Hydrothermal destabilization of spent slurries and recovery of stable emulsified slurries

Abstract

Systems and methods of separating hydrocarbon fractions from an emulsified thermodynamically stable slurry containing ultra-fine solids and surfactants. The fluid is subjected to controlled elevated temperatures and pressures while maintaining a liquid phase, inducing thermal degradation and decomposition of stabilizing surfactants, leading to the destabilization of the fluid thereby allowing for the efficient mechanical separation of oil, water, and solids phases. The invention offers numerous benefits, including enhanced energy efficiency and high recovery yield of valuable base oil / synthetic. This method presents a significant advancement in the management of stable emulsified slurries such as spent drilling fluids in the oil and gas industry.

Description

HYDROTHERMAL DESTABILIZATION OF SPENT SLURRIES AND RECOVERY OF STABLE EMULSIFIED SLURRIES Cross-reference to related applications

[0001] This application claims domestic priority benefit under 35 U.S.C. § 119(e) from Applicant’s provisional patent application number 63618697, filed January 8, 2024, which is hereby explicitly incorporated herein by reference in its entirety.

[0002] BACKGROUND INFORMATION

[0003] Technical Field

[0004] The present disclosure relates to systems and methods to effectively recover base oil / synthetic from emulsified thermodynamically stable slurries such as spent drilling fluids while mitigating disposal expenses.

[0005] Background Art

[0006] Drilling fluids are essential for safe and efficient drilling operations, but the accumulation of ultra-fine solids in drilling fluids poses significant problems, including operational issues such as pipe sticking, increased torque, decreased rate of penetration, increased disposal costs, loss of valuable fluid and environmental impact. In the realm of oil and gas exploration, the role of drilling fluids is paramount in ensuring the safe and efficient execution of drilling operations. These specialized fluids are systematically circulated through the wellbore, performing a multitude of crucial functions. They are responsible for transporting drill cuttings from the wellbore to the surface, facilitating their separation and removal, and executing various other indispensable tasks.

[0007] Throughout the entirety of the drilling process, meticulous management of drilled solids within the circulating drilling fluid is imperative. This management is essential to uphold the requisite fluid properties in accordance with engineering specifications. These properties encompass critical parameters such as fluid density,rheology, particle size distribution, water activity, and chemical composition. In scenarios involving invert drilling fluids, an additional dimension arises, involving the precise control of brine droplet size distribution and their colloidal stability.

[0008] The challenge at hand lies in the unceasing requirement to maintain the stability and integrity of the drilling fluid as drilling progresses. This is particularly crucial for oil and synthetic based drilling fluids, such as Oil-Based Mud (OBM) and Synthetic- Based Mud (SBM), which serve as the lifeblood of drilling operations. However, as drilling proceeds to greater depths, a pressing concern emerges—the accumulation of unwanted Ultra Fine Solids (UFS) within the drilling fluid, forming an emulsified thermodynamically stable slurry.

[0009] These UFS particles, measuring smaller than 5 to 7 microns in size, gradually amass within the drilling fluid during the course of drilling operations. In stark contrast to water-based drilling fluids, OBM and SBM exhibit remarkable stability and resistance to flocculation and separation through conventional solids-control equipment and methods. Consequently, this gradual build-up of UFS within the drilling fluid presents a formidable impediment to the efficiency of drilling operations.

[0010] One of the pivotal ramifications of UFS presence in the drilling fluid is the distortion of its rheological properties. This distortion manifests as a series of operational challenges during drilling, including pipe sticking, heightened torque requirements, reduced Rate of Penetration (ROP), and various other complications associated with high-viscosity mud.

[0011] Extensive data analysis within the drilling industry has unequivocally demonstrated the adverse consequences of drilling with a high concentration of drilled solids, particularly UFS, referred to as low gravity solids (LGS). Wells subjected to a high concentration of LGS, typically exceeding 10% by volume, have exhibited a significantly elevated frequency of Non-Productive Time (NPT) events. These includethreefold instances of stuck pipe occurrences and hole pack-off events, when compared to wells drilled with a LGS concentration below 10%.

[0012] Furthermore, an in-depth examination of drilling data reveals that a higher LGS content directly correlates with reduced drilling efficiency, translating to a decrease in the number of feet drilled per day by as much as 14% to 18%. Concurrently, it amplifies the cost of drilling fluids per foot, registering an increase of up to 23%.

[0013] Another critical challenge lies in the management of spent drilling fluids containing UFS. Conventional practices for addressing this issue include diluting the mud system to diminish the concentration of fine solids or opting for complete disposal and the formulation of entirely new drilling fluid. However, these traditional methods often prove to be impractical and cost-prohibitive, limiting their applicability in diverse drilling applications.

[0014] A secondary source of waste drilling fluid stems from the processing of drill cuttings through vertical cuttings dryers, specialized basket centrifuges designed to pass fluid through screens while discharging dried solid cuttings with relatively low residual oil content. Despite being an energy-efficient and cost-effective solution for removing oil / synthetic fluid contamination from drill cuttings, the recovered fluid still bears a high concentration of UFS in an emulsified thermodynamically stable slurry, rendering it unsuitable for reuse even after high g-force centrifugation. Consequently, the application of efficient cuttings dryers is constrained by this inherent limitation, necessitating alternative approaches for handling spent drilling fluids in an environmentally responsible and economically efficient manner.

[0015] Existing systems and methods rely on disposal or treatment of the spent drilling fluids. Existing disposal methods include deep well injection; land application (landfarming); bioremediation (microbial activity); incineration; and solidification and stabilization. Existing treatment methods include cross-flow filtration; electrophoresis; chemical / mechanical methods with surfactants and centrifuges; indirect thermaldesorption using hot oil; thermal desorption using hammermill; thermal slurry distillation using vacuum distillation methods; indirect thermal desorption using screw and heated tube. Each of these disposal and treatment methods presents its own set of challenges and limitations.

[0016] At this time, there are no commercial scale hydrothermal destabilization (HTD) systems and methods for the recovery of oil / synthetic and water / brine phases from emulsified thermodynamically stable slurries such as drilling fluid, largely due to these inherent challenges. There remains a need for improved HTD systems and methods for the recovery of oil / synthetic and water / brine phases from emulsified thermodynamically stable slurries such as drilling fluid.

[0017] SUMMARY

[0018] In accordance with the present disclosure, systems and methods for recovery and reuse of valuable base oil / synthetic drilling fluids are described which reduce or overcome many of the faults of previously known systems and methods. In particular, we have designed unique systems and methods wherein the spent drilling fluid is subjected to controlled elevated temperatures and pressures in a liquid phase, inducing thermal degradation and decomposition of surfactants and additives, leading to the destabilization of the fluid. This allows for the efficient separation of oil, water, and solids phases resulting in recovery and reuse of valuable base oil / synthetic drilling fluids. This method presents a significant advancement in the management of spent drilling fluids in the oil and gas industry.

[0019] A first aspect of the disclosure is a system comprising (or consisting essentially of, or consisting of): a well having a well depth, a top positioned at a surface location, and a bottom portion positioned at a subterranean location, the well comprising a casing and one or more tubing (in certain embodiments, coiled tubing) positioned therein, forming an annulus there between, the casing and the one or more tubing defining a hydrothermaldestabilization (HTD) zone in the bottom portion of the well and a heat transfer and separation zone above the HTD zone; the well further comprising a cable comprising an electric heating element segment positioned in one or more of the one or more tubing in the HTD zone and configured to transfer energy endothermically to a spent drilling fluid flowing downward through at least one of the one or more tubing, and convert at least a portion of the spent drilling fluid into an oil phase and a water phase by HTD, with the spent drilling fluid entering into the tubing at the top of the well at a first temperature and a first pressure, the well depth and the electrical heating element sufficient to produce a product fluid comprising the oil phase and the water phase.

[0020] A second aspect of this disclosure is a method comprising (or consisting essentially of, or consisting of): flowing a spent drilling fluid into a top of one or more tubing positioned inside a casing of a well, the well having a well depth, a top positioned at a surface location, and a bottom portion positioned at a subterranean location, the well comprising a casing and one or more tubing positioned therein, forming an annulus there between, the casing and the one or more tubing defining a hydrothermal destabilization (HTD) zone in the bottom portion of the well and a heat transfer and separation zone above the HTD zone; heating the spent drilling fluid flowing downward through the HTD zone employing a cable comprising an electric heating element positioned in one or more of the one or more tubing in the HTD zone; converting at least a portion of the spent drilling fluid into an oil phase and a water phase by HTD in the HTD zone, the spent drilling fluid entering into the tubing at the top of the well at a first temperature and a first pressure, the well depth and the electrical heating element sufficient to produce a second temperature and a second pressure in the HTD zone sufficient to produce a product fluid comprising the oil phase and the water phase;flowing the product fluid comprising the oil phase and the water phase upward through the annulus between the casing and the one or more tubing; and transferring heat between the product fluid and the spent drilling fluid in the heat transfer and separation zone.

[0021] These and other features of the systems and methods of the disclosure will become more apparent upon review of the brief description of the drawings, the detailed description, and the claims that follow. Wherever the term “comprising” is used herein, other embodiments where the term “comprising” is substituted with “consisting essentially of” are explicitly disclosed herein. Wherever the term “comprising” is used herein, other embodiments where the term “comprising” is substituted with “consisting of” are explicitly disclosed herein. Moreover, the use of negative limitations is specifically contemplated; for example, certain systems and methods may comprise several physical components and features but may be devoid of certain optional hardware and / or other features. For example, certain systems may be devoid of auxiliary tanks, pumps, and other equipment. As another example, systems of this disclosure may be devoid of heat exchangers employing inert metals, or other expensive equipment.

[0022] BRIEF DESCRIPTION OF THE DRAWINGS

[0023] The manner in which the objectives of this disclosure and other desirable characteristics can be obtained is explained in the following description and attached drawings in which:

[0024] FIG. 1 schematically illustrates generic known hydrothermal destabilization (HTD) systems and methods for the recovery of oil / synthetic and water / brine phases from emulsified thermodynamically stable slurries such as drilling fluid and separated drilling fluid from drill cuttings;

[0025] FIG.2 schematically illustrates generic known HTD systems and methods for the recovery of oil / synthetic and water / brine phases with the aid of chemicals pre and post reaction;

[0026] FIGS.3A and 3B schematically illustrate known HTD systems and methods in more detail for the recovery of oil / synthetic and water / brine phases where all the equipment is present at the surface in an ambient environment;

[0027] FIG 4. is a graphical representation of the phase diagram presenting the relationship between pressure vs. temperature of various components of the feed slurry in HTC systems and methods in accordance with the present disclosure;

[0028] FIG. 5 is a schematic representation of a material balance for one method embodiment of the present disclosure, illustrating that one embodiment in accordance with the present disclosure can process 100 metric tonnes per day of drill cuttings and 83 metric tonnes per day of spent drilling fluid, generating 32 metric tonnes of recovered fluid suitable for recycling into a virgin drilling fluid;

[0029] FIG.6 schematically illustrates more detailed HTD systems and methods of the present disclosure for the recovery of oil / synthetic and water / brine phases where all the hydrothermal reactor and primary heat exchanger is present sub surface with the remaining equipment at surface in an ambient environment; and

[0030] FIGS. 7, 8, 9, 10, 10A, 11 illustrate various system and method embodiments in accordance with the present disclosure.

[0031] It is to be noted, however, that the appended drawings are not to scale and illustrate only typical embodiments of this disclosure, and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effectiveembodiments. Identical reference numerals are used throughout the several views for like or similar elements.

[0032] DETAILED DESCRIPTION

[0033] In the following description, numerous details are set forth to provide an understanding of the disclosed methods, systems, and apparatus. However, it will be understood by those skilled in the art that the methods, systems, and apparatus may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. All U.S. published patent applications, U.S. Patents, and non-patent literature referenced herein are hereby explicitly incorporated herein by reference. In the event definitions of terms in the referenced patents and applications conflict with how those terms are defined in the present application, the definitions for those terms that are provided in the present application shall be deemed controlling. Where a range of values describes a parameter, all sub-ranges, point values and endpoints within that range are explicitly disclosed herein. This document follows the well-established principle that the words “a” and “an” mean “one or more” unless we evince a clear intent to limit “a” or “an” to “one.” For example, when we state “flowing a biomass slurry into a top of a tubing positioned inside a casing of a well”, we mean that the specification supports a legal construction of “a tubing” that encompasses structure distributed among multiple physical structures, and a legal construction of “a well” that encompasses structure distributed among multiple physical structures.

[0034] In oil and gas exploration, drilling fluids play a crucial role in safe and efficient drilling operations. Table 1 shows the components of an invert emulsion oil-based drilling fluid along with their function and commonly used compounds. These fluids circulate through the wellbore, carrying drill cuttings to the surface while maintaining fluid properties. However, oil-based drilling fluids face a significant issue while drilling – the accumulation of Ultra Fine Solids (UFS), smaller than 5 to 7 microns, increasinguse of surfactants and continuous shearing of the fluid, all of which increase fluid stability making it more and more difficult to separate and recover base oil and water per McCosh et al, “Invert-Fluid Flocculation: A Method for Recycling Drilling Fluid”, Journal of Petroleum Technology (May 2007). Unlike water-based fluids, oil-based ones are resistant to conventional solids-control methods, resulting in costly disposal without recovering valuable base oil / synthetic, costing the industry billions annually. Table 1. Summary of Typical Components of an Invert Emulsion Oil-Based Drilling Fluid* COMPONENT FUNCTION EXAMPLES r d y ,COMPONENT FUNCTION EXAMPLES n; sTHERMAL RECOVERY TREATMENTS”, T.G.J. Jones, Schlumberger Cambridge Research, M.W. Sanders, M-I L.L.C. and B.D. Chambers, bp.

[0035] The presence of UFS leads to undesirable rheology, causing problems like stuck pipes and reduced drilling efficiency per “Improving Drilling Economics Through Drilling Fluids and Solids Control in the Eagle Ford - Case Examples and Results”. Guo et al, IADC / SPE-170525-MS. Current practices involve dilution or complete fluid replacement, but these are often impractical and expensive per “A Cross Flow Filtration Process to Manage Fines in Non-Aqueous Drilling Fluids”, Garcia and Falgout, Schlumberger, AADE-16-FTCE-45.

[0036] Additionally, waste drilling fluid is generated from processing drill cuttings using cuttings dryers, which remove oil / synthetic contamination but leave high UFS concentrations, rendering the fluid unusable and necessitating disposal. Table 2 shows an example of physical properties and primary components of blended spent drilling fluid.Table 2 Example Properties of a Blended Spent Drilling Fluid Blended Feed Drilling Fluid Wt% Vol% % % % %

[0037] nt drilling fluid and drill cuttings constitute a pivotal facet of drilling operations, encompassing various methods, each accompanied by its own set of challenges and limitations. The pursuit of waste-reuse and disposal in the past has given rise to several distinct prior art approaches, which have been rigorously analyzed in numerous studies, shedding light on their respective advantages and disadvantages.

[0038] Previously Known Disposal Methods:

[0039] Deep Well Injection: Spent drilling fluid and drill cuttings find their way into deep geological formations through specialized injection wells. The integrity of these wells is of paramount importance to prevent the inadvertent release of contaminants into underground sources of drinking water or surface breaches. The selection of a suitable geological formation takes into account factors like porosity, permeability, and confinement. Strict adherence to regulations and permits governing deep well injection is mandatory to avert potential environmental harm.

[0040] Land Application (Landfarming): Drill cuttings can undergo treatment and be distributed across designated land areas, allowing natural processes to break down the waste materials. However, there exists a risk of contaminantsleaching into groundwater or surface water if not managed with utmost care. Furthermore, the substantial land area required for landfarming may not always be readily available near drilling sites. Biodegradation during this process contributes to CO2 and CH4 emissions, necessitating regulatory compliance, continuous monitoring, and potential remediation efforts.

[0041] Bioremediation: Microbial activity is harnessed to degrade organic components present in spent drilling fluids and drill cuttings. In some instances, engineered microbes are introduced to surmount resistance to bioremediation. Bioremediation can take place either on-site or at specialized treatment facilities. Nevertheless, it can be a time-consuming process, with its effectiveness subject to environmental conditions and the nature of contaminants. The provision of adequate nutrients and meticulous control of conditions are prerequisites to sustain microbial activity. Despite its merits, bioremediation carries the risk of not achieving desired reduction target levels and contributes to CO2 and CH4 emissions.

[0042] Incineration: The incineration process subjects spent drilling fluids and drill cuttings to high temperatures, transforming them into ash and gaseous byproducts, primarily CO2. Controlling air emissions, including particulate matter and hazardous gases, is imperative for environmental protection. However, incineration is often energy-intensive, costly, and does not offer resource recovery, thus making it a less frequently utilized option.

[0043] Solidification and Stabilization: Drill cuttings and spent drilling fluids can be treated with binders or stabilizing agents to immobilize contaminants and reduce leachability. The efficacy of solidification and stabilization hinges on the types and concentrations of contaminants as well as the choice of stabilizing agents. It is worth noting that solidification may increase the volume of waste material, necessitating additional disposal considerations. Ensuring thelong-term durability of solidified / stabilized waste materials is critical to prevent leaching.

[0044] Previously Known Treatment & Reuse Methods:

[0045] The pursuit of environmentally responsible approaches to manage drilling waste has given rise to treatment and reuse methods, each presenting its own set of challenges and limitations:

[0046] Cross Flow Filtration: Employing tangential-flow filtration, cross flow filtration represents a batch process that utilizes a tubular-style membrane module. It necessitates significant tubular surface area, employs expensive titanium oxide membranes, and exhibits complex operation characteristics with high energy consumption. High transmembrane pressure results in low processing rates.

[0047] Electrophoresis: This separation technique utilizes an electric field to manipulate charged particles within drilling fluid. However, the migration of solids and liquid phases within the drilling fluid is notably slow, rendering the process time-consuming. Effectively isolating and recovering specific components from a wide range of spent drilling fluids or cuttings can pose a challenge, often resulting in poor separation and low recovery of valuable fluids.

[0048] Chemical / Mechanical Methods with Surfactants and Centrifuges: Spent drilling fluids containing ultra-fine solids (<10 um) beyond the capability of mechanical separation equipment can benefit from the addition of surfactants like demulsifiers and polymers. These substances enhance the separation of oil and water phases while promoting flocculation of fine solids. However, selecting the appropriate surfactants and concentrations is critical, and theireffectiveness can vary depending on location-specific factors. Variability and high chemical costs can render the process uncertain and expensive.

[0049] Indirect Thermal Desorption Using Hot Oil: Thermal desorption entails heating drilling waste with hot oil to volatilize and recover hydrocarbons. The process is energy-intensive and limited by the relatively low temperature constraints of the hot oil thermal transfer fluid. Its setup and operation occupy substantial space and complexity, requiring specialized knowledge and maintenance.

[0050] Thermal Desorption Using Hammermill: In this method, hammermills within a drum containing drilling waste rotate at high RPM to generate heat through friction. Adequate solids content in the waste is essential for effective thermal desorption, rendering it less suitable for high-liquid-content wastes. Hammermills may experience wear and require maintenance due to the abrasive nature of drill cuttings.

[0051] Thermal Slurry Distillation: This approach adapts typical vacuum distillation methods to accommodate high solids content feedstock. However, it involves a complex process with significant energy consumption and susceptibility to fouling and solid build-up. The quantity of solids in the feed slurry imposes constraints on the process.

[0052] Indirect Thermal Desorption Using Screw and Heated Tube: Employing a single or twin screw within a heated tube, this method transfers heat generated by electric resistance heaters or combustion of fuel to the drilling waste. High- fluid-content drilling wastes are amenable to this technique, and the application of vacuum reduces volatilization temperature, aiding in the recovery of valuable hydrocarbons. Ensuring efficient energy utilization is pivotal to reducing operating costs. Achieving uniform heating throughout the heated tube is a complex task.

[0053] In all thermal technologies, significant energy consumption is associated with the volatilization of the liquid phase of drilling waste. High water content fluids demand even more energy due to the heat of vaporization. Additionally, energy recovery is not a feature of thermal desorption systems, often relying on direct fuel combustion, leading to substantial CO2 emissions. Stringent control of dust emissions is essential for worker safety and environmental compliance during the drying process, with certain systems, such as the Hammermill, generating fine dust. Reclaimed oils from thermal desorption technologies can be reused in drilling fluids, although these processes may introduce volatile components, resulting in unpleasant odors and potential changes in flash points. Recent studies have identified various volatile contaminants in recovered oils, including isobutyraldehyde, toluene, and dimethyl disulfide, which may contribute to these undesirable alterations.

[0054] The systems and methods of the present disclosure address the critical industry issue of spent drilling fluids by introducing innovative thermochemical systems and processes for the separation and recovery of base oil / synthetic components. The systems and methods of the present disclosure not only mitigate the challenges posed by spent drilling fluids but also offer a sustainable approach to reduce disposal costs while promoting the reuse of recovered materials.

[0055] Hydrothermal Destabilization Technology

[0056] The present disclosure describes novel systems and methods for thermochemical hydrothermal degradation of drilling fluids (HTD), coupled with mechanical separation. The systems and methods of the present disclosure subject spent drilling fluids (SDF) to temperatures exceeding 200°C but below 300°C, at pressures ranging from 500 psi to 2,000 psi, ensuring the fluid remains in a liquid state. The operating pressures are determined by the summation of partial saturation pressures of the complex mixture of water, hydrocarbons, and solids. At these elevated temperaturesand pressures, several critical reactions occur, impacting the stability and separation of drilling fluid components:

[0057] Thermal Degradation of Polymers: Polymers commonly added to drilling fluids for rheological control can undergo thermal degradation at high temperatures, leading to a loss of their effectiveness in maintaining fluid stability and viscosity.

[0058] Chemical Reactions: Components like emulsifiers, surfactants, and additives used in oil-based drilling fluids may undergo thermal decomposition at elevated temperatures, resulting in phase separation of aqueous and non- aqueous phases. Table 3 shows the degradation and decomposition temperature of surfactants used in drilling fluids.

[0059] Clay Swelling and Disintegration: The clay minerals present in drilling fluids can experience changes in their crystal structure at high temperatures, leading to swelling or disintegration and the separation of hydrocarbons. Cationic amines used in OBM will bind bentonite clays thereby preventing delamination of clay layer that inhibits the adsorption of water. The degradation of cationic amines results in the adsorption of water, making the clays hydrophilic and more oleophobic thereby making the clays disperse allowing for subsequent coagulation and flocculation.

[0060] Solubility Changes: The solubility of various compounds in the drilling fluid can change with temperature such as salts in the internal phase of the drilling fluids by precipitation of certain compounds that were previously dissolved in the drilling fluid.

[0061] Precipitation of solids or changes in the concentration of dissolved ions can affect the charges on clay particles leading to increased absorption of water and thereby resulting in separation of the hydrocarbons in the drilling fluid.Table 3 - Degradation and decomposition temperature of surfactants used in drilling fluids Surfactant Degradation Temperature (Approx.) Anionic Surfactants Exam les

[0062] Benefits of Hydrothermal Destabilization (HTD)

[0063] The hydrothermal destabilization technology offers a range of significant benefits for processing spent drilling fluids:

[0064] Fluid Recovery Yields: The process efficiently recovers 40% to 60% of the available fluid within the spent drilling fluid, reducing waste and resource consumption.

[0065] High-Quality Oil / Synthetic Recovery: The recovered base oil / synthetic boasts exceptional quality, containing less than 2% solids and less than 2% water. This high-quality recovered base oil / synthetic can be recycled and used in the formulation of new drilling fluids, without introducing any contaminants.

[0066] Heat Recovery: The technology allows for the recovery of heat generated during the hydrothermal process. This not only reduces overall energy consumption but also enhances the cost-effectiveness of the process.

[0067] Energy Efficiency: In comparison to thermal desorption methods, which demand high temperatures for hydrocarbon volatilization and consume energy for heat of vaporization, hydrothermal destabilization stands out as a more energy-efficient solution. It operates at lower temperatures, in a liquid phase, eliminating the need for heat of vaporization and energy for volatilizing hydrocarbons. As a result, the hydrothermal treatment and destabilization process consumes 79% less energy compared to thermal desorption.

[0068] Robust Process: The process exhibits robustness and is not sensitive to changes in fluid composition, including variations in particle size, oil / synthetic types, surfactant types or concentrations, clay types, or water contamination. This resilience is particularly valuable, as it mitigates issues often encountered with chemical-based solutions.

[0069] High Throughput: The technology can be configured in multiple setups, allowing for the processing of up to 400 barrels per day (bbl / day). This optimal processing rate facilitates efficient management of spent drilling fluid, minimizing storage requirements and enhancing logistical efficiency.

[0070] Minimal Non-Hazardous Chemicals: The process can be operated without the addition of chemicals, and when chemical additions are necessary, no hazardous chemicals are required. This reduces environmental and safety concerns associated with chemical usage while maintaining high recovery efficiency.

[0071] Referring now to the drawing figures, process or method embodiment 100 illustrated schematically in FIG. 1 presents a scheme where drill cuttings 10 contaminated with oil / synthetic based drilling fluid are separated with a bulk liquid - solid separator 11. A separated solid stream 14 is produced with the majority of the liquid portion removed; stream 14 is either disposed of or further treated. A separated liquid stream 12 contains a significant solids fraction requiring further liquid-solid separation 13 into a second solids stream which is combined with stream 14 for disposal or treatment. The separated liquid stream 13 is blended with spent drilling fluid 15. The blended spent drilling fluid, referred to as SDF 16 herein is subjected to pressure and heat in a reactor 18 for the selective decomposition of surfactants. With the surfactants decomposed, the SDF becomes destabilized 19 and is further cooled 20 and depressurized prior to mechanical separation 26. The separated solids 24 are combined with 14 and disposed of or treated. The recovered product fluid 27 consisting of base oil or base oil and brine containing salts in water is used for the makeup of new drilling fluid 29 with the addition of drilling fluid additives 28 previously destroyed along with traditional adjustments such as oil to water ratio, density, pH and other adjustments as necessary for drilling conditions.

[0072] FIG. 2 illustrates another system and method embodiment 200 in accordance with the present disclosure. In embodiment 200 one or more inorganic additives 17 such as an inorganic coagulant, acid or base pH adjustments, water, and / or catalysts are added to the SDF 16. Base oil ranging 1% - 50% may also be added which is not impacted by HTD. These are summarized in Table 4. The mixture enters the reactor 18 where it is subjected to heat and pressure followed by cooling and depressurization step 20. The cooled fluid 21 is further mixed with a coagulant 22 such as aluminum that can neutralize or destabilize the charge of clay particles. Most swelling clay platelets have a negative charge on the face and positive charge on the edges form “Time-dependent clay gels: Stepdown shear rate behavior, microstructure, ageing, and phase state ambiguity". Leong & Clode, Physics of Fluids 35, 123329 (2023). Once neutralized, a polymer flocculant 23 can be used to form well defined flocs for settling as traditionally used in separating solids in water based slurries by a mechanical separation step 26. The separated solids 24 are removed and disposed of or treated. The recovered product fluid 27 consisting of base oil or base oil and brine containing salts in water is used for the makeup of new drilling fluid 29 with the addition of drilling fluid additives 28 surfactants previously destroyed along with traditional adjustments as previously described herein.Table 4 –Pre HTD Treatment Additives Functional Examples Concentration Dosage Chemical Group Wt % of SDF

[0073] The input process streams may be in any combination of 0%:100% drill cuttings to spent drilling fluid or 100%:0% such that fluid from the drillings are blended with spent drilling fluid to form a feed slurry that contains oil and water of about 25% to 50% wt%, or 40% to 70% wt% or 60% to 95% wt%.

[0074] In certain embodiments a surface-based hydrothermal treatment system, including reactor 18, may be employed, where all high-pressure equipment is located above ground. In certain other embodiments, a sub-surface-based hydrothermal treatment system (including reactor 18) may be employed, where high-pressure and high-temperature hydrothermal treatment equipment is placed in a wellbore, with remaining equipment positioned above ground. These implementations offer flexibility and adaptability to diverse drilling and drilling waste management scenarios.

[0075] FIGS. 3A and 3B illustrates schematically another system and method embodiment 300 in accordance with the present disclosure. Embodiment 300 illustrates a hydrothermal treatment schematic to efficiently process drill cuttings and spent drilling fluids from drilling rig operations, major components, their purposes, design options, and availability. Drill cuttings 10 contaminated with oil / synthetic based drilling fluid are separated with a bulk liquid - solid separator 40 using a cuttings dryer basket centrifuge (cuttings dryer). The cuttings dryer serves the crucial function of separating bulk drilling fluid from drill cuttings, resulting in solid cuttings 14 with less than 5% dry wt% residual oil, suitable for disposal in landfills in most jurisdictions. It can achieve a processing rate of >20 t / hr., generating a liquid effluent with high solids content (>25% vol%) and fine particle size distribution (d90 <100 um). Cuttings dryers and decanting centrifuge equipment are available from manufacturers such as Elgin, Schlumberger (SLB), Halliburton, and National Oilwell Varco (NOV).

[0076] The separated liquid stream from cuttings drier 40 contains a significant solids ranging from 20% - 60% wt% fraction requiring further liquid-solid separation using a decanting centrifuge 41 into a second solids stream that is combined with solids 14 for disposal or treatment. A decanting centrifuge is available from numerous manufacturers such as Flottweg, Elgin, Alfa Laval, and GEA. These systems can process more than 4 m³ / hr. at over 1,500 g-force with up to 30% vol% of viscous solids.

[0077] The separated liquid stream 13 composed of drilling fluids with excess ultra- fine solids ranging from about 15% to about 50% wt% that were not separated with decanting centrifuge 41 are blended with spent drilling fluid (SDF) in mix tank 16. The composition and properties of this mixture can vary widely. Depending on the specific requirements, additives 42 such as catalysts, alkali, acids, water, and base oil / synthetic may be introduced to the SDF feed material as shown in Table 5. An acid treatment involves adding dilute acid, typically hydrochloric acid (HCl), to react with the clay surface, reducing its hydrophobicity and affinity for oil-wetting compounds (concentration range: 1% to 5% HCl by volume). A base treatment involves adding adilute base, like sodium hydroxide (NaOH), to deprotonate clay surface functional groups, reducing their affinity for oil-wetting compounds (concentration range: 0.1% to 2% NaOH by volume). Table 5 –Post HTD Treatment Additives Functional Examples Concentration Dosage Chemical Group Wt % of SDF

[0078] The blended SDF from 16 is pumped from ambient levels to up to 1,500 psi, in certain embodiments below 1,200 psi, and in some embodiments sometimes below 800 psi using high pressure progressive cavity pump 43. High-Pressure Pumps are available from manufacturers such as National Oilwell Varco (NOV) or Weatherford. Option 1 involves using a triplex pump commonly used for drilling fluid circulation, while Option 2 employs a single or dual-stroke piston pump, typically used for concrete pumping.

[0079] The high pressure SDF is introduced into the Preheat High-Pressure High- Temperature (HPHT) Heat Exchanger (HX) 44 to recover the thermal energy added to the SDF downstream. For example, 550 kW of heat may be recovered from the hot product fluid 47 to preheat the incoming drilling fluid feed at 100 tonnes / day. HPHT HXs such as Tube in Tube HXs are available from manufacturers such as Alfa Laval, Sacome, and Teralba Industries. Alternatively, a spiral heat exchanger that encompasses a spiral coil of multiple parallel tubes mounted within a casing. The case / coil construction creates a spiral flow path providing counterflow. High pressure, specialized materials, cyclic operation, temperature extremes, and other conditions can be handled easily. HPHT spiral heat exchangers are available from Graham Manufacturing. Another option design for a heat exchanger is to use a solid metal block HX in a housing where the block has holes drilled in a vertical and horizontal pattern. One fluid flows vertically through the holes and the fluid flows horizontally, thereby transferring heat via conduction. These block style heat exchangers are capable of high temperature and moderate pressure that include block materials like silicon carbide and available from GAB Neumann GmbH. Finally, another heat exchanger design is based on a cold plate heat exchanger concept where the hot fluid in a thin walled pipe that circulates through a cold metal casting. Specifically for this application, both the hot and cold fluid pipe are adjacent one another and completely encased in a metal plate or block except for the inlet and outlet. The heat is transferred via conduction. The benefit is the long pipe runs that can withstand high pressures with minimal connections which simplify construction and risk of leakage.

[0080] Once the fluid is preheated in the heat exchanger 44 to approximately 200 C, the fluid enters the Trim Heater 45 where the temperature of the fluid is raised to 250 C. Taking heat losses in consideration, approximately 200 kW of heating is required to process 100 t / day. As the temperature of the feed SDF slurry increases in 44 and 45, sufficient pressure must be applied to ensure that feed SDF slurry remains substantially (at least 95 percent, or at least 99 percent) in the liquid phase and above the liquid-gas saturation curve (FIG.4) as the feed slurry is heated and cooled in the reactor system for two reasons:

[0081] To ensure that steam is not generated that can impact fluid flow and heat transfer coefficient; and

[0082] To ensure energy is not wasted for the energy intensive step of water vaporization. The pressure in the system is generated by the hydrostatic pressure, as illustrated in the graph in FIG.4 which illustrates the feed SDF (upper straight dotted line) and reacted HTD fluid (lower straight dotted line) are not in proximity to the saturation line (curved dotted line) thereby eliminating the risk of steam and hydrocarbon vapor generation.

[0083] Four heating options are available - Option 1 uses a cable heater with a watt density of approximately 500 - 1,000 W / m placed inside the feed tube (suppliers: Thermon, Andmir, and Salamander). Option 2 employs external band heaters (suppliers: Tempco, Chromolox, and Omega), which may also include induction heating. Option 3 is a Countercurrent Tube in Tube HX similar to the HPHT heat exchanger with hot oil thermal fluid flowing on the annulus of the pipe (suppliers Alfa Laval and Teralba). Option 4 utilizes flanged heaters which consist of several hairpin elements or bugle tubular heater elements extending from the face of the flange. The heater elements directly heat the fluid. Flange can be constructed of stainless steel while the sheath materials can be stainless steel, Inconel, Hastelloy and titanium for corrosive drilling fluids. Flanged heaters use bent tubular elements that are brazed or welded onto a flange (suppliers: Wattco and Tempco).

[0084] The heated SDF fluid at the design temperature from the Trim Heater 45 continues to the Reactor 46. Under these hydrothermal temperatures > 150 and <250 C or >200 C and <250 C or >250 C and <300 C and pressure to maintain liquid phase of the fluid mixture, the degradation and decomposition of the surfactants without the degradation of the base oil. The Reactor 46 temperature is maintained at the target temperature by implementing similar heating methods as previously described in the Trim Heater 45.

[0085] The reacted product fluid exits the Reactor 46 and enters the HPHT heat exchanger 44 as previously described where the reacted fluid is cooled and the heat transferred to the incoming feed fluid. To ensure that the target temperature of < 50 C entering the depressurization system 50 is achieved, a Trim Cooler 48 is utilized. Depending on the chosen option, suppliers may include those offering plate and shell, countercurrent tube in tube or metal block conduction heat exchanger designs as previously described suitable for high pressure conditions. These trim cooler heat exchangers utilize a separate cooling fluid system 49 that provides the heat transfer medium, typically water. The excess heat in the cooling loop is removed using traditional methods such as air cooled fin fan coolers or cooling towers.

[0086] The pressurized and cooled reacted fluid enters the depressurization step 50. Depressurization is achieved using a labyrinth or multistage high-pressure control valve, available from suppliers like Baker Hughes or Mogas’ FlexStream Control Valve technology. Alternatively, a pressure letdown system that is more tolerant of abrasive solids consists of the use of two or more hydraulic pistons working alternatively. These pistons are mechanically connected to an external hydraulic circuit or spring that applies a resistance which dampens the high pressure allowing the depressurization with minimal wear. The high pressure fluid is directed to these pistons through a series of valves and the fluid is rotated through the pistons. The depressurized fluid from the cylinder exits for collection.

[0087] The cooled and depressurized reacted fluid undergoes a two-step liquid-solid separation. First, a non-mechanical bulk separator 51, such as a lamella separator or a surge tank, is used under gravity force. This gravity separator separates and collects fluid that readily floats to the top without any aid from chemical or mechanical means. This concentrates the solids fraction and thereby lowering the volume required for further processing. The second step utilizes a mechanical centrifuge 58, such as a tricanter or decanter centrifuge, accelerates separation based on density. Equipment for this purpose is available from numerous manufacturers such as Flottweg, Elgin, Alfa Laval, and GEA. These systems can process more than 4 m³ / hr at over 1,500 g-force with up to 30% vol% of viscous solids. Two options are available for centrifuge selection - Option 1 involves the use of a Tricanter centrifuge which can separate the reacted fluid into oil, water and solids fractions, while Option 2 employs a Decanter centrifuge which separates into liquid and solids fractions.

[0088] The mechanical liquid - solid phase separation of the reacted fluid using centrifuge 58 can be enhanced with the introduction of chemical aids as is typical of water treatment processes. Enhanced separation methods can be applied to improve efficiency of separating ultra fine solid particles, such as modifying water content, oil dilution, addition of coagulants, and polymer flocculants. These are summarized in Table 4. By way of example, coagulant 56 and flocculant 57 are shown added with a mix tank and pump 55. Coagulants could include iron or aluminum based coagulants such as ferric chloride, aluminum chloride or aluminum sulfate. Flocculants could include polyacrylamide, polyacrylates, polyamines, sodium polyacrylate, polyoxyethylene, polyvinylamine, polyvinyl sulfonate and polyethylene oxides. Coagulants and flocculants are available from suppliers such as Kemira, Veolia and Dow.

[0089] The separated and recovered fluid 59 from centrifuge 58 can be either pure oil or an oil and water / brine mixture. Both fluid types can be used as premix drilling fluid 27 where drilling fluid additives 26 such as surfactants that were degraded in the reactor46, adjusting the oil-to-water ratio, salts, pH adjustment chemicals, organophilic clays and any other adjustments to make a virgin drilling 28 suitable for drilling activity. These special additives are available from SLB, Halliburton and Baker Hughes.

[0090] The separated solids 24 from centrifuge 58 contains clay solids with residual oil / synthetic and water. The volume of the separated solids phase is significantly reduced, equivalent to <50% of the total feed volume, facilitating disposal or further treatment.

[0091] A clean in place system is utilized for routine cleaning and maintenance is not shown in the process flow diagram for simplicity. Components typically consist of water or oil, chemical injection pump, chemical storage, and a fluid collection tank.

[0092] FIG.5 illustrates a high-level process flow diagram and material balance of one system and method embodiment of the present disclosure which will be described in more detail herein in various embodiments. All streams are expressed in metric tons / day. Drill cuttings stream 10 includes 100 metric tons / day of 12 metric tons / day oil, 5 metric tons / day water, and 83 metric dry tons / day solids, as depicted in chart 110 are separated with a dryer 40 into substantially liquid stream 13 and solids stream 14. Solids stream 14 consists of 2.5 metric tons / day oil, 0.6 metric tons / day water, and 79.9 metric dry tons / day solids as depicted in chart 111. Spent drilling fluids stream 15 includes 86 metric tons / day of 40.5 metric tons / day oil, 11.6 metric tons / day water, and 30.9 metric dry tons / day solids, as depicted in chart 113 are blended with the fluid stream 15. The blended fluid stream 16 consists of 50.0 metric tons / day oil, 16.0 metric tons / day water, and 34.0 metric dry tons / day solids as depicted in chart 114 are feed to the reactor 45. The reacted products 17 are primarily fluid with minor gas products 53 consisting of 0.1 metric tonnes of CO2 gas and 0.0047 metric tonnes of methane as depicted in chart 115. The fluid stream 59 is further separated with a centrifuge 58 into a recovered fluid stream 59 consisting of 19.6 metric tons / day oil, 12.0 metric tons / day water, and 0.6 metric dry tons / day solids as depicted in chart 116. The decanted solids stream 24 from the centrifuge 58 consists of 30.3 metric tons / day oil, 4.0 metrictons / day water, and 33.3 metric dry tons / day solids as depicted in chart 117. The decanted solids stream 24 may be combined with the dryer solids stream 14 and routed to a thermal desorption recovery process for further recovery and disposal volume reduction.

[0093] An energy balance for the high-level process flow diagram illustrated in FIG.5 may use 0.6 MWh / day for equipment 40, 26 and plant ancillary equipment. The energy for the hydrothermal reactor 45 after heat recovery may use 4.8 MWh / day. Separation equipment 58 may use about 0.5 MWh / day giving a combined total energy input of 5.9 MWh / day. However, the recovered hydrocarbons will provide about 247 MWh / day of energy, providing a net benefit of 241 MWh / day or generating 41 times more energy than consumed. (“MWh / day” means megawatt hours per day.) 200 metric tonnes of CO2 are averted if the oil in the drilling fluid were allowed to decompose naturally over time.

[0094] FIG.6 schematically illustrates another system and method embodiment 400 in accordance with the present disclosure. Addressing the primary challenges associated with a surface-based hydrothermal system requires careful consideration of several factors. Firstly, the system operates at very high pressures and high temperatures, necessitating additional safety control systems, instrumentation, redundancy, and the selection of rugged and special metallurgy equipment. This, in turn, results in high footprint, capital expenditures (CAPEX) and operating expenditures (OPEX). Another challenge involves the movement of solids into and out of this high-pressure and high- temperature environment, which can lead to issues such as plugging, fouling, and significant wear and tear.

[0095] One critical aspect for economic viability is heat recovery, which demands a substantial surface area and specialized heat exchangers (HXs) designed to operate at the required temperature and pressure with slurries.

[0096] Overcoming these challenges can be achieved through the implementation of a novel deep wellbore reactor, 64. This deep well can safely and inexpensively generate the high pressures required via hydrostatic pressure by using commonly available metallurgy, wellbore dimensions and geometry. The depth of the well largely determines the pressure along with density of the slurry. The well 64 consists of an inner and outer tube where the SDF enters the inner tube to the bottom of the well and returns to the surface in the annulus. No high pressure pumping is required as the process takes advantage of the hydraulic U tube effect and hydrostatic pressure simultaneously. The SDF is heated at the bottom of the well to the target temperature but prior to reaching the bottom of the well, the return fluid in the annulus preheats the incoming fluid. The majority of the heat is recovered via the transfer of thermal energy from the hot fluid in the annulus to the incoming cold SDF. In this invention, the temperature of the preheated SDF feed in the inner tubing is boosted at the bottom portion of the well while under sufficient pressure to ensure the oil and water components in the SDF remain in a liquid phase for the hydrothermal degradation of the SDF surfactants. The heat source comes from a submersed electrical resistance heater cable which is commonly used in oil and gas production to reduce viscosity of heavy oils and waxes, provide flow assurance and to increase production or other methods of heating the inner tubing for those skilled in the art.

[0097] In the embodiment 400 as illustrated in FIG 6, input streams from drill cuttings 10, spent drilling fluid 15, use of cuttings dryer 40, blended spent drilling fluid 16, additives 42, gas-liquid-solid separation 41, 51, 52, 55, 56, 57, 58, liquid phase recovery 52, and clean in place methods are the same as those illustrated in FIG 3, surface based hydrothermal treatment system embodied in 200.

[0098] Depth and pressure are directly correlated with hydrostatic pressure. The graph of FIG.4 illustrates schematically the temperature and pressure of the feed SDF slurry (upper dashed line) of embodiment 500 as it travels down the inner pipe of the wellbore while increasing temperature and depth / pressure. The return HTD product fluid (lowerdotted line) exits the inner tube and travels to the surface as it decreases slowly in temperature and pressure. As previously indicated, the time spent in the HTD favorable environments should be maximized as further explained herein.

[0099] In certain embodiments, as in embodiment 500 illustrated schematically in FIG. 7, the well includes an inner tubing 70 and an outer tubing 71 where the feed slurry enters inner tubing 70 at the top 72 of the well at the surface 73 and flows to the bottom portion 72 of the well, and product fluid 21 returns to the surface in a microannulus 73 formed between inner tubing 70 and outer tubing 71. The outer tubing is placed inside the wellbore 72 between the casing 74. No high-pressure pumping is required as the systems and methods take advantage of the hydraulic U tube effect and hydrostatic pressure simultaneously. SDF slurry is heated at the bottom of the well to the target temperature by a heating element 75 of an electric cable 76 but prior to reaching bottom portion 77 of the well, while product fluid 19 returning in microannulus 73 preheats the incoming biomass slurry 16. The majority of the heat in product fluid 19 is recovered via the transfer of thermal energy from the hot product fluid 19 flowing upward in microannulus 73 to the incoming cold feed SDF slurry 16 in a heat transfer and coalescing zone 78. In systems and methods of the present disclosure, the temperature of the preheated feed slurry in inner tubing 70 is boosted at bottom portion 77 (HTD reaction zone) of the well under pressure to ensure the SDF slurry fluid remains as a liquid for the hydrothermal reactions to occur. The well will essentially be our reactor. The heat source comes from the submersed electrical resistance heater cable (75, 76) powered by a power source 79, which may employ grid power or other power) which is commonly used in oil and gas production to reduce viscosity of heavy oils and waxes, flow assurance and to increase production or other methods of heating inner tubing 70. Also illustrated in FIG.7 are pressure chart 80, depth chart 81 based on an example feed slurry density of 1.47 kg / L.

[0100] To perform the efficient operation of an HTD plant in terms of total operating costs and optimal physio-chemical performance, certain systems and methods of thepresent disclosure may employ: (a) energy recovery; (b) feed slurry preheating; c) boost heating to reach HTD temperature; and d) drilling fluid and / or insulating gels and / or cements having insulating properties to minimize heat losses. Some or all of these may be satisfied by the design of specific thermal components, as well as configuration design of the processing systems. In certain embodiments, thermal management in systems and embodiments of the present disclosure may include one or more of the following components: (1) a heat exchanger which is designed to ensure the thermal energy recovery with primary functions of SDF slurry preheating and product fluid cooling; (2) the electrical heater, which serves to boost the temperature after pre- heating; and (3) the well reactor where the majority of chemical HTD reactions occur.

[0101] In certain embodiments, the well can be a non-producing oil and gas well which is an operational liability to the owner of the well requiring an expensive plug and abandonment procedure. In addition, a non-producing well can be an environmental liability that can leak fluids and methane into the environment. Methane is more than 25 times as potent as carbon dioxide at trapping heat in the atmosphere. The systems and methods of the present disclosure turn these liabilities into valuable assets. The technology reverses these negative environmental impacts while simultaneously generating a recycled fluid thereby significantly reducing greenhouse gas (GHG) emissions.

[0102] FIG.8 schematically illustrates another system and method embodiment 600 in accordance with the present disclosure. As illustrated schematically in FIGS.6 of my co-pending United States provisional patent application number 63379127, the well is constructed using an existing oil and gas production well, so that terminology is used. The well includes of production tubing or coiled tubing 104 serving as the inner tubing, and a insulated tubing 107 serving as an outer tubing that is placed inside a production casing 102 that is bonded to the subsurface formation 82 using cement 90, forming a well annulus 106 and a microannulus 108 between the inner tubing and insulated tubing. Multiple inner tubes could be used but for simplicity, only one is described inthis embodiment. “Casing” in this embodiment includes a conductor casing 92, surface casing 94, intermediate casing 96, and production casing 102. “Insulated Tubing” refers to a set of concentric pipes with an insulating layer between them. When the insulating layer is a vacuum, it is referred to as “Vacuum Insulated Tubing”. The inner tubing 104 length is selectively sized (or modified as described in other embodiments to achieve the selected length) to achieve the desired hydrostatic pressure. In embodiment 500 the inner tubing 104 length is typically about 700 m. This type of well construction is commonly used in the production of oil and gas.

[0103] Referring to FIGS.9, another well HTD reactor embodiment 700 of the present disclosure is presented, comprising two primary zones and a third zone:

[0104] Heat Transfer & Sub-surface Coalescence Zone (120);

[0105] HTD Reaction Zone (121); and

[0106] Return (product) fluid plenum (122).

[0107] In the Heat Transfer & Sub-surface Coalescence Zone 120, hot product HTD fluid that is heated at the bottom of the well travels to the surface in microannulus 73. The HTD fluid in zone 120 preheats incoming feed slurry stream 16 in inner tubing 71 from ambient to approximately 200 ºC. Most of the heat is recovered via the transfer of thermal energy from the hot product fluid in microannulus 73 to incoming cold feed slurry 16 in inner tubing 71 while the remaining heat is lost to the exiting product fluid 19, wellbore 72 and the formation 82. In addition, the reacted fluid with the surfactants decomposed or substantially decomposed from the HTD reactions coalesce the oil and water phases in microannulus 73 in zone 120. The coalescence aids in the separation with equipment at the surface (51, 58). There is sufficient hydrostatic pressure to ensure that the water does not boil to steam.

[0108] In HTD Reaction Zone 121, the temperature of preheated feed slurry 16 flowing downward in inner tubing 70 is boosted from about 200 ºC to about 250 ºC at the bottom portion of the well, 121. At this depth and in zones 120, 121, the feed SDF slurry isunder sufficient pressure to ensure the fluid remains as a liquid and not turn to steam or hydrocarbon vapors which is critical for managing volume in the wellbore 72. The heat source comes from a submersed electrical resistance heater cable 75 inside inner tubing 70 which has an open ending. The inner tubing is isolated and encased by the outer tubing 71 within the wellbore 72. The outer tubing 71 has a closed and sealed end to create the plenum zone 122. A cement plug 123 is used to isolate the remaining portion of the wellbore 72 from zones 120, 121 and 122.

[0109] As the temperature of the feed slurry 16 increases, sufficient pressure must be applied to ensure that feed slurry 16 remains substantially (at least 95 percent, or at least 99 percent) in the multicomponent hydrocarbon and water liquid phase and above the liquid-gas saturation curve (FIG. 4) as the feed slurry is heated and cooled in the deep well reactor system for two reasons:

[0110] To ensure that steam and hydrocarbon vapors are not generated that can impact volumetric fluid flow and heat transfer coefficient; and

[0111] To ensure energy is not wasted for the energy intensive step of water and hydrocarbon vaporization. The pressure in the system is generated by the hydrostatic pressure, as illustrated in the graph in FIG.4 which illustrates the feed SDF slurry (upper straight dotted line) and return HTC fluid (lower straight dotted line) are not in proximity to the saturation lines of water (curved solid line) and example hydrocarbons decane (square dotted) and dedecane (triangle dotted) that may be used in the makeup of a drilling fluid, thereby eliminating the risk of steam and hydrocarbon vapor generation.

[0112] Ideally, the heater section 121 covers the bottom 100 - 300 meters of the inner feed tube length. These cable heaters typically offer specifications of up to 1,300 W / m, a maximum temperature of up to 300°C, a diameter of less than 25 mm, and a capacity of 200 kW. Higher lineal watt density and smallest diameter is preferred that can be placed either inside or outside inner tubing 70 so long as flow velocities and residencetimes are generally the same. Manufacturers such as Salamander, Andmir, and Thermon offer such equipment.

[0113] While there is no standard well design given the numerous possible combinations of tubing lengths, tubing diameters, metallurgy, thickness, connectors, and the like, the following example provides insight into the process equipment and methods, operating parameters, features and limitations that determine deep well HTD reactor design. (Refer to Table 6.) Table 6 Well Construction Mechanics Cable in Cable in Configuration Microannulus Inner Tubing

[0114] Since there is no advantage in higher pressures to promote hydrothermal decomposition reactions, the length of inner tubing 70 (FIG.9) should be kept to the minimum length to minimize heat losses to the environment, cost of power and heater cable (76, 75), cost of insulated tubing (71), reduce repairs / maintenance and well intervention costs. If greater residence time is required, the length of inner tubing 70 could be increased and / or increase the diameter of outer tubing (insulated tubing) 70.

[0115] Most existing oil and gas production wells exceed the typical depth required for HTD reactions. Therefore, in certain embodiments using such wells, the well may be sealed from the unused bottom portion of the well. The well can be sealed at depths ranging from about 5 to about 10 m below a bottom or distal end of the outer tubing 71 to allow for the thermal expansion. There are three primary methods of sealing a well at the bottom of the outer tubing that are commonly used in oil and gas well construction: cement plug, cast iron bridge plug and packer which is shown as 123. The plug 123 prevents the flow of fluids or gasses via lower plenum from the original oil and gas bearing formation. The inner tubing 70 is isolated and encased in the outer tubing 71 where the inner tubing has an open end to create an upper plenum above the bottom of the sealed outer tubing 71 to ensure sufficient space in the upper plenum for the fluid 16 to reverse flow towards the surface in the microannulus 73 and allow for the thermal expansion of inner tubing 70 (calculations indicate that the inner tube 70 will expand and grow in length approximately 0.9 – 1.3 m depending upon steel type).

[0016] Multiple Feed Slurry Tubes

[0117] For maximum capital, footprint, startup and heat loss efficiency, in certain embodiments, such as embodiment 800 illustrated schematically in FIGS.10 and 10A, multiple feed SDF slurry inner tubings 70 may be placed inside an insulated tubing 71 and may be utilized within a single wellbore, each having its own heater cable 75. The wellbore geometry should be such that the fluid velocities, residence times and flow regimes remain in the same range as outlined herein. Generally, this would involve a larger diameter outer tubing (insulated tubing) 71 to accommodate a larger flow through microannulus 73. In these embodiments the flow to each inner tubing 70 would be controlled to be independent and monitored so as not to have reverse flow. It will be understood that other embodiments are possible than those illustrated in FIGS.10 and 10A. For example, the number of inner tubing 70 and heater cables 75, 76, may be lower or higher than illustrated. FIG.10A illustrates a cross section of a wellbore withseven inner tubing 70 and seven heater cables 75 within an outer insulated tubing 71 placed inside casing 74.

[0118] To perform the efficient operation of the plant in terms of total operating costs and optimal physio-chemical performance, several requirements are imposed to the thermal part of the processing system: (a) energy recovery; (b) feed SDF preheating; c) trim heating to reach temp; d) minimize heat losses. These have been satisfied by the design of the specific thermal components, as well as configuration design of the processing system. The thermal processing system consists of three major components: (1) the heat exchanger which is designed to ensure the thermal energy recovery with primary functions of SDF preheating and product cooling; (2) the heater, which serves to boost the temperature after pre-heating; and (3) the reactor where the majority of thermo-chemical reactions occur.

[0119] To ensure that the product fluid 21 exiting the annulus of the wellbore is cooled to below 50°C and to maximize energy recovery while minimizing the heat output from the cable heater, a low pressure heat exchanger 63 is employed that is designed for low pressures and temperatures, typically around 100 psi and 150°C, resulting in cost- effective solutions. These heat exchangers can be sourced from numerous manufacturers like Alfa Laval or Xylem. Option 1, the preferred choice, involves a plate and frame heat exchanger with Treated Fluid on the hot side and Feed Drilling Fluid on the cold side. This configuration is commonly used in mud cooling applications during drilling in hot formations. Option 2 is a Countercurrent Tube in Tube HX with feed flowing in the annulus of the pipe. Option 3 is a Spiral HX which is suited for fluids with high solids, high viscosities and high fouling tendencies. Spiral HX are available from Alfa Laval, Shineheat Corp and Elanco Heat Exchangers.

[0120] The well 72 can potentially be a non-producing oil and gas well which is an operational liability to the owner of the well requiring an expensive plug and abandonment procedure. In addition, a non-producing well can be an environmental liability that can leak fluids and methane into the environment. Methane is more than25 times as potent as carbon dioxide at trapping heat in the atmosphere. The technology turns these liabilities into valuable assets. The technology reverses these negative environmental impacts while simultaneously becoming a method to generate a refined base oil for recycling or energy that would have normally decomposed in the atmosphere thereby significantly reducing GHG emissions.

[0121] Pumping pressures are significantly lower in this process as the pump is only required to overcome friction losses in the wellbore in the feed tube and annulus. No high pressure pumping is required as the process takes advantage of the hydraulic U tube effect and hydrostatic pressure simultaneously. Pump 62 increases the SDF feed slurry pressure from ambient levels to typically around 150 psi with a range of 0 psi - 700 psi. These pumps can be multistage centrifugal or progressive cavity or plunger types, all of which are readily available from multiple suppliers such as National Oilwell Varco and SLB. The pressure is increased inside the wellbore based on the hydrostatic head, which depends on the depth of the wellbore (typically 500 - 700 meters). As the product fluid 19 is returned via the microannulus in the wellbore, the pressure gradually decreases with decreasing depth, requiring no specialized depressurizing equipment, a significant advantage.

[0122] FIG.11 illustrates the outer insulated tubing 71 consists of an enclosed welded double wall structure where the prestressed inner tube 136 fitted into the outer tube 134 of the insulated tubing. Stabilizer blocks 137 are placed intermittently between the double walls to provide additional structural integrity. The internal space between the double wall jacket can be a vacuum or insulated material 135 such as aerogel or low thermal conductivity material suitable for high temperatures. To minimize heat loss at the coupling 131, an additional insulated liner 132 is placed in the coupling along with a seal ring 133 to prevent leakage of fluid in the coupling. The insulated tubing is designed to minimize heat losses to the formation and should have an overall thermal conductivity of <0.15 W / m K where lower is preferred. The insulated tubing / pipe sections are joined together with a coupler making up the desired length of the wellborewith an inner diameter of 50 mm - 200 mm. The insulated tubing is commonly used for heavy oil and bitumen extraction, steam flooding and for controlling paraffin deposits in wellbores. Insulated tubing is available from Exceed Oilfield Equipment, Shen Ji, Nakasawa and Vallourec.

[0123] In addition to the general benefits of hydrothermal destabilization, methods and systems illustrated in embodiment 400, involving subsurface hydrothermal destabilization reactor illustrated in embodiments 500,700, 800, offers specific advantages:

[0124] Mitigation of High-Pressure Challenges: The Hydrothermal Treatment and Destabilization DeepWell Reactor effectively addresses the challenges associated with high pressures and temperatures. It minimizes the risk of plugging, fouling, and wear and tear associated with solids movement in high- pressure and high-temperature environments.

[0125] Cost Efficiency: Hydrothermal destabilization, with its energy efficiency, heat recovery capabilities, and reduced well depths, offers cost- effective processing of spent drilling fluids. The long-term savings and efficiency improvements outweigh any initial capital expenditure (CAPEX) and operating costs (OPEX).

[0126] Additional benefits are possible by reducing well depths based on factors such as higher fluid density, lower partial saturation pressures based on fluid composition, and higher surface pumping pressure. Shallow well depths result in reduced capital expenditure (CAPEX) and heat loss to the formation, enhancing cost efficiency.

[0127] Examples

[0128] Testing of the feed drilling fluid (DF) was conducted in accordance with the American Petroleum Institute (API) Recommended Practice 13B-2 (RP 13B-2) thatestablishes recommended practices for field testing oil-based drilling fluids. Table 5 tabulates the properties of the DF used for the hydrothermal destabilization testing tabulated below in Table 7 using the following test methodology. Table 7. Feed Material Drilling Fluid A Properties Drilling Fluid Type Invert diesel

[0129] The DF was mixed until homogenous and fluid characteristics were measured. A 200 ml DF sample was poured into a 500 ml Parr Autoclave Reactor cell with controller Model. No catalysts, pH adjustments or additives were made. The temperature of the cell was increased gradually at 5°C per minute until the target temperature of 250°C was reached. The pressure generated autogenically in the cell. The mixer was set at 120 rotations per minute. Temperature and pressure was recorded. Residence Time was adjusted between tests. After the hydrothermal reaction was complete, the cell was cooled at approximately 20°C per minute initially, and 2°C per minute at the end of the cooling cycle, reaching the final temperature of 40°C.

[0130] A gas sample of the headspace in the cell was taken using a Tedlar bag for gas chromatography (GC-TCD) analysis before opening the cell to remove DF fluid.

[0131] The reacted product DF was poured into a 250 ml beaker where any fluid was allowed to breakout and separate. This breakout fluid under gravity was decanted and measured. A 25 ml sample of the fluid settled fluid was poured into a 50 ml centrifuged tube and centrifuged in laboratory centrifuge at 4,000 rpm for 5 minutes, generating approximately 1800 g-force to emulate a typical field decanter centrifuge. The volume of the liquid and solids phases in the graduated centrifuge tubes was measured to calculate the oil recovered from the DF. General observations of the physical state of the centrifuged DF was made including the physical characteristics of the phases, flocculation of the solids, color, clarity and rheological properties of the phases. See Table 8.Table 8. Lab Test Results No HTD HTD HTD HTD HTD Test #1 Test #2 Test #3 Test #4

[0132] From the foregoing detailed description of specific embodiments, it should be apparent that patentable systems and methods have been described. Although specific embodiments of the disclosure have been described herein in some detail, this has been done solely for the purposes of describing various features and aspects of the systems, methods and media, and is not intended to be limiting with respect to the scope of thesystems, methods and media. It is contemplated that various substitutions, alterations, and / or modifications, including but not limited to those implementation variations which may have been suggested herein, may be made to the described embodiments without departing from the scope of the appended claims.

Claims

Claims:

1. A method for separating hydrocarbon fractions from an emulsified thermodynamically stable slurry comprising water, hydrocarbons, ultra-fine solids and stabilizing surfactants, comprising: a) subjecting the slurry to a controlled elevated temperature and a controlled elevated pressure while maintaining a liquid phase; b) while at the controlled elevated temperature and the controlled elevated pressure, thermally degrading and decomposing the stabilizing surfactants, and destabilizing the liquid phase; and c) mechanically separating the liquid phase into a substantially hydrocarbon phase, a substantially water phase, and a substantially solids phase.

2. The method of claim 1, wherein the elevated temperature ranges from about 200°C to about 300°C, and the elevated pressure ranges from about 500 psi to about 2,000 psi.

3. The method of claim 1, wherein the emulsified thermodynamically stable slurry comprises spent drilling fluids having an oil / water ratio ranging from about 99:1 to about 10:

90.

4. The method of claim 1, wherein the thermally degrading and decomposing the stabilizing surfactants comprises thermally degrading and decomposing anionic, cationic, nonionic, amphoteric and polymeric polymers used in drilling fluids, and occurs the elevated temperature ranging from about 200°C and 300°C in the liquid phase.

5. The method of claim 1, wherein the emulsified thermodynamically stable slurry comprises clay minerals which undergo changes in crystal structure at the elevated temperature, the elevated temperature ranging from about 200°C to about 300°C, leading to swelling or flocculation for mechanical separation.

6. The method of claim 1, further comprising the addition of inorganic additives such as coagulants, acids, bases, or catalysts to enhance the destabilization process, wherein the elevated temperatures range from 200°C to 300°C in liquid phase.

7. The method of claim 1, further comprising the addition of coagulants and / or flocculants to the destabilized liquid phase prior to the step of mechanically separating the liquid phase.

8. The system of claim 1, wherein the step of mechanically separating the liquid phase employs a mechanical separator selected from centrifuges, filters, and combinations thereof.

9. The method of claim 1, further comprising blending some or all of the substantially hydrocarbon phase and some or all of the aqueous phase are used for the makeup of new drilling fluids.

10. A system for hydrothermal treatment of drilling fluids, comprising: a) an inner tubing configured to receive a feed slurry, the inner tubing positioned within an outer tubing; b) the outer tubing positioned within a wellbore; c) the inner tubing having a length in the wellbore sufficient to produce hydrostatic pressure inside of the inner tubing to maintain the feed slurry and a product fluid in the inner tubing in liquid phases at all times; d) a heat transfer and coalescence zone in which hot product fluid preheats the feed slurry while coalescing oil and water phases in the feed slurry, and flocculating clay solids; e) a hydrothermal destabilization reaction zone in which the preheated feed slurry is heated to a target temperature using a submersed electrical resistance heater cable;f) a return fluid plenum formed between the inner tubing and the outer tubing, where the product fluid exits and transfers thermal energy to the feed slurry, ensuring the feed slurry remains in a liquid phase throughout the hydrothermal degradation process.

11. The system of claim 10, wherein the wellbore serves as a deep wellbore reactor for the hydrothermal destabilization.

12. The system of claim 10, wherein the inner tubing length is selectively sized to achieve the desired hydrostatic pressure.

13. The system of claim 10, wherein the submersed electrical resistance heater cable has a lineal watt density of up to 2,000 W / m and a maximum temperature of up to 350°C.

14. The system of claim 10, wherein pressure in the system is generated primarily by the hydrostatic pressure, ensuring that the feed slurry remains substantially in the multicomponent hydrocarbon and water liquid phase throughout the hydrothermal degradation process.

15. The system of claim 10, wherein the outer tubing is an insulated tubing consisting of a double walled tubing with insulating material or vacuum within the double walls.

16. A method for efficiently operating a plant for hydrothermal treatment of drilling fluids, comprising: a) recovering thermal energy from a product fluid; b) preheating a feed slurry using the recovered thermal energy; c) boost heating the preheated feed slurry to reach a target hydrothermal degradation temperature to form a heated slurry.

17. The method of claim 16, wherein thermal energy recovery involves using a high pressure high temperature heat exchanger designed to ensure thermal energy recovery for the feed slurry preheating and product fluid cooling.

18. The method of claim 16, wherein the preheating of the feed slurry comprises heating the feed slurry to 200 - 300 C indirectly or directly while maintaining system pressure.

19. The method of claim 16, wherein the heated feed slurry undergoes decomposition reactions in a reactor suitable to withstand pressures ensuring aqueous and non-aqueous components in the feed slurry remain in liquid state for a period of time greater than 15 minutes.

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