ABDALLAH, Wael (Canary Village, Villa 221P.O. Box 446, Al-Khobar ., 31952, SA)
ESKIN, Dmitry (11727 - 1 Avenue NW, Edmonton, Alberta T6J 7G1, CA)
BRUNET-CAMBUS, Chrystel (Le Four à Chaux, Route de Houdan, Richebourg, F-78550, FR)
KEFI, Slaheddine (6 rue du Lavoir, Velizy Villacoublay, F-78140, FR)
PERSHIKOVA, Elena (90 avenue du Maine, Paris, Paris, F-75014, FR)
SERVICES PETROLIERS SCHLUMBERGER (42 rue Saint Dominique, Paris, F-75007, FR)
SCHLUMBERGER HOLDINGS LIMITED (P.O. Box 71, Craigmuir ChambersRoad Town, Tortola, VG)
SCHLUMBERGER TECHNOLOGY B.V. (Parkstraat 83-89, JG The Hague, NL-2514, NL)
PRAD RESEARCH AND DEVELOPMENT LIMITED (P.O. Box 71, Craigmuir ChambersRoad Town, Tortola, VG)
SZABO, Geza Horvath (7919 - 14Ave SW, Edmonton, Alberta T6X 1H3, CA)
ABDALLAH, Wael (Canary Village, Villa 221P.O. Box 446, Al-Khobar ., 31952, SA)
ESKIN, Dmitry (11727 - 1 Avenue NW, Edmonton, Alberta T6J 7G1, CA)
BRUNET-CAMBUS, Chrystel (Le Four à Chaux, Route de Houdan, Richebourg, F-78550, FR)
KEFI, Slaheddine (6 rue du Lavoir, Velizy Villacoublay, F-78140, FR)
PERSHIKOVA, Elena (90 avenue du Maine, Paris, Paris, F-75014, FR)
| CLAIMS What is claimed is: 1 . A system for determining the effect of water-based additives on oil recovery, comprising: a water source; a water pump in fluid communication with the water source; a water-soluble additive source; a water-soluble additive pump in fluid communication with the additive source; a first mixer in fluid communication with the water pump and the additive pump; a primary core holder inlet valve in fluid communication with the first mixer; a core holder in fluid communication with the primary core holder inlet valve; a core holder outlet valve in fluid communication with the core holder; a solvent mixture pump in fluid communication with the core holder outlet valve; a solvent mixture source in fluid communication with the solvent mixture pump; a second mixer in fluid communication with the core holder outlet valve; a first oil pump in fluid communication with the second mixer; a first oil source in fluid communication with the first oil pump; a detector in fluid communication with the second mixer; a secondary core holder inlet valve in fluid communication with the primary core holder inlet valve; a suspension pump in fluid communication with the secondary core holder inlet valve; a source of rock particles suspended in a fluid in fluid communication with the suspension pump; a second oil pump in fluid communication with the secondary core holder inlet valve; a second oil source in fluid communication with the second oil pump; an acid mixture pump in fluid communication with the secondary core holder inlet valve; an acid mixture source in fluid communication with the acid mixture pump; an oil/water mixable fluid pump in fluid communication with the secondary core holder inlet valve; an oil/water mixable fluid source in fluid communication with the oil/water mixable fluid pump; and a gas source in fluid communication with the secondary core holder inlet valve. 2. The system of claim 1 , further comprising a bypass circuit configured to bypass the core holder. 3. The system of claim 1 , further comprising an oven in which the core holder is disposed. 4. The system of claim 1 , further comprising a back-pressure regulator in fluid communication with the core holder outlet valve. 5. The system of claim 1 , further comprising a back-pressure regulator in fluid communication with the detector. 6. The system of claim 1 , wherein the first oil source and the second oil source are integrated into a single source. 7. The system of claim 1 , wherein the first oil source and the second oil source are crude oil sources. 8. The system of claim 7, wherein at least one of the first oil source and the second oil source is a live crude oil source. 9. The system of claim 1 , wherein at least one of the first oil source and the second oil source is a drilling fluid oil source. 10. The system of claim 1 , wherein the solvent mixture source provides a mixture including at least one of an organic solvent, an alcohol, a surfactant, brine, and water. 1 1 . The system of claim 10, wherein the solvent mixture is a mixture of toluene and isopropanol or toluene and tetrahydrofuran. 12. The system of claim 1 , wherein the acid mixture source provides one or more acids in a mixture with at least one of a surfactant and water. 13. The system of claim 12, wherein the one or more acids comprises at least one of hydrochloric acid, nitric acid, acetic acid, formic acid, and naphthenic acid. 14. The system of claim 1 , wherein the oil/water mixable fluid source provides, separately or in any combination, acetone, isopropanol, methanol, and ethanol. 15. The system of claim 1 , wherein the core holder comprises an internal member configured to form a filter cake thereon. 16. The system of claim 1 , wherein the gas source provides nitrogen, carbon dioxide, a noble gas, air, or any mixture thereof. 17. The system of claim 1 , wherein the detector is one of a spectrometer and an ultraviolet-visible spectrometer. 18. The system of claim 1 , wherein the detector is configured to measure one of conductivity, dielectric permittivity, density, acoustic velocity, acoustic attenuation, a refractive index property, a light scattering property, fluorescence, chemiluminescence, a flame ionization property, and an infrared property. 19. A system for determining the effect of water-based additives on oil recovery, comprising: a water source; a water pump in fluid communication with the water source; a water-soluble additive source; a water-soluble additive pump in fluid communication with the additive source; a first mixer in fluid communication with the water pump and the additive pump; a primary core holder inlet valve in fluid communication with the first mixer; a core holder in fluid communication with the primary core holder inlet valve; a core holder outlet valve in fluid communication with the core holder; a solvent mixture pump in fluid communication with the core holder outlet valve; a solvent mixture source in fluid communication with the solvent mixture pump; a second mixer in fluid communication with the core holder outlet valve; a first oil pump in fluid communication with the second mixer; a first oil source in fluid communication with the first oil pump; a detector in fluid communication with the second mixer; a secondary core holder inlet valve in fluid communication with the primary core holder inlet valve; a second oil pump in fluid communication with the secondary core holder inlet valve; a second oil source in fluid communication with the second oil pump; an acid mixture pump in fluid communication with the secondary core holder inlet valve; an acid mixture source in fluid communication with the acid mixture pump; an oil/water mixable fluid pump in fluid communication with the secondary core holder inlet valve; an oil/water mixable fluid source in fluid communication with the oil/water mixable fluid pump; and a gas source in fluid communication with the secondary core holder inlet valve. 20. The system of claim 19, wherein the core holder comprises a coating on an internal surface of the core holder, the coating comprising formation rock particles or an artificially created layer with chemical composition similar to that of formation rock. 21 . The system of claim 19, further comprising a single crystal of rock exhibiting substantially no porosity disposed in a cavity of the core holder. 22. The system of claim 19, further comprising: a body of rock exhibiting substantially no porosity disposed in a cavity of the core holder. 23. A system for determining the effect of water-based additives on oil recovery, comprising: a water source; a water pump in fluid communication with the water source; a water-soluble additive source; a water-soluble additive pump in fluid communication with the additive source; a first mixer in fluid communication with the water pump and the additive pump; a primary core holder inlet valve in fluid communication with the first mixer; a core holder in fluid communication with the primary core holder inlet valve; a core holder outlet valve in fluid communication with the core holder; a solvent mixture pump in fluid communication with the core holder outlet valve; a solvent mixture source in fluid communication with the solvent mixture pump; a second mixer in fluid communication with the core holder outlet valve; a first oil pump in fluid communication with the second mixer; a first oil source in fluid communication with the first oil pump; a detector in fluid communication with the second mixer; a secondary core holder inlet valve in fluid communication with the primary core holder inlet valve; a suspension pump in fluid communication with the secondary core holder inlet valve; a source of rock particles suspended in a fluid in fluid communication with the suspension pump; an acid mixture pump in fluid communication with the secondary core holder inlet valve; an acid mixture source in fluid communication with the acid mixture pump; an oil/water mixable fluid pump in fluid communication with the secondary core holder inlet valve; an oil/water mixable fluid source in fluid communication with the oil/water mixable fluid pump; and a gas source in fluid communication with the secondary core holder inlet valve. 24. A method for determining the effect of water-based additives on oil recovery, comprising: saturating a core with oil; flushing water through the oil-saturated core; establishing a low rate of water flow through the core; injecting a solvent mixture into fluid recovered from the core; measuring a baseline characteristic of the recovered fluid; setting an initial water-based additive injection rate; injecting a water-based additive into the water flow at the initial injection rate; and measuring a characteristic of the fluid into which the water-based additive has been injected at the initial injection rate. 25. The method of claim 24, further comprising comparing the result of measuring the characteristic of the fluid into which the water-based additive has been injected at the initial injection rate to a calibration curve if the result of measuring the characteristic of the fluid into which the water-based additive has been injected at the initial injection rate is significantly different than the result of measuring the baseline characteristic of the fluid recovered from the core. 26. The method of claim 24, further comprising: increasing the water-based additive injection rate; injecting the water-based additive into the water flow at the increased injection rate; and measuring the characteristic of the fluid into which the water-based additive has been injected at the increased rate if the result of measuring the characteristic of the fluid into which the water-based additive has been injected at the initial injection rate is not significantly different than the result of measuring the baseline characteristic of the fluid recovered from the core. 27. The method of claim 26, further comprising comparing the result of measuring the characteristic of the fluid into which the water-based additive has been injected at the increased injection rate to a calibration curve if the result of measuring the characteristic of the fluid into which the water-based additive has been injected at the increased injection rate is significantly different than the result of measuring the baseline characteristic of the fluid recovered from the core. 28. The method of claim 24, further comprising: forming the core as a filter cake. 29. The method of claim 28, further comprising cleaning a system for determining the effect of water-based additives on oil recovery. 30. The method of claim 29, wherein cleaning the system comprises: dissolving the filter cake using an acid mixture; flushing the system with an oil/water mixable fluid; and drying the system. 31 . The method of claim 28, wherein forming the core as the filter cake is accomplished by flowing a suspension of rock particles and water through a permeable element. 32. The method of claim 28, wherein removing liquid from the core is accomplished by flowing a gas through the core. 33. The method of claim 24, wherein injecting the solvent mixture into the fluid recovered from the core is accomplished by injecting a mixture including at least one of an organic solvent, an alcohol, a surfactant, brine, and water into the fluid recovered from the core. 34. The method of claim 33, wherein the mixture is a mixture of toluene and isopropanol or toluene and tetrahydrofuran. 35. The method of claim 24, wherein at least one of measuring the baseline characteristic of the recovered fluid and measuring the characteristic of the fluid into which the water-based additive has been injected at the initial injection rate is accomplished by one of a spectrographic technique and an ultraviolet-visible spectrographic technique. 36. The method of claim 24, wherein at least one of measuring the baseline characteristic of the recovered fluid and measuring the characteristic of the fluid into which the water-based additive has been injected at the initial injection rate is accomplished by measuring one of conductivity, dielectric permittivity, density, acoustic velocity, acoustic attenuation, a refractive index property, a light scattering property, fluorescence, chemiluminescence, a flame ionization property, and an infrared property. 37. The method of claim 24, further comprising: flowing water including entrained oil through a detector at varying concentrations; periodically measuring a characteristic of the oil entrained in the water or a characteristic of the water and the entrained oil; and preparing a calibration curve using the periodic measurements. 38. The method of claim 37, wherein the characteristic is one of an optical density and an optical density measured within an ultraviolet-visible range. 39. The method of claim 37, wherein the characteristic is one of conductivity, dielectric permittivity, density, acoustic velocity, acoustic attenuation, a refractive index property, a light scattering property, fluorescence, chemiluminescence, a flame ionization property, and an infrared property. 40. A system for determining the effect of water-based additives on oil recovery, comprising: a water source; a water pump in fluid communication with the water source; a water-soluble additive source; a water-soluble additive pump in fluid communication with the additive source; a first mixer in fluid communication with the water pump and the additive pump; a core holder in fluid communication with the first mixer; a second mixer in fluid communication with the core holder; a solvent mixture pump in fluid communication with the second mixer; a solvent mixture source in fluid communication with the solvent mixture pump; and a detector in fluid communication with the second mixer. 41 . The system of claim 40, wherein the first mixer is a static mixer. 42. The system of claim 40, wherein the second mixer is a dynamic mixer. 43. The system of claim 40, wherein the solvent mixture source provides a mixture including at least one of an organic solvent, an alcohol, a surfactant, brine, and water. 44. The system of claim 43, wherein the solvent mixture is a mixture of toluene and isopropanol or toluene and tetrahydrofuran. 45. A device for forming a core in a core holder, comprising: a source of ground rock particles suspended in a fluid; a suspension pump in fluid communication with the source of ground rock particles suspended in a fluid; and a core holder in fluid communication with the suspension pump, the core holder comprising a permeable element on which the core is formed, the permeable element extending across an internal cavity of the core holder. 46. The device of claim 45, wherein the permeable element comprises a sieve. |
ADDITIVES ON OIL RECOVERY
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from U.S. Provisional Applications 61/329,917, filed April 30, 2010, and 61/344,209, filed June 1 1 , 2010, both of which are incorporated herein by reference.
BACKGROUND OF THE INVENTION
Field of the Invention
[0002] The present invention relates to a system and method for determining the effect of water-based additives on oil recovery.
Description of Related Art
[0003] Increasing the amount of crude oil that can be recovered from a well has become more important as crude oil prices have increased. Many methodologies may be employed to enhance crude oil recovery. Water can be injected into an earth formation to flush oil from fractures in the formation, leaving oil trapped in the formation's matrix. Another methodology employs additives that are injected into the crude oil reservoir to aid in producing oil from the formation's matrix and/or to aid in releasing an oil-based fluid layer from metallic well casings leading to or from the formation. Such additives may be either oil-soluble or water-soluble. Oil-soluble additives may be injected into a reservoir via an organic carrier, such as a synthetic oil, a refined oil, or the like. Water-soluble additives may be injected into a reservoir via a water phase. Examples of such water-soluble additives include, but are not limited to, water-based foams, water-based polymer solutions, emulsions, brines, and the like. In a majority of applications, water-soluble additives are used, rather than oil-soluble additives, for economic reasons. Because water-soluble additives are often preferred by the industry, the efficiencies of various water-soluble additives are of interest. [0004] Oil-bearing formations primarily comprise either silicate-based rock or carbonate-based rock. While carbonate formations are currently estimated to hold about 60 percent of the world's conventional oil reserves, the worldwide average oil recovery from carbonate formations is currently estimated to be less than about 35 percent, as these formations present particularly difficult obstacles in reserves evaluation, reservoir modeling and simulation, and in maximizing the recovery of crude oil from the formations. For example, carbonates form different rock types with a heterogeneous distribution through a reservoir. Moreover, unlike silicate formations that are typically water-wet, most carbonate reservoir rocks are known to be mixed-wet or oil-wet to some degree. In water-wet formations, a thin film of water coats the surface of the formation matrix, a condition that is desirable for efficient oil transport. In oil-wet formations, however, the formation matrix imbibes oil, inhibiting the recovery of oil from the formation. Furthermore, carbonate formations comprise sedimentary rocks that were formed from deposits in marine environments. Such formations contain fragments of marine organisms, skeletons, coral, algae, and the like. Carbonate formations are comprised primarily of calcium carbonate, which is more easily dissolved by water than sand, of which silicate-based, sandstone formations are composed. Crude oil can be difficult to produce from carbonate formations because of the formations' varying degrees of permeability, wettability, and susceptibility to fractures. Additives aid in controlling the wettability of carbonate formations, which can dramatically increase the amount of crude oil produced from such formations.
[0005] The crude oil/carbonate interaction involves several factors. Physical interactions occur between the crude oil and carbonate formation, resulting in adsorption of polar compounds of oils, primarily carboxylic acids, asphaltenes, and resins, on rock surfaces. Chemical interactions occur between the crude oil and carbonate formation leading to the formation of surface-active compounds. Redistribution of these chemical interaction products can occur between the oil and water phases. Adsorption of the chemical interaction products on the rock/oil interface can occur, altering the formation's wetting properties. [0006] One particularly difficult problem in dealing with carbonate reservoirs is that chemical additives can react with crude oil compounds, such as organic acids, injected water, or water soluble compounds. To alter the chemical and physical properties of these reaction products, acids and surface active compounds are injected into carbonate formations. Acids have a chemical interaction with the carbonate rocks, while the surface active compounds have a physical interaction with the carbonate rocks. Acids enhance the recovery of crude oil from carbonate reservoirs due to their chemical reactions with carbonate rocks, see Canadian Patent Application 2,675,903 for example, by changing the oil-wet carbonate surfaces of the rocks to water-wet surfaces. Salts are used as well to fine tune properties of injected surfactant mixtures and are also utilized during foam flooding.
[0007] Crude oil production-enhancing additives, therefore, are very important, particularly in carbonate formations. Water-soluble additives impact fundamental aspects of oil recovery in at least two ways, by altering the oil-water interfacial tension of reservoir fluids and/or by altering the wettability of an oil-producing formation. Testing methodologies exist to assess the impact of a particular water- soluble additive on oil-water interfacial tension and/or on wettability of the formation. For example, the wettability can be determined by measuring the "contact angle" between a sample of crude oil and a sample of the formation from which the crude oil is being produced. Such measurements can be conducted in a water environment or in an environment including both water and a surfactant additive. Figures 1 A and 1 B depict examples of such measurements. In Figure 1 A, a drop 101 of crude oil is adhered via interfacial tension to a sample 103 of a formation from which the crude oil is to be produced. Drop 101 of the crude oil and sample 103 of the formation are in an environment of water. Drop 101 of crude oil and sample 103 of the formation define a contact angle θι. In Figure 1 B, a drop 105 of the crude oil is adhered via interfacial tension to a sample 107 of the formation from which the crude oil is to be produced. Drop 105 of the crude oil and sample 107 of the formation are in an environment of water and a water-based surfactant additive. Drop 105 of crude oil and sample 107 of the formation define a contact angle θ 2 , which is smaller than contact angle θι. Accordingly, crude oil will be more easily produced from the formation of sample 107 than from the formation of sample 103 due to the effects of the water-based surfactant additive. Within a range, the contact angle generally decreases with increasing concentrations of surfactant additive, for example, as shown in Figure 2. Contact angle tests, however, must be performed in a controlled environment using sophisticated equipment, such as the equipment found in a laboratory setting.
[0008] Another assessment methodology is "core flooding," wherein a generally cylindrical piece of reservoir rock, obtained by drilling, is tested in a setup, such as shown in Figure 3. Sample 301 of reservoir rock is placed in a core holder 303 having seals 305 at each end. The maximum amount of recoverable crude oil is measured in a "water-flooding" experiment, wherein water is urged by a pump 307, via an accumulator 309, into core holder 303. Because sample 301 cannot be produced to exactly fit the internal dimension of core holder 303, a cylindrical flexible sealing element is inserted into the internal cavity of core holder 303. This sealing element is expanded by injecting fluid into the internal cavity of core holder 303. A pump 31 1 provides the differential pressure causing the water to travel through sample 301 . An oven 313 (shown in phantom for clarity) controlled by a temperature controller 315, or other such heating device, maintains core holder 303 at a desired temperature. A two- phase mixture of oil and water is produced from core holder 303, which is routed to an oil/water separator 317 via a back-pressure regulator 319, which maintains a predetermined back-pressure upstream of regulator 319, as indicated by pressure gages 321 and 323. The crude oil is separated from the water by separator 317 and the volume of oil is plotted as a function of the volume of injected water. The result of such a plot is a saturation-type function showing that after injecting a certain amount of water, the amount of the total recovered crude oil does not substantially change. The maximum recoverable oil is characteristic to the crude oil, the surface and pore properties of the reservoir rock, the initial oil saturation, and the chemistry of the injected water. The effectiveness of various additives may be discovered by performing the above-described experiment for each additive being considered. This type of testing, however, is time-consuming and laborious. A separate, individual reservoir rock sample, such as sample 301 , must be provided for each additive that is to be tested. Moreover, rock sample 301 must be carefully placed into core holder 303 so that the integrity of sample 301 is not compromised. Furthermore, volumetric measurements of the oil separated from the testing fluid is limited in precision, requiring the volume of crude oil required for each test to be excessively large and prohibiting large or small ratios to be measured.
[0009] There are methods and devices for evaluating the effectiveness of additives on the production of crude oil that are well known in the art, however, considerable shortcomings remain.
BRIEF SUMMARY OF THE INVENTION
[0010] In one aspect, the present invention provides a system for determining the effect of water-based additives on oil recovery. The system includes a water source, a water pump in fluid communication with the water source, a water-soluble additive source, and a water-soluble additive pump in fluid communication with the additive source. The system further comprises a first mixer in fluid communication with the water pump and the additive pump, a primary core holder inlet valve in fluid communication with the first mixer, a core holder in fluid communication with the primary core holder inlet valve, and a core holder outlet valve in fluid communication with the core holder. The system further comprises a solvent mixture pump in fluid communication with the core holder outlet valve, a solvent mixture source in fluid communication with the solvent mixture pump, a second mixer in fluid communication with the core holder outlet valve, and a first oil pump in fluid communication with the second mixer. The system further comprises a first oil source in fluid communication with the first oil pump, a detector in fluid communication with the second mixer, a secondary core holder inlet valve in fluid communication with the primary core holder inlet valve, and a suspension pump in fluid communication with the secondary core holder inlet valve. The system further includes a source of rock particles suspended in a fluid in fluid communication with the suspension pump, a second oil pump in fluid communication with the secondary core holder inlet valve, a second oil source in fluid communication with the second oil pump, and an acid mixture pump in fluid communication with the secondary core holder inlet valve. The system further includes an acid mixture source in fluid communication with the acid mixture pump, an oil/water mixable fluid pump in fluid communication with the secondary core holder inlet valve, an oil/water mixable fluid source in fluid communication with the oil/water mixable fluid pump, and a gas source in fluid communication with the secondary core holder inlet valve.
[0011] In another aspect, the present invention provides a method for determining the effect of water-based additives on oil recovery. The method comprises saturating a core with oil, flushing water through the oil-saturated core, establishing a low rate of water flow through the core, and injecting a solvent mixture into fluid recovered from the core. The method further includes measuring a baseline characteristic of the recovered fluid, setting an initial water-based additive injection rate, injecting a water-based additive into the water flow at the initial injection rate, and measuring a characteristic of the fluid into which the water-based additive has been injected at the initial injection rate.
[0012] In yet another aspect, the present invention provides a system for determining the effect of water-based additives on oil recovery. The system comprises a water source, a water pump in fluid communication with the water source, a water- soluble additive source, and a water-soluble additive pump in fluid communication with the additive source. The system further includes a first mixer in fluid communication with the water pump and the additive pump, a core holder in fluid communication with the first mixer, a second mixer in fluid communication with the core holder, and a solvent mixture pump in fluid communication with the second mixer. The system further includes a solvent mixture source in fluid communication with the solvent mixture pump and a detector in fluid communication with the second mixer.
[0013] In another aspect, the present invention provides a device for forming a core in a core holder. The device comprises a source of ground rock particles suspended in a fluid, a suspension pump in fluid communication with the source of ground rock particles suspended in a fluid, and a core holder in fluid communication with the suspension pump, the core holder comprising a permeable element on which the core is formed, the permeable element extending across an internal cavity of the core holder.
[0014] The present invention provides significant advantages, including, but not limited to, (1 ) providing a system and method for determining the effects of water- based additives on oil recovery in real-time and for defining optimum additive concentration to enhance oil recovery; (2) providing a way to automatically generate rock cores; (3) providing a system and method for determining the effects of water- based additives on oil recovery that are adaptable for use in the field; (4) providing a way to determine precise quantities of released oil; and (5) providing a system and method for determining the effects of water-based additives on oil recovery from both rock formations and metallic casings.
[0015] Additional objectives, features and advantages will be apparent in the written description which follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] The novel features characteristic of the invention are set forth in the appended claims. However, the invention itself, as well as a preferred mode of use, and further objectives and advantages thereof, will best be understood by reference to the following detailed description when read in conjunction with the accompanying drawings, in which the leftmost significant digit(s) in the reference numerals denote the first figure in which the respective reference numerals appear, wherein:
[0017] Figures 1 A and 1 B are stylized, side, elevational views illustrating conventional measurement of contact angles of oil adhered to a carbonate surface; [0018] Figure 2 is a graphical representation of conventional contact angle versus surfactant concentration;
[0019] Figure 3 is a schematic view of a conventional core flooding setup;
[0020] Figure 4 is a schematic view of a first illustrative embodiment of a system for screening the effects of water-based additives on crude oil recovery;
[0021] Figure 5 is a flow chart illustrating an exemplary method for screening the effects of water-based additives on crude oil recovery;
[0022] Figure 6 is a side, elevational and partial cross-sectional view of a first illustrative embodiment of a core holder and a filter cake;
[0023] Figure 7 is a graphical representation illustrating the optical density of a substantially homogenous organic fluid containing crude oil at various concentrations of surfactant additive in the fluid;
[0024] Figure 8 is a graphical representation illustrating a critical threshold surfactant additive concentration;
[0025] Figure 9 is a schematic view of a second illustrative embodiment of a system for screening the effects of water-based additives on crude oil recovery;
[0026] Figure 10 is a side, elevational and partial cross-sectional view of a second illustrative embodiment of a core holder;
[0027] Figure 1 1 is a side, elevational and partial cross-sectional view of a third illustrative embodiment of a core holder;
[0028] Figure 12 is a side, elevational and partial cross-sectional view of a third illustrative embodiment of a core holder; [0029] Figure 13 is a schematic view of a third illustrative embodiment of a system for screening the effects of water-based additives on crude oil recovery;
[0030] Figure 14 is a schematic view of a fourth illustrative embodiment of a system for screening the effects of water-based additives on crude oil recovery;
[0031] Figure 15 is a graphical representation illustrating the optical density of a toluene/oil blue mixture for various concentrations of surfactant additive;
[0032] Figure 16 is a graphical representation illustrating water and surfactant additive gradients for a testing setup utilizing the system of Figure 14;
[0033] Figure 17 is a graphical representation illustrating the optical density of an oil for various concentrations of surfactant additive; and
[0034] Figure 18 is a graphical representation illustrating oil release concentrations for various surfactant additives.
[0035] While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the scope of the invention as defined by the appended claims.
DETAILED DESCRIPTION OF THE INVENTION
[0036] Illustrative embodiments of the invention are described below. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system-related and business- related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.
[0037] The present invention relates to a system and method for determining the effect of water-soluble additives on oil recovery from carbonate-based rock formations, silicate-based rock formations, and metallic casings leading to or from such formations. Such effects can be determined under elevated temperature and pressure conditions. The effects of additives and pH on the wetting properties of rocks or casings can also be determined. The system and method of the present invention provides realtime concentrations of crude oil in testing fluids, as compared to traditional core-flooding tests wherein the total amount of recovered and separated crude oil is measured at a later time, when the separation of oil and water phases are difficult or time consuming. This is usually the case when production-enhancing additives such as surfactants are tested, because surfactant can promote emulsion formation or the appearance of a microemulsion phase between the oil and water layer. Emulsions are well stabilized in the presence of surfactants. Therefore, a "rag" layer is formed in the separator between the oil and water layers. This "rag" layer contains massive amounts of oil and water. Because of this, the amount of recovered oil cannot be determined precisely. If a separation technique, such as centrifugation or chemical demulsification is applied, the amount of recovered oil cannot be measured in real-time. Thus, traditional core- flooding measures an integrated quantity (usually not in real-time) of crude oil, while the system and method of the present invention measures a real-time differential quantity of crude oil, i.e., an oil concentration at a given time. Nevertheless, the total amount of recovered crude oil as a function of the injected fluid volume can be obtained utilizing the present system and method by integrating the concentration as a function of the injected, and hence recovered fluid volume. [0038] In this description and in the drawings provided herewith, features of certain elements are referenced by the element number followed by a suffix letter. For example, a first inlet of a primary core holder inlet valve 413 is referenced herein and in the accompanying drawings as first inlet 413a.
[0039] Figure 4 depicts a first illustrative embodiment of a system 401 for screening the effects of water-based additives on crude oil recovery. In the illustrated embodiment, a water reservoir 403 or other such water source is in fluid communication with a water pump 405. An additive reservoir 407 is in fluid communication with an additive pump 409. A first mixer 41 1 is in fluid communication with both water pump 405 and additive pump 409. First mixer 41 1 is also in fluid communication with first inlet 413a of primary core holder inlet valve 413. A second inlet 413b of primary core holder inlet valve 413 is in fluid communication with an outlet 415a of a secondary core holder inlet valve 415, which is described in further detail below. An outlet 413c of primary core holder inlet valve 413 is in fluid communication with an inlet 417a of a core holder 417, in which a filter cake is formed and housed for testing, as described in greater detail below. Core holder 417 is disposed within a heating device, such as an oven 419. An outlet 417b of core holder 417 is in fluid communication with a first inlet 421 a of a core holder outlet valve 421 . A second inlet 421 b of core holder outlet valve 421 is in fluid communication with a solvent mixture pump 423 that, in turn, is in fluid communication with a solvent mixture reservoir 425. A first outlet 421 c of core holder outlet valve 421 is in fluid communication with a first back-pressure regulator 429, which may be omitted in some embodiments. Any fluid emanating from first back-pressure regulator 429 is routed to waste discharge. If back-pressure regulator 429 is omitted, first outlet 421 c of core holder outlet valve 421 is routed to waste discharge. A second outlet 421 d of core holder outlet valve 421 is in fluid communication with a second mixer 431 . Second mixer 431 is also in fluid communication with a first crude oil pump 433 that, in turn, is in fluid communication with a crude oil source, such as a crude oil reservoir 435. Second mixer 431 is also in fluid communication with a first detector 437 that, in turn, is in fluid communication with a second back-pressure regulator 439. Second back-pressure regulator 439 is in fluid communication with a second detector 441 . Any fluid emanating from second detector 441 is routed to waste discharge. In one embodiment, first detector 437 and second detector 441 are spectrometers and, in such an embodiment, detectors 437 and 441 are preferably spectrometers configured to measure the ultraviolet-visible spectra of the fluid. Detectors 437 and/or 441 may also be configured to detect other characteristics of the fluid, such as conductivity, dielectric permittivity, density, acoustic velocity, acoustic attenuation, refractive index properties, light scattering properties, fluorescence, chemiluminescence, flame ionization properties, infrared properties, or the like. While detectors 437 and 441 may utilize any of a variety of methodologies for characterizing the concentration of crude oil within a test fluid, detectors configured to employ ultraviolet-visible spectroscopy are particularly advantageous. Unsaturated carbon-carbon bonds and aromatic or condensed-aromatic structures frequently observed in crude oil compounds provide strong optical density peaks in the ultraviolet-visible range, for example, having wavelengths within a range of about 200 nanometers to about 800 nanometers. It should also be noted that first detector 437 and second detector 441 may be combined into a single detector.
[0040] Still referring to Figure 4, a first inlet 415b of secondary core holder inlet valve 415 is in fluid communication with a suspension pump 443 that, in turn, is in fluid communication with a source of a suspension of formation rock particles in water, such as a reservoir 445 containing such a suspension. It should also be noted that, in one embodiment, suspension pump 443 is in fluid communication with a source of a suspension of formation rock particles in an oil phase, such as suspension reservoir 445. The formation rock particles may be silicate particles or carbonate particles. A second inlet 415c of secondary core holder inlet valve 415 is in fluid communication with a second crude oil pump 447 that, in turn, is in fluid communication with a crude oil source, such as a crude oil reservoir 449. It should be noted that in certain embodiments crude oil reservoirs 435 and 449 may be combined into a common reservoir. Moreover, crude oil reservoirs 435 and 449 may be a naturally-formed, subterranean reservoir, or a fluid sample taken at reservoir pressure and temperature from the reservoir such that the crude oil provided to crude oil pumps 433 and 447 is "live oil." A third inlet 415d of secondary core holder inlet valve 415 is in fluid communication with an acid mixture pump 451 that, in turn, is in fluid communication with an acid mixture source, such as an acid mixture reservoir 453. Acid mixture reservoir 453 or other such source provides one or more acids in a mixture along with, for example, one or more surfactants and water. Examples of the acids of the acid mixture include, but are not limited to, hydrochloric acid, nitric acid, acetic acid, formic acid, naphthenic acid, and the like. A fourth inlet 415e of secondary core holder inlet valve 415 is in fluid communication with an oil/water mixable fluid pump 455 that, in turn, is in fluid communication with a source of fluid that is mixable with oil and water, such as an oil/water mixable fluid reservoir 457. An example of a fluid that is mixable with oil and water is acetone; however, the present invention also contemplates the use of other such fluids, separately or in any combination, including isopropanol, methanol, and ethanol. A fifth inlet 415f of secondary core holder inlet valve 415 is in fluid communication with a gas source 459, which provides a gas such as nitrogen, carbon dioxide, a noble gas, air, or any mixture thereof. In the illustrated embodiment, a bypass circuit 461 , which is in fluid communication with first mixer 41 1 and core holder outlet valve 421 , is controlled by a bypass valve 463, which allows fluid flow to bypass core holder 417.
[0041] Figure 5 provides a flow chart depicting an exemplary embodiment of a method for screening the effects of water-based additives on crude oil recovery. The method of Figure 5 will now be described in light of system 401 illustrated in Figure 4. First, a filter cake core is formed in a core holder or core holder 417 (block 501 ). Employing system 401 , primary core holder inlet valve 413 is set to be open between second inlet 413b and outlet 413c. Secondary core holder inlet valve 415 is set to be open between first inlet 415b and outlet 415a. Bypass valve 463 is closed. Core holder outlet valve 421 is set to be open between first inlet 421 a and first outlet 421 c. Suspension pump 443 is then operated to urge the rock suspension, which comprises ground rock particles suspended in a fluid, from reservoir 445 through secondary core holder inlet valve 415, primary core holder inlet valve 413, and core holder inlet 417a into core holder 417. A filter cake is formed on a sieve or other such permeable member inside core holder 417. Figure 6 depicts one such embodiment. In the embodiment of Figure 6, a sieve 601 extends across an internal cavity 603 of core holder 417. Sieve 601 allows liquid to flow therethrough but retains particulates, forming filter cake 605. Once the filter cake is formed, suspension pump 443 is inactivated.
[0042] As noted herein, consolidated cores are often used in traditional core- flooding testing procedures. Because these conventional cores fail to exactly fit the internal dimensions of core holders, traditional core holders include a flexible internal seal of cylindrical shape that is kept under overburden pressure to seal against fluid flow around the core. The present system and method requires no such seal or equipment to provide overburden pressure, as the unconsolidated filter cake 605 (shown in Figure 6) adequately fits internal dimensions of core holder 417 to alleviate fluid flow between filter cake 605 and an internal wall 607 (shown in Figure 6) of core holder 417.
[0043] Returning to Figures 4 and 5, liquid is then removed from the filter cake, such as filter cake 605 of Figure 6, (block 503). Primary core holder inlet valve 413 remains set to be open between second inlet 413b and outlet 413c. Using system 401 , bypass valve 463 remains closed and core holder outlet valve 421 remains set to be open between first inlet 421 a and second outlet 421 d. Secondary core holder inlet valve 415 is set to be open between fifth inlet 415f and outlet 415a, allowing gas from gas source 459 to flow through secondary core holder inlet valve 415, primary core holder inlet valve 413, and core holder inlet 417a into core holder 417. Liquid within core holder 417 and within the filter cake is urged out of core holder 417 through core holder outlet 417b. Alternatively, the liquid, which is the continuous phase of the suspension in suspension reservoir 445, may be replaced with a different liquid. For example, it may be replaced by formation water.
[0044] Still referring to Figures 4, 5, and 6, filter cake 605 is then saturated with crude oil (block 505). Employing system 401 , primary core holder inlet valve 413 remains set to be open between second inlet 413b and outlet 413c. Bypass valve 463 remains closed and core holder outlet valve 421 is set to be open between first inlet 421 a and first outlet 421 c. Secondary core holder inlet valve 415 is set to be open between second inlet 415c and outlet 415a. Second crude oil pump 447 is then operated to urge crude oil from crude oil reservoir 449 through secondary core holder inlet valve 415, primary core holder inlet valve 413, and core holder inlet 417a into core holder 417. After filter cake 605 is saturated with crude oil, second crude oil pump 447 is inactivated.
[0045] Crude oil is then removed from the pores of filter cake 605 of Figure 6, with a water flush (block 507), leaving behind rock particles that are covered with a thin film of oil. Using system 401 , primary core holder inlet valve 413 is set to be open between first inlet 413a and outlet 413c. Bypass valve 463 remains closed, while core holder outlet valve 421 is set to be open between first inlet 421 a and first outlet 421 c. The position of secondary core holder inlet valve 415 is disregarded, as second input 413b of primary core holder inlet valve 413 is closed. Water pump 405 is then operated to urge water from water reservoir 403 or other such water source through first mixer 41 1 , primary core holder inlet valve 413, and core holder 417 at a high flow rate to flush crude oil from the pores of the filter cake 605. Water reservoir 403 can contain either de-ionized water, water used for formation flooding, or formation water, either simulated or taken from the formation.
[0046] Still referring to Figures 4 and 5, a low rate of water flow is established through the filter cake (block 509), a solvent mixture is injected into fluid recovered from the filter cake (block 51 1 ), and a baseline characteristic of the recovered fluid is measured (block 513). Employing system 401 , primary core holder inlet valve 413 is set to be open between first inlet 413a and outlet 413c. Core holder outlet valve 421 is set to be open between first inlet 421 a, first inlet 421 b, and second outlet 421 d. The position of secondary core holder inlet valve 415 is disregarded, as second input 413b of primary core holder inlet valve 413 is closed. Bypass valve 463 remains closed. Water pump 405 is then operated to urge water from water reservoir 403 or other such water source through first mixer 41 1 , primary core holder inlet valve 413, and core holder 417 to core holder outlet valve 421 at a lower rate of flow than described herein concerning block 507 of Figure 5. Solvent mixture pump 423 is operated to urge a solvent mixture from solvent mixture reservoir 425 or other such source to second input 421 b of core holder outlet valve 421 . The solvent mixture of reservoir 425 is a mixture of one or more organic solvents, and one or more alcohols, and/or one or more surfactants, brine, and/or water, as is discussed in greater detail below. The particular composition and flow rate of the solvent mixture are implementation specific and are chosen such that the solvent mixture fully incorporates the fluid flowing downstream of core holder 417 in second mixer 431 , producing a substantially homogenous organic phase containing a small amount of water. The substantially homogenous organic phase fluid is then routed to first detector 437. In embodiments wherein detector 437 is a spectrometer, detector 437 measures the baseline optical density of the substantially homogenous organic phase fluid at a predetermined selective wavelength, corresponding to a peak characteristic of the crude oil being tested. Figure 7 depicts an exemplary graph 701 representing the optical densities of such a substantially homogenous organic fluid. The baseline in the example of Figure 7 is generally at 701 , prior to the start of a concentration gradient, generally at 703. In embodiments wherein detector 437 measures another type of characteristic, such as conductivity, dielectric permittivity, density, acoustic velocity, acoustic attenuation, refractive index properties, light scattering properties, fluorescence, chemiluminescence, flame ionization properties, infrared properties, or the like, detector 437 determines or measures a baseline measurement of the characteristic of the substantially homogenous organic phase fluid.
[0047] The effect of various concentrations of chemical additive on the release of crude oil from the filter cake is now measured under a constant total flow rate through the core, as well as under a constant ratio of the flow rate at core holder outlet valve 421 inlet 421 a to the flow rate at inlet 421 b. Referring to Figure 5, an initial additive injection rate is set (block 515). This initial injection rate is preferably one that is estimated to be a lower rate than the rate required to release substantial amounts of crude oil from the filter cake. Additive is then injected into the water flow (block 517) and the characteristic of the resulting recovered fluid is measured (block 519). If there is a significant change in the characteristic from the baseline measurement, (block 521 ), such as a spike in the optical density, an additive injection rate resulting in the release of at least a portion of the crude oil film from the filter cake has been determined and the measurement of the characteristic is compared to a calibration curve (block 525) to determine the concentration of crude oil in the fluid. However, if there is no significant change in the characteristic (block 521 ), the additive injection rate is increased (block 523). Additive is injected at the increased rate into the water flow (block 517) and the characteristic, such as the optical density, of the resulting fluid is measured (block 519). If, now, there is a significant change in the measurement of the characteristic (block 521 ), such as a spike in the optical density, an additive injection rate resulting in the release of crude oil from the filter cake has been determined and the measurement of the characteristic is compared to the calibration curve (block 525). However, if there is no significant change in the measurement of the characteristic (block 521 ), the additive injection rate is again increased (block 523) and the process of injecting additive into the water flow (block 517), measuring the characteristic of the resulting fluid (block 519), and determining whether a change in the characteristic has occurred (block 521 ) is repeated until a significant change in the measured characteristic occurs.
[0048] Figure 8 depicts an exemplary illustration of the critical threshold surfactant additive concentration. In Figure 8, the concentration of surfactant additive in the fluid stream is represented by line 801 and the concentration of oil in the fluid stream released from the filter cake is represented by line 803. Line 803 demonstrates an increase in released oil concentration generally at 805. The critical threshold surfactant additive concentration is the concentration, generally at 807, of surfactant additive corresponding to the point at which an increased released oil concentration occurs (generally at 805).
[0049] Employing system 401 of Figure 4, blocks 515, 517, 519, 521 , and 523 of the method depicted in Figure 5 are accomplished by setting primary core holder inlet valve 413 to be open between first inlet 413a and outlet 413c. Core holder outlet valve 421 is set to be open between first inlet 421 a and second outlet 421 d. The position of secondary core holder inlet valve 415 is disregarded, as second input 413b of primary core holder inlet valve 413 is closed. Bypass valve 463 remains closed. Water pump 405 and additive pump 409 are operated to urge water from water reservoir 403 and additive from additive reservoir 407, or other such sources, to provide a predetermined, initial concentration gradient of additive in water to first mixer 41 1 . The resulting mixed fluid is routed through primary core holder inlet valve 413, core holder 417, core holder outlet valve 421 , and second mixer 431 to first detector 437, wherein a characteristic, such as the optical density, of the fluid is measured. If there is significant change in the characteristic, (block 521 of Figure 5), such as a spike in the optical density, the additive injection rate currently in use is deemed to result in the release of a significant portion of the crude oil film from the filter cake, such as filter cake 605 of Figure 6. The measured characteristic can be compared to a calibration curve that provides a correlation between the particular characteristic of the fluid and the concentration of crude oil in the fluid, which is generated in block 525, to determine the concentration of crude oil in the fluid. Note that, in some embodiments, block 525 is omitted from the method of Figure 5, as this operation can be performed independently from the method of Figure 5. If, however, there is no significant change in the characteristic (block 521 of Figure 5), the additive injection rate is increased (block 523 of Figure 5), such that water pump 405 and additive pump 409 are operated to urge water from water reservoir 403 and additive from additive reservoir 407, or other such sources, to provide a larger concentration gradient of additive in water to first mixer 41 1 . The operation of system 401 is continued in this way until a significant change in the characteristic is measured by first detector 437. Referring again to Figure 7, such a significant change in the optical density of the fluid presented to first detector 437 is shown generally at 705.
[0050] Generally, crude oil and water produce a multi-phase system when mixed, which can cause strong light scattering when ultraviolet-visible spectroscopy is utilized in the determination of crude oil concentration in the testing stream. The emulsified oil or water droplets in the multi-phase system divert part of the incident light beam in the spectroscopic cell. This diverted fraction of light may not reach the spectroscopic detector. Hence, the apparent optical density is considerably increased in such multi-phase fluids, leading to misleading concentration determination, because the apparent optical density, besides the volume fraction, is very dependent on the particle size. The solvent mixture of reservoir 425, which is a mixture of one or more organic solvents, and one or more alcohols, and/or one or more surfactants, brine, and/or water, is injected into the testing stream to alleviate this problem by making the multi-phase testing stream into a single phase. In one embodiment, a mixture of toluene and isopropanol or toluene and tetrahydrofuran forms the solvent mixture, as the mixture is capable of dissolving at least some of the water phase and is mixable with the crude oil.
[0051] As discussed above, the optical density or other such characteristic of the fluid can be compared to a calibration curve (block 525 of Figure 5), which provides a correlation between optical density or other such characteristic of the fluid and concentration of crude oil in the fluid, to determine the concentration of crude oil in the fluid when using a particular concentration of additive in the water flush. System 401 can be used in the generation of such calibration curves. In the embodiment of Figure 4, bypass valve 463 is set open and primary core holder inlet valve 413 is set closed, i.e., inlets 413a and 413b, as well as outlet 413c are closed. Core holder outlet valve 421 is set to be open between first inlet 421 a, second inlet 421 b, and second outlet 421 d. Water pump 405 or additive pump 409, or both, are then operated to urge water from water reservoir 403, or other such water source, or aqueous phase through first mixer 41 1 , bypass circuit 461 , core holder outlet valve 421 , and second mixer 431 to first detector 437. Solvent mixture pump 423 is operated to urge the solvent mixture from solvent mixture reservoir 425, or other such source, to second input 421 b of core holder outlet valve 421 . As discussed above, the particular composition and flow rate of the solvent mixture are chosen such that the solvent mixture fully incorporates the water flowing from water pump 405 in second mixer 431 . Crude oil pump 433 is operated to urge crude oil from crude oil reservoir 435, or other such crude oil source, to second mixer 431 , where the water, solvent mixture, and crude oil are mixed. Crude oil is provided by crude oil pump 433 to second mixer 431 at a predetermined flow rate corresponding to a predetermined desired concentration of crude oil in the water/solvent mixture. The mixture emitted from second mixer 431 , which is a homogeneous, organic phase having small water content, is routed to first detector 437, wherein a characteristic, such as the optical density at a specified wavelength, of the water/solvent mixture/crude oil mixture is measured or determined. The measured characteristic corresponds to the concentration of crude oil in the water/solvent mixture/crude oil mixture for the particular crude oil being tested. The crude oil concentration is then changed by altering the injection rate of crude oil provided by crude oil pump 433 (while maintaining constant the total flow rate through the core and the ratio of the flow exiting the core to the solvent mixture, i.e. the flow rate at the first inlet 421 a of core holder outlet valve 421 to the flow rate at second inlet 421 b) and the optical density at the specified wavelength or other such characteristic, depending upon the type of first detector 437, of the water/solvent mixture/crude oil mixture is determined in first detector 437. This second measurement of the characteristic corresponds to the increased concentration of crude oil in the water/solvent mixture/crude oil mixture for the particular crude oil being tested. The steps of increasing the concentration of crude oil provided by crude oil pump 433 and measuring the characteristic, such as the optical density, of the water/solvent mixture/crude oil mixture in first detector 437 are repeated a sufficient number of times to generate a calibration curve of the characteristic versus crude oil concentration for the crude oil being investigated.
[0052] Referring still to Figure 4, system 401 may be cleaned by dissolving the filter cake from core holder 417, removing water and other residues, and drying core holder 417. Dissolving the filter cake is accomplished by setting primary core holder inlet valve 413 to be open between second inlet 413b and outlet 413c. Secondary core holder inlet valve 415 is set to be open between third inlet 415d and outlet 415a. Core holder outlet valve 421 is set to be open between first inlet 421 a and first outlet 421 c. Bypass valve 463 is closed. Acid mixture pump 451 is operated to urge the acid mixture from acid mixture reservoir 453, or other such acid mixture source, to secondary core holder inlet valve 415. The acid mixture flows through secondary core holder inlet valve 415 and primary core holder inlet valve 413 to core holder 417, wherein the acid mixture dissolves the filter cake. Surfactants entrained in the fluid remove oil residues from core holder 417. The fluid then flows through core holder outlet valve 421 and first back-pressure regulator 429 to waste discharge.
[0053] Water and other residues, such as acid and surfactant residues, are now removed. Primary core holder inlet valve 413 remains open between second inlet 413b and outlet 413c. Secondary core holder inlet valve 415 is set to be open between fourth inlet 415e and outlet 415a. Core holder outlet valve 421 remains open between first inlet 421 a and first outlet 421 c. Bypass valve 463 remains closed. Oil/water mixable fluid pump 455 is operated to urge the fluid that is mixable with oil and water, such as acetone, isopropanol, methanol, or ethanol, or any combination thereof, from oil/water mixable fluid reservoir 457, or other such source, to secondary core holder inlet valve 415. The fluid mixable with oil and water flows through secondary core holder inlet valve 415 and primary core holder inlet valve 413 to core holder 417, where the fluid mixable with oil and water removes water, acid, surfactants, and the like from core holder 417. The fluid then flows through core holder outlet valve 421 and first back-pressure regulator 429 to waste discharge.
[0054] Core holder 417 is now dried. Primary core holder inlet valve 413 remains open between second inlet 413b and outlet 413c. Secondary core holder inlet valve 415 is set to be open between fifth inlet 415f and outlet 415a. Core holder outlet valve 421 remains open between first inlet 421 a and first outlet 421 c. Bypass valve 463 remains closed. Gas from gas source 459 flows through secondary core holder inlet valve 415 and primary core holder inlet valve 413 to core holder 417, where the gas dries core holder 417. The gas then flows through core holder outlet valve 421 and first back-pressure regulator 429 to waste discharge.
[0055] It should be noted that first detector 437 and/or second detector 441 may be omitted from system 401 in some embodiments, wherein optical densities of fluids associated with system 401 are determined separate from system 401 .
[0056] The present invention yet further contemplates a second illustrative embodiment of a system 901 , shown in Figure 9, for screening the effects of water- based additives on crude oil recovery. In such an embodiment, core holder 417 of system 401 of Figure 4 is replaced with a core holder 903 having a coating on an interior surface thereof comprising particles of formation rock or an artificially created layer with chemical composition similar to that of formation rock. Figure 10 depicts an illustrative embodiment of core holder 903, in which a coating 1001 is disposed on an interior surface 1003 of core holder 903. Coating 1001 replaces but functionally corresponds to a filter cake, such as filter cake 605 of Figure 6. Coating 1001 may comprise a silica- or carbonate-based material. For example, coating 1001 may comprise a calcium carbonate layer applied to interior surface 1001 by electrodeposition or a silica or carbonate layer applied to interior surface 1001 by a vacuum deposition technique. When employing such an embodiment, system 901 may omit suspension pump 443 and suspension reservoir 445.
[0057] In other embodiments, core holder 417 of Figure 4 or core holder 903 of Figure 9 can be replaced with core holders having other configurations. For example, the present invention contemplates a configuration wherein core holder 903 of system 901 is replaced with a core holder 1 101 of Figure 1 1 . In the illustrated embodiment, a single calcite or quartz crystal 1 103 exhibiting substantially no porosity is disposed in an internal cavity 1 105 of core holder 1 101 . In another configuration contemplated by the present invention, core holder 903 of system 901 is replaced with a core holder 1201 of Figure 12. In this illustrated embodiment, a macroscopic body 1203 of silicate or carbonate rock exhibiting substantially no porosity is disposed in an internal cavity 1205 of core holder 1201 . In the embodiments of Figures 1 1 and 12, crystal 1 103 and macroscopic body 1203 exhibit substantially no porosity so that oil is not contained within crystal 1 103 or macroscopic body 1203 by capillary forces. As a result, oil released from crystal 1 103 and macroscopic body 1203 is controlled by altering the wettabilities of crystal 1 103 and macroscopic body 1203.
[0058] The present invention further contemplates a third illustrative embodiment of a system 1301 , shown in Figure 13, for screening the effects of water- based additives on crude oil recovery. In such an embodiment, second crude oil pump 447 and second crude oil reservoir 449 are omitted from system 401 and first detector 437 detects the production of crude oil-in-water emulsions released from a filter cake, such as filter cake 605 (Figure 6), disposed in core holder 417; from a coating, such as coating 1001 (Figure 10) of core holder 903 (Figure 9); from a single calcite or quartz crystal exhibiting substantially no porosity, such as crystal 1 103 (Figure 1 1 ); from a macroscopic body of silicate or carbonate rock exhibiting substantially no porosity, such as macroscopic body 1203 (Figure 12); or the like.
[0059] Figure 14 depicts a fourth illustrative embodiment of a system 1401 for screening the effects of water-based additives on crude oil recovery. In the illustrated embodiment, a water reservoir 1403 or other such water source is in fluid communication with a water pump 1405. An additive reservoir 1407 is in fluid communication with an additive pump 1409. A first mixer 141 1 is in fluid communication with both water pump 1405 and additive pump 1409. In one embodiment, first mixer 141 1 is a static mixer. First mixer 141 1 is also in fluid communication with an inlet 1413a of a core holder inlet valve 1413. An outlet 1413b of core holder inlet valve 1413 is in fluid communication with an inlet 1415a of a core holder 1415. Note that core holder 1415 may be configured to house any type of sample, such as those disclosed herein concerning Figures 6, 10-12, or the like. An outlet 1415b of core holder 1415 is in fluid communication with an inlet 1417a of a core holder outlet valve 1417. An outlet 1417b of core holder outlet valve 1417 is in fluid communication with a second mixer 1419. In one embodiment, second mixer 1419 is a dynamic mixer. Second mixer 1419 is also in fluid communication with a solvent mixture pump 1421 that, in turn, is in fluid communication with a solvent mixture reservoir 1423, or other such supply of solvent. Furthermore, second mixer 1419 is in fluid communication with a detector 1425 that, in turn, is in fluid communication with a back-pressure regulator 1427. Detector 1425 may be of any type suitable to measure a characteristic that can correspond to the crude oil concentration of a fluid, such as the detector types disclosed herein concerning detectors 437 and 441 of Figure 4. Any fluid emanating from back-pressure regulator 1427 is routed to waste discharge. [0060] System 1401 was utilized in tests to determine water-soluble surfactant levels that resulted in (1 ) simulated crude oil being released from an oil-soaked and water-flushed packing of material simulating ground formation rocks, referred to herein as the "model" setup, and (2) crude oil being released from calcite particles soaked in oil and flushed with water, referred to herein as the "real" setup. In the model setup, core holder 1415 was loaded with hydrophobic silica beads exhibiting diameters of about 75 micrometers each, representing particles of formation rock. The hydrophobic silica beads were coated with a mixture of toluene and "oil blue," which was used as a model crude oil as oil blue is an oil-soluble surfactant that has a measurable optical peak in the ultraviolet-visible range. Dodecylbenzene sulfonic acid sodium salt was used as a water-soluble surfactant additive in additive reservoir 1407. Detector 1425 was a spectrometer configured to measure the ultraviolet-visible spectra of fluid. To obtain a baseline optical density, core holder inlet valve 1413 was set open between inlet 1413a and outlet 1413b. Core holder outlet valve 1417 was set open between inlet 1417a and outlet 1417b. Water pump 1405 was operated to urge water from water reservoir 1403 through first mixer 141 1 , core holder inlet valve 1413, core holder 1415, core holder outlet valve 1417, second mixer 1419, and detector 1425. Solvent mixture pump 1421 was operated to urge an isopropyl alcohol and toluene solution from solvent mixture reservoir 1423 into mixer 1419 to provide a homogeneous, organic phase having a small water content to detector 1425. Figure 15 depicts a graph 1501 representing optical densities of the toluene/oil blue mixture at a wavelength of about 651 nanometers for various concentrations of surfactant additive, in which the baseline optical density is illustrated generally at 1503. After obtaining a baseline optical density of the fluid passing through detector 1425, the surfactant additive from additive reservoir 1407 was gradually increased in the water stream from water reservoir 1403 by simultaneously altering the flow rates of water pump 1405 and additive pump 1409 according to the graphical representation provided in Figure 16, in which line 1601 represents the gradient for water flow and line 1603 represents the gradient for surfactant additive flow, as a percentage of total fluid flow. At a point represented generally at 1505 on graph 1501 in Figure 15, the optical density of the toluene/oil blue mixture significantly increases when a critical threshold surfactant additive concentration is reached.
[0061] Still referring to Figure 14, and referring to the "real" setup, calcite chunks, such as those provided by Ward's Natural Science Limited of St. Catharines, Ontario, Canada, were cleaned using 1 .0 M hydrochloric acid in an ultrasonic bath. The cleaned calcite was dried and crushed, then passed through 212 micrometer and 180 micrometer sieves. The 212-180 micrometer fraction was collected in the 180 micrometer sieve and flushed for several minutes with tap water, followed by a flushing with acetone for one to two minutes. The 212-180 micrometer fraction was then left to dry. Forty micrometer frit was placed into the bottom of core holder 1415, i.e., proximate outlet 1415b thereof, and core holder 1415 was then filled with the dried calcite powder. Note that several times during the filling process core holder 1415 was vibrated and tapped on a solid surface to pack the calcite powder. Once fully packed, 2 micrometer frit was fixed to seal the calcite powder in core holder 1415. The sealed core holder 1415 was then placed in an oven at about 200 °C for about 45 minutes under vacuum. Core holder 1415 was cooled for about 10 minutes after being removed from the oven. Following the cooling period, core holder 1415 was held generally vertically with outlet 1415b of the column submerged in oil, such as S32845E oil. A vacuum line was connected to inlet 1415a of core holder 1415. Oil was allowed to flow through core holder 1415 with vacuum applied thereto for about one minute after oil was first seen emanating from inlet 1415a. Note that core holder 1415 was flooded with oil relatively soon after the calcite powder had been heat treated to avoid inconsistent measurements relating to the critical threshold surfactant additive concentration.
[0062] Core holder 1415 was then installed into system 1401 and water flushed at a rate increasing from about 0.3 milliliters per minute to about 20 milliliters per minute over a time span of about 40 minutes. After flushing, the baseline was established with a flow rate of about 0.8 milliliters per minute of water pump 1405. The combined flow rate from water pump 1405 and additive pump 1409 was then set to the same rate of about 0.8 milliliters per minute, while the concentration of additive in the integrated flow during the additive injection period was increasing at about 2.18 x 10 moles per milliliter per minute. The flow rate from solvent mixture pump 1421 was about 5.9 milliliters per minute. Figure 17 depicts a graph 1701 representing the optical density at a wavelength of about 280 nanometers of the oil in the fluid flowing through detector 1425 during the test. A baseline measurement is shown at 1703 in Figure 17. A spike in the optical density corresponding to the critical threshold surfactant additive concentration is shown generally at 1705, which is the first point of sustained oil release. Note the similarities in graphs 1501 and 1701 representing the model setup and real setup, respectively.
[0063] Referring now to Figure 18, the use of several alkyl trimethyl ammonium bromide (CnTAB) surfactant additives resulted in significant oil release from the oil-treated calcite particles. The use of the C16TAB additive resulted in an oil concentration of between 0.00004 and 0.00005 moles per liter, while the use of the C14TAB additive resulted in an oil concentration of about 0.00005 moles per liter. The use of the C12TAB additive resulted in an oil concentration between 0.00005 and 0.00006 moles per liter and the use of the C10TAB additive resulted in an oil concentration between 0.00007 and 0.00008 moles per liter. Note that C8TAB and C6TAB additives were tested but did not result in significant oil release. It should also be noted that when using CnTAB-type surfactants the critical threshold surfactant additive concentration is dependent upon the rate of increase of the concentration rate above about 2.18 x 10 "6 moles per liter per minute.
[0064] As noted herein, the present system and method is useful in determining the effect of water-soluble additives on oil recovery from metallic casings. In an exemplary implementation for screening surfactant additives for mud removal from metallic casings, the silicate or calcite particles disposed in the core holder are replaced with stainless steel powder, for example, AISI 316 powder having a maximum particle size of 150 microns, such as part number FE246010 available from Goodfellow Corporation of Oakdale, Pennsylvania, USA, or stainless steel beads, for example AISI 316 beads having diameters of about 0.5 millimeters, such as part number FE246805 also available from Goodfellow Corporation. The stainless steel powder or beads simulate a casing or liner surface. Moreover, sieved sand, calcite, or ground shale can be used to simulate the mud-formation interface. Calcite or barite may be used to simulate weighting agents of the initial mud in order to determine the dewetting of these oil-based mud solids, helpful for dispersing them in the spacer fluid. Rather than crude oil, the base oil of the drilling fluid or mud is used in the test. If the particular drilling fluid or mud is easily dissolved by the solvent mixture, i.e., the solvent mixture of reservoir 425, such as toluene/isopropanol or toluene/tetrahydrofuran, the complete drilling fluid or mud formulation, rather than just the base oil of the drilling fluid or mud, may be employed.
[0065] The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the invention. Accordingly, the protection sought herein is as set forth in the claims below. Although the present invention is shown in a limited number of forms, it is not limited to just these forms, but is amenable to various changes and modifications.