Patent Application
20180362842
The present disclosure relates to compositions, methods, and systems for crude oil extraction.
In current oilfield technology, there are several methods used in medium, heavy and extra heavy crude extraction during production, secondary and tertiary recovery processes, to minimize the energy required to pump the crude up to the surface.
Among such methods, some relate to the modification of the crude properties like viscosity. Other methods modify the interaction between the oil/gas and the formation. Still other methods deal with different pumping technologies. Such methods aim to maximize the “oil production rate vs. energy consumed” ratio, with the main limiting factors being the equipment and material costs together with the energy demands.
Among the known methods used to modify the interaction between the oil/gas and the formation are the so-called “flooding” methods, which comprise the injection of surfactant containing chemicals in order to increase the amount of oil extracted from the formation without increasing the supplied pumping energy. The main role of the injected surfactant is to modify the wettability of the formation rocks or sands, turning the hydrophobic behavior into a hydrophilic behavior; thus, the oil-wet behavior of the rock, or sand of the formation or bituminous sands, changes into a water-wet behavior.
Commercial surfactants currently used in medium, heavy and extra heavy crude oil wells perform differently in different wells. Some surfactants are better suited for certain crude and/or formation characteristics, and consequently, effective for those wells, while showing only a marginal oil recovery improvement in other wells, which may even elevate the overall production cost of those wells without a net benefit.
The “Faja Petrolifera del Orinoco” (Orinoco Belt) is an oil producing region located in south western Venezuela, and one of the largest reservoirs of medium, heavy and extra heavy crude oils on Earth. Production of medium (API gravity from 22 to 30), heavy (API gravity from 12 to about 22) and extra heavy (API gravity from 7 to about 12) crude oil entails elevated costs and exhibit additional complexity due to a high variability in mechanical and physical properties of both oil and formation, even in geographically nearby wells. Due to this variability, the same methods are not equally effective in different wells within the same field, decreasing the efficiency of those methods and, in certain instances, even making them useless. The crude oils of the Orinoco Belt are Junin (API 10), Boyacá (API 10.5), Ayacucho (API 16), and Carabobo (API 4 to 16), named after the fields where they are found and produced. Even within crudes of the same field, significant behavioral differences regarding crude and formation characteristics and behavior towards production strategies can be found.
The friction of medium, heavy and extra heavy crude oils from “La Faja del Orinoco” with the pipeline walls can be successfully reduced through the addition of a specially formulated surfactant mixture described by U.S. Pat. No. 9,587,199 B2, the entirety of which is incorporated herein by reference, that promotes the formation of a multiphase mixture and simultaneously turns the pipeline's inner walls into hydrophilic surfaces.
Formation wettability is one of the physical properties of an oil formation that can lead to an abrupt decrease of a well production once the natural pressure of the reservoir decays as the reservoir depletes, and when it exhibits an oil-wet tendency added to a low porosity and permeability. This may cause the early abandonment of the well when Enhanced Oil Recovery (EOR) methods prove inefficient or useless. Improper EOR operations, like the application of polymer based stimulation fluids, can lead to severe reservoir damage, including permeability and wettability changes that turn the formation into oil-wet and thereby inhibit the flow of crude to the well. The crude oil flow from the reservoir into the well hole depends on several factors such as permeability, viscosity and temperature of the fluid, and the confining pressure of the fluid, in addition to the wettability properties of the formation.
The measurement of the damage caused by a fluid that was injected into the reservoir can be carried out by a Permeability Restoration Test, which comprises a forced flow of a typical oil of the formation through a mineral core sample before and after implicating the stimulation fluid.
Current experimental surface wettability measurements in oil field applications involve qualitative methods like the floatation method and the relative permeability method, and quantitative methods, which include the Contact Angle measurement, the Amott Method, and the USBM method. Each of the wettability measurement techniques has relative advantages and disadvantages, depending on the surface type of the application and the required response time, cost, accuracy and precision.
The present disclosure provides a stable, homogeneous, low-cost, easy-to-adapt chemical formulation for wettability modification, a procedure to inject the formulation into an oil well, and a method to determine the required proportions of the formulation's constituent components to best suit each particular well characteristics and conditions, as well as the crude oil properties, in order to reduce the overall production costs of medium, heavy and extra heavy oil wells with different characteristics.
Friction reduction observed in pipelines of different medium, heavy and extra heavy oil from “La Faja del Orinoco” (Orinoco Belt) after addition of a mixture described by U.S. Pat. No. 9,587,199 B2 provides evidence of the influence of particular chemical components and their relative concentrations in a multiphase mixture that can be used to turn the oil-wet behavior of formation rocks, sands or bituminous sands into water-wet behavior.
In some embodiments, the present disclosure provides a formulation for wettability modification which can be injected into medium, heavy or extra-heavy crude oil/gas wells during regular production or as an Enhanced Oil Recovery method during secondary or tertiary recovery procedures, which can produce a change from oil-wet tendency into a mixed or a water-wet tendency in order to increase the oil production/energy consumption ratio of the well, and allow profitable operations in wells with very poor to negligible recovery rates due to reduced formation permeability and natural pressure drop.
In some embodiments, the present disclosure provides a basic chemical formulation for wettability modification of medium, heavy and extra heavy oil wells which can produce similar positive oil recovery results in oil/gas wells with different specific mineral characteristics of the formation or bituminous sands, bearing different medium, heavy and extra heavy oil types and characteristics, and different reservoir conditions, by the variation in the relative concentration of the chemical components of the basic chemical formulation while remaining as a stable mixture, allowing the use of the chemical formulation among a large number of oil fields and wells which simplifies procedures and reduces operating costs.
In some embodiments, the present disclosure provides a chemical formulation for wettability modification that is non-harmful to a formation's original permeability.
In some embodiments, the present disclosure provides a chemical formulation for wettability modification that contributes to the restoration of the original wettability tendency of a formation, distorted by former treatment with harmful stimulation fluids.
In some embodiments, the present disclosure provides a chemical formulation for wettability modification that may be obtained from mixing low cost commercial chemical components by standard procedures, resulting in a lower cost option than commonly used oilfield stimulation fluids.
In some embodiments, the chemical formulation for wettability modification disclosed herein reduces the friction of a multiphase fluid comprising the chemical formulation, medium, heavy or extra-heavy oil, some formation water and, if present, natural gas, and also reduces the necessary pumping energy to move the fluid, without creating an emulsion or modifying the viscosity of the oil.
In some embodiments, the present disclosure provides a method to obtain the most suitable approximate relative concentration of each component of the chemical formulation according to the well, formation and oil characteristics, in order to achieve the best performance in wettability modulation of the formation rocks and sands.
In some embodiments, the present disclosure provides a method for oil/gas well stimulation by modifying the wettability of the rock or sands in an oil bearing formation, which may include treating the well with a stimulation fluid derived from a basic chemical formulation.
In some embodiments, a chemical formulation, which is based on brine but not on polyolefins, polyacrylamides, or polyacrylates, is mixed with water-soluble surfactants as active components, the salt of a weak acid as a pH regulator, and non-aromatic solvents. Such a formulation may exhibit a satisfactory friction reduction, permeability enhancement and capability to modulate wettability from oil-wet to water-wet, achieved for medium, heavy and extra-heavy oil, in producing oil wells, as well as in multiphase fluid conduits.
One potential benefit that may be realized is that the proportions of the components of the chemical formulation for well stimulation can be adjusted to best suit the formation/oil characteristics combination by utilizing a method that considers historical well data and laboratory test results.
Savings in the consumption of pumping energy, and a real possibility to increase the oil production rate, especially for medium, heavy and extra-heavy oil, may be realized according to certain embodiments disclosed herein.
Friction reduction, permeability enhancement and wettability changes to, preferentially, water-wet, without formation damage, are achieved through changes in the physical-chemical interaction between the fluid and the rock, allowing the crude oil to flow with relatively less applied energy and without major viscosity changes.
In addition to reducing crude oil friction, the disclosed chemical formulation may restore damage or permeability and wettability changes in a formation that may have occurred during the well construction and production stages.
The hydrophilic groups on the head of the surfactant molecules allow creation of a thin film of water on the rock and/or inner conduit surfaces that result in an enhanced crude oil mobility due to the sliding of the crude over the surfaces. The hydrophobic chains (or tails) keep the crude moisture away from the water-wetted surfaces.
The above and further advantages of the exemplary embodiments may be better understood by referring to the following description in conjunction with the accompanying drawings, in which same numbers indicate similar structural elements and features in various figures. The drawings are not necessarily to scale; instead the emphasis is placed on illustrating the features of the exemplary embodiments.
Exemplary embodiments of the present disclosure relate to a chemical formulation that may be used as a wettability improver in medium, heavy and extra heavy oil wells, resulting in a change of the wettability of the formation rocks and sands from oil-wet into water-wet tendency, which may improve the oil recovery performance of the well. In some embodiments, the proportions of the chemical components of the chemical formulation are adjusted according to characteristics of the well.
This disclosure relates to a brine based chemical formulation that is not based on polyolefins, polyacrylamides, or polyacrylates, for which reason it is less harmful to the formation.
By including a water soluble surfactant as active component in a brine and a non-aromatic solvent as part of the chemical formulation, chemical formulations disclosed herein exhibit satisfactory friction reduction, permeability enhancement and capability to change wettability from oil-wet to water-wet for medium, heavy and extra-heavy oil in producing oil wells, as well as in multiphasic fluid conduits. Some observed benefits include the increase of the production rate, especially for medium, heavy and extra-heavy oil, together with pumping energy consumption savings.
Exemplary embodiments of chemical formulations for wettability modification disclosed herein comprise a brine based mixture of non-aromatic solvents with low-toxicity, biodegradable components. The components include as active components, but are not limited to, a strong organic acid, a non-ionic surfactant and a pH adjuster.
The organic acid, that acts as surfactant precursor, may be utilized at a 0.1 to 10% weight concentration, preferably between 0.2 and 5% weight concentration, based on the weight of the final formulation. Suitable organic acids preferably have a pKa value between −2 and 2, and include, but are not limited to sulfonic acids, alkylsulphonic acids, arylsulfonic acids and/or mixtures thereof. Preferred organic acids are selected from the group consisting of formulas (1) and (2) below:
where:
R1 is an hydrogen atom and R2 is a linear or branched saturated, unsaturated or cyclic hydrocarbon substituent or R1 and R2 are both linear or branched, saturated, unsaturated or cyclic hydrocarbon substituents and R1 and R2 together have a total of 10 to 50 carbon atoms.
where:
R1 is an hydrogen atom and R2 is an alkyl substituent or R1 and R2 are both alkyl substituents, and R1 and R2 together have a total of 6 to 24 carbon atoms.
Some examples are linear dodecylsulfonic acid, 1-dodecenesulphonic acid, or petroleum sulfonic acid.
The non-ionic surfactant that acts as co-surfactant may be utilized at a 0.1 to 10% weight concentration, preferably between 0.5 and 5% weight concentration, based on the weight of the final formulation. Suitable non-ionic surfactants include, but are not limited to ethoxylated fatty alcohols, ethoxylated fatty acids, ethoxylated fatty acid esters, ethoxylated phenols and alkylphenols, polyethylene glycol ethers and/or mixture thereof. Preferred non-ionic surfactants are selected from the group consisting of formulas (3), (4), (5) and (6) below:
where:
R1 is a linear, branched or cyclic saturated or unsaturated hydrocarbon substituent with 4 to 20 carbon atoms, and R2 is an alkyl substituent with 1 to 10 carbon atoms.
n is an integer number representing the number of repeated ethoxy groups, with n between 2 and 70.
where:
R1 in a hydrogen atom or an linear or branched alkyl substituents with a total of 4 to 12 carbon atoms;
R2 is a hydrogen atom or n alkyl group with 1 to 4 carbon atoms.
n is an integer number representing the number of repeated ethoxy groups, with n between 4 and 70.
Some examples are Etholxylated nonylphenol (12) mole, Polyoxyethylene (20) oleyl ether, Poly(ethylene glycol) (12) tridecyl ether, Polyoxyethylene sorbitan monostearate (60) mole.
Exemplary pH adjusters include, but are not restricted to, weak bases, preferably selected from the group that comprises bases with pKb values between 6 and 10 and belong to the group of sodium or potassium carboxylates, carbonates, phosphonates and/or mixtures thereof. The base may be utilized in 0.1 to 10% weight, preferably between 0.2 and 5% weight concentration, based on the weight of the final formulation. The pH of the chemical formulation may be between 4 and 7. Suitable examples are sodium or potassium acetate and sodium or potassium citrates.
Table 1 describes an exemplary composition with corresponding weight percent ranges of the chemical formulation.
2-5
80-99
The abovementioned compounds are dissolved in a mixture of brine with a non-aromatic solvent selected from the group of low-molecular oxygenated compounds, preferably a low molecular alcohol such as ethanol or isopropanol. In some embodiments, the mixture comprises between 80 and 99% weight of the chemical formulation for wettability modification. The brine is a 1 to 10% weight solution of sodium or potassium chloride in water, where the water might be fresh water, formation water, or water from any other source, and/or a combination thereof.
The wettability modification may be achieved by direct injection of an aqueous solution of the chemical formulation for wettability modification downhole in crude oil wells were it penetrates the surrounding formation and impregnates the sands or rocks with the active ingredients. The dilution of the chemical formulation for wettability modification for its application depends upon the characteristics of each well. In some embodiments, a 10 to 30% weight of the formulation in water, formation water or brine is preferred.
The negligible effect of exemplary embodiments of the chemical formulation for wettability modification on the oil viscosity while reducing the friction of different heavy oil samples is demonstrated through laboratory viscosity Test 1 and Test 2.
Measurements on untreated and treated crude oils, performed with a Brookfield-CAP2000+L viscometer and the CapCalc 32 software, evidenced the friction reduction effect when the chemical formulation for wettability modification is used. The crude oils showed a Visco-Plastic or Pseudoplastic behavior.
Visco-Plastic fluid can be modeled by the Bingham Equation (Eq 1):
τ=τ0+η{dot over (y)} (Eq 1)
τ=m{dot over (y)}n (Ec 2)
The shear stress was measured in untreated (blank) and treated (1% V/V chemical formulation/crude oil) samples of the extra-heavy crude oil at different rotational speeds.
The Shear Stress (τ in Dynes/cm2 units) vs Rotational Speed (Y in 1/s units) results from Test 1 (
In
Test N.2 (Friction Test on Extra Heavy Crude Oil from Junin Field)
The shear stress was measured in untreated (blank) and treated (1% V/V chemical formulation/crude oil) samples of the extra-heavy crude oil at different rotational speeds.
Results from Test 2 (
As for the Test 1 results,
Exemplary embodiments provided in the present disclosure may improve the medium, heavy and extra-heavy crude oil flow from the reservoir to the well due to the wettability modification of the formation sands achieved through the effect of the surfactant on the mineral-crude oil interface.
Test 3 shows the changes in wettability of a sand surrogate (glass, silicate) in contact with a heavy crude oil treated with various commercial surfactant-based well stimulation fluids or wettability modifiers.
Test 3 (wettability changes of the heavy crude oil-glass interface)
A simple test was performed to evaluate changes in the crude oil-glass interface wettability due to the application of the herein disclosed chemical formulation for wettability modification and other commercial surfactants.
Test 3 was repeated by inserting grained mineral into the bottles, resulting that cleaner grains were recovered from the samples treated with the chemical formulation of the present invention.
Test 4 was performed in order to assess the effect of an exemplary embodiment of a chemical formulation over the reservoir permeability and the formation wettability.
The chemical formulation for wettability modification was evaluated, including the application of the Amott test, in the Petroleum Laboratory of Zulia University's Technical Services Foundation, File: NUC-009-2016. The test was performed with three heavy crude oil samples (Petroboscan and two oils from the Orinoco Belt, namely, from the Petrocedeno and Petropiar oilfields) over Berea sandstone samples, before and after the addition of the chemical formulation.
The irreducible water saturation (Swi) and the initial oil permeability (Koi) were measured using samples saturated with a surrogate of each formation water at T=60° C. and P=600 psi during 24 hours.
The final oil permeability (Kof) was measured thereafter by sweeping the sample saturated with the chemical formulation.
The damage to the formation was estimated through the following equation 3 that relates the final permeability with the initial permeability:
Formation Damage=(Kof−Koi)/(Koi)*100 (Eq. 3)
The test results are displayed in Tables 2 and 3, showing the comparative wettability index and permeability results before and after the addition of the disclosed chemical formulation. The initial Berea sandstone samples with the heavy crude oils from Petrocedeno, Petropiar and Petroboscan oilfields were identified as “1A”, “2A” and “3A” while “1”, “2” and “3” were the same samples treated with the exemplary chemical formulation.
Table 2 shows a clear change from Oil-wet to Water-wet for the Berea samples impregnated with the three heavy oil tested when the chemical formulation was added.
Table 3 shows negative values for the “Formation Damage” assessment in samples treated with the exemplary chemical formulation, which means that the fluid does not react adversely with the formation fluids and minerals.
Other results show significant differences for porosities and permeabilities among crude oils-formation pairs. Further experiences demonstrated that by varying the proportions of the chemical formulation components, i.e. tuning the chemical formulation, it is possible to obtain better results.
Those results lead to the development of a method to obtain a specific chemical formulation for the different producing formations or bituminous sands, bearing a particular type of medium, heavy or extra-heavy weight crude oil. The method can include three sub methods and systems: (a) a “Well Characterization” subsystem, (b) a “Knowledge Database” subsystem, and (c) a “Processing” Subsystem.
In some exemplary embodiments disclosed herein, a method includes a first step comprising a “Well Characterization” process that allows putting together well data, such as formation and oil physical/chemical properties, residual pressure and reservoir temperature, which are obtained either by preceding existing data or by data obtained from lab tests. Such data, entered into an information system called a “Processing Subsystem”, is analyzed and compared with the data stored in the “Knowledge Database”, by mathematical and statistical procedures. The “Knowledge Database” is a database created from laboratory tests made with different crude oil and formation typical pairs to evaluate the right proportion of the components in the chemical formulation to achieve the desired wettability change in each case. Once the adjusted chemical formulation is used in the well stimulation process, the obtained results improve the “Knowledge Database” for other well stimulation processes.
The subsystems comprise at least one of the following steps:
The variables of the experiments may include, but are not limited to:
Once the correct proportion and concentration of the chemical formulation for a specific well is determined, the stimulation operation begins with the preparation of a diluted solution from 10 to 30% weight in water, formation water or brine. The volume of the diluted solution to be injected depends on the desirable penetration into the formation, formation permeability and porosity, reservoir residual pressure, reservoir temperature, surface ambient temperature, reservoir oil physical properties, depth of formation to be stimulated, well completion dimensions and percentage of oil/gas/water presence in reservoir. The diluted solution may be injected into the oil well by existing workover equipment with the ability of regulating the pressure and flow of such fluid. Some exemplary embodiments of the method involves the use of a coiled tubing equipment to produce the injection of the diluted fluid into the formation. As mentioned above, the theoretical injection pressure is also estimated considering the same parameters used for the calculation of the diluted fluid volume. The diluted fluid can be injected at constant pressure or following pressure ramps or by pulsating pressure, depending on the well formation and oil characteristics. After injection of the fluid, a certain dine period, from 12 to 48 h. elapses to allow the fluid to penetrate in the formation and modify the wettability of the formation, promoting crude oil flow into the well, or until a new diluted stimulation fluid injection is made. The evaluation of the well oil production determines the decision of a new cycle of injection/waiting time.
While the invention has been shown and described with reference to specific exemplary embodiments, it should be understood by those skilled in the art that several changes in form and detail may be made therein without departing from the spirit and scope of the invention as defined by the following claims.
This application claims the benefit of U.S. Provisional Application No. 62/521,131 filed on Jun. 16, 2017, which is incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 62521131 | Jun 2017 | US |
