The SWA Property is being assessed by Standard Lithium for its lithium-brine potential. The brine is situated within an aquifer associated with the Late Jurassic Smackover Formation, which has produced hydrocarbons since the 1940s on the Property and brine to the east of the Property since the late 1950s. Hyper-saline brine (total dissolved solids of 293,000 to 448,000 mg/L) with elevated lithium has been verified in the 2018 brine sampling programs conducted by Standard Lithium.

The Smackover Formation in south Arkansas consists of a shoaling-upward cycle capped by ooidal/oncolitic packstone and grainstone (Vestal, 1950), with a maximum thickness of 365 m (1,200 feet). It has been interpreted as a low-gradient slope (<1°) homoclinal ramp succession due to its series of strike-oriented, relatively narrow depositional lithofacies belts across Texas, Arkansas, Louisiana, and Mississippi (Ahr, 1973; Bishop, 1968; Handford and Baria, 2007. These belts include evaporite and redbed sequences in the north that change basin-ward into ooidal (inner ramp beaches and shoals) peloidal facies belt (mid-outer ramp), and laminated mudstone (basin).

During rifting phases, evolving grabens were filled with the earliest Late Triassic-Early Jurassic red-bed sedimentary sequences of the Eagle Mills Formation. This unit comprises a variety of terrestrial sedimentary rocks including red, reddish-brown, purplish, and greenish-gray coloured shale, mudstone, siltstone, and lesser amounts of sandstone and conglomerate. In southern Arkansas, the Eagle Mills Formation includes conglomeratic sandstone and red shale with igneous fragments (diabase). The Late Triassic-Early Jurassic age is based on the study of remnant plants and radiometric dating of intrusive material (Scott et al., 1961; Baldwin and Adams, 1971).

Smackover Formation diagenesis was dominated by early cementation, leaching of calcium carbonate allochems and dolomitization; other processes include: pressure solution, late (postdolomitization) calcite and anhydrite cementation, and fracturing, both tectonic and caused by collapse of partially dissolved rock frameworks (Kopaska-Merkel et al., 1992). Early marine phreatic cementation was followed by leaching of ooids and widespread particle dissolution that vastly increased porosity values (to 40% or more) but had little direct effect on permeability. Early dolomitization of uppermost Smackover Formation strata by reflux of hypersaline brine was widespread and is responsible for formation and/or preservation of many permeable Smackover Formation pore systems.

The Upper Smackover and Middle Smackover formations are the target horizon for the mineral resource evaluation in this Technical Report. Their depositional models have been described as follows:
• The Upper Smackover Formation or Reynolds Member was deposited in a beach and/or shoal environment and composed of ooids and non-sketelal Carbonate that formed ooidal, chalky limestone (Vestal, 1950; Tonietto and Pope, 2013).
• The Middle Smackover Formation was deposited in a high-stand system tract in response to sea level rise. The uppermost portion of the Middle Smackover Formation would have been in the transition zone to a shallower sea water environment forming laminated, pelletal, lime-mudstone and fossiliferous lime-wackestone and locally the upper portion of this unit is also pelletoid and oolitic limestone (Dickinson, 1968).

Brine extraction and disposal will occur using a conventional brine supply and injection wellfield. A network of twenty-three (23) brine supply wells will produce from the Smackover Formation in the South resource area. The brine supply wells will produce between 200 m3/day and 2,100 m3/day with an average rate of 1,715 m3/day. The average brine production rate will be 1,800 m3/hr (7,925 US gallons per minute) during the 8,000 hours in the operational year. The supply wells, as modelled, are grouped into five (5) multi-well pad facilities to minimize initial capital expenditure and improve long-term maintainability. Brine from the supply facilities will be conveyed from the five multi-well pads to the single processing facility by a network of underground fiberglass pipelines totaling approximately 18.3 km (11.4 miles) in length. After processing, the lithium-depleted brine will be returned to the North resource area by a pipeline system 20.3 km (12.6 miles) in length to a network of 24 brine injection wells completed in the Smackover Formation. As with the supply wells, the injection wells are proposed to be grouped into five (5) multi-well pad facilities. All extraction and reinjection will occur in the single unitized area to maintain reservoir pressures.

The brine supply wells will extract the raw brine from the Smackover Formation on a continuous, 24-hour, 365 days per year operation. Operational time has been estimated to be 8,000 hours per year to account for ongoing maintenance, system upsets, weather outages, etc. An 800 HP electric submersible pump (ESP) will be installed in each production well that will pump the brine to the surface through a 17.8 cm (7 inch) tubing.

As the brine is pumped to the surface, natural gas (usually sour in the project area) will degas out of the brine as the pressure drops. The brine, sour gas, and trace amounts of oil and solids (sludge) will be separated from one another at the wellheads using three-phase separators. The brine and sour gas streams produced will be sent from the separators to the main processing facility in pipelines. The oil/sludge mixture that is separated from the brine will be stored in tanks on the well pad and periodically removed via a pump truck for further processing at a local refinery or by a 3rd party.

Brine from the brine supply wells will be combined prior to leaving the well pad into single headers and “boosted” with pumps to deliver it to the central processing facility via a common brine pipeline. Brine variability is reduced by combining and mixing all the brine streams at the well pads and from all the well pads in the brine pipelines. Brine pumped from production wells and well pads through the brine pipeline is discharged to a large capacity brine receiving tank at the main processing facility.

Pressurized hot sour natural gas, containing light hydrocarbons (i.e., ethane, propane and butane), hydrogen sulfide, carbon dioxide and water vapor, separated from the brine in the three phase separators will be cooled to condense out higher boiling point condensable hydrocarbons and water. The liquids (condensate) will be separated and returned to the three-phase separator feed. The “dried” sour gas from all of the brine supply wells will be collected into a single sour gas pipeline and delivered to the central processing facility (CPF). At the CPF, the sour gas will be transferred into an existing sour natural gas gathering pipeline supplying sour gas to the nearby Mission Creek Dorcheat Gas Plant where it will be sweetened for beneficial re-use.

Once the lithium is removed from the brine, barren brine (or lithium-free brine) is then disposed of through the injection wellfield in the North resource area. A network of pipelines connects the CPF to the injection (or disposal) wells. Like the supply wells, the injection wells will be grouped into five (5) multi-well pad facilities. Barren brine is delivered from the main processing facility by brine pumps to the well pads. The barren brine is pumped down through the injection wells into the Smackover Formation. The reinjection of the barren brine is necessary to maintain the pressure in the Smackover Formation aquifer.

The well design and drilling methodologies included in the wellfield plan for this project are detailed below.

Vertical Wells – Vertical wells are drilled at a near vertical approach angle to the target location in the Smackover Formation. These wells have the lowest capital cost but will only be used for access to targets in the Smackover Formation directly below the multiwell pads.

Directional Wells – Directional wells are initially drilled at a near vertical angle, but they eventually deviate with an angled approach to the target well location. These wells typically carry a greater capital and maintenance cost but allow multiple wells to be drilled from one surface location which reduces the overall environmental impact at the surface and minimizes costs by sharing the required surface resources and infrastructure. Directional wells also typically provide additional bore length in the “pay zone” than vertical wells which usually results in increased production/injection rates from the well.

Horizontal Wells – Horizontal wells are similar to directional wells but are unique in that they continue their bend or “build” at the end of the well to allow the well tubing to approach the target well location at an angle that is in line with target formation. This allows the horizontal wells to provide an elongated “horizontal” stretch of well boring directly in the “pay zone” providing increased production and flexibility for the well location.

Standard Lithium will produce battery-quality lithium hydroxide monohydrate (LHM or LiOH•H2O) from Smackover Formation brine. Lithium-containing brine will be produced from brine supply wells. The produced brine will be pipelined to the CPF for further processing to the final product. Average LHM production will be 30,000 tonnes/year over a 20-year operating timeframe. The lithium recovery from the brine to the final product is about 90%. The production process includes the following major unit processes:
• lithium chloride extraction from the brine;
• lithium chloride purification and concentration;
• lithium chloride electrolysis to convert to lithium hydroxide;
• LHM crystallization and drying.

Brine will be delivered from the wellfield via pipelines to the brine receiving tank at the Central Processing Facility (CPF). The first step in producing LHM will be the production of purified and concentrated lithium chloride solution in the CPF. Produced brin ........