An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford Shale Formation

Fan, Liping; Martin, Ronald B.; Thompson, John W.; Atwood, Keith; Robinson, John R.; Lindsay, Garrett

doi:10.2118/148751-ms

Cited by 39 publications

(11 citation statements)

References 7 publications

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“…The play contains a high liquid component. There are three zones; an oil zone, a condensate zone, and a dry gas zone (Fan et al 2011). The Mancos oil and gas shale deposited during the western Cretaceous Seaway provides the source for the major shale play in the Rockies.…”

Section: Shale Formations Related To This Studymentioning

confidence: 99%

Potential of Waterflooding in Shale Formations

2013

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Waterflooding is the cheapest and most profitable secondary recovery method that has been used for more than seventy years for conventional oil reservoirs. However, few studies have been done on its viability on unconventional tight formations especially shales. The objective of this study is to investigate the potential of water imbibition in different shale formations. In this study, fresh water, water with different salinities, and high pH alkaline solutions were examined to recover oil from different shale formations. Reservoir core samples from Eagle Ford and outcrop samples from Mancos, Barnett, and Marcellus shales 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. First, we studied the porosity of samples using helium porosimeter, weight difference, and CT Scanning. The average porosity was 3.4% for Mancos, 2% for Eagle Ford, 2.6% for Marcellus, and 7.7% for Barnett shale samples. Second, we studied the rock stability and spontaneous imbibtion of the different used samples in fresh water, different saline solutions (5-15 eq wt% of NaCl and KCl), and high pH alkaline solutions (0.1-2 wt% NaOH). During the spontaneous imbibition, the maximum oil recovery was 59% for Mancos using fresh water, 44% for Eagle Ford using 2 wt% NaOH and fresh water, 24% for Barnett using fresh water, and 4% for Marcellus using 2 wt% NaOH and 2 eq wt% of KCl. The Mancos shale samples were very sensitive to low water salinity (0-15 eq wt %) compared with the other shales. The higher oil recoveries of Mancos samples were positively correlated with clay swelling in fresh water and low saline solutions. Eagle Ford recovered more oil when exposed to NaOH solutions due to favorable mineral dissolution without affecting the cores' stability. On the other hand, Barnett was partially damaged when exposed to higher alkaline solutions (2 wt% NaOH) and Marcellus was very tight to allow any fluid imbibition. Collectively, our study showed a great potential of waterflooding in unconventional shale reservoirs.

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Section: Shale Formations Related To This Studymentioning

confidence: 99%

Potential of Waterflooding in Shale Formations

2013

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“…However, the production forecasts were only compared with production of a couple of individual wells rather than with the production of all the wells, so the results cannot be used to evaluate field-level reserves. Fan et al (2011) performed an extensive production data analysis that covers the oil, condensate, and gas windows. However, their production analysis only includes performance indicators, such as best month or best 3 consecutive months, and does not include long-term forecasts.…”

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confidence: 99%

Assessment of Eagle Ford Shale Oil and Gas Resources

et al. 2013

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The Eagle Ford play in south Texas is currently one of the hottest plays in the United States. In 2012, the average Eagle Ford rig count (269 rigs) was 15% of the total US rig count. Assessment of Eagle Ford oil and gas resources and their associated uncertainties in the early stages is critical for optimal development. The objective of our research was to assess Eagle Ford shale oil and gas reserves, contingent resources, and prospective resources.Probabilistic decline curves using Markov Chain Monte Carlo (MCMC) were used to forecast reserves and resources. The Eagle Ford play from the Sligo Shelf Margin to the San Marcos Arch was divided into 8 different production regions based on geology, fluid type, and well performance. We used the Duong model switching to the Arps model with b = 0.3 at the minimum decline rate to model the linear flow to boundary-dominated flow behavior often observed in shale plays. Cumulative production after 20 years predicted from Monte Carlo simulation combined with reservoir simulation was used as prior information in the Bayesian decline-curve methodology. Probabilistic type decline curves for oil and gas were then generated for all production regions. Individual-well reserves and resources estimates were aggregated probabilistically within each production region and arithmetically between production regions.The total oil reserves and resources range from a P 90 of 5.3 to P 10 of 28.7 billion barrels of oil (BBO), with a P 50 of 11.7 BBO; the total gas reserves and resources range from a P 90 of 53.4 to P 10 of 313.5 trillion cubic feet (TCF), with a P 50 of 121.7 TCF. These reserves and resources estimates are much higher than the U.S. Energy Information Administration's 2011 recoverable resource estimates of 3.35 BBO and 21 TCF. The results of this study provide a critical update of the reserves and resources estimates and their associated uncertainties for the Eagle Ford shale formation of South Texas.

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“…The play contains a high liquid component. There are three zones; an oil zone, a condensate zone, and a dry gas zone (Fan et al 2011). Thickness in the productive area ranges from 40ft to over 450ft.…”

Section: Eagle Ford Shale Formationmentioning

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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An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford Shale Formation

Cited by 39 publications

References 7 publications

Potential of Waterflooding in Shale Formations

Potential of Waterflooding in Shale Formations

Assessment of Eagle Ford Shale Oil and Gas Resources

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

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