Physicochemical Interactions of Source Rocks with Injected Water-Based Fluids

Abdulsattar, Zaid R.; Agim, K..; Lane, Robert H.; Hasçakir, Berna

doi:10.2118/173727-ms

Cited by 9 publications

(4 citation statements)

References 61 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…According to Figure , the Marcellus and Collingwood samples have similar, but relatively lower, estimated Ba(II) maximum uptake values compared to the Utica and Antrim. The estimated CEC of Marcellus (2 meq/100g-shale, Table S4) from Figure is nearly 1 order of magnitude lower than the value calculated on the basis of clay content (11.4 meq/100g, Table S4), but it is still within the CEC range from a previous study. , The Ba CEC values for the Antrim, Utica, and Collingwood are close to the estimates based on clay mineral content (Table S4). The relatively small differences in the shale CEC cannot account for the several orders of magnitude Ra activity variation measured in produced water from the Antrim and Marcellus shale formations.…”

Section: Results and Discussionsupporting

confidence: 73%

Estimating Radium Activity in Shale Gas Produced Brine

Fan

Hayes

Ellis

2018

Environ. Sci. Technol.

View full text Add to dashboard Cite

Shale gas reservoir-produced brines may contain elevated levels of naturally occurring radioactive material, including Ra-226 and Ra-228, which come from the decay of U-238 and Th-232 in shale. While the total Ra activity in shale gas wastewaters can vary by over 3 orders of magnitude, the parent radionuclides tend to only vary by 1 order of magnitude. The extent of Ra mobilization from the shale into produced brines is thought to be largely controlled by adsorption/desorption from the shale, which is influenced by shale cation exchange capacity (CEC) and reservoir brine salinity, often reported as the total dissolved solids (TDS). To determine how these factors lead to such large variation in Ra activity of produced brines, the U content and CEC of shale samples from the Antrim and Utica-Collingwood shales in Michigan and the Marcellus shale in Pennsylvania were evaluated. Analysis of produced brine from 17 Antrim shale gas wells was then used to develop an empirical relationship between Ra-226 activity and produced water TDS for a given U content of the shale. This correlation will provide an a priori estimate of the expected Ra activity of a produced brine from a given shale gas play when the brine salinity and U content of the shale are known. Such information can serve as a guide for optimal wastewater treatment and disposal strategies prior to any drilling activity, thereby reducing risks associated with elevated Ra activity in shale gas wastewaters.

show abstract

Section: Results and Discussionsupporting

confidence: 73%

Estimating Radium Activity in Shale Gas Produced Brine

Fan

Hayes

Ellis

2018

Environ. Sci. Technol.

View full text Add to dashboard Cite

show abstract

“…The greatest TDS value is detected after Eagle Ford shale-water interaction and the lowest after Barnett shale-water interaction. TDS, pH, zeta potential, and particle size measurements are important to determine the treatment and/or handling recipes of the produced water after interacting with rock for any fracturing job [16]. The lower the value for particle size, the settlement of the total solids will be more difficult due to having lower settling velocity.…”

Section: Figure 5-relationship Between Calcium and Magnesium Ions Of mentioning

confidence: 99%

“…The temperature ranges for dehydroxyliation, dehydration, and decomposition reactions of common minerals and organic materials found in shales are compiled from the literature and summarized in Table 2. The cation exchange capacity (CEC) of minerals also plays an important role on rock-fluid interaction [16]. The CEC indicates the ability of the rock to retain cations; the larger the value of CEC, the more cations the rock can hold [17].…”

Section: Introductionmentioning

confidence: 99%

Water-Rock Interaction for Eagle Ford, Marcellus, Green River, and Barnett Shale Samples

Ali

Hasçakir

2015

SPE Eastern Regional Meeting

View full text Add to dashboard Cite

Knowledge of water-rock interactions on the surface of fractures is important to develop an understanding of the geological structures and changes within the formation, to determine the water pollutants in produced water during hydraulic fracturing, and to manage effectively the produced waters. To obtain this knowledge, the water-shale interaction is investigated on carbonate-rich (Eagle Ford), organic-rich (Green River), clay-rich (Barnett), and other minerals rich (Marcellus) shale samples.Crushed shale samples were exposed to water for three weeks at reservoir conditions. The water and rock samples before and after each static experiment subjected to several analyses. The change in the rock mineralogy was defined with XRD, the elemental composition of rock was determined with XPS and SEM-EDS. The water was analyzed for its anions and cations, total dissolved solids (TDS), conductivity, pH, total organic carbon (TOC), and average particle sizes of colloids. The stability of the colloids are characterized with Zeta potential.It has been observed that Barnett rock is high in illite content, the greatest calcite concentration is determined for Eagle Ford rock. The sulfate source of water correlates with the atomic percent of the sulfur and oxygen elements determined through XPS analyses. The magnesium content of water correlates mainly with illite amount in the rock and calcium concentration associates with the calcite and gypsum content of the rock samples. The greatest dissolution rate belongs to the minerals which yields sulfate in the water, then, gypsum and calcite which yield calcium cation in the water come second, and the lowest dissolution rates obtained from the magnesium containing minerals mainly dolomite. TDS of the water samples shows that Green River has the least tendency to interact with water and Barnett has the greatest tendency. Zeta potential values indicate that the particles in the water interacted with Eagle Ford have the highest tendency for precipitation, since it has the lowest zeta potential value.This study provides correlations on water-rock interaction for four different shale samples. These correlations can be used to understand the water-rock interactions for different rocks by conducting simple XRD and XPS measurements only on rock samples.

show abstract

“…Their results imply that the potential determined ions (PDIs), typically the bivalent ions, are able to adsorb on the mineral surface through surface complexation and ion exchange, which likely affects the in situ fluid salinity. Teppen and Miller, 52 Ali and Hascakir, 53 and Abdulsattar et al 54 pointed out that, for the shales containing a certain amount of clays with a high value of cation-exchange capacity (CEC), such as smectite and zeolite, cations can be held on the negatively charged surfaces of the rock, thereby affecting the flowback water chemistry.…”

Section: Introductionmentioning

confidence: 99%

Effect of the Fluid–Shale Interaction on Salinity: Implications for High-Salinity Flowback Water during Hydraulic Fracturing in Shales

Zeng

Reid

et al. 2020

Energy Fuels

View full text Add to dashboard Cite

Hydraulic fracturing has been widely implemented to enhance hydrocarbon production from shale reservoirs. However, one of the main challenges during hydraulic fracturing is to understand what factor(s) trigger high salinity of flowback water, which sometimes can be up to 300 000 mg/L. While several mechanisms have been proposed to explain the controlling factor behind the high salinity of flowback water, there has been little discussion about the effect of fluid–shale interactions (e.g., mineral dissolution and surface complexation) on the high salinity and far less attention has been paid to quantify the contribution of fluid–shale interactions. We thus conducted spontaneous imbibition experiments using deionized water and outcrops from Marcellus, Barnett, and Eagle Ford shale plays with minor precipitated salts. We also monitored the pH, electrical conductivity, and ion concentrations (Cl–, K+, Ca2+, NO3 –, F–, Br–, and NH+) of the surrounding water during the spontaneous imbibition process in 4 consecutive weeks. To quantify the impact of fluid–shale interactions on salinity, we performed geochemical modeling to examine the contribution of mineral dissolution (calcite, albite, quartz, chalcopyrite, pyrite, and dolomite) and surface complexation on fluid salinity. Spontaneous imbibition tests show that Barnett shale plugs imbibed more water than Marcellus and Eagle Ford largely as a result of the highest content of calcite and lowest content of organic carbon. The order of sequence of pH is Eagle Ford (8.3) > Barnett (8.0) > Marcellus (7.6), in line with prediction of geochemical modeling, confirming that pyrite oxidation plays a significant role in local pH and, thereby, brine composition at ambient conditions. Geochemical modeling also shows that salinity increment induced by fluid–shale interactions is less than 3% of flowback water salinity, suggesting a minor impact of fluid–shale interactions on the salinity increase. These findings point out that fluid–fluid and fluid–salt interactions likely play a more important role in high salinity of flowback water during hydraulic fracturing in shales.

show abstract

Physicochemical Interactions of Source Rocks with Injected Water-Based Fluids

Cited by 9 publications

References 61 publications

Estimating Radium Activity in Shale Gas Produced Brine

Estimating Radium Activity in Shale Gas Produced Brine

Water-Rock Interaction for Eagle Ford, Marcellus, Green River, and Barnett Shale Samples

Effect of the Fluid–Shale Interaction on Salinity: Implications for High-Salinity Flowback Water during Hydraulic Fracturing in Shales

Contact Info

Product

Resources

About