Method for determining residual oil saturation by miscible gas injection (Sorm)

Abstract

The invention relates to a method for determining residual oil saturation by miscible gas injection (Sorm) wherein the method comprises a first volume equilibrium step followed by a dispensed tracer injection step. Two steps are performed sequentially and independently in a closed system.

Description

Technical Field

[0001] The present invention relates to a method for determining residual oil saturation by miscible gas injection (Sorm), wherein the method comprises a first volume balancing step followed by a distribution tracer injection step. Both steps are performed in situ in a sequential and independent manner.

[0002] The invention is applicable in the field of reservoir engineering, in oil fields undergoing miscible gas injection for the following purposes: secondary oil recovery; advanced oil recovery or carbon capture, use and storage (CCUS). Therefore, the field of application of the method of the invention lies in the modeling, simulation and evaluation of reservoirs and in oil recovery technology. Background of the Invention

[0004] Most oil fields that undergo gas injection, whether rich or poor in CO2, do so under so-called miscible conditions, where the interfacial tension between gas and oil is zero.

[0005] Although more efficient than immiscible gas injection, miscible injection cannot remove all the oil from the reservoir rock, leaving a portion of the oil still trapped in the reservoir. The remainder is not due to large-scale defects, even on a microscopic scale, and consists of the heaviest and most viscous fractions of the original hydrocarbon mixture. This composition is due to the intense mass transfer effects between the gas and oil phases after the passage of the miscible front, which preferentially extracts the light components and leaves the heavy components behind.

[0006] This fraction of oil still trapped in the reservoir is called residual oil saturation (Ros or Sor in Portuguese), which is an important parameter for characterizing a reservoir, as it is an important input for reserve calculations and mathematical reservoir simulations that predict oil production curves, thus affecting the valuation of the deposit and the economic attractiveness of exploration projects.

[0007] This parameter can be determined using different techniques and at different scales, including direct measurement of fluid saturation in core samples (e.g., retort or Dean-Stark method); laboratory tests of fluid injection in core samples (e.g., relative permeability tests); well logging; injection of tracers in wells (e.g., single well tracer testing - SWTT); and mathematical simulations in digital rock twins (e.g., Digital Rock).

[0008] The industry standard for laboratory methods for fluid injection is to determine residual oil saturation under immiscible conditions. In rare cases, measurements are made under nearly miscible conditions. Even more rare is the measurement under fully miscible conditions.

[0009] In cases where gas injection is required under predominantly miscible conditions, the residual oil saturation values ​​obtained by conventional methods are often much higher than the actual values, which can lead to an underestimation of reserves and oil production curves. In this sense, it is worth noting that residual oil saturation values ​​in miscible gas injection (Sorm) are rare, considering the difficulty in obtaining them under the precise and representative conditions of temperature and pressure (pore pressure and subsurface overburden pressure) found in reservoir rocks.

[0010] The traditional method of measuring residual oil saturation under conditions of immiscibility between the oil and the injected phase, such as is found in conventional water or gas injection, is also constrained by the fact that immiscibility is a condition that is conducive to the determination of relative permeability, a test usually associated with laboratory Sor measurements. In this case, the presence of both phases throughout the displacement process is guaranteed, and the average saturation of the fluid in the core plug can be determined by a simple volume balance, regardless of the flow regime. In the case of miscibility, in addition to the intense mass transfer between the displacing and displaced phases, sometimes a single-phase flow may exist in a certain part of the rock, resulting in a saturation variation. In this way, volume balance throughout the injection becomes operationally impossible.

[0011] However, when the aim is limited to measuring Sor at the end of gas injection, a specific volume balance method can be used that allows obtaining this value. However, this calculation depends on some calibrations and data checks that can make the calculation uncertain, for example, it is necessary to know parameters such as the oil formation volume factor (Bo); the volume of condensate in the injected gas and the dead volume at the outlet of the high-pressure pipeline downstream of the core sample.

[0012] Therefore, it is desirable to have a second method to determine in situ oil saturation that works under reservoir conditions and can be applied immediately after gas injection is completed without the need to depressurize and remove the sample from the sample holder, as the depressurization will already cause a change in Sorm due to the release and expansion of the gas.

[0013] From this point of view, tracer injection is a very precise technique in which two tracer chemicals dissolved in water are injected simultaneously in small quantities. One of them has an affinity only for the water phase (non-partitioning tracer) and the other has an affinity also for the oil phase (partitioning tracer). When the water containing the tracers flows and comes into contact with the residual, immobile oil, the molecules of the partitioning tracer dissolve (partition) in the oil phase and remain immobile during the period of time they stay. The process is dynamic and when they return to the water phase, they begin to migrate again with this fluid. The non-partitioning tracer, in turn, always remains in the water phase and therefore always flows at the same speed as the water. The end result of this process is a separation of the production curves of the partitioning and non-partitioning tracers, where the partitioning tracer shows a delay in its production.

[0014] Therefore, the great advantage of the tracer injection technique is that Sor depends only on the degree of separation between the tracer curves and the water-oil partition coefficient of the partitioned tracer, which is also easy to measure in the laboratory.

[0015] The object of the present invention is therefore to develop and implement a method which allows to quantify Sor with less uncertainty. This is possible thanks to the sequential in situ application of two different and independent techniques which can validate each other: volume balance and distribution tracer injection. The sequential in situ combination of the two techniques reduces the uncertainty regarding the quantified Sor. Thus, a more accurate determination of the Sor values ​​leads to an improved predictability of the production curves and reserves of the oil field, as well as to the development of optimized exploration projects. Background Art

[0016] Prior art discloses the application of volume balance and distribution tracer injection techniques alone for determining saturation in residual oil, of which volume balance is the most common technique. However, these techniques are performed alone, i.e. not sequential methods without the need to remove the sample from the holder or sample holder. Therefore, removal of the sample from the device results in decompression and consequent gas evolution, thereby causing a reduction in the amount of oil due to the release of gas in the residual oil. This phenomenon changes the saturation of the residual oil and thus increases the uncertainty of the final result.

[0017] In-situ monitoring methods known in the prior art are based on physical techniques, such as X-ray or nuclear magnetic resonance. However, these methods are usually not fast and accurate enough to monitor such saturation changes, especially during miscible recovery. It is also common to add chemicals to the fluid in order to ensure image contrast / attenuation between phases. A disadvantage of this is that these substances can change the properties of the fluid and interfere with the behavior to be evaluated (e.g. miscibility).

[0018] The method of the invention ensures reliable quantification of residual oil saturation, since the volume balancing and distribution tracer injection steps are performed sequentially, without the need to remove the sample from the system, thus avoiding gas escape. Therefore, the method of the invention has a clear advantage over the prior art due to the sequential in situ steps, reducing the uncertainty of the results obtained due to interference from external factors in an open system. Summary of the invention

[0019] The purpose of the present invention is to determine the residual oil saturation in a rock sample under miscible gas injection (Sorm) and reservoir conditions close to real conditions by means of two different and independent techniques (volume balance and partition tracer injection) applied sequentially in situ. The Sorm values ​​obtained are closer to real values ​​(and significantly lower) than those obtained by existing conventional methods.

[0020] The method according to the invention obtains two values ​​for the same parameter by means of different techniques performed sequentially in a closed system, thus reducing the uncertainty of the obtained parameter. BRIEF DESCRIPTION OF THE DRAWINGS

[0022] In order to make the invention more easily understandable, the figures numbered 1 to 8 (which are associated with the present description and are an integral part thereof) are shown by way of illustration but are not intended to limit the invention.

[0023] Figure 1 The system used in the present invention is described.

[0024] Figure 2 Illustrated are the adjustments of the partitioning (ethyl acetate) and non-partitioning (ethanol) tracer curves for one of the samples evaluated (Rock 5).

[0025] Figure 3 Schematic representation illustrating several portions of a reservoir undergoing miscible gas injection and their residual oil saturations.

[0026] Figure 4 The behavior of oil saturation under different injection conditions is illustrated for one of the samples evaluated (Rock 4).

[0027] Figure 5 The behavior of the residual oil saturation as a function of the CO2 content in the injected gas is illustrated for one of the samples evaluated (Rock 1).

[0028] Figure 6 The behavior of oil saturation as a function of continuous and alternating water and gas injection patterns (continuous xWAG (water alternating gas)) is illustrated for one of the samples evaluated (Rock 1).

[0029] Figure 7 The behavior of oil saturation as a function of gas injection mode (continuous xWAG) is illustrated for one of the samples evaluated (Rock 10).

[0030] Figure 8 The behavior of oil saturation as a function of gas injection mode (continuous xWAG) is illustrated for one of the samples evaluated (Rock 13). DETAILED DESCRIPTION OF THE INVENTION

[0032] The present invention relates to a method for determining residual oil saturation by miscible gas injection (Sorm), wherein the method comprises a first volume balancing step followed by a partitioning tracer injection step, both steps being performed in situ by a closed system.

[0033] The system used in this application ( Figure 1) focuses on fluid displacement testing in porous media at reservoir conditions, fully replicating temperature, pore pressure and subsurface overburden pressure (close to actual reservoir conditions). The system consists of: a large oven; sample holder for 1.5” diameter plugs; a sophisticated pump set; a three-phase separator; a fluid accumulator container; electro-pneumatic valves; piping; pressure and temperature sensors and remote monitoring and control equipment. The system is suitable for sour services, which makes it suitable for handling fluids containing CO2.

[0034] The in situ method for determining residual oil saturation by miscible gas injection consists of the following sequential steps:

[0035] (a) volume balance; wherein the volume balance step comprises:

[0036] (a1) Fill the sample holder bypass and converter lines with degassed water;

[0037] (a2) injecting live oil through the sample;

[0038] (a3) Fill the air pump with test gas;

[0039] (a4) 0.5 to 1 cm 3 The miscible gas is injected at a flow rate of the order of / min, and the oil (dead oil) produced over time under atmospheric conditions is collected;

[0040] (a5) determining the volume of condensate produced by the gas;

[0041] (a6) determining the dead volume at the outlet of the sample holder by continuously injecting dead water (deionized water) through a bypass of the sample holder and injecting a gas through the sample; and

[0042] (a7) calculating the measured value of Sorm;

[0043] (b) injecting a distribution tracer; wherein the distribution tracer injection step comprises:

[0044] (b1) injecting degassed water through the sample after completing the gas injection of step (a4) of volume balancing;

[0045] (b2) 1cm 3 An aqueous solution containing 1% v / v of a partitioning tracer and 1% v / v of a non-partitioning tracer was injected at a flow rate of / min, and samples were collected at 5% of the pore volume of each fraction under atmospheric conditions;

[0046] (b3) delivering the collected samples for quantification of the tracer by means of gas chromatography and / or spectrophotometry in the infrared region; and

[0047] (b4) Calculate the measured value of Sorm.

[0048] The purpose of step (a1) is to ensure that all oil produced during gas injection comes only from the rock sample.

[0049] The purpose of step (a2) is to fill the outlet dead volume with oil; and to determine the "live oil formation volume factor (Bo)". Since the quantification of the residual oil saturation when injecting miscible gas must be carried out by collecting the dead oil produced outside the system under atmospheric conditions, it is necessary to obtain a calibration of the dead oil volume produced under atmospheric conditions for the same live oil volume injected under reservoir conditions. This calibration factor is called the "live oil formation volume factor (Bo)". After the value of the dead oil volume produced by each live oil volume injected stabilizes, the injection of live oil must be stopped.

[0050] With regard to the step (a5) of determining the volume of condensate, it is worth noting that at the end of the injection of some pore volumes of gas, the production of oil from the sample ceases, possibly leaving behind the production of condensate, which is the light components dissolved in the gas at reservoir conditions and condensed upon depressurization and cooling to atmospheric conditions. For each volume of gas injected at reservoir conditions, the volume of condensate produced at ambient conditions must be known so that it can then be subtracted from the observed oil production. The drier the gas (fewer condensable light components), the smaller this condensate volume will be, and the less relevant the correction will be.

[0051] The determination of the dead volume in step (a6) can optionally be carried out by other methods, such as expansion with an inert gas or continuous injection of water and oil.

[0052] The injection of deionized water in step (b1) is sometimes important to avoid damage to the equipment quantifying the tracer, which may be caused by the presence of dissolved salts.

[0053] When injecting the tracer in step (b2), in order to determine the residual oil saturation, two substances are injected simultaneously, one having affinity only for the water phase (non-partitioning tracer) and the other having affinity for both the water phase and the oil phase (partitioning tracer). The degree of hysteresis (delay) of the elution curve of the partitioning tracer relative to the elution curve of the non-partitioning tracer is proportional to the residual oil saturation. The partitioning tracer used is ethyl acetate and the non-partitioning tracer is ethanol.

[0054] Use of this technique allows for in situ determination of residual oil saturation; without the need to depressurize, defibrate, and remove the sample from the sample holder. Typically, the level of measurement accuracy is approximately ±2 percentage points of saturation. This is an alternative / complementary method to quantifying residual oil saturation via volume balance, helping to increase the level of certainty regarding the final value of Sorm determined, especially in miscible gas injection where residual oil values ​​are typically very low.

[0055] The Sorm calculation by volume balance (step a7) and by tracer injection (step b4) is performed as follows:

[0056] Determination of water-oil partition coefficient

[0057] The partition coefficient of the partition tracer is determined before the Sorm calculation by volume balance and by injection of the partition tracer. This coefficient is the basic information for determining the residual oil saturation analytically or numerically using the tracer injection technique. It is therefore important that the measurement of this parameter is carried out with the water and oil actually used and at the temperature of the displacement test. The prior art shows that it is indifferent whether the measurement is carried out with live or dead oil, or even at a pressure comparable to that used in the experiment.

[0058] Partitioning in the oil causes the partitioning tracer to lag behind the non-partitioning tracer because it does not flow at the same rate as the water carrying the non-partitioning tracer when it is in the residual (immobile) oil phase.

[0059] The partition coefficient was calculated using the following equation 1.

[0060]

[0061] in:

[0062] Kd: oil-water partition coefficient of the partition tracer;

[0063] C o : Concentration of partitioned tracer in the oil phase;

[0064] C a : the concentration of the partitioned tracer in the aqueous phase;

[0065] C ai : The concentration of the partitioned tracer in the water phase before water-oil equilibrium;

[0066] C af : the concentration of the partitioned tracer in the water phase after water-oil equilibrium; and

[0067] V o : The volume of the oil phase.

[0068] Calculation of Sorm by volume balance

[0069] The calculation of Sorm by volume balance is performed using equation 2 (step a7).

[0070]

[0071] in:

[0072] V p : pore volume;

[0073] S wi : bound water saturation;

[0074] V om : The volume of oil produced under atmospheric conditions (dead oil);

[0075] V gi : volume of injected gas under reservoir conditions (test pressure and temperature);

[0076] V c : Volume of condensed gas under bulk conditions / volume of injected gas under reservoir conditions;

[0077] B o : Formation volume factor = volume of oil (live oil) at reservoir conditions / volume of oil (dead oil) at atmospheric conditions; and

[0078] V m : Output dead volume.

[0079] Calculation by tracer injection

[0080] Calculation of Sorm from tracer injection can be performed analytically or numerically.

[0081] The analysis accounts for the time lag ( ) between the pore volumes produced by the normalized tracer concentration x) based on the partitioning and non-partitioning tracer curves. Equations 3 to 5 are applied to specific points of the tracer elution curve and the values ​​found at each point are averaged to yield the final value.

[0082]

[0083] in:

[0084] b i : Delay factor for distributing tracers;

[0085] v 水 : Water velocity = velocity of non-partitioned tracer;

[0086] v 分配示踪剂 : the speed of dispensing tracer;

[0087] V 水 : Elution volume of water = elution volume of non-partitioned tracer;

[0088] V 分配示踪剂 : the elution volume of the distributed tracer; and

[0089] K i = Water-oil partition coefficient of the partition tracer

[0090] In the numerical interpretation, the experimental model was assembled in a porous media flow simulator that provides the possibility to inject and consider several phenomena related to the tracer flow such as water-oil partitioning, physical dispersion, molecular diffusion and adsorption.

[0091] Unlike analytical interpretation, numerical interpretation considers the complete elution curve, not just certain points. It also allows consideration of some non-ideal situations and phenomena that cannot be fully captured in analytical interpretation, such as attributing different residual oil saturations to different layers, multiphase samples, and molecular diffusion.

[0092] The numerical interpretation starts with tuning the elution curve of the non-partitioning tracer. It acts as a source of information characterizing the pore space itself. The more heterogeneous the sample is, the more layers of different permeabilities and thicknesses are needed to tune the entire non-partitioning tracer curve (shoulders, plateaus and rising / falling trends). The curve is usually tuned by the number of layers and their hydraulic conductivity (thickness and absolute permeability). Once a good tuning of the non-partitioning tracer is achieved, the next step is to tune the elution curve of the partitioning tracer, which is simply achieved by changing the residual oil saturation of each layer.

[0093] the term

[0094] The following nomenclature is used in this invention:

[0095] B o : Reservoir volume factor. It is the ratio between the volume of oil at reservoir conditions (live oil) and the volume of dead oil resulting from decompression / cooling of this oil to atmospheric conditions.

[0096] Rich or Wet Gas: Gas enriched with light petroleum components that are condensable under ambient conditions.

[0097] Barren or Dry Gas: A gas that has no condensable components at ambient conditions.

[0098] WAG injection: Advanced oil recovery method in which alternating cycles of water and gas (WAG - Water Alternating Gas) are injected.

[0099] Immiscible Gas Injection: This is where the gas-oil interfacial tension is high, typically greater than 1 dyne / cm. The system pressure is below the minimum miscibility pressure. The gas and oil remain distinct phases, although there is mass transfer between these phases, such as dissolution of gas in oil and absorption of light components of the oil by the gas, up to a certain equilibrium limit.

[0100] Nearly miscible gas injection: This is where the gas-oil interfacial tension is close to zero (<1 dyne / cm) but not zero. The system pressure is very close to the minimum miscibility pressure, but still below it. The gas and oil are still as different phases.

[0101] Miscible Injection: This is where the interfacial tension is zero. The system pressure is above the minimum miscibility pressure. The gas and oil form a single phase.

[0102] MMP: Minimum Miscibility Pressure. For a given temperature and gas and oil composition, this is the lowest pressure at which the gas-oil interfacial tension is zero and therefore the gas and oil phases are indistinguishable.

[0103] Sorw: Residual oil saturation under continuous water injection.

[0104] Sorg: Residual oil saturation under continuous gas injection, usually immiscible or near miscible conditions.

[0105] Sorm: Residual oil saturation in the case of gas injection, usually continuous and miscible. Example

[0106] A person skilled in the art will appreciate the knowledge presented herein and will be able to reproduce the invention in the indicated embodiments and other variations covered by the scope of the appended claims.Thus, the following examples describe the instruments, rock / fluid samples and experimental procedures used.

[0107] Experimental instruments

[0108] The system used in this example is Figure 1 The system described in .

[0109] Rock samples, fluids and tracers

[0110] Validation of the method was done using rock samples (presented in the table below) and fluids from Brazilian oil fields.

[0111] The selected rock samples were divided into composite plugs as shown in Table 1. Composite plugs that are longer and have more pore volume have advantages in displacement testing, such as greater accuracy in determining pressure and production.

[0112] Table 1 Rock samples evaluated

[0113]

[0114] The tests were conducted using recombinant live oil. In addition to pure CO2, the gases used were hydrocarbon gases (C1-C4) containing different levels of CO2. Synthetic formation water and seawater from each of these oil fields were also used.

[0115] The minimum miscibility pressures (MMP) of the different oils and gases used had been previously determined in the laboratory using the rising bubble method.

[0116] The partitioning and non-partitioning tracers chosen were ethyl acetate and ethanol, respectively.

[0117] Experimental plan

[0118] Experiments were planned under reservoir conditions considering the following gas injection:

[0119] 1) Injection under near-miscible conditions, where gas and oil are pre-equilibrated with each other at a pressure 100 psi (689.48 kPa) below the minimum miscibility pressure until mass transfer between the phases ceases.

[0120] 2) Injection with wet gas under miscible conditions, where a pre-equilibration between the phases is carried out as in item (1) above, in order to enrich the gas with the light components of the oil. However, the injection itself is carried out above the minimum miscibility pressure.

[0121] 3) Injection with dry gas under miscible conditions, wherein the injection is carried out above the minimum miscible pressure as in item (2) above, but the gas is not pre-equilibrated with the oil.

[0122] 4) Changing the CO2 content by injecting dry gas under miscible conditions, wherein the injection is the same as in item (3) above, thereby changing the CO2 content in the gas.

[0123] 5) Injection with dry gas WAG (alternating injection of water and gas) under miscible conditions, where the injection is the same as item (3), alternating gas and water cycles (5% of the pore volume of the sample for each gas or water cycle).

[0124] Gas injection process

[0125] The adopted process consists of the following steps:

[0126] ·Preparation of rock samples 1 to 15;

[0127] - Clean and determine the absolute permeability and effective porosity of rock samples;

[0128] - Saturate with formation water and build up Swi;

[0129] Movement of the equipment;

[0130] - Restriction of rock samples;

[0131] - Prepare a container with live oil;

[0132] - Pressurization and heating;

[0133] - Leakage test;

[0134] Restoration of wettability;

[0135] Pre-equilibrium between the phases at a pressure 100 psi (689.48 kPa) below the minimum miscibility pressure;

[0136] Determination of Sorg by continuous gas injection under near-miscible conditions;

[0137] The pore pressure increases to a value above the minimum miscibility pressure;

[0138] Determination of Sorg by continuous injection of moisture under miscible conditions;

[0139] Determination of Sorg (Sorm) by continuous injection of dry gas under miscible conditions;

[0140] Inject deionized water;

[0141] Inject partitioning and non-partitioning tracers at a concentration of 1% v / v in deionized water;

[0142] • Resulting water samples were collected at intervals of 5 pore volumes for quantification of the tracer.

[0143] Between gas injections, live oil injections were performed in order to reabsorb and return the sample to the initial condition of So = 1-Swi, until the relative permeability to oil (Kro@Swi) recovered to its original value.

[0144] Demobi li se some samples; clean and go through the entire previous preparation process again, then do one of the following:

[0145] Determine Sorg (Sorm) by continuously injecting dry gas under miscible conditions, thereby changing the CO2 content of the gas; or

[0146] • Determination of Sorg by alternate injection of miscible dry gas and water (cycle of 5% of the pore volume).

[0147] Determination of water-oil partition coefficient

[0148] The determination of the partition coefficient of a partition tracer is performed by a method known as the bottle test, using the fluid and temperature used in the test. In this method, a volume of an aqueous solution of a known concentration of the partition tracer is placed in a bottle with a known volume of dead oil. The bottle is heated and stirred periodically for 24 hours to promote water-oil equilibrium, at the end of which time the concentration of the tracer in the aqueous phase is sampled and quantified. The partition coefficient is calculated using Equation 1 as described in the Sorm calculation section.

[0149] In both cases, the values ​​found for the ethyl acetate partition coefficient in the oils evaluated were very similar, with a value of 4.73 being adopted.

[0150] Calculation by volume balance

[0151] Sorm calculations were performed by volume balance using Equation 2 as described in the Sorm calculation section.

[0152] Calculation by tracer injection

[0153] The calculation of Sorm from tracer injection was performed analytically and numerically (as described in detail in the Sorm calculation section). Briefly, the analytical interpretation is based on the time lag between the partitioning and non-partitioning tracer curves, where equations 3 to 5 are applied. In the numerical interpretation, the experimental model was assembled in a numerical reservoir simulator.

[0154] Regarding numerical interpretation, Figure 2 An example of adjustment of the generation curves of partitioned and non-partitioned tracers for Sample 5 is shown.

[0155] Results and discussion

[0156] The main results and discussions to be highlighted are categorized as follows:

[0157] Sorm results;

[0158] The impact of miscibility / extraction mechanisms;

[0159] The effect of the CO2 content of the injected gas; and

[0160] ·The influence of gas injection method.

[0161] Sorm Results

[0162] Table 2 shows the residual oil saturation results for continuous injection of dry miscible gas, quantified by volume balance and injection of tracers in the evaluation samples. However, in all cases, miscible conditions were emphasized where the injection was greater than the MMP.

[0163] In general, there was excellent agreement between the two methods, which reduced the uncertainty about the measured values. However, exceptions to this rule were observed in two samples (Rock 6 and Rock 9). In these cases, the correct value was the one determined by the volume balance, assuming that the tracer indicated an abnormally low Sorm.

[0164] These are the values ​​used as a benchmark for reservoir simulation after appropriate upscaling and are considered to be the minimum residual oil saturations that can be obtained using continuous gas injection.

[0165] Table 2 Sorm measured in the evaluation samples

[0166]

[0167]

[0168] 1Sorm obtained by volume balance 2 Sorm obtained by tracer

[0169] *Values ​​ignored in the average calculation

[0170] Effects of Miscibility and Extraction

[0171] While in waterflooding the relevant recovery mechanism is oil displacement, in gas flooding other specific mechanisms exist, namely: swelling and viscosity reduction of the oil phase, miscibility (elimination of gas-oil interfacial tension) and extraction of light components from the oil phase by the seeping gas. All these additional effects are due to the greater physicochemical similarity of these phases at reservoir pressure, which is not present in the water-oil system.

[0172] Therefore, much more than in water-oil systems, the absolute value of the residual oil saturation in the gas may vary depending on the conditions under which the injection is carried out, in particular with regard to the miscibility and the light extractability shown by the gas.

[0173] The approximate degree of miscibility affects the porous fraction accessible by the gas. The closer the gas-oil system is to miscible conditions, the lower the capillary forces and therefore the smaller the pores the gas can penetrate, increasing the likelihood of contact and oil removal.

[0174] The extraction capacity of a gas can be converted by its potential to absorb the lower molecular weight components of the oil. This mass transfer process is determined not only by the pressure and temperature conditions, but also by the content of pre-existing light components in the injected gas. Gases known as "dry" or "poor", with few dissolved light components, have a greater extraction capacity than gases known as "rich" or "wet".

[0175] Table 3 compares the Sor results measured with continuous injection of approximately 5 pore volumes of gas under the following three conditions:

[0176] Near miscible conditions (PM). This condition is characterized by a gas-oil interfacial tension (G / OIFT) below 1 dyne / cm, but not zero, and by a state of equilibrium between gas and oil. In this case, the mechanisms of gas-oil miscibility, mass transfer between these phases (extraction), swelling, and oil viscosity reduction are inhibited. From this point of view, this is a condition that approximates the SOR measured in conventional special petrophysical analysis, both in water-oil and immiscible gas-oil systems, where these phases are usually in equilibrium before injection. The ability of the gas to displace the oil is evaluated, but other recovery mechanisms typical of gas injection are not observed.

[0177] Miscible conditions, gas rich. Enriched gas is obtained by contacting dry gas with oil before injection, so that it pre-contains these components. However, the injection is carried out at pressures and temperatures where miscible behavior exists. In this way, the extraction recovery mechanism is limited, while the miscible mechanism still exists.

[0178] Miscible conditions, gas deficient. Under these conditions, the particular mechanism of gas injection is fully present, resulting in the lowest achievable oil saturation values.

[0179] Figure 3 Representative values ​​of Sor determined for different portions of the reservoir undergoing miscible gas injection in each of these conditions are illustrated, with the numerical index describing the following regions:

[0180] - Index 1 indicates the area after the miscibility zone, with the original oil saturation;

[0181] - Index 2 indicates the area corresponding to the miscible zone where miscibility is achieved, but the mass transfer effect is limited because the gas has been enriched with light oil components on its way from the injection well to the miscible front area. A representative Sorm will be obtained by injecting a miscible gas rich in miscible gas;

[0182] - Index 3 indicates the region just after the miscibility zone where miscibility with the residual oil has been lost, but the gas-oil interfacial tension (IFT G / O) is very close to zero and the gas is rich in light oil components. A representative SOR would be obtained using gas injection under near miscible conditions; and

[0183] - Index 4 indicates the area before the miscible zone where the gas-oil mass transfer effect occurs extensively because the injected gas does not contain light oil components. A representative Sorm will be obtained by injecting dry miscible gas. This is the lowest Sor value that can be obtained in a rock section that is extensively swept by continuously injected miscible gas.

[0184] The results show how the Sor measured under near miscible and pre-equilibrium gas-oil conditions, where additional gas recovery mechanisms are suppressed, is significantly higher than the values ​​obtained when activating them by injection of either wet miscible gas or dry miscible gas. Figure 4 This difference is illustrated for one of the samples analyzed (Rock 4).

[0185] The data therefore highlight the importance of measuring Sorm with dry gas under the most representative conditions possible for field injection.

[0186] Table 3 Sorm measured in rock samples from the evaluated oil fields under different injection conditions

[0187]

[0188] 1Sor obtained under near-miscible conditions 2Sor obtained under miscible conditions, rich in (wet) gas

[0189] 3Sor obtained under miscible conditions, lacking (dry) gas

[0190] Effect of CO2 content in injected gas

[0191] Experiments with gases containing different CO2 contents showed that this component has an effect on Sorm only when its concentration increases to very high levels (Table 4). For example, in one of the samples evaluated (Rock 1), the Sorm obtained by injecting pure CO2 was about 1 / 4 of that obtained using hydrocarbon gas without CO2 (Table 4). Figure 5 ). At low to moderate levels, the effect was not noticeable. Similar observations were made in the other samples evaluated, although at very low Sorm levels, even at low CO2 levels, the effect was less noticeable.

[0192] Because all injections were performed under miscible conditions, this result is attributed to the high solubility of CO2 compared to natural gas, which enhances the extraction mechanism and highlights the value of injecting CO2-rich streams for oil recovery in typical CCUS (CO2 capture, use and geological storage) applications.

[0193] Table 4 Sorm measured at different CO2 contents in samples from the evaluated oil fields

[0194]

[0195] Effect of injection method (continuous xWAG)

[0196] Alternating water and gas (WAG) injection has the effect of reducing gas permeability, controlling its mobility and increasing its range.

[0197] In experiments comparing the Sorm of continuous injection of miscible gas with the Sorm of miscible WAG injection, the latter proved to be significantly lower (Table 5). Oil production ( Figures 6 to 8 ). This shows the potential of alternating injection for controlling gas mobility and improving oil recovery, even in cases where the injected gas shows enhanced miscibility and extraction effects, has very good contact with the rock (plugging experiments) and is rich in CO2.

[0198] Table 5 Sorm measured using different injection methods (continuous xWAG) in samples from the evaluated fields

[0199]

[0200] Using core samples and representative reservoir conditions, it is possible to quantitatively determine the residual oil saturation for different cases of miscible gas injection. Using the Sorm quantification method via tracers, in sequential volumetric balance, the uncertainty in determining this parameter has been reduced to a level as low as ±2 percentage points.

[0201] After appropriate upscaling and scaling, the results can be used as a benchmark for reservoir simulation and curve interpretation, helping to reduce uncertainties in reserve calculations and production curve predictions; improving oil field management and increasing the accuracy of evaluation and feasibility analysis of gas injection projects.

[0202] The developed method can also be applied to immiscible injection.

[0203] Therefore, the potential advantages of using more reliable Sorm values ​​are: reduced uncertainty in reserve calculations and oil production curve predictions, better field management, greater accuracy in the evaluation and feasibility analysis of gas injection projects.

Claims

1. A method for determining residual oil saturation by miscible gas injection, characterized by comprising the following sequential and independent in-situ steps: (a) volume balance; and (b) Distribution tracer injection.

2. The method according to claim 1, characterized in that the volume balancing step comprises: (a1) Fill the bypass and converter lines of the sample holder with degassed water; (a2) injecting live oil through the sample; (a3) Fill the air pump with test gas; (a4) 0.5 to 1 cm 3 Inject miscible gas at a flow rate of the order of 1 / min to collect the oil (dead oil) produced over time under atmospheric conditions; (a5) determining the volume of condensate produced by the gas; (a6) determining the dead volume at the outlet of the sample holder by continuously injecting dead water (deionized water) through a bypass of the sample holder and injecting a gas through the sample; and (a7) Calculate the measured value of Sorm.

3. The method according to claim 1, characterized in that the step of distributing the tracer injection comprises: (b1) injecting degassed water through the sample after completing the gas injection of step (a4) of volume balancing; (b2) 1cm 3 An aqueous solution containing 1% v / v of a partitioning tracer and 1% v / v of a non-partitioning tracer was injected at a flow rate of / min, and samples were collected at 5% of the pore volume of each fraction under atmospheric conditions; (b3) delivering the collected samples for quantification of the tracer by means of gas chromatography and / or spectrophotometry in the infrared region; and (b4) Calculate the measured value of Sorm.

4. The method according to claim 2, characterized in that the dead volume determination in step (a6) is optionally carried out by an inert gas expansion method.

5. The method according to claim 3, characterized in that the partition tracer in step (b2) is ethyl acetate.

6. The method according to claim 3, characterized in that the non-partitioning tracer in step (b2) is ethanol.

7. The method according to claim 2, characterized in that the calculation of Sorm by volume balance (step a7) is performed by the following equation:

8. The method according to claim 3, characterized in that the calculation of Sorm by tracer injection is performed analytically and numerically.

9. The method according to claim 8, characterized in that the analytical form calculates the mean value of the values ​​found at each point of the elution curve of the tracer by applying the following equation: or 10. The method according to claim 8, characterized in that the numerical form is calculated by a flow simulator in porous media.

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