Methods of enhancing oil recovery from tight subterranean hydrocarbon reservoirs

Abstract

Methods are disclosed for enhancing hydrocarbon recovery from tight subterranean reservoirs using dimethyl ether (DME) in a cyclic enhanced oil recovery (EOR) process. The methods include injecting DME into a hydraulically fractured well, allowing the DME to soak within the reservoir to promote diffusion-dominated mixing with resident hydrocarbons, and producing hydrocarbons and DME from the well, wherein the DME may be separated and reused in subsequent cycles. In certain embodiments, the cyclic EOR process is designed and optimized using a mathematical transport model that represents diffusion-controlled mass transfer of DME between a fracture network and a tight reservoir matrix. The model may incorporate one-dimensional diffusion equations derived from Fick's law. effective diffusion coefficients accounting for pore-scale properties, and scaling parameters that relate laboratory-scale behavior to field-scale fracture spacing. Model outputs are used to select injection, soaking, and production parameters to improve solvent penetration, reduce oil viscosity, and increase hydrocarbon recovery relative to non-optimized cyclic EOR processes.

Description

FILED MARCH 24, 2026 P2977PC01 (2024-052)METHODS OF ENHANCING OIL RECOVERY FROM TIGHT SUBTERRANEAN HYDROCARBON RESERVOIRS RELATED APPLICATIONS

[0001] This application claims the benefit of United States Provisional Patent Application Serial No.63 / 776,896 filed March 24, 2025 and entitled, “Methods of Enhancing Oil Recovery from Tight Subterranean Hydrocarbon Reservoirs,” the disclosure of which is incorporated by reference as if fully set forth herein.FIELD OF THE INVENTION

[0002] The present disclosure is generally related to methods for carrying out enhanced oil recovery processes to increase the recovery of petroleum products from subterranean wells.BACKGROUND OF THE INVENTION

[0003] Enhanced oil recove ly (EOR) techniques have long been employed to increase hydrocarbon recovery beyond that achievable through primary and secondary production methods. Such techniques include thermal processes, chemical flooding, and gas injection strategies intended to improve reservoir drive mechanisms, reduce oil viscosity, or enhance sweep efficiency. In recent years, as unconventional and tight formations have become increasingly important sources of hydrocarbon production, EOR methods have been adapted for use in low-permeability reservoirs where traditional flooding approaches are impractical. Among these adapted techniques, cyclic injection processes— commonly referred to as "huff-and-puff methods-have received significant attention due to their ability to utilize a single wellbore for both injection and production, thereby reducing surface infrastructure and well pattern requirements.

[0004] In a typical huff-and-puff operation, a fluid such as a gas, solvent, or combination thereof is injected into a producing well during a first phase, followed by a soak period intended to promote pressure redistribution, fluid mixing, or viscosity reduction within the formation, and a subsequent production phase in which mobilized hydrocarbons are produced back through the same well. While such techniques have been demonstrated to yield incremental recovery in certain reservoirs, their performance has been inconsistent and highly dependent on reservoir characteristics, fracture connectivity, inj ectant composition, and operational parameters.FILED MARCH 24, 2026 P2977PC01 (2024-052)

[0005] Due to the tight flow characteristics, conventional miscible and immiscible flooding EOR techniques using injector and producer well pairs may not apply to unconventional shale reservoirs. As a result, over the past decade, the industry has shifted to cyclic miscible gas huff-and-puff EOR from the same well. Although multiple wells on a pad (or field) may be part of the huff-and-puff EOR implementation, the application is a single-well technique in which the miscible gas is injected, and the remaining oil is produced from the same well, as illustrated in FIG. 1. The method involves injecting a miscible gas into a well (referred to as the injection or “huff’ phase), shutting in the well for some amount of time to allow the injected gas to mix with the remaining oil (soaking phase), and then producing back hydrocarbons from the same well (production or “puff’ phase). These are three distinct phases for each huff-and-puff cycle, each lasting between 15 to 90 days, and then the cycle is repeated multiple times to recover the remaining oil in the shale matrix.

[0006] FIG. 1 shows a schematic of the cyclic EOR process. During the gas injection (or huff) phase, the injected fluid is injected into the tight rock to increase the reservoir pressure and achieve miscibility with the remaining oil during the soaking period (or shut-in) phase to reduce oil viscosity, followed by the produced fluids (or puff) stage in which the less viscous oil is produced back. Although miscible gas huff-and-puff EOR has now been field-tested in several shale plays in the U.S. (Eagle Ford, Bakken, Permian, and SCOOP / STACK), the trials have had varying degrees of success. The gas injectivity into the tight shale reservoirs has not been the issue. However, pressure buildup or increasing reservoir pressure above minimum miscibility pressure (MMP) to achieve miscibility has been challenging primarily due to the lack of containment of the injected gas within the drainage area of the treatment well. Additionally, the lack of optimization of the injected gas composition results in asphaltene deposition during the miscible gas injection process, further reducing the efficacy of the gas injectants. As a result, although operators have expected incremental recoveries in the range of 30-70% of the primary recovery, the actual recoveries after three to five years of huff-and-puff have been typically 10-40%. Lastly, in addition to less-than-expected oil recoveries, the large initial investment required for high-horsepower compressors and gas pipelines to source the inj ectant has resulted in less attractive project economics.

[0007] The use of conventional gas injectants also requires expensive high-horsepower compressors with large surface (pad-size) and carbon footprint impact, which can adversely impact projectFILED MARCH 24, 2026 P2977PC01 (2024-052)economics. Because existing injectant gases like CO2 and field gas occur naturally in the tight subterranean reservoirs, it can be challenging to track the injected gas and separate or extract it from the produced well stream fluid for recycling and reinjection. Compared to produced field gas that is rich in methane, CO2 has lower miscibility pressure but is corrosive in nature, thereby requiring wellbore tubulars to be rated for sour service and additional facility costs.

[0008] Thus, challenges commonly associated with huff-and-puff EOR include limited containment of injected fluids, difficulty in achieving and maintaining favorable in-situ conditions, suboptimal utilization of injected energy or materials, and uncertain project economics. As a result, there remains a need for improved systems and methods that enhance the effectiveness, predictability, and economic viability of cyclic EOR operations, particularly in unconventional and tight formations.BRIEF DESCRIPTION OF THE DRAWINGS

[0009] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate one or more implementations described herein and, together with the description, explain these implementations. The drawings are not intended to be drawn to scale, and certain features and certain views of the figures may be shown exaggerated, to scale or in schematic in the interest of clarity and conciseness. Not every component may be labeled in every drawing. Like reference numerals in the figures may represent and refer to the same or similar element or function.

[0010] FIG. 1 depicts three phases of a typical EOR process: (i) gas injection; (ii) soaking period; and (iii) production of fluids from the well.

[0011] FIG. 2 is a diagram of oil production rates over a period that includes periodic EOR injection following primary recovery of petroleum products.

[0012] FIG. 3 is a graph illustrating the liquid-vapor equilibrium characteristics of DME compared to n-propane and n-butane.

[0013] FIG. 4 compares the oil rate, cumulative oil production, bottom hole pressure, and cumulative water production for comparative EOR application suing field gas, CO2 and DME.

[0014] FIG. 5 shows the mole fraction of field gas injectant in the oil phase (a proxy for oil solubility) and oil viscosity changes at the six different grid blocks of the experimental well.

[0015] FIG. 6 shows the oil mole fraction for CO2 and DME, together with the oil viscosities, at different locations relative to the hydraulic fractures.FILED MARCH 24, 2026 P2977PC01 (2024-052)

[0016] FIG. 7 shows the perforation to matrix profile along the hydraulic fracture for the first injection cycle for Scenario 2 (field gas inj ectant).

[0017] FIG. 8 shows the perforation to matrix profile along the hydraulic fracture for the first injection cycle for Scenario 9 (CO2 gas inj ectant).

[0018] FIG. 9 shows the perforation to matrix profile along the hydraulic fracture for the first injection cycle for Scenario 10 (DME inj ectant).

[0019] FIG. 10 depicts steps of an EOR process in which DME is the injectant.DETAILED DESCRIPTION

[0020] The present disclosure is directed at methods of enhancing recovery of oil from subterranean reservoirs. Instead of the gas inj ectants currently being used by the oil and gas industry for EOR process, the novel process involves the use of a liquid solvent that is optimally designed for each phase of the cyclic process based on the production response. Additionally, the produced liquid solvent is easily extracted from the production well stream, and reinjected for the subsequent cycle, thereby reducing material costs. In exemplary embodiments, the method includes the steps of: (1) recurrent injection of a novel solvent into a partially depleted hydraulically-fractured horizontal well (the injection phase); followed by (2) a predetermined soaking time (the soaking phase) to allow the solvent to mix with the remaining hydrocarbons in the subterranean reservoir; followed by (3) recovering the hydrocarbon mixture (the production phase); then (4) recovering the solvent from the hydrocarbon mixture; and (5) reinjecting the recovered solvent into the well.

[0021] In some embodiments, the present disclosure is directed at the novel use of a liquid injectant, Dimethyl Ether (DME), as part of an EOR process to enhance oil production from subterranean shale reservoirs using DME shows transformative benefits to currently available technologies using gas inj ectants like CO2 and produced gas in the field. DME is an industrial chemical widely used as a liquid refrigerant and aerosol propellant. In recent years, it has been used as a replacement for transport fuels and, with characteristics similar to liquified petroleum gas (LPG), in domestic applications for cooking and heating. It is used extensively in the chemical industry because it is miscible with most organic solvents and has a high solubility in water.

[0022] In certain embodiments, the enhanced oil recovery process is actively controlled and configured based on outputs of a mathematical transport model, such that physical operating parameters of the wellFILED MARCH 24, 2026 P2977PC01 (2024-052)are selected, modified, or terminated in response to model-predicted diffusion behavior of the injected solvent. In these embodiments, the mathematical transport model is not used merely for simulation or analysis, but rather functions as a process-control tool that governs injection volume, soaking duration, and production timing to achieve improved hydrocarbon recovery under field conditions. The disclosed methods provide a technological improvement to cyclic enhanced oil recovery operations in tight reservoirs by enabling diffusion-dominated solvent transport to be predicted and exploited in a manner that was not previously possible using empirical cycle timing or pressure-based heuristics.

[0023] Before further describing various embodiments of the compositions and methods of the present disclosure in more detail by way of exemplary description, examples, and results, it is to be understood that the embodiments of the present disclosure are not limited in application to the details of compositions and methods as set forth in the following description. The embodiments of the composition and methods of the present disclosure are capable of being practiced or carried out in various ways not explicitly described herein. As such, the language used herein is intended to be given the broadest possible scope and meaning; and the embodiments are meant to be exemplary, not exhaustive. Also, it is to be understood that the phraseology and terminology employed herein is for the purpose of description and should not be regarded as limiting unless otherwise indicated as so. Moreover, in the following detailed description, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to a person having ordinary skill in the art that the embodiments of the present disclosure may be practiced without these specific details. In other instances, features which are well known to persons of ordinary skill in the art have not been described in detail to avoid unnecessary complication of the description. While the apparatus and methods of the present disclosure have been described in terms of particular embodiments, it will be apparent to those of skill in the art that variations may be applied to the apparatus, compositions and / or methods and in the steps or in the sequence of steps of the method described herein without departing from the concept, spirit, and scope of the inventive concepts as described herein. All such similar substitutes and modifications apparent to those having ordinary skill in the art are deemed to be within the spirit and scope of the inventive concepts as disclosed herein.

[0024] All patents, published patent applications, and non-patent publications referenced or mentioned in any portion of the present specification are indicative of the level of skill of those skilled in the art toFILED MARCH 24, 2026 P2977PC01 (2024-052)which the present disclosure pertains, and are hereby expressly incorporated by reference in their entirety to the same extent as if the contents of each individual patent or publication was specifically and individually incorporated herein.

[0025] Unless otherwise defined herein, scientific and technical terms used in connection with the present disclosure shall have the meanings that are commonly understood by those having ordinary skill in the art. Further, unless otherwise required by context, singular terms shall include pluralities and plural terms shall include the singular.

[0026] As utilized in accordance with the methods and compositions of the present disclosure, the following terms, unless otherwise indicated, shall be understood to have the following meanings:

[0027] The use of the word "a" or "an" when used in conjunction with the term "comprising" in the claims and / or the specification may mean "one," but it is also consistent with the meaning of "one or more," "at least one," and "one or more than one." The use of the term "or" in the claims is used to mean "and / or" unless explicitly indicated to refer to alternatives only or when the alternatives are mutually exclusive, although the disclosure supports a definition that refers to only alternatives and "and / or." The use of the term "at least one" will be understood to include one as well as any quantity more than one, including but not limited to, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 30, 40, 50, 100, or any integer inclusive therein. The term "at least one" may extend up to 100 or 1000 or more, depending on the term to which it is attached; in addition, the quantities of 100 / 1000 are not to be considered limiting, as higher limits may also produce satisfactory results. In addition, the use of the term "at least one of X, Y and Z" will be understood to include X alone, Y alone, and Z alone, as well as any combination of X, Y and Z.

[0028] As used in this specification and claims, the words "comprising" (and any form of comprising, such as "comprise" and "comprises"), "having" (and any form of having, such as "have" and "has"), "including" (and any form of including, such as "includes" and "include") or "containing" (and any form of containing, such as "contains" and "contain") are inclusive or open-ended and do not exclude additional, unrecited elements or method steps.

[0029] The term "or combinations thereof as used herein refers to all permutations and combinations of the listed items preceding the term. For example, "A, B, C, or combinations thereof' is intended to include at least one of: A, B, C, AB, AC, BC, or ABC, and if order is important in a particular context, also BA, CA, CB, CBA, BCA, ACB, BAC, or CAB. Continuing with this example, expressly includedFILED MARCH 24, 2026 P2977PC01 (2024-052)are combinations that contain repeats of one or more item or term, such as BB, AAA, AAB, BBC, AAABCCCC, CBBAAA, CABABB, and so forth. The skilled artisan will understand that typically there is no limit on the number of items or terms in any combination, unless otherwise apparent from the context.

[0030] Throughout this application, the terms "about" or "approximately" are used to indicate that a value includes the inherent variation of error for the apparatus or the methods or the variation that exists among the objects, or study subjects. As used herein the qualifiers "about" or "approximately" are intended to include not only the exact value, amount, degree, orientation, or other qualified characteristic or value, but are intended to include some slight variations due to measuring error, manufacturing tolerances, stress exerted on various parts or components, observer error, wear and tear, and combinations thereof, for example. The terms "about" or "approximately", where used herein when referring to a measurable value such as an amount, percentage, temporal duration, and the like, is meant to encompass, for example, variations of ± 20% or ± 10%, or± 5%, or± 1%, or ± 0.1% from the specified value, as such variations are appropriate to perform the disclosed methods and as understood by persons having ordinary skill in the art. As used herein, the term "substantially" means that the subsequently described event or circumstance completely occurs or that the subsequently described event or circumstance occurs to a great extent or degree. For example, the term "substantially" means that the subsequently described event or circumstance occurs at least 90% of the time, or at least 95% of the time, or at least 98% of the time.

[0031] As used herein any reference to "one embodiment" or "an embodiment" means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment. The appearances of the phrase "in one embodiment" in various places in the specification are not necessarily all referring to the same embodiment.

[0032] As used herein, all numerical values or ranges include fractions of the values and integers within such ranges and fractions of the integers within such ranges unless the context clearly indicates otherwise. Thus, to illustrate, reference to a numerical range, such as 1-10 includes 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, as well as l.l, 1.2, 1.3, 1.4, 1.5, etc., and so forth. Reference to a range of 1-50 therefore includes 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, etc., up to and including 50, as well as 1.1, 1.2, 1.3, 1.4, 1.5, etc., 2.1, 2.2, 2.3, 2.4, 2.5, etc., and so forth. Reference to a series of ranges includesFILED MARCH 24, 2026 P2977PC01 (2024-052)ranges which combine the values of the boundaries of different ranges within the series. Thus, to illustrate reference to a series of ranges, for example, a range of 1-1,000 includes, for example, 1-10, 10-20, 20-30, 30-40, 40-50, 50-60, 60-75, 75-100, 100-150, 150-200, 200-250, 250-300, 300-400, 400-500, 500-750, 750-1,000, and includes ranges of 1-20, 10-50, 50-100, 100-500, and 500-1,000. The range 100 units to 2000 units therefore refers to and includes all values or ranges of values of the units, and fractions of the values of the units and integers within said range, including for example, but not limited to 100 units to 1000 units, 100 units to 500 units, 200 units to 1000 units, 300 units to 1500 units, 400 units to 2000 units, 500 units to 2000 units, 500 units to 1000 units, 250 units to 1750 units, 250 units to 1200 units, 750 units to 2000 units, 150 units to 1500 units, 100 units to 1250 units, and 800 units to 1200 units. Any two values within the range of about 100 units to about 2000 units therefore can be used to set the lower and upper boundaries of a range in accordance with the embodiments of the present disclosure.

[0033] As used herein any reference to "we" as a pronoun herein refers generally to laboratory personnel or other contributors who assisted in the laboratory procedures and data collection and is not intended to represent an inventorship role by said laboratory personnel or other contributors in any subject matter disclosed herein.

[0034] Returning now to the various embodiments disclosed herein, under normal atmospheric conditions, DME is a colorless gas and can be liquified at low pressures. Under reservoir conditions, the DME exists as a liquified gas and shows liquid-vapor equilibrium characteristics similar to n-propane and n-butane (FIG. 3). Due to its polarity, DME is partially soluble in water, and under moderate temperature and pressure conditions, it is fully miscible with oil. Like other solvents, the oil recovery mechanism with DME is also dictated by the phase behavior and distribution of DME among the fluid phases in the reservoir. Experimental and simulation results of core-flood tests have confirmed the robustness of the DME-based EOR application for different rock types. Experimental work shows that the oil viscosity is significantly reduced when DME mixes with oil at low DME ratios. The oil viscosity of 100 centipoise (cP) at 212 °F was decreased to 24 cP and 1 cP by mixing it with 5% and 30% by weight of DME, respectively. The viscosity of the aqueous phase was also reduced due to DME dissolution. DME has a higher preferential solubility in the oleic phase at intermediate pressures thanFILED MARCH 24, 2026 P2977PC01 (2024-052)other injectants. Under reservoir conditions, first contact miscibility occurs, thereby reducing the viscosity of the contacted oil, enhancing oil mobility, and ultimately resulting in a higher oil recovery.[00351 Importantly, no asphaltene precipitation (with asphaltene content of 6.4% by weight) occurs when oil is mixed with DME at increasing ratios up to 80% v / v. Compatibility tests with formation water with a salinity of 9.2 wt.% show that DME is soluble in formation water without any incompatibility or salting-out effect. The DME partitioning into the oleic phase improved with increased temperature and salinity. In contrast, the vaporizing mechanisms of CO2 lead to reduced intermediate hydrocarbon components in the contacted oil, leaving behind a heavier residual oil with increasing viscosity over time.

[0036] At the surface, the unique property of DME being liquified at low pressures makes it easier to handle and inject using a triplex or other high pressure pump. DME injectants do not require the types of high-horsepower compressors needed with conventional gas injectants like field gas and CO2, thereby reducing the overall project costs by an order of magnitude, making DME a significantly cost-effective inj ectant. The DME can be supplied for the EOR operations via trucks and does not require significant investment for a new pipeline or vicinity to a gas pipeline nearby as is the case with gas injectants.

[0037] As DME is currently being used as a replacement for transport fuel, the mixing of DME with hydrocarbons upgrades the quality of the produced well stream rather than being an impurity (as is the case of other injectants). DME application can be applied to severely depleted old hydrocarbon wells with low reservoir pressure to improve oil recovery, which would otherwise be abandoned as injection of hydrocarbon gas is not technically or commercially viable.

[0038] Significant research has been conducted to understand the pressure-volume-temperature (PVT) behavior of DME and DME / crude oil mixtures, with a focus on the partitioning behavior of DME. The efficacy of the DME-based EOR process is primarily controlled by the mass transfer of DME into the aqueous and oleic phases. DME transfers to both oleic and aqueous phases because of its polarity, with preference to the oleic phase. The DME concentration in the oil affects the extent of oil swelling and viscosity reduction, ultimately increasing the oil mobility. With DME injection, the first contact miscibility occurs under the reservoir conditions. Partitioning of DME between the two phases is influenced by temperature, salinity, pH of the aqueous phase, and oil composition.FILED MARCH 24, 2026 P2977PC01 (2024-052)

[0039] Having similar physical properties, including molecular weight, the DME is often compared to liquified petroleum gas (LPG). However, DME has a water solubility of three orders of magnitude greater than LPG. Additionally, the DME has the advantages of lower cost, higher efficiency, and is easily extracted from produced well stream fluids for reinjection.

[0040] The efficacy of the DME inj ectant was compared against two existing gas inj ectants - produced field gas and CO2 - for a volatile oil pilot in the Eagle Ford play. For this comparison, For this comparison, 30 days each of injection and production were modeled for the three injectants. For the DME, the phase change data is summarized in Table 1 below:Mol ecul ar W ei ght 46.0684 g / moleCritical Pressure 52.6701209 atmCritical Temperature 400.378 KAcentric Factor 0.196Critical Volume 0.164 m3 / kg-moleAverage Normal Boiling Point -12.6076 Fahrenheit Parachor 132Table 1

[0041] FIG. 4 compares the oil rate, cumulative oil production, bottom hole pressure for the test wells, and cumulative water production for the different injectants (field gas, CO2 and DME). Although the bottom hole pressure was observed to be the lowest with DME, the oil rate was highest with DME. The DME has a higher preferential solubility in the oleic phase at intermediate pressures than other inj ectants. The water production was observed to be the lowest for the DME due to partial solubility. However, the water production was the highest with the CO2 due to higher water solubility than light hydrocarbon gases like Ci gases (e.g., CO2, methane).

[0042] In the comparative study, DME resulted in 59% and 66% higher cumulative oil production than produced gas and CO2 as indicated in Table 2:FILED MARCH 24, 2026 P2977PC01 (2024-052)Scenario Inject ant Cycles Total Maximum Cumulati Oil Recovery Oil Huff-and- Fully Gas BHP ve Oil Uplift Recovery Puff Completed Volume Reached Volume Relative to Uplift Efficiency in 26 Injected for (Mbo) Non- FOR Relative (STB / MMcf) months (MMcf) Different Scenario to Non- Wells after 1 year EOR(psi) Scenarioafter 26Months2 Field Gas 13 360.0 2,220 - 28.814 18.3% 10.6% 7.72,7289 CO213 360.0 1,656 - 27.668 17.8% 6.2% 4.52.06310 DME 13 360.0 1.287 - 45.855 47.5% 76.0% 55.01,914Table![00431 Table 2 summarizes the results for these sensitivities, with DME resulting in -60% higher cumulative oil production after 26 months and a much favorable Huff-and-Puff Efficiency (HPE) metric. To benchmark different scenarios, the Huff-and-Puff Efficiency (HPE) metric is defined as the ratio of incremental oil recovered with the huff-and-puff process to the total gas injected, with a higher HPE number indicating a more efficient process.

[0044] Based on the experimental work published in the literature, no asphaltene deposition has been reported when oil was mixed with DME at increasing ratios up to 80% v / v. Because of its low boiling point, DME can be easily extracted from the produced well stream fluid by distillation and reused for injection. Unlike CO2, DME will not contaminate the produced well stream. Additionally, because the DME does not occur naturally, it can be easily tagged and used as a tracer, helping understand inter-well connectivity. In the case of containment issues, the DME injection (rate and volume) can be controlled / optimized, which cannot be done with the hydrocarbon inj ectants that occur naturally. The DME is not corrosive like CO2, so it does not need specific wellbore tubulars to be rated for sour service, and additional cost at the refinery to take out the impurity.

[0045] At reservoir conditions, the DME exists in a liquid state, making it a more efficient solvent promoting single-phase flow. As a result, DME shows a greater penetration distance compared to the other two gas inj ectants (FIGS. 5-9). For the cases studied here, at reservoir conditions, both produced field gas and CO2 existed in a gaseous phase, increasing gas saturation and promoting inefficient two-phase flow. In contrast, DME is an efficient solvent, and as it mixes with remaining oil (even) at lowFILED MARCH 24, 2026 P2977PC01 (2024-052)DME ratios and reduces oil viscosity significantly. Because DME exists in a liquid state under reservoir conditions, it is not expected to show the gravity override issues typically seen with gas injectants, which have lower densities than oil.

[0046] FIGS. 5 and 6 show the mole fraction of the inj ectant in the oil phase (a proxy for oil solubility) and oil viscosity changes at the six different grid blocks shown in Figure 5- left. For the two scenarios of field gas and CO2, the oil swelling and corresponding oil viscosity reduction were observed to decrease with distance away from the primary hydraulic fracture. The reversal in oil viscosity trend at -0.45 cP for the different grid blocks is due to the grid block pressure decreasing below the bubble point pressure. In the case of DME (Figure 6 - right), both the oil swelling (DME mole fraction in oil phase) and oil viscosity reduction with time indicate greater penetration within the SRV. This suggests that the DME is more effective than other injectants at oil recovery due to higher solubility at intermediate pressures with deeper penetration.

[0047] FIGS. 7-9 show the profile of the field gas, CO2, and DME for the first injection cycle, as the bottom hole pressures were usually the highest during the first injection cycle for the three injectants (Figure 4). The field gas and CO2 stayed in the gas phase for the duration of the injection cycle as the miscibility conditions were not achieved, making both sub-optimal injectants. At a reservoir temperature of 215 °F, the bottom hole pressure was high for CO2 to be in the supercritical state for some time towards the end of the injection phase. Methane, which makes most of the field gas (-73% Ci -22% C2 & C3, -5% C4 ), is a poor hydrocarbon solvent. It can only dissolve light hydrocarbons (up to about C12) and has a low propensity towards dissolving intermediate and heavier molecular weight hydrocarbons.

[0048] In contrast, CO2 is better at dissolving the light and intermediate components (up to Cie). The mass transfer of the lighter and / or intermediate components with the injected gas results in higher viscosity and density of residual oil after injection. In scenarios 2 (field gas) and 9 (CO2), with the selective mass transfer for the field gas and CO2, an increase in the oil viscosity was observed nearwellbore, up to 10-15 feet from the perforation, which could cause further restriction for lighter oil stranded deeper in the reservoir.

[0049] Even though the bottom hole pressures of DME were lower than those of the other two inj ectants, DME was injected in the liquid phase as it can be liquified at low pressures with its favorable liquidvapor equilibrium characteristics (FIG. 3). When DME is injected into the reservoir and comes in contactFILED MARCH 24, 2026 P2977PC01 (2024-052)with the remaining mobile oil, the first-contact miscibility process occurs, leading to oil swelling and viscosity reduction. Significant oil viscosity reduction was observed ~50 feet into the reservoir compared to the other two inj ectants.

[0050] Because the DME boils at a much lower temperature compared to other hydrocarbons, it is easier to extract DME from the produced well stream compared to the other inj ectants, especially CO2. The cyclic process is modified to include separation of the DME at the flash tank, and then reinjecting the produced DME (FIG. 10). The reuse of the DME reduces the overall project costs, thereby making the modified cyclic process more efficient than currently available technology.

[0051] Thus, in exemplary embodiments, the present disclosure is directed at novel EOR methods that incorporate the use of DME as liquid injectant. This EOR inject and these processes show promising modeling results and provides several potential transformative benefits compared to the two gas injectants (produced gas and CO2). In particular, the unique characteristic of DME being liquified at low pressures makes it suitable and cost-effective as an injectant. The DME preferentially partitions into the oleic phase at intermediate pressures, thereby swelling and mobilizing the oil phase. The oil recovery with the huff-and-puff process with DME is much higher than that with the two other gas injectants. Additionally, DME shows a greater penetration distance as it stays in the liquid phase at reservoir conditions, promoting single-phase flow (efficient process). The two gas injectants at reservoir conditions (at least in cases studied here) existed in a gaseous phase, increasing gas saturation and promoting two-phase flow (inefficient process).

[0052] Furthermore, there is no evidence that DME interferes with the resident oil chemistry to create asphaltene deposition problems. The issues of asphaltene deposition and permeability impairment are well documented with other gas injectants such as CO2. Because DME does not occur naturally in petroleum reservoirs, it can be used as a tracer to understand inter-well connectivity. In the case of containment issues, the DME injection rate and volumes can be controlled / optimized. Because of its low boiling point, the DME can be easily extracted from the produced well stream fluid by distillation and reused for injection, thereby reducing project costs.

[0053] Although the addition of the soaking phase extends the duration of each huff-and-puff cycle, it allows the extended mixing of the fluids, resulting in additional cumulative oil recovely and an improved Huff-and-Puff Efficiency (HPE) metric. The oil viscosity reduction is the same for the initial two cycles,FILED MARCH 24, 2026 P2977PC01 (2024-052)with or without soaking. However, the addition of the soaking phase results in higher viscosity reduction from the third cycle onwards and higher peak oil rates for subsequent cycles, compared to no soaking. In contrast, the viscosity reduction mechanism with no soaking continues to become less effective in subsequent cycles. Overall, the huff-and-puff cycles should be tailored to increase the soaking period (assuming the injection rate is fixed) with every subsequent cycle to increase the penetration and oil recovery. This corroborates previous findings where the initial cycles were found to be tapping into smaller matrix blocks closer to the wellbore, but soaking is needed in subsequent cycles to tap into larger matrix blocks away from the wellbore.

[0054] In certain embodiments, enhanced oil recovery (EOR) operations using dimethyl ether (DME) are designed, controlled, and optimized using a mathematical transport model that represents diffusion-dominated mass transfer of DME between a hydraulically induced fracture network and a tight subterranean reservoir matrix. Unlike conventional solvent or gas injection techniques that rely primarily on empirical cycle timing or pressure heuristics, the disclosed methods use physics-based analytical modeling to predict solvent penetration, mixing behavior, and hydrocarbon mobilization prior to field implementation. The mathematical transport model enables selection and adjustment of injection, soaking, and production parameters such that DME diffusion into the reservoir matrix is maximized while minimizing solvent loss, inefficient two-phase flow, or premature breakthrough.

[0055] In tight and ultra-tight formations, including shale and low-permeability carbonate reservoirs, advective flow within the reservoir matrix is negligible relative to molecular diffusion. In such formations, Peclet numbers are significantly less than unity, indicating that mass transport is dominated by diffusion rather than Darcy-driven flow. Accordingly, the mathematical transport model assumes that DME transport within the matrix occurs primarily by diffusion from fracture faces into adjacent matrix blocks, while advection is limited to the wellbore and fracture network. This assumption is consistent with laboratory observations and field behavior in hydraulically fractured unconventional reservoirs.

[0056] In one embodiment, the mathematical transport model includes one-dimensional diffusion equations derived from Fick’s laws of diffusion, applied along a spatial coordinate extending from a fracture face into a matrix block. The model treats the matrix as a semi-infinite or finite slab bounded by fracture discontinuities and no-flow symmetry planes. The mathematical transport model applies one-dimensional diffusion equations derived from Fick’s laws of diffusion along a spatial coordinateFILED MARCH 24, 2026 P2977PC01 (2024-052)extending from a fracture face into a matrix block. The governing equation is used to calculate DME concentration as a function of time and distance from the fracture face, thereby determining penetration length, solvent uptake, and timing of subsequent production operations.

[0057] The governing equation may be expressed as a diffusion equation of the form:dC _ d2Cdt dx2

[0058] where C represents DME concentration within the matrix, t represents time, x represents distance from the fracture face, and Deis an effective diffusion coefficient. Analytical or semi -analytical solutions are used to determine concentration profiles, penetration length, and solvent mass uptake during injection, soaking, and production phases.

[0059] The effective diffusion coefficient used in the mathematical transport model accounts for pore-scale and rock-fabric effects that impede bulk molecular diffusion. In certain embodiments, the effective diffusion coefficient incorporates one or more of: tortuosity of the pore network, pore constrictivity, effective transport-through porosity, lithofacies-dependent pore size distribution, and composition-dependent diffusivity of DME. The effective diffusion coefficient may be treated as constant for a given phase or varied parametrically to capture changes in pressure, solvent composition, or cycle number.

[0060] To translate laboratory-scale diffusion behavior to field-scale fracture spacing and matrix block sizes, the mathematical transport model includes dimensionless scaling parameters. In certain embodiments, these parameters include: a ratio of fracture network volume to matrix volume (a), and a dimensionless mass transfer coefficient (Bi). These parameters allow the model to account for differences in solvent availability, fracture density, damaged zones near fractures, and non-uniform mass transfer between laboratory cores and field reservoirs. Using these scaling parameters, the model predicts recovery factors and solvent penetration at reservoir scale that would otherwise be overestimated by laboratory data alone.

[0061] Using the mathematical transport model, predicted outputs may include one or more of: penetration length of DME into the matrix as a function of time, DME concentration profiles during injection, soaking, and production phases, solvent mass uptake by matrix blocks of varying size, hydrocarbon recovery factor attributable to diffusion-driven mixing, and relative effectiveness of DMEFILED MARCH 24, 2026 P2977PC01 (2024-052)compared to gaseous injectants. These predictions enable quantitative comparison of operating scenarios prior to field execution. Due to the non-linear relationship between diffusion penetration length and time, fracture spacing, and matrix block size, the resulting operating parameters cannot be reliably determined through empirical observation or manual calculation alone, particularly at field scale. The disclosed modeling approach enables operating decisions that would not otherwise be achievable using conventional engineering heuristics. The effective diffusion coefficient represents measurable physical properties of the reservoir matrix and is derived from laboratory data, core analysis, or field characterization, such that the mathematical transport model is grounded in the physical structure of the reservoir.

[0062] In certain embodiments, outputs of the mathematical transport model are used to select operating parameters for a cyclic EOR process using DME. These parameters may include: DME injection volume, injection pressure or rate, soaking duration sufficient to increase diffusion-controlled penetration, production timing to recover mobilized hydrocarbons, and cycle repetition strategy for accessing progressively larger matrix blocks. The model may indicate, for example, that soaking time provides limited benefit for small matrix blocks near the wellbore but becomes increasingly important for larger blocks farther from the fracture network.

[0063] Following model-based parameter selection, DME is injected into the hydraulically fractured well in accordance with the selected operating parameters. Under reservoir conditions, DME exists primarily in a liquid or dense phase and exhibits first-contact miscibility with reservoir hydrocarbons. During a soaking period, DME diffuses from the fracture network into the reservoir matrix, resulting in oil swelling, viscosity reduction, and enhanced mobility. Because diffusion proceeds as a function of the square root of time, the soaking duration is selected based on predicted penetration length rather than arbitrary shut-in intervals.

[0064] The methods disclosed herein are directed to specific technological processes for controlling enhanced oil recovery operations and do not recite abstract mathematical relationships in isolation. Any mathematical expressions or models described are integrated into practical field operations and are used to configure physical injection, soaking, and production steps performed on a subterranean well, resulting in improved hydrocarbon recovery.FILED MARCH 24, 2026 P2977PC01 (2024-052)

[0065] After soaking, hydrocarbons are produced from the well, with the recovered fluids exhibiting increased oil recovery relative to non-optimized or non-modeled DME injection processes. In certain embodiments, the produced stream includes recoverable DME, which may be separated and reused in subsequent cycles. The disclosed model-driven approach enables systematic improvement in EOR performance, reduced solvent loss, and improved predictability of recovery outcomes compared to empirical huff-and-puff techniques.

[0066] It is to be understood that even though numerous characteristics and advantages of various embodiments of the present invention have been set forth in the foregoing description, together with details of the structure and functions of various embodiments of the invention, this disclosure is illustrative only, and changes may be made in detail, especially in matters of structure and arrangement of parts within the principles of the present invention to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed.

Claims

FILED MARCH 24, 2026 P2977PC01 (2024-052)It is Claimed:

1. A process for conducting an enhanced oil recovery (EOR) application on a subterranean well, the process comprising the steps of:injecting a volume of dimethyl ether (DME) into a target formation within the subterranean well;allowing the dimethyl ether to soak for a resident time within the target formation; producing the dimethyl ether and hydrocarbons from the target formation; and separating the dimethyl ether from the hy drocarbons produced from the well.

2. The process of claim 1, wherein the steps of injecting the volume of dimethyl ether, allowing the dimethyl ether to soak within the target formation, and producing the dimethyl ether and hydrocarbons are repeated on a cyclic basis until a sufficient quantity of hydrocarbons is recovered from the well.

3. The process of claim 2, wherein a duration of the soaking step is increased in successive cycles to promote penetration of the dimethyl ether into progressively larger reservoir matrix blocks.

4. The process of claim 1, wherein the step of separating the dimethyl ether from the produced hydrocarbons comprises distilling the dimethyl ether from the produced hydrocarbons.

5. The process of claim 4, further comprising the step of reinjecting the separated dimethyl ether into the subterranean well.

6. The process of claim 1 , further comprising the step of using the dimethyl ether as a tracer to identify subterranean communication between the well and a nearby well.FILED MARCH 24, 2026 P2977PC01 (2024-052)7. The process of claim 1, wherein the dimethyl ether is injected into a hydraulically fractured horizontal well completed in a tight shale or ultra-low-permeability reservoir.

8. The process of claim 1, wherein the dimethyl ether is injected in a liquid or dense phase under reservoir pressure and temperature conditions such that the dimethyl ether exhibits first-contact miscibility with resident hydrocarbons.

9. A method for enhancing hydrocarbon recovery from a subterranean reservoir penetrated by a hydraulically fractured well, the method comprising:(a) constructing a mathematical transport model representing diffusion-dominated mass transfer of an injected solvent between a fracture network and a tight reservoir matrix, wherein the mathematical transport model includes:(i) one-dimensional diffusion equations derived from Fick’s law;(ii) an effective diffusion coefficient accounting for at least tortuosity, pore constrictivity, and effective transport porosity' of the reservoir matrix, and (iii) one or more scaling parameters relating laboratory-scale diffusion behavior to field-scale fracture spacing and matrix block size;(b) using the mathematical transport model to predict, for dimethyl ether (DME) injected into the reservoir, at least one of:(i) penetration length of DME into the reservoir matrix as a function of time; (ii) concentration profiles of DME during injection, soaking, and production phases; or(iii) hydrocarbon recovery factor attributable to diffusion-driven mixing of DME with resident hydrocarbons;FILED MARCH 24, 2026 P2977PC01 (2024-052)(c) selecting operating parameters for a cyclic enhanced oil recovery process based on outputs of the mathematical transport model, the operating parameters comprising at least one of(i) a DME injection volume or injection pressure;(ii) a soaking duration sufficient to increase diffusion-controlled penetration into the reservoir matrix, or(iii) a production timing configured to recover hydrocarbons mobilized by DME diffusion;(d) injecting DME into the hydraulically fractured well in accordance with the selected operating parameters;(e) allowing the injected DME to diffuse into the reservoir matrix during a soaking period predicted by the mathematical transport model to promote oil swelling and viscosity reduction under first-contact miscible conditions; and(f) producing hydrocarbons from the well, wherein the produced hydrocarbons exhibit increased recovery relative to an unmodeled or non-optimized DME injection process.FILED MARCH 24, 2026 P2977PC01 (2024-052)10. The method of claim 9, wherein the mathematical transport model assumes diffusion-dominated mass transfer within the reservoir matrix and negligible advective flow, corresponding to a Peclet number less than unity.

11. The method of claim 9, wherein the mathematical transport model treats the reservoir matrix as a finite or semi-infinite slab bounded by fracture faces and no-flow symmetry planes.

12. The method of claim 9, wherein the effective diffusion coefficient is parameterized based on at least one of temperature, reservoir pressure, solvent composition, or cycle number.

13. The method of claim 9, wherein the scaling parameters include a fracture-to-matrix volume ratio (a) and a dimensionless mass-transfer coefficient (Bi) used to relate laboratory diffusion behavior to field-scale fracture spacing.

14. The method of claim 9, wherein selecting the operating parameters comprises selecting a soaking duration based on a predicted diffusion penetration length proportional to the square root of time.

15. The method of claim 9, further comprising recovering dimethyl ether from produced fluids and reinjecting the recovered dimethyl ether in a subsequent cycle, wherein the mathematical transport model is updated based on prior-cycle production data.

Images