Co-Current And Counter-Current Imbibition Analysis For Tight Fractured Carbonate Gas Reservoirs

Kantzas, Apostolos; Pow, M.; Allsopp, K.; Marentette, D.F.

doi:10.2118/97-181

Cited by 35 publications

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“…In petroleum reservoir exploitation, fractured oil and gas reservoirs are primary targets, as they hold a considerable amount of the remaining petroleum resources of this world [3][4][5][6][7], but pose significant challenges to achieving efficient recovery due mainly to their stress-sensitive nature [8][9][10].…”

Section: Introductionmentioning

confidence: 99%

Research on Stress Sensitivity of Fractured Carbonate Reservoirs Based on CT Technology

et al. 2017

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Fracture aperture change under stress has long been considered as one of primary causes of stress sensitivity of fractured gas reservoirs. However, little is known about the evolution of the morphology of fracture apertures on flow property in loading and unloading cycles. This paper reports a stress sensitivity experiment on carbonate core plugs in which Computed Tomography (CT) technology is applied to visualize and quantitatively evaluate morphological changes to the fracture aperture with respect to confining pressure. Fracture models were obtained at selected confining pressures on which pore-scale flow simulations were performed to estimate the equivalent absolute permeability. The results showed that with the increase of confining pressure from 0 to 0.6 MPa, the fracture aperture and equivalent permeability decreased at a greater gradient than their counterparts after 0.6 MPa. This meant that the rock sample is more stress-sensitive at low effective stress than at high effective stress. On the loading path, an exponential fitting was found to fit well between the effective confining pressure and the calculated permeability. On the unloading path, the relationship is found partially reversible, which can evidently be attributed to plastic deformation of the fracture as observed in CT images.

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Section: Introductionmentioning

confidence: 99%

Research on Stress Sensitivity of Fractured Carbonate Reservoirs Based on CT Technology

et al. 2017

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“…1978, Cuiec et al 1994, Akin et al 2000, and Kantzas et al 1997, while very limited studies had focused on shale reservoirs. In order to understand water imbibition performance in shale formations, this paper studies the effect of different water formulations on Barnett shale imbibition.…”

Section: Introductionmentioning

confidence: 99%

Imbibition Characteristics of the Barnett Shale Formation

Morsy¹,

Sheng²

2014

SPE Unconventional Resources Conference

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In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition has been performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was improved using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4) were examined to recover oil from shale rocks. Outcrop samples from the Barnett shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 7%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Barnett samples in distilled water, 2 wt% KCl, low pH solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4). During the spontaneous imbibition, the maximum oil recovery was 24% using distilled water and low pH solution of pH0.74 (3 wt% HCl in 2 wt% KCl base brine solution). Clay swelling can contribute to the Barnett oil recovery improvement by creating along bedding cracks. Oil recoveries from the Barnett shale can be improved by 56% when used 2 wt% NaOH solution and 88% when used 3 wt% HCl when added to 2 wt% KCl simulation base fluid. High pH solutions did not improve oil recoveries from the Barnett samples when added to distilled water due to pore plugging resulted from the combination of clay swelling with mineral dissolution. Low pH solutions showed along bedding cracks similar to distilled water effect on the Barnett shale samples that helped recovery accelerations, while higher pH solutions showed sever samples damage with higher alkaline concentrations (2 wt% NaOH).

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“…1978, Cuiec et al 1994, Akin et al 2000, and Kantzas et al 1997, while very limited studies had focused on shale reservoirs. In order to understand and improve waterflooding performance in shale formations, this paper presents an experimental study to understand the effect of using different water formulations to improve water imbibition in Eagle Ford shale samples.…”

Section: Introductionmentioning

confidence: 99%

Improvement of Eagle Ford Shale Formation's Water Imbibition by Mineral Dissolution and Wettability Alteration

Morsy

Gomaa

Sheng

2014

SPE Unconventional Resources Conference

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In order to understand the performance of waterflooding in nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition has been performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was improved using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4) were examined to recover oil from shale rocks. Reservoir core samples from Eagle Ford shale were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the porosity of the used samples using CT Scanning. The average porosity was 1.6% for Eagle Ford shale samples. Secondly, we studied the rock stability and spontaneous imbibtion of the different Eagle Ford samples in distilled water, 2 wt% KCl, low pH solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4). During the spontaneous imbibition, the maximum oil recovery was 37% for Eagle Ford using pH 0.74 (3 wt% HCl in 2 wt% KCl) and 44% using pH 11.7 (0.1 wt% NaOH in distilled water). The oil recovery was improved by mineral dissolution using low and high pH solutions along with wettability alteration. The rock hardness was significantly affected by using both high and low pH solutions, which resulted in 93-98% loss of its initial value. IntroductionIn shale reservoirs, oil is stored in a very tight matrix, with virtually all permeability concentrated in a large number of natural fractures (Fakcharoenphol et al. 2012). Due to these fractures, oil cannot be displaced from the matrix by means of conventional waterflooding. Channeling and bypassing through the fractures would result in extremely poor recovery (Guo et al. 1998). Primary oil production from such fractured reservoirs in which the storage occurs in the matrix and flow happens in fractures can be divided into three stages: 1) production from the fracture network at early time; 2) production from the fracture network and rock matrix at intermediate time; and 3) production from the rock matrix at a later time (Guo et al. 1998). Early production from the fracture network of shale formation declines rapidly because of a variety of reasons: increasing effective stress, proppant fatigue due to stress cycling, and digenesis. Most of the recovery of the intermediate and long-term stages of production depends on spontaneous imbibition of brine into the rock matrix and expulsion of oil via the fracture face. Spontaneous imbibition can add significant amount of oil recovery in fractured reservoirs with low matrix permeability depending on rock wetness quality. The rate of imbibition is mainly affected by the net effect of capillary pressure driving force and the opposing viscous resistance to flow. Because of the strong capillary forces, the small...

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Co-Current And Counter-Current Imbibition Analysis For Tight Fractured Carbonate Gas Reservoirs

Cited by 35 publications

References 0 publications

Research on Stress Sensitivity of Fractured Carbonate Reservoirs Based on CT Technology

Research on Stress Sensitivity of Fractured Carbonate Reservoirs Based on CT Technology

Imbibition Characteristics of the Barnett Shale Formation

Improvement of Eagle Ford Shale Formation's Water Imbibition by Mineral Dissolution and Wettability Alteration

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