CO2 Stripping of Kerogen Condensates in Source Rocks

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1415-1434 ◽  
Author(s):  
Seunghwan Baek ◽  
I.. Yucel Akkutlu
Keyword(s):  
Phase Equilibrium ◽  
Capillary Condensation ◽  
Source Rocks ◽  
Co2 Injection ◽  
Compositional Variation ◽  
Hydrocarbon Mixtures ◽  
Bulk Fluid ◽  
Hydrocarbon Recovery ◽  
Pressure Depletion ◽  
The Impact

Summary Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO2 injection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N2 injection were also recorded for comparison.

Enhanced Recovery of Nanoconfined Oil in Tight Rocks Using Lean Gas (C2H6 and CO2) Injection

SPE Journal ◽  
2021 ◽  
pp. 1-20
Author(s):  
Seunghwan Baek ◽  
I. Yucel Akkutlu
Keyword(s):  
Free Energy ◽  
Oil Recovery ◽  
Enhanced Recovery ◽  
Source Rocks ◽  
Superior Performance ◽  
Co2 Injection ◽  
Molecular Configuration ◽  
Pressure Depletion ◽  
Reservoir Conditions ◽  
Recovery Mechanisms

Summary Organic matters in source rocks store oil in significantly larger volume than that based on its pore volume (PV) due to so-called nanoconfinement effects. With pressure depletion and production, however, oil recovery is characteristically low because of the low compressibility of the fluid and amplified interaction with pore surface in the nanoporous material. For the additional recovery, CO2 injection has been widely adopted in shale gas and tight oil recovery over the last decades. But its supply and corrosion are often pointed out as drawbacks. In this study, we propose ethane injection as an alternative enhanced oil recovery (EOR) strategy for more productive oil production from tight unconventional reservoirs. Monte Carlo (MC) molecular simulation is used to reconstruct molecular configuration in pores under reservoir conditions. Further, molecular dynamics (MD) simulation provides the basis for understanding the recovery mechanism of in-situ fluids. These enable us to estimate thermodynamic recovery and the free energy associated with dissolution of injected gas. Primary oil recovery is typically below 15%, indicating that pressure depletion and fluid expansion are no longer effective recovery mechanisms. Ethane injection shows 5 to 20% higher recovery enhancement than CO2 injection. The superior performance is more pronounced, especially in nanopores, because oil in the smaller pores is richer in heavy components compared to the bulk fluids, and ethane molecules are more effective in displacing the heavy hydrocarbons. Analysis of the dissolution free energy confirms that introducing ethane into reservoirs is more favored and requires less energy for the enhanced recovery.

scholarly journals Paleoenvironment of the Lower–Middle Cambrian Evaporite Series in the Tarim Basin and Its Impact on the Organic Matter Enrichment of Shallow Water Source Rocks

Minerals ◽  
2021 ◽  
Vol 11 (7) ◽  
pp. 659
Author(s):  
Mingyang Wei ◽  
Zhidong Bao ◽  
Axel Munnecke ◽  
Wei Liu ◽  
G. William M. Harrison ◽  
...  
Keyword(s):  
Organic Matter ◽  
Shallow Water ◽  
Tarim Basin ◽  
Water Environment ◽  
Water Source ◽  
Major Elements ◽  
Source Rocks ◽  
Middle Cambrian ◽  
Sedimentary Environments ◽  
The Impact

Just as in deep-water sedimentary environments, productive source rocks can be developed in an evaporitic platform, where claystones are interbedded with evaporites and carbonates. However, the impact of the paleoenvironment on the organic matter enrichment of shallow water source rocks in an evaporite series has not been well explored. In this study, two wells in the central uplift of the Tarim Basin were systematically sampled and analyzed for a basic geochemical study, including major elements, trace elements, and total organic carbon (TOC), to understand the relationship between TOC and the paleoenvironmental parameters, such as paleosalinity, redox, paleoclimate, paleo-seawater depth, and paleoproductivity. The results show that the Lower–Middle Cambrian mainly developed in a fluctuating salinity, weak anoxic to anoxic, continuous dry and hot, and proper shallow water environment. The interfingering section of evaporites, carbonates, and claystones of the Awatag Fm. have higher paleoproductivity and higher enrichment of organic matter. Paleosalinity, redox, paleoclimate, paleo-seawater depth, and paleoproductivity jointly control the organic matter enrichment of shallow water source rocks in the evaporite series. The degree of enrichment of organic matter in shallow water source rocks first increases and then decreases with the increase in paleosalinity. All the samples with high content of organic matter come from the shallower environment of the Awatag Fm.

How Digital Transformation Improves Perceptions of Oil and Gas Industry

2020 ◽  
Vol 72 (12) ◽  
pp. 33-33
Author(s):  
Chris Carpenter
Keyword(s):  
Digital Technology ◽  
Public Perception ◽  
Business Models ◽  
Oil And Gas ◽  
Digital Technologies ◽  
Oil And Gas Industry ◽  
Production Optimization ◽  
Petroleum Engineering ◽  
Co2 Injection ◽  
The Impact

The final afternoon of the 2020 ATCE saw a wide-ranging virtual special session that covered an important but often overlooked facet of the unfolding digitalization revolution. While the rising wave of digital technology usually has been associated with production optimization and cost savings, panelists emphasized that it can also positively influence the global perception of the industry and enhance the lives of its employees. Chaired by Weatherford’s Dimitrios Pirovolou and moderated by John Clegg, J.M. Clegg Ltd., the session, “The Impact of Digital Technologies on Upstream Operations To Improve Stakeholder Perception, Business Models, and Work-Life Balance,” highlighted expertise taken from professionals across the industry. Panelists included petroleum engineering professor Linda Battalora and graduate research assistant Kirt McKenna, both from the Colorado School of Mines; former SPE President Darcy Spady of Carbon Connect International; and Dirk McDermott of Altira Group, an industry-centered venture-capital company. Battalora described the complex ways in which digital technology and the goal of sustainability might interact, highlighting recent SPE and other industry initiatives such as the GAIA Sustainability Program and reviewing the United Nations Sustainable Development Goals (SDGs). McKenna, representing the perspective of the Millennial generation, described the importance of “agile development,” in which the industry uses new techniques not only to improve production but also to manage its employees in a way that heightens engagement while reducing greenhouse-gas emissions. Addressing the fact that greater commitment will be required to remove the “tougher two-thirds” of the world’s hydrocarbons that remain unexploited, Spady explained that digital sophistication will allow heightened productivity for professionals without a sacrifice in quality of life. Finally, McDermott stressed the importance of acknowledging that the industry often has not rewarded shareholders adequately, but pointed to growing digital components of oil and gas portfolios as an encouraging sign. After the initial presentations, Clegg moderated a discussion of questions sourced from the virtual audience. While the questions spanned a range of concerns, three central themes included the pursuit of sustainability, with an emphasis on carbon capture; the shape that future work environments might take; and how digital technologies power industry innovation and thus affect public perception. In addressing the first of these, Battalora identified major projects involving society-wide stakeholder involvement in pursuit of a regenerative “circular economy” model, such as Scotland’s Zero Waste Plan, while McKenna cited the positives of CO2-injection approaches, which he said would involve “partnering with the world” to achieve both economic and sustainability goals. While recognizing the importance of the UN SDGs in providing a global template for sustainability, McDermott said that the industry must address the fact that many investors fear rigid guidelines, which to them can represent limitations for growth or worse.

Experimental Investigation of Asphaltene-Induced Formation Damage Caused by Pressure Depletion of Live Reservoir Fluids in Porous Media

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 01-20 ◽  
Author(s):  
Omid Mohammadzadeh ◽  
Shawn David Taylor ◽  
Dmitry Eskin ◽  
John Ratulowski
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Flow Rate ◽  
Formation Damage ◽  
Bulk Fluid ◽  
Asphaltene Content ◽  
Pressure Depletion ◽  
Asphaltene Deposition ◽  
Permeability Impairment ◽  
Live Oil

Summary One of the complex processes of permeability impairment in porous media, especially in the near-wellbore region, is asphaltene-induced formation damage. During production, asphaltene particles precipitate out of the bulk fluid phase because of pressure drop, which might result in permeability reduction caused by both deposition of asphaltene nanoparticles on porous-medium surfaces and clogging of pore throats by larger asphaltene agglomerates. Experimental data will be used to identify the parameters of an impairment model being developed. As part of a larger effort to identify key mechanisms of asphaltene deposition in porous media and develop a model for asphaltene impairment by pressure depletion, this paper focuses on a systematic design and execution of an experimental study of asphaltene-related permeability damage caused by live-oil depressurization along the length of a flow system. An experiment was performed using a custom-designed 60-ft slimtube-coil assembly packed with silica sands to a permeability of 55 md. The customized design included a number of pressure gauges at regular intervals along the coil length, which enabled real-time measurement of the fluid-pressure profile across the full length of the slimtube coil. The test was performed on a well-characterized recombined live oil from the Gulf of Mexico (GOM) that is a known problematic asphaltenic oil. Under a constant differential pressure, the injection flow rate of the live oil through the slimtube coil decreased over time as the porous medium became impaired. During the impairment stage, samples of the produced oil were collected on a regular basis for asphaltene-content measurement. After more than 1 month, the impairment test was terminated; the live oil was purged from the slimtube coil with helium at a pressure above the asphaltene-onset pressure (AOP); and the entire system was gently depressurized to bring the coil to atmospheric conditions while preserving the asphaltene-damaged zones of the coil. The permeability and porosity of the porous medium changed because of asphaltene impairment that was triggered by pressure depletion. Results indicated that the coil permeability was impaired by approximately 32% because of pressure depletion below the AOP, with most of the damage occurring in the latter section of the tube, which operated entirely below the AOP. Post-analytical studies indicated lower asphaltene content of the produced-oil samples compared with the injecting fluid. The distribution of asphaltene deposits along the length of the coil was determined by cutting the slimtube coil into 2- to 3-ft-long sections and using solvent extraction to collect the asphaltenes in each section. The extraction results confirmed that the observed permeability impairment was indeed caused by asphaltene deposition in the middle and latter sections of the coil, where the pressure was less than the AOP. With the success of this experiment, the same detailed analysis can be extended to a series of experiments to determine the effects of different key parameters on pressure-induced asphaltene impairment, including flow rate, wettability, and permeability.

scholarly journals GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

Pore-scale study of effects of surface roughness on the transport of interfacial reactive tracers during primary drainage process

2021 ◽  
Author(s):  
Huhao Gao ◽  
Alexandru Tatomir ◽  
Nikolaos Karadimitriou ◽  
Holger Steeb ◽  
Martin Sauter
Keyword(s):  
Surface Roughness ◽  
Porous Media ◽  
Reactive Transport ◽  
Capillary Condensation ◽  
Field Method ◽  
Phase Field Method ◽  
Pore Scale ◽  
Water Films ◽  
Mobile Mass ◽  
The Impact

&lt;p&gt;Porous media surface roughness strongly influences the transport of solutes during drainage, due to the formation of thick water films (capillary condensation) on the porous media surface. In the case of interfacial-reacted, water-based solutes, these water films increase both the production of the solute, due to the increased number of fluid-fluid interfaces, and the loss of the solute by the retention in the stagnant water films. The retention of the solute in flowing water is described by a mobile mass retention term. This study applies the pore-scale direct simulation with the phase-field method based continuous solute transport (PFM-CST) model on the kinetic interfacial sensitive (KIS) tracer reactive transport during primary drainage in a 2D slit with a wall with variable fractal geometries. The capillary-associated moving interface is found to be larger for rough surfaces than smoother ones. The results confirm that the impact of roughness regarding the film-associated interfacial area can be partly, or totally masked, in a drained slit. It is found that the mobile mass retention term is increased with larger volumes of capillary condensed water films. To conclude, it is also found that the surface roughness factor has a non-monotonic relationship with the overall production rate of solute mass in moving water.&lt;/p&gt;

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