Oil Formation Research Articles

Contribution of the Lower-Middle Jurassic source rocks in petroleum potential of the Jurassic-Cretaceous series within the central part of West Siberia

In this paper, based on a geochemical study of rock samples and fluids, it is proven that carbon-bearing deposits of the Lower and Middle Jurassic complex of Western Siberia on the southern outskirts of the Khanty-Mansiysk and Yamalo-Nenets Autonomous Okrug can generate liquid hydrocarbons. It has been established that the oil-generation potential of carbon-bearing deposits depends on the paleogeographic conditions of burial of the organic matter and the enrichment of rocks with macerals of the liptinite group. The complex of studies included pyrolysis of coals, coal-rich shale of Lower and Middle Jurassic rocks, study of maceral composition and measurement of reflectivity indicators, hydrocarbon and isotopic composition of extracts from rocks, as well as study of the composition of oils from the studied area, selected both within the Jurassic and Cretaceous complexes. The studied area is located in the Frolov megadepression and the South Nadym megamonoclise. The result of the research was the identification of significant geochemical characteristics of an additional source of hydrocarbons – coals, coal-rich shale of the Lower and Middle Jurassic, which had not previously been proven on the studied area, the contribution of which to the formation of oil and gas potential was confirmed by the correlation of hydrocarbon and isotopic characteristics of fluids and extracts from source rocks. Сluster and the principal component analysis were used for genetic correlation of extracts and oils. The conclusions obtained from geochemical studies suggest the possible prospects of Lower and Middle Jurassic deposits from the point of view of detecting hydrocarbon accumulations.

Research on the relationship between hydrocarbon source-reservoir assemblage system and lacustrine level changes in Triassic period of Lunnan area

The lacustrine level changes affects the sedimentary process of the basin, and has an important influence on the hydrocarbon source-Reservoir assemblage system. In this study, the method of wavelet transform and Fisher plot were used to identify 58 high-frequency cycles on drilling well, with an average cycle thickness of 8.21 m. On this basis, the cumulative offset value was calculated, and finally the lacustrine level changes curve was established during the Triassic period in Lunnan area. The results show that there were three obvious lacustrine level fluctuation cycles in the Triassic period in this area. In the descending stage of lacustrine level, the grain size of the sediments in the study area is large, mainly medium-fine sandstone. In the ascending stage of Lacustrine level, the sediment granularity is small, mainly fine-siltstone and mudstone deposits. Under the control of lacustrine level changes, three sets of “binary structure” lithologic assemblage were deposited in the study area, with large grain size lower and small grain size upper. It is found that the sandstone in the lower part of the “binary structure” has good porosity and permeability. The average porosity of the TⅢ oil formation of Karamay Formation is 15.80 %, and the maximum permeability is 3.785 μm2, which can be used as a good reservoir. The TOC content of the upper part of the “binary structure” is very high, and the average TOC is 3.8 % in Huangshanjie Formation, which is a very good source rock. Therefore, lacustrine level changes in this area has a very important control effect on the on the hydrocarbon source rock and reservoir.

Geochemical prerequisites for the formation of oil and gas accumulation zones in the South Turgay basin, Kazakhstan

This study predicts favorable oil and gas source-rock formation conditions in the Aryskum Depression of the South Turgay Basin, Kazakhstan. This study assesses the thermal maturity and characteristics of organic matter by determining its environmental conditions using data from geochemical analysis of core (pyrolysis) and oil (biomarkers and carbon isotopic compositions) samples. According to the geochemical parameters obtained by pyrolysis, the oil generation potential of the original rocks of most studied samples varies from poor to rich. The facies–genetic organic matter is predominantly humic and less frequently humus–sapropel, indicating organic matter accumulation in the studied samples were under moderately reducing conditions (kerogen III and II types) and coastal–marine environments (kerogen type I). The carbon isotopic compositions of oils derived from the Jurassic deposits of the Aryskum Depression also indicate the sapropelic and mixed humic–sapropelic type of organic matter (kerogen II and I). Biomarker analysis of oils indicates original organic matter formation in an anoxic environment.

Thermal maturity of organic matter and type of kerogen of Mesozoic sediments, Aryskum depression

This work is devoted to the study of the oil and gas source potential of the Mesozoic deposits of the Aryskum depression of the South Turgay oil and gas basin and aims to study the features of the geological structure, determine the facial-genetic type and degree of maturity of organic matter. Geochemical methods play an important role in assessing oil and gas source potential, one of which is pyrolytic core analysis to determine the type of organic matter and thermal maturity of the studied rock material samples. To achieve this goal, the results of pyrolytic analysis of stone material from Neocomian and Jurassic deposits were used. Analysis of geological and geophysical materials made it possible to trace the pattern of distribution over the area of oil and gas-bearing sandy layers and the underlying clay layers with high insulating properties in the Aryskum horizon. The results obtained show that the total organic carbon content ranges from 0.47 to 1.41 wt%. To establish the type of kerogen and its position relative to the zones of oil and gas formation, the Van Krevelen diagram was used in the coordinates of atomic ratios of the elemental composition of kerogen and its modification for pyrolytic data, indicating that the kerogen of the studied samples is a mixture of types I, II and III, facies-genetic the type of organic matter of which belongs to humic, humic-sapropelic, and the sedimentation conditions are coastal-marine environment in moderately reducing conditions.

On modern oil and gas formation

According to the organic theory of oil and gas origin, hydrocarbon potential of their deposits is limited. Therefore, during the exploitation of deposits, this potential must decrease. The discovery of the phenomenon of oil and gas reserves replenishment in developed fields, as well as the experimentally proven possibility of transferring these fields to “inexhaustible” hydrocarbon production mode, poses a number of new tasks for developers. The main one is controlling the hydrocarbon potential of oil and gas deposits and maintaining it at highest possible level. In the article we draw attention to a number of fundamental achievements of domestic scientists, which made it possible to create a biosphere concept of oil and gas formation, on its basis to adequately solve the problem of the origin of oil and gas, and also to explain the modern replenishment of hydrocarbon reserves in developed fields. From the standpoint of biosphere concept, a system of measures is considered that increases the efficiency of developing oil and gas fields in conditions of replenishment of hydrocarbon reserves.

Analysis and systematization of ideas about the influence of geological and geochemical factors on the formation and oil and gas content of megareservoirs of sedimentary basins

The influence of geological and geochemical factors on the properties of oils saturating combined traps in various oil and gas basins is analyzed. A way is developed for predicting the properties of fluids (physicochemical, hydrocarbon and trace element compositions), as well as the phase state of accumulations in traps of various structures in connection with the vertical scale of oil and gas formation. The evaluation of the search criteria for their identification, analysis and systematization of ideas about the influence of various geological and geochemical factors on the formation and oil and gas content of megareservoirs is carried out. Of great importance is the possibility of assessing the productivity of shale formations and the selection of “sweet spots” by geochemical methods.

Расчет гидродинамических показателей вязкопластичных нефтей в задачах термозаводнения

With the discovery of heavy oil deposits, great attention has been paid to the development of oil fields using thermal methods of influencing oil formations. Theoretical studies of reservoir hydrodynamics, as well as temperature fields in multilayer formations, were stimulated with the advent of modern computers and personal computers. Thanks to the mathematical description, hydrodynamic calculations of the displacement of viscoplastic oil by water with abnormal properties became possible. In the case of displacement of high-viscosity and paraffinic oils by cold water in multi-layer formations, paraffin deposition and blockage of weakly permeable formations occur, as a result of the advanced displacement of oil through layers with high permeability. The results of the conducted research show that the creation of a hot water delay at different stages of the development of deposits of high-viscosity paraffin oil improves the development rate, increases the oil recovery coefficient.

In-situ hydrocarbon formation and accumulation mechanisms of micro- and nano-scale pore-fracture in Gulong shale, Songliao Basin, NE China

By conducting experimental analyses, including thermal pyrolysis, micro-/nano-CT, argon-ion polishing field emission scanning electron microscopy (FE-SEM), confocal laser scanning microscopy (CLSM), and two-dimensional nuclear magnetic resonance (2D NMR), the Gulong shale oil in the Songliao Basin was investigated with respect to formation model, pore structure and accumulation mechanism. First, in the Gulong shale, there are a large number of pico-algae, nano-algae and dinoflagellates, which were formed in brackish water environment and constituted the hydrogen-rich oil source materials of shale. Second, most of the oil-generating materials of the Qingshankou Formation shale exist in the form of organo-clay complex. During organic matter thermal evolution, clay minerals had double effects of suppression and catalytic hydrogenation, which expanded shale oil window and increased light hydrocarbon yield. Third, the formation of storage space in the Gulong Shale was related to dissolution and hydrocarbon generation. With the diagenesis, micro-/nano-pores increased, pore diameter decreased and more bedding fractures appeared, which jointly gave rise to the unique reservoir with dual media (i.e. nano-scale pores and micro-scale bedding fractures) in the Gulong shale. Fourth, the micro-/nano-scale oil storage unit in the Gulong shale exhibits independent oil/gas occurrence phase, and shows that all-size pores contain oils, which occur in condensate state in micropores or in oil-gas two phase (or liquid) state in macropores/mesopores. The understanding about Gulong shale oil formation and accumulation mechanism has theoretical and practical significance for advancing continental shale oil exploration in China.

Salt Eruptions and Their Role in the Shaping of the Oil Trapping for Selected Fields in Eastern Iraq

This research had been achieved using 2D seismic sections to study the presence of subsurface salty bodies in the Khashim Al-Ahmer, Galabat, Injana fields as a case study. The selected oil fields is located to the northeast of Baquba city within Diyala Governorate. The study aims to determine the salt accumulations of the selected fields and their role in the formation of oil traps. The interpretation of seismic data was focused on two reflectors Fatha and Jeribe Formations which belong to the lower and Middle Miocene. Structurally, Two systems of reversal faults are affecting the fields, according to seismic sections, the first represents thrust faults affected on the top part of Fatha (Red Beds & Seepage) and the layers above with large displacements and trending in an NW-SE orientation; The separation surface of these faults is the salt bed in the Fatha Formation. the second represents reversal faults affected on the lower section of Fatha (Transition beds) and the layers beneath with high displacements. The research concludes Petroleum flow from the source was directed by the faults created by the broad Zagros tectonism to Miocene and younger traps, also seal fracturing exceeds vertical petroleum flow. The differences in fault types are caused by the presence of a salt bed within the Fatha Formation and the high variation in its thickness at the crest and flanks. So, the main recommendation of research is to implement a 3D seismic survey covering these fields to determine salt body areas.

Pyrolysis of Solid Recovered Fuel Using Fixed and Fluidized Bed Reactors

Currently, most plastic waste stems from packaging materials, with a large proportion of this waste either discarded by incineration or used to derive fuel. Accordingly, there is growing interest in the use of pyrolysis to chemically recycle non-recyclable (i.e., via mechanical means) plastic waste into petrochemical feedstock. This comparative study compared pyrolysis characteristics of two types of reactors, namely fixed and fluidized bed reactors. Kinetic analysis for pyrolysis of SRF was also performed. Based on the kinetic analysis of the pyrolytic reactions using differential and integral methods applied to the TGA results, it was seen that the activation energy was lower in the initial stage of pyrolysis. This trend can be mainly attributed to the initial decomposition of PP components, which was subsequently followed by the decomposition of PE. From the kinetic analysis, the activation energy corresponding to the rate of pyrolysis reaction conversion was obtained. In conclusion, pyrolysis carried out using the fluidized bed reactor resulted in a more active decomposition of SRF. The relatively superior performance of this reactor can be attributed to the increased mass and heat transfer effects caused by fluidizing gases, which result in greater gas yields. Regarding the characteristics of liquid products generated during pyrolysis, it was seen that the hydrogen content in the liquid products obtained from the fluidized bed reactor decreased, leading to the formation of oils with higher molecular weights and higher C/H ratios, because the pyrolysis of SRF in the fluidized bed reactor progressed more rapidly than that in the fixed bed reactor.

Boosting concurrent yeast oil production and secretion by Rhodosporidium toruloides through non-ionic surfactant addition and gene expression monitoring

Yeast oil (YO) secretion derived from glycerol was facilitated by non-ionic surfactant-enhanced conditions, leading to extracellular yeast oil formation and expression of the ACC and DGA genes. The kinetic parameters of oleaginous yeast cultivation were estimated by employing through mathematical modeling. Seven yeast strains were cultivated on a glycerol-based oil production medium. Rhodosporidium toruloides TISTR 5186 demonstrated the highest efficacy in YO production and was chosen to investigate the impact of non-ionic surfactant supplementation on releasing intracellular YO into the extracellular space. Adding Triton X-100, Tween 20, and Brij 58 induced the release of YO by R. toruloides. Highest total YO formation and oil content were observed at 4.00 ± 0.07 g/L and 78.38 ± 0.37% (w/w) for 0.7% (w/v) Tween 20, respectively. Under this condition, the expression of the ACC and DGA genes was significantly increased by 3.4 and 3.6-fold, respectively compared to the control treatment. The YO fatty acids were consistently dominated by C16:0 and C18:1 under different yeast strains and cultural conditions. Modulation of YO secretion by non-ionic surfactants is a simple technique for enhancing oil recovery without the need for cell digestion. This strategy is a promising and straightforward process that can be employed for simultaneous oil production and recovery.

Adsorption-induced swelling impact on CO[formula omitted] transport in kerogen microporosity described by free volume theory

In order to examine the impact of the flexibility of kerogens’ microstructure on the transport of adsorbed CO2, we develop a free volume model that notably accounts for adsorption-induced swelling exhibited by flexible kerogen structures. We first show that, for CO2 compared to CH4 at constant fluid molar loading and in the same temperature and confining pressure conditions, an atomistic model of microporous type I kerogen in the middle of the oil formation window exhibits slightly less swelling upon adsorption. This swelling comes with an increase in the free volume accessible to the CO2 molecules, which can then diffuse faster when the fluid loading increases, without introducing significant collective effects on the transport properties. Consequently, transport can be considered diffusive, and the self-diffusion coefficient can be used as a proxy for the collective diffusion (or transport) coefficient. Finally, as previously demonstrated for CH4, a free volume model based on the Fujita–Kishimoto theory describes the transport enhancement with CO2 fluid loading. Although CO2 interacts more strongly than CH4, the parameters of the free volume models for both fluids are shown to be similar. Together with the diffusive nature of transport, it suggests an even broader applicability of the model to the transport of light alkanes and mixtures, thus greatly simplifying transport modeling for geological applications such as carbon sequestration in shales.

Reservoir Characteristics and Main Factors Controlling Carboniferous Volcanic Rocks in the Well CH471 Area of the Hongche Fault Zone: Northwest Margin of Junggar Basin, China

Nearly 100 million tons of reserves have been explored in the Well 471 area of the Hongche Fault zone. The Carboniferous volcanic rock reservoir is the main oil-bearing reservoir in the well CH471 area and is the main target of exploration and development. The characteristics of the Carboniferous volcanic rock reservoir are studied through core, thin section, physical property, logging, and other data, and its main controlling factors are analyzed in combination with actual means of production. The lithologies of the volcanic reservoir in the study area are mainly volcanic breccia, andesite, and basalt. The matrix physical properties of volcanic rock reservoirs are medium-porosity and ultralow-permeability, among which volcanic breccia has the best physical properties. The reservoir space mainly comprises primary pores, secondary dissolution pores, and fractures, resulting in a dual medium pore-fracture-type reservoir. Combined with production data analysis, the lateral distribution of oil and gas is controlled by lithology and lithofacies, with explosive volcanic breccia being the best, followed by the basalt and andesite of overflow facies, which are vertically affected by weathering and leaching and distributed within 50~300 m from the top of the Carboniferous system. The area with densely developed fractures was conducive to developing high-quality reservoirs. The tectonic movement promoted the formation of weathering and controlled the development of faults. Based on a comprehensive analysis, it is believed that the formation of Carboniferous volcanic oil and gas reservoirs in the study area was controlled and influenced by the lithology, lithofacies, weathering, leaching, faults (fractures), and tectonics.

Pore-scale study of the effects of DTPA chelating agent flooding on oil recovery utilizing a clay-coated micromodel

The use of diethylenetriaminepentaacetic acid (DTPA) chelating agent has shown promising results for enhanced oil recovery (EOR) in prior research. Several mechanisms, mainly resulting from rock-fluid interaction, have been proposed for chelating agent flooding; however, little attention has been paid to fluid-fluid interaction thus far. The assessment of these mechanisms has primarily relied on macroscopic techniques such as core flooding. This paper aims to investigate the injection of DTPA brine and its dominant mechanisms at the pore scale using a clay-coated micromodel. The micromodel tests were performed under oil-wet and water-wet states. For a more precise examination of fluid/fluid interactions, the dynamic interfacial tension (IFT) and Zeta potential were measured. It was observed that the injection of DTPA brine in water-wet state changed the saturation distribution and increased oil recovery. Based on visual inspections, this change in saturation distribution could potentially be linked to the formation of micro-dispersions and viscoelastic interfacial phenomena. Micro-dispersions facilitate flow to unswept areas, and viscoelastic interface formation reshapes the interface between oil and brine, causing disconnected oil droplets to coalesce and thus increase recovery. Under the oil-wet state, the micro-dispersion formation and wettability alteration can be the dominant mechanisms, and the amount of recovered oil was higher than that observed in the water-wet state. Furthermore, Zeta potential measurements at the interface between brine and oil showed a more negative value for DTPA brine, which is effective in wettability alteration and micro-dispersions stability. The results indicate that IFT reduction was not significant enough to be considered the dominant mechanism, although it assists in DTPA brine penetration into the crude oil and subsequent micro-dispersion formation.

Aliphatic Biomarker Signatures of Crude Oil from Tarakan Subbasin, Tarakan Basin, North Kalimantan, Indonesia

Organic geochemical studies of crude oil from Pamusian Field, Tarakan Subbasin, Tarakan Basin, North Kalimantan, have been done. Biomarker aliphatic hydrocarbon fractions were identified using a combined gas chromatography-mass spectrometer (GC - MS). Identified biomarkers consist of n-alkane groups, isoprenoids, bicyclic sesquiterpenoids, and pentacyclic triterpenoids. The most abundant aliphatic hydrocarbon biomarker is pristane followed by n-C19. The existence of n-alkanes shows a homologous (n-C16- n-C30) with a unimodal distribution type. The abundance of n-C19 is higher than other n-alkanes, supported by LHCPI value of 2.03, as an indicator of organic matter derived from microbial organisms. The amount of long chain n-alkanes (n-C25- n-C30) is almost the same as medium chain n-alkanes (n-C19 - n-C24) indicating the source of organic compounds is not only from microbial organisms, but also from terrestrial higher plants. The presence of 8β (H)-drimane compounds together with homodrimane shows the presence of bacterial input on the formation of oil from organic compounds. Ratio of Pr/Ph is 3.76, ratio of drimane/homodrimane is 1.058, ratio of Pr/n-C17 is 34.41, and ratio of Ph/n-C18 is 16.02 indicating the source of organic compounds came from terrestrial higher plants deposited in the oxic environment, and disposed to increase biodegradation. The CPI value is 0.95, and the highest amount of 17α (H), 21β (H)-hopane compounds suggest that Tarakan Subbasin oil was mature, and the source of organic compounds was derived from bacteria Keywords: Tarakan Basin, organic geochemistry, aliphatic hydrocarbon fraction, CPI

MODELING TOOLS USED FOR OPERATIONAL FIELD DEVELOPMENT MANAGEMENT

The increase in the share of hard-to-recover reserves increases the need to use modern technologies in the development of oil fields to increase the efficiency of reserves development. One of the tools for identifying zones with hard-to-recover reserves is the geological and hydrodynamic model, which allows simulating various geological and technical measures carried out on production and injection wells. It is possible to lay down both predicted and already carried out measures for testing hypotheses and making decisions on field development. In this work, we have considered the area where the problem of premature water flooding of products has been identified from a certain period of time. After an analytical review of the site, a theory was put forward about the source of water flooding. In the analyzed area there is also a horizontal well, which is not currently in operation. The well was fractured immediately after drilling. The well was put into operation with a high water cut and shut down, and no crossflows were detected during additional field geophysical surveys. In terms of indirect parameters (properties of produced water, pressure, parameters during hydraulic fracturing), the created fracture overcame the clay bridge and created a hydrodynamic connection with the underlying aquifer. Based on the analysis, a theory was put forward that the formation water of the lower aquifer along the fracture of the frac migrated to the zone of extraction of the productive oil formation due to the large difference in the current formation pressure between the facilities. The hypothesis is confirmed by calculations on the hydrodynamic model. Several options were proposed at the end of the site to slow further water breakthrough to the production wells. Among them, the injection of various polymer-based compositions into a horizontal well is a «source».

ROLE OF ELECTROMAGNETIC FIELDS IN DEVELOPMENT OF OIL AND GAS GENERATION PROCESSES IN UNCONVENTIONAL RESERVOIR ROCKS

The specifics of the Bazhenov Formation sediments, which are fundamentally different from traditional Green River oil shales, is that the processes of organic matter (kerogen) transformation into hydrocarbons have not yet been completed in them. The achieved paleotemperatures allowed the studied sediments to enter the main phase of oil formation during the regional catagenetic transformation of kerogen, but they failed to realize their oil-maternal potential to the full extent. At present, there are several unsolved problems for these rocks, related both to the genesis of oil and to the search for commercial hydrocarbon deposits in them and the development of technologies for their further development. The processes of «proto-oil» formation in the Bazhenov Formation sediments are still poorly understood. In fact, these processes are a system of equations with many unknowns, the correct solution of which is still impossible at the current stage of study. In our opinion, an important role in the development of oil formation processes in the Earth’s subsurface is played by magnetic fields formed under the action of a number of reasons (in particular, during the development of numerous tectonic disturbances). Our laboratory experiments by gas chromatography showed that in bitumoids of the studied samples there is a progressive shift of the «naphthenic hump» associated with internal transformations in the magnetic field. As a result of these studies, a decrease in the naphthenic fraction of hydrocarbons in samples heated in a magnetic field was recorded compared to samples without exposure to a magnetic field. Significant differences were found in paired samples of most geochemical characteristics - n-C23/24, n-C25/26, n-C26/27, n-C29/30, OEP, CPI, naphthene sum. Taking into account the influence of electromagnetic fields on the development of oil and gas generation processes allows us to create a completely new technology of «maturation» of hydrocarbon compounds (proto-oil) directly in the oil-maternal sediments and the formation of «artificial/technogenic» oil deposits.

Effects of suspended particles and dispersants on marine oil snow formation of crude oil/diesel oil.

Marine oil snow (MOS) potentially forms after an oil spill. To fully understand the mechanism of its formation, we investigated the effects of suspended particles (SP) and dispersants on MOS formation of crude oil and diesel oil by laboratory experiments. In the crude oil experiment, the SP concentration of 0.2 g L-1 was more suitable for crude oil MOS formation. The addition of dispersants significantly stimulated N and TV during MS/MOS formation of SP at 0.4 g L-1 and 0.8 g L-1 concentration (p < 0.05). Without SP, the dispersants also stimulated crude oil MOS formation. Furthermore, the concentration of SP had a significantly positive effect on the reduction of the total amount of N-alkanes (p < 0.05). In the diesel oil experiment, after adding dispersants to diesel oil, the maximum N, Dm, and TV values at a SP concentration of 0.2 g L-1 were significantly higher than those at 0.4 g L-1 and 0.8 g L-1 (p < 0.05). Besides, we found that dispersants stimulated MOS formation in diesel oil at a SP concentration of 0.2 g L-1. However, the dispersants had an inhibitory effect on diesel oil MOS formation without SP. Notably, the MOS formed by diesel oil appeared white, unlike the black MOS associated with crude oil. These findings are important for the environmental impact of oil spills and elevated SP concentrations.

Effects of Pore Water Content on Stress Sensitivity of Tight Sandstone Oil Reservoirs: A Study of the Mahu Block (Xinjiang Province, China)

Traditional stress sensitivity experiments are typically conducted under dry conditions, without considering the reservoir’s water content. In reality, the presence of water within pores significantly influences the extent of stress sensitivity damage in tight sandstone oil formations, subsequently affecting the determination of stress sensitivity coefficients during experimentation. By investigating sandstone samples from wells in the Mahu Block of China’s Xinjiang province, we observed that increasing water saturation reduces the stress sensitivity of tight sandstone. By conducting stress sensitivity experiments under varying water content conditions, we found that the stress sensitivity coefficient is not a constant value but decreases as water saturation increases. Based on experimental comparisons, an optimized power-law model for stress-sensitive damage assessment was refined. By conducting stress-sensitive damage assessment experiments under different water content conditions and integrating the concept of comprehensive compression coefficient, an improved stress-sensitive power-law model was established allowing for the influence of water content. The accuracy of this improved model was increased by 46.98% compared to the original power-law model through experimental validation. The research outcomes can enhance the accuracy of permeability and productivity evaluation, providing valuable guidance for unconventional oil and gas development.

It Is Easy To Find Lithium; Turning a Profit Is Hard

Finding lithium in the water from oil and gas wells is easy. Finding enough to make money is hard. In the US and Canada there has been growing interest in directly extracting lithium from the water coming out of the oil/water separator, which is competing with more established techniques such as mining and evaporating lithium-rich fluids. The race to find lithium is driven by expectations that fast-rising electric car sales will make the lithium required for batteries in those vehicles a valuable commodity. Those chasing direct extraction are also betting that their innovations can do what they say. Direct extraction from water started looking like a real possibility earlier this year when ExxonMobil paid $100 million to buy a company holding 120,000 gross acres of leases in south Arkansas. The price reflected the location in the heart of the direct lithium extraction industry of the future. The area offers a unique combination of lithium-rich water plus the infrastructure and expertise needed to transport, process, and dispose of the billions of gallons of water needed for industrial-scale mineral extraction. Commercial production of battery-quality lithium carbonate in Arkansas is years off. But the sprawling network of water-producing wells, pipelines, and processing that have made the state one of the world’s leading bromine producers, lowers the risk and cost of commercial lithium production. The source of the lithium-rich water is the Smackover—an oil formation discovered near El Dorado, Arkansas, back in 1921 when a gusher blew in. A year after that discovery, there were 608 producing wells nearby, according to the El Dorado News-Times. Now with lithium looking like battery gold, investors are rushing in. In this emotional market, lithium carbonate prices have swung like cryptocurrency. As of mid-October, a ton of it was selling for about $25,000. Over the past quarter it averaged $32,000/ton. Late last year it stood at $85,000. And in 2021 it was going for $10,000, said Graham Bain, vice president for subsurface opportunities at Enverus. He offered $25,000/ton as a “go forward price.” As with oil and gas, hopes of high prices have a way of rapidly increasing supplies, resulting in price-crashing gluts. So far, most oil companies sound curious but far from committed to lithium. “There’s a big rush. I have received several requests from companies in the Permian Basin to discuss lithium in the water,” said Jean-Philippe Nicot, senior research scientist at the Bureau of Economic Geology (BEG) at The University of Texas at Austin. He is the lead author on recent paper that offered a primer on what’s known about lithium brines from oil wells in states from Texas to Mississippi. It is based on nearly 1,802 water analyses from the US Geological Survey (USGS)—some dating back to the 1960s—plus a recent 576-well survey by the BEG. The geologists, whose work ranged from hard-rock mining to water research, said this is an early effort to begin figuring out how to find the lithium in subsurface water.