reservoirs is currently of great interest to operators. One reason is the low primary oil recovery of tight/shale reservoirs, which ranges between 5-10% (Shoaib and Hoffman, 2009) even after expensive multi-stage hydraulic fracture stimulation. Enhanced recovery using the "huff-n-puff" process could be an effective solution to increase recovery without drilling new wells. There are a number of published lab and simulation studies that investigate the efficiency of huff-n-puff in tight/shale reservoirs. These studies, however, have yielded contradictory results. For example, Chen et al. (2014) concluded that huff-n-puff has a negative impact on recovery while Yu et al. (2014) concluded that it improves recovery by 2-9%. These conflicting results underscore the need for further research. The current study, therefore, endeavors to investigate possible causes of these discrepancies. Compositional numerical simulation is used to investigate key simulation model setup and reservoir controls on huff-n-puff efficiency in tight reservoirs. Some of these controls have never been investigated for tight reservoirs, such as the influence of grid refinement, in-situ fluid composition, and fracture pore volume/hydraulic fracture representation. One important finding of this work is that grid refinement, and fracture pseudo width, greatly impact huff-n-puff results. The combination of coarse gridding and improper fracture representation through the pseudo width approach can lead to falsely optimistic incremental recovery associated with huff-n-puff relative to primary recovery. While the findings presented herein are useful in explaining possible causes of the discrepancies in results reported in previous work, they can also be used to improve huff-n-puff design. For example, the combination of fine fracture spacing in multi-fractured horizontal wells and increased fracture complexity can positively influence incremental recovery obtained from huff-n-puff. Further, the results suggest that huff-n-puff timing (with respect to primary production operations) should be carefully considered. This study will help simulation engineers improve their evaluations of huff-n-puff in tight/shales reservoirs. Additionally, it will help operators decide which reservoir is suitable for huff-n-puff operations to improve liquids recovery. Application of the findings of this study to actual field scenarios will be presented as a separate work.

Huff-n-Puff Technology for Enhanced Oil Recovery in Shale/Tight Oil Reservoirs: Progress, Gaps, and Perspectives

“…Lately, a constant CO 2 diffusion coefficient has been substituted into the model through the data of laboratory experiments. 95 However, other researchers 96 claim insistently that the CO 2 diffusion coefficient is a variable in the gas H-n-P procedure of tight formations. They mentioned that the mechanism can be affected by several factors or conditions, such as pressure, temperature, pore throat, composition, and the behavior of the phase changes in nanopores.…”

“…To tackle the issue, Hoteit proposed a new model with the assumption of a chemical equilibrium at the gas/oil interface, yet the model was not checked by the laboratory investigation procedure. Lately, a constant CO 2 diffusion coefficient has been substituted into the model through the data of laboratory experiments . However, other researchers claim insistently that the CO 2 diffusion coefficient is a variable in the gas H-n-P procedure of tight formations.…”

Experimental and computational evaluation of cyclic solvent injection in fractured tight hydrocarbon reservoirs

“…A summary of the theory behind the HNP process in tight hydrocarbon systems is provided in Supplementary Appendix S1 online. There are now numerous studies of improved oil recovery in a variety of North American tight oil reservoirs that have examined the feasibility of incremental oil recovery using gas injection [1][2][3][4][5][6] . These studies have primarily focused on numerical 2,3,6 or laboratory-based approaches 1,[7][8][9] .…”

“…There are now numerous studies of improved oil recovery in a variety of North American tight oil reservoirs that have examined the feasibility of incremental oil recovery using gas injection [1][2][3][4][5][6] . These studies have primarily focused on numerical 2,3,6 or laboratory-based approaches 1,[7][8][9] . Laboratory-based studies are important for assessing (1) the key mechanisms controlling injected gas transport into the reservoir, and miscibility with the oil 7,8,10 and (2) the influence of operational parameters including injection pressure/time, soaking time, production pressure/time-among other factors (e.g.…”

CO2 Mass Transfer and Oil Replacement Capacity in Fractured Shale Oil Reservoirs: From Laboratory to Field

“…Although the diffusion phenomenon in the laboratory is widely studied, there are few studies on the role of CO 2 diffusion in field-scale simulation. The phenomenon that the distance of CO 2 penetrating the matrix from fractures is usually several meters cannot be captured with the grids of several meters to tens of meters used in field-scale simulation (Alharthy et al, 2015;Ribeiro et al, 2015;Kanfar and Clarkson, 2017;Zuloaga et al, 2017;Zhang et al, 2019). Moreover, the dua-porosity model applied generally to simulate fractured reservoirs uses two independent sets of grids to simulate fractures and matrix respectively, which results that transient mass transfer process cannot be identified in the matrix adjacent to the fractures (Hoteit, 2011;Ghasemi and Suicmez, 2019).…”