Minimum Miscibility Pressure, Miscible Displacement, CO₂ Capture, and Injection

Abstract

The Minimum Miscibility Displacement Pressure, and the strategies to maintain the reservoir pressure above the minimum miscibility pressure are the most important elements for a successful EOR Dry Gas, CO2, or N2 Miscible injection project. The Miscibility behaviour needs to be understood early after the reservoir discovery to establish if a miscible displacement is economically attractive. The difference of a miscible gas displacement with an immiscible displacement is of such importance because a miscible displacement could achieve a recovery factor as high as 75% to 90% of the contacted oil compared to 30–40% recovery factor for an immiscible displacement process. In some field cases, the MMP is determined in the mid or late field life when the reservoir pressure, temperature and fluids distribution might limit the time left to design and implement a miscible gas displacement; in other, the operators possess the technology to design and implement Miscible Gas Displacement and the ability to articulate the project economy allowing time on decisions to implement, operate, and materialize the incremental recovery from a miscible displacement; therefore, it is recommended to determine the miscibility pressure, as soon the field is identified as candidates for EOR.

1. Introduction

This chapter discuss the concepts and elements that drive a Miscible Displacement, some practical strategies for project design, implementation and evaluation, field experiences from the Minimum Miscibility Pressure concept, application, and influence in field cases of Miscible Gas Injection projects performance, including natural gas, Dioxide Carbonate (CO₂), Nitrogen (N₂) and Flue. Some field cases of EOR Miscible Displacements injecting dry gas and CO₂ are also discussed in the context of EOR operations.

Historically it is more common to deal with immiscible gas injection projects, compared with the cases of miscible gas injection projects possibly because the opportunities for implementation of miscible displacement have not been identified in early stages, the high costs of compression to achieve miscibility and the access to the know-how.

There have been cases where the implemented reservoir management strategy was focused to let the reservoir pressure to deplete below the bubble gas pressure to create a secondary gas cap to use the gas cap expansion as production mechanism. This strategy might be considered reasonable and economic; however the cases that we have seen have recoveries in the range of 35–45% of the original oil in place at the time when the GOR has increased to extremely high values that suggest the injected gas is being recycled. The recovery factor in those cases might had been in order of 60–70% if a miscible gas injection process would have been implemented at early stage of the field life cycle.

The determination of the MMP can be estimated with reasonable accuracy if there is available a compositional analysis of the reservoir oil and a representative PVT analysis, which can be used to build a representative one-dimension compositional simulations for various types of gases that might be available for injection. Usually it is important a survey of potential gas sources in the area. Once the MMP has been estimated by compositional reservoir simulation, the next step is to verify the model work with laboratory experiments applying methods such as slim tube tests, rising bubble, zero interfacial tension, these last two are more recent developments in determination of MMP.

The typical candidate gases for injection are dry or wet natural gases, Nitrogen, CO₂ and flue gas, a product from natural gas combustion; from those gases, the CO₂ has been identified as the more efficient miscible agent based in its property to dissolve the oil.

The current trend of Carbon Capture and Storage (CCS) objectives pursued by the industry to reduce the green house effects can be levered with the implementation of more CO₂ miscible injection projects elsewhere the CO₂ is available, as there are several oil fields that have not developed because the hight CO₂ content.

An early evaluation of the economic feasibility to achieve a miscible displacement is of paramount importance which should be followed with the formulation of a doable strategic implementation plan for the project construction to materialize the incremental recovery factor and the incremental production, that in turn is dependent of a sound reservoir management conscious of the project objectives, that works with open communication between and with participation of all the company players from top management to field engineers and operators.

2. Generalities of gas injection miscible displacement process

The crestal gas injection is one of the more efficient traditional displacements processes, it works by the gravity segregation drive mechanism displacing the oil downward toward the producer wells placed down in the structure. A miscible displacement is if not the most efficient, one of the more efficient displacement processes because the injectant fluid dissolves the oil as the injectant at displacement front gets in contact with the oil in the reservoir zones, once it gets in contact; therefore, the displacement front not only displaces the movable oil saturation but also dissolves the residual oil saturation that is typically left behind in an immiscible gas injection process. Therefore, the oil saturation behind the displacement front in a Miscible Displacement can be as very low virtually zero.

3. What is miscibility

Miscibility is the mixture of two fluids, one fluid dissolves a second fluid either at first contact or in multiple consecutive stages as the injectant fluid contact and displace the second fluid. First, contact miscibility is driven by the fluid s composition and the thermodynamic conditions: pressure and temperature.

An important feature of the Miscible Gas injection Displacement is the solubility effect of the gas displacing miscible oil which eliminates the gas oil relative permeabilities effect, which is a consequence of the dissolution of the displacing fluid into de displaced fluid, that convert the displacement as one uniform front moving at the interface of gas displacing oil.

The Figure 1 shows gas (CO₂) miscible displacement of trapped oil in a porous media, the CO₂ gas mix with the oil, swells the oil molecules, and extract light components from the oil as it moves into the reservoir, creating a virtual wash of the porous media.

Figure 1.

CO₂ injection miscible displacement in pore scale [1].

Other characteristics of a miscible gas displacement:

• A miscible gas displacement can remove and displace the trapped oil in the porous, which is not movable by immiscible displacement.

• Miscible displacement can be achieved injecting lean gas, wet gas, (C1, C1–C2, CO₂, etc.).

• At minimum miscibility pressure (MMP), the interfacial tension between the oil and the displacing fluid is approaching zero.

• Under normal conditions, oil & gas reservoir fluids form distinct, immiscible phases; the immiscible phases are separated by an interface associated with interfacial tension (IFT), when the interfacial tension is equal to zero the two fluids mix achieving the miscible condition.

• The residual oil saturation to gas (and water) is directly proportional to IFT

• A miscible displacement is characterized by low/zero residual oil saturations.

Miscible displacement processes can be implemented in absence of structural dip as it is shown in Figure 2. In dipping reservoirs, the gravity segregation will favour a stable displacement as described in the Field case. Early Identification of Multiple Contact Miscibility injecting Dry Gas El Furrial Field, a Case of Multiple Contact Miscible Gas Injection combined with Low-Salt Water Injection.

Figure 2.

Miscible gas injection in absence of structural dip.

4. Types of miscible process and mechanisms

There are two basic types of miscibility:

4.1 First contact miscibility

Occurs when the injectant dissolves the oil as soon it gets in contact with the reservoir, it usually occurs with solvents as gasolines, and very rich gases.

4.2 Multiple contact miscibility (MCM)

A multi contact miscibility starts as an immiscible displacement, then the thermodynamic conditions (Pressure and Temperature) allow a continuous transfer of molecules of hydrocarbon from the displaced oil to the injectant (displacing phase), in a condensing and vaporising process, that enrich continuously the injected gas, until it becomes miscible with the displaced oil. The mechanic of miscibility injecting a dry gas is defined as Vaporizing Drive, it is controlled by the oil composition, the pressure, and the temperature.

The miscibility achieved through multiple contacts between the injection gas and the oil in-place occurs after the injection gas at the displacement front progressively contact the oil in the reservoir. As the displacement front moves into the reservoir the gas takes more heavier components until the miscibility is achieved. In presence of viscous fingering or permeability heterogeneity, the minimum distance to accomplish miscibility increases because of dispersion at the displacement front. The total recovery in a MCM process is the sum of the recovery obtained while injection gas travels the immiscible portion of the porous media plus the recovery obtained when the gas displaces the miscible portion.

In a phase envelope Figure 3 the first contact miscibility pressure usually occurs above the bubble point pressure. The Cricondenbar is the maximum pressure that gas phase cannot be formed any more regardless of its temperature, its temperature is called cricondenbar temperature.

Figure 3.

Pressure volume phase diagram for a typical oil composition [2].

The Cricondentherm is the maximum temperature that liquid cannot be formed regardless of pressure and its pressure is called cricondentherm pressure.

At temperatures higher than Cricondentherm, only one phase occurs at any pressure, the corresponding pressure is called Cricondenbar that is the maximum pressure above which no gas can be formed regardless of the temperature.

The chart Pressure Temperature phase diagram for an oil system illustrates the position of the cricondenbar pressure, the bubble point line and the two phases liquid and gas envelop; the area above the bubble point line and below the cricondenbar pressure defines the region where the multiple contact miscibility might take place.

5. Ternary diagrams

Ternary diagrams are used to represent the phase behaviour of hydrocarbon systems, the mixture of components of the fluids with more than three components is divided into three pseudo components, such as light, intermediate, and heavy components of a hydrocarbon phase. The ternary diagrams are developed based on compositional equations of state (EOS) developed to replicate the phase behaviour of hydrocarbon systems, are useful to represent the phase behaviour of a mixture of pure hydrocarbons. The composition of the 3 points in ternary diagrams is defined based on the oil composition and the injection fluid composition., and the diagrams are generated with specialized commercial software as Eclipse 300, GEM, etc. The grouping of components is usually a convention defined by the user

• Thermodynamic criteria define the minimum miscibility pressure MMP in a ternary diagram as the pressure at which the limiting tie line passes through the point representing the oil composition.

• The tie lines in a ternary diagram, represents the two fluids being mixed, compositional concentrations of the two mixed fluids are given by the ends of the tie lines.

• The mixture composition lies on the line, its position depends on the concentration ratio of the two end-point fluids.

As for example in Figure 4, a gas composition 50% C1 and 50% C2–C4 will lie in the midpoint of the C1 and C2–4 corners.

Figure 4.

Typical Ternary phase diagram, hydrocarbon system: the limiting tie line passes through the oil composition at minimum miscibility pressure (MMP) [1].

The composition of an Oil sample in the centre of the triangle represents a mixture of:

• 30% C1 with 70% C2–4

• 30% C7+7 with 30%C2–4

• 37% C7+ with 3% C1

The green area represents the mixture of 3 groups C1, C2–4 and C7+ result in 2 phases gas and liquid.

The Triangular Diagrams in Figure 5 represents a system with C1 at the top corner, C2–C4 at the bottom right corner and C7+ at the left corner. A point between two corners represents a composition proportional to the corners, as example a midpoint between C1 and C4 represent a mixture 50% C1 and 50% C2–4; similarly the midpoint between C4–C2 and C7+ represent 50% of each corner. For this composition, the blue areas correspond to the mixtures that result in 2 phases oil and gas. The miscibility occurs when a gas composition gets in contact with an oil composition without crossing the two phases area.

Figure 5.

Ternary diagrams system with limited miscibility [3].

A multiple contact miscible process MMP with dry gas is illustrated in 4 steps in the phase diagram in Figure 6.

1. The injection gas is composed by pure C1, it is represented with the point “G” in the diagram. As the C1 gas moves in the reservoir, thermodynamic interactions with the oil components, makes the C1 extract intermediate components such as C2–C4 etc. from the contacted oil phase.

2. As the gas move forward, the intermediate molecular weight hydrocarbons from the injected gas are transferred into the oil in the reservoir.

3. Them, because of the phase transfer mechanism some of the gas “condenses” into the oil.

4. The reservoir oil becomes enriched with these materials, until the miscibility occurs between the injection gas that has already extracted high Molecular weight components from the residual oil and the enriched oil at the displacement front.

Figure 6.

Three phases’ diagrams condensing gas drive miscibility [3].

The plait point is a critical point at which the liquid and vapor phases are identical.

The miscibility occurrence is a function of the solvent concentration, (C4). The injectant composed by pure C4 and high C4 concentration achieve first contact miscibility. As the proportion of the solvent C–4 reduces, there will be a composition where there is not first contact miscibility, and miscibility might occurs by multiple contact, then as the C4 proportion reduces the miscibility is lower until a point where there is no miscibility at all, as shown in Figure 7.

Figure 7.

Three phases diagrams showing gas composition with multiple MCM and gas composition with first contact miscibility FCM [4].

6. Condensing—Gas mechanism sequence

1. Reservoir pressure is lower than the MMP (minimum miscibility pressure)

2. The solvent (injectant) and the oil are not miscible initially.

3. As the dry gas move in the reservoir there is transfer of hydrocarbon components from the residual oil to the injectant and from the solvent components transfer to liquid oil phase.

4. Repeated contact between oil and solvent moves system towards the plait (critical) point (dynamic miscibility).

As the pressure increases the two-phase region becomes smaller. At some pressure the injected gas is to the right of the limiting tie line and MCM develops. This process is known as condensing vaporizing multiple contact miscible drive.

7. Vaporizing gas mechanism

Intermediate hydrocarbon components in the oil vaporize to enrich the gas. As the leading edge of the gas slug becomes sufficiently enriched, it becomes miscible with the reservoir oil.

7.1 What happens in the simulation when miscibility is achieved?

When the miscibility is achieved into the reservoir, the displacement will be very efficient and virtually all the oil in the reservoir will be removed and displaced toward the producer wells, the characteristic of miscible displacement projects is the high recovery factors in order of 60–75% of the oil in place; higher figures of the recovery factor are not commonly reported, limited by the operational pressure in the field, or lack of gas injection continuity, reservoir heterogeneities, etc.

Experiments show that final recovery increases by increasing the slim tube length for any injection rate.

8. Challenges in miscible gas injection projects

One difficulty in a Miscible Gas Displacement project is to keep all the reservoir porous media above the minimum displacement pressure. Several pressures levels can coexist in the reservoir because of the pressure gradient and the flow dynamics in a heterogeneous reservoir as sedimentary environments composed typically by river channels, plains, sandstones, bars, splays, etc. or in carbonate reservoirs with several facies within the reservoir unit; if there is not a well-defined safety margin above the MMP, there might be areas with pressures below the minimum miscibility pressure.

It is common to receive management requirements to produce at maximum potential which might not correspond to the injection rates designed to maintain the reservoir pressure above the MMP, this is a challenge in a MMP project that might cause detrimental effects to the recovery factor.

In the last decades of past century and early times of this century, the oil and gas operators realized the importance of understanding the fluid behaviour and its characterization with application of fluid phase envelops and its use as a reservoir management tool. In many cases, the feasibility to increase dramatically the recovery factors was recognized after understanding the reservoir the reservoir dynamic, in some cases a late implementation of a MMP EOR project was hampered by the high cost of repressurizing the reservoir at levels adequate for a MMP displacement; this type of issues has avoided a more extended implementation of EOR Miscible gas injection projects.

Gravity stable injection of gases into high relief oil reservoirs can result in substantial incremental oil recovery, depending on the densities of the gases at reservoir conditions, the gases should be injected at the crest or bottom of the reservoir, while miscible displacement scan be in low relief of flat reservoirs, however the process will be more challenging because no gravity effects.

Viscous fingering is another challenge that can result in poor vertical and horizontal sweep efficiency (Figure 8).

Figure 8.

Fingering in a miscible displacement [2].

Other challenges are the potential corrosion, affecting the well and the production facilities as also nonhydrocarbon gases must be separated from saleable gas.

9. Typical gases that can be used as injectants

The more common gases for injection are the associated gas produced with the oil, dry gases, or gases available in the nearby of the field’s candidate for miscible injection, and other gases as CO₂, N₂, and Flue gas. Flue gas is a mixture of air with combustion gases, with the advantage that the volume of gas used in the combustion is multiplied by several orders of magnitude. Cleaning requirement of impurities in the flue gas will be depending in each case. The miscibility displacement with flue gas usually requires much higher reservoir pressures sometimes to impractical levels.

Usually, it is important to execute a source of injectant fluid study covering for example 100 kilometres around the project location with the purpose to investigate the potential sources of gases for injection. It should be done in a short period by personal of the operators familiar with this type of process. From the gas’s availability study, it should be generated the different types of gases to be used in the determination of the optimum injectant for a particular EOR miscible gas injection project.

10. Screening parameters for a miscible project

The typical parameters for a favourable miscible process are shown below, it has been defined in several known publications, as “Updated EOR screening, JJ Taber, F.D. Martin, SPE, and R.S. Seright, SPE, New Mexico Petroleum Recovery Research Center SPE 1997 [5]^, and Aladasani, Ahmad, “Updated EOR screening criteria and modeling the impacts of water salinity changes on oil recovery” (2012). Doctoral Dissertations [6].

However, every field case should be studied individually considering all factors inherent to the field as reservoir size, reserves, available fluids for injection, markets, among others.

• Gravity >24°API (35°API for N₂)

• Viscosity <10cp

• Composition C1–C7

• Oil saturation 30%

• Formation type sandstone/carbonate

• Net thickness (thin unless dipping)

• Average formation permeability (not critical)

• Reservoir Transmissibility (not critical)

• Depth >4000ft

• Temperature not critical

The average reservoir permeability is the arithmetic or geometric, weighted average of the permeabilities defined from electrical logs and cores used to populate a reservoir grid. Transmissibility is a term to express the reservoir ability to move fluids as function of relative permeabilities, fluid viscosity, formation volume factor, and geometric parameters.

11. Experimental determination of the minimum miscibility pressure (MMP)

There are several experimental methods to determine the MPP, the more known are the Slim Tube Tests, the Raising Bubble, the Zero Interfacial Tension; en addition there are other methods to estimate the MPP as compositional reservoir simulations and correlations.

Before initiation of the experimental laboratory work, it is recommendable to preliminary estimate the MMP by means of compositional reservoir simulations, this can be done building a simple one-dimensional reservoir simulation model based in the compositional fluid characterization, representative rock properties pressures and temperatures, then displace the oil using various injectants and various reservoir pressures; the obtained results can be used to evaluate the process under several pressures and to determine the conditions required to achieve a miscible displacement.

The one-dimension compositional modelling is recommended to be the first task to be done as soon as the compositional description and the PVT data is available, these will guide the laboratory experiments, and the preparation of full field compositional reservoir simulations studies.

12. Slim tube tests

The slim tube test is an apparatus laboratory test used to estimate the minimum miscibility pressure (MMP) or minimum miscibility concentration (MMC) of a given injection solvent and reservoir oil. It allows to create a porous media saturated with the reservoir fluid at representative pressure and temperature to establish the original conditions prevalent in the reservoir, which will be used to test the injectant as dry gas, wet gas, separator gases, CO₂, Nitrogen, or Flue Gas.

The slim tube Figure 9 is a narrow long-coiled stainless-steel tube. It is filled with sand of a specific mesh size like the reservoir porous media. To model the displacement process in the reservoir, the tube is saturated with reservoir oil at a reservoir temperature, then the Gas injection is performed at several test predefined pressures, or at the field reservoir pressure if this is a undersaturated reservoir and the investigation is done aiming to investigate the process at that operational pressure. The produced effluents, density and composition are measured as functions of the injected volume.

Figure 9.

Slim tube test apparatus schematic [3].

A slim tube internal diameter (ID) is typically about 5/16 inches, with length from 5 to 40 meters. The tube is filled up with glass beads or sand of a specific mesh size, the ratio of particle size to tubing diameter is sufficiently small, less than 1/10, to neglect wall effects, it can be idealized as a one-dimensional element of the reservoir.

When gas is injected in the sand packed slim tube apparatus will take place multiple equilibrium contacts, at the end of the experiment the recovery factor is calculated to identify the type of displacement, a miscible displacement will be concluded at recovery factor close to 95% or more. The slim-tube tests result should not be indicative of ultimate recovery to be achieved in actual reservoir, because the Slim Tube is not including factors sweep efficiency, transition zone length, etc. The experiment should be done at constant reservoir temperature.

The experimental procedure requires an initial calibrating of the apparatus with known fully miscible fluids. To determine the MMP, the slim tube is saturated with crude oil and several consecutive displacements are executed at various reservoir pressures.

The oil recovery after injection of a specific number of pore volumes (PV) such as 1.2 PV of solvent is the test criterion for miscibility. The recovery factors for the different pressures are plotted versus pore pressure for the several slim-tube tests, typically at low pressures recoveries will be low, and will increase as the pore pressure increases, when the slop of the first line exhibit a noticeable change, it is indicative of the multiple contact miscible pressure, further higher pressures should reach higher recoveries, Figure 10.

Figure 10.

Plotting results from the slim tube test experiments.

The slim tube test usually considers consecutive displacements at different pressures, starting from the estimated from the MMP compositional simulation, the obtained results for the several pressures are plotted and the tests are repeated until reaching a near 95% recovery factor. The 2 lower plots in Figure 10 show the MMP determination injecting soltrol (an isoparaffinic solvent) in slim tube saturated with synthetic oil. The experiments can be done with different solvent concentrations to evaluate the solvent minimum requirements.

Different strategies for the determination of the MMP can be designed, as for example, reducing the number displacements to at least four pore pressures, if the results show two trends, the point of intersection of the trends is considered the estimated MMP for the given oil-solvent system. In other cases, a particular reservoir pressure might have been defined as the target operation reservoir pressure to operate the reservoir with specific purpose as to avoid crossing the asphaltene flocculation onset, in that case it is a practice to run the slim tube tests a that specific operational pressure with the objective to understand the process, a particular case where this strategy was successfully applied is described in the field experiences section.

In any strategy that is used, the results obtained from a slim tube test must be used as input to fine-tune an equation of state for reservoir simulation, that will be applied in the full field compositional simulation required to estimate the field recovery factor; the accuracy of the predictions is function of the data representativeness.

The displacement from the reservoir is affected by various mechanisms that causing dispersion, such as gravity override and viscous fingering caused by unfavourable viscosity ratio. The porosity heterogeneity if present will also cause dispersion of the front. The slim tube provides a one-dimensional dispersion free displacement of oil; therefore, the dispersion effects must be studied with a three-dimension multi geocellular model representative of the reservoir. At field condition, the MMP and the final recovery are function of the thermodynamic behaviour in the system, the gravity effects, reservoir heterogeneities, etc.

12.1 Micro slim tube test

Interface Fluidics has created a novel method to estimate miscibility using a microfluidic chip capable of measuring MMP with greater precision and confidence than the standard slim tube method. The slim-tube standard apparatus estimates MMP by constructing a linear regression around a few critical data points, Micro Slim Tube use Interface’s analogue a data-driven approach to yield results with greater accuracy. Each chip run collects anywhere from 25 to 75 values per gas-oil system, resulting in high-resolution data plots that can be used to determine MMP directly.

The Micro Slim Tube Figure 11, is a miniature of the slim-tube method via microfluidic technology, for rapid and cost-efficient determination of MMP using smaller sample volumes to conduct initial tests. This allows to analyse several reservoirs samples and conditions for the MMP investigation. Changes in oil and gas composition can dramatically impact MMP values, accurately capturing this variable allows to cover a wider spectrum of condition for reservoir simulation models and detailed planning of miscible gas flooding processes.

Figure 11.

Micro slim testing by interface fluidics oil.

It can reduce cost for miscibility measurements, and execution of minimum miscibility enrichment (MME) studies, to optimize the gas injection strategy. Requirement of lower sample volumes impact favourably the economy and health/environmental risks associated with sampling from wells.

12.2 Raising bubble method

This s a more recent development laboratory method to indicate miscibility between the reservoir oil and injection gas at specific conditions of pressure and temperature.

• A gas bubble is injected into an oil-filled visual cell at a given temperature and test pressure.

• The progressive change in shape of the rising bubble indicates its miscibility with the oil at those conditions.

• Below the minimum miscibility pressure (MMP), the bubble holds its shape as it rises, above the MMP, the bubble shape changes as it rises.

• It may disintegrate, dissolve, or disappear into the oil.

Testing at several pressures helps to determine the MMP between the gas and oil. The rising-bubble test represents a forward-contacting miscibility process and therefore may not accurately to estimate the MMP for a backward or combined contact mechanism [7].

12.3 Rising bubble apparatus by core laboratories

The Rising bubble apparatus (RBA) offered by Core laboratories provides a fast, accurate, cost-effective measurement of minimum miscibility pressure. The essential feature of the apparatus is a flat glass tube mounted vertically in a high-pressure sight gauge in a temperature-controlled oven.

The glass tube, its Figure 12 approximately 20 cm long, facilitates the examination of bubbles rising in opaque oils. The glass tube is back lit for visual observation of the tube contents. A hollow needle is mounted at the bottom of the of the sight gauge and protrudes into the rounded portion of the glass tube.

Figure 12.

Raising bubble apparatus by core lab [8].

The Raising Bubble Apparatus has a needle that is set and kept about 3–5 centimetres below the flat portion of the tube. The sight gauge and glass tube are pre-filled with deionised water at the initial test pressure and reservoir temperature., the reservoir oil is then injected downwards into the flat glass tube, displacing the water until only the lower circular portion of the glass tube contains any water.

A small gas bubble must be placed at the tip of the hollow needle and liberated into the tube, it will rise through the water, through the water/oil interface and up through the column of oil. After two or three bubbles have risen through the oil the water oil interface, then it is replaced with a fresh reservoir oil.

All the process of the gas bubble raising is monitored using a motion tracking optical system with a video camera mounted on a rail parallel to the path of the rising bubble. A magnified view of the bubble can be observed on screen and recorded as a small movie clip (mpeg). The time of the raising process for each injected gas bubble is calculated for each test pressure and use this data to interpolate the MMP.

12.4 Zero interfacial tension (VIT vanished interfacial tension)

At the Miscible Pressure, no interface exists between crude oil and injection fluid, i.e., interfacial tension approaches zero Figure 13. The VIT method measures the interfacial tension between the two phases, the measurements are done in a high-pressure cell with an optical tensiometer, the oil is introduced as a drop phase into the chamber filled with the injection fluid [9].

Figure 13.

Vanishing interfacial method to estimate the MMP.

The interfacial tension is measured with the Pendant Drop Shape analysis. It is measured at 5–10 different pressures at reservoir temperature after which the line is extrapolated to zero IFT. When the interface between two phases vanishes in all proportions, that is first contact miscibility. In a field CO₂ project, it is always multi contact miscible, never first contact miscible.

Although it has been established that VIT is NOT a rigorous measurement of MMP, it provides a good approximation. The measurement of MMPs in a high-Pressure Temperature Tensiometer apparatus Figure 14 it can be done in two weeks for 20 ft columns and less than a month for 6-point, 80-foot columns [9].

Figure 14.

High P/T tensiometer for the VIT [9].

12.5 Correlations to estimate the miscibility pressure

Stalkup, JR [10] presented his Correlation to estimate the MMP (1983-4) developed from 9 different miscible process displacing oil of different compositions with gas composed by more than 80% mol methane, it correlates MPP as function of the oil composition and saturation pressure. The correlation results exhibited average deviation of 260 psi, and maximum deviation of 640 psi; however, the correlation exhibited large errors for displacements with gases with methane content lower than 80 mole percent [11].

12.6 When is the best time to determine the minimum miscibility pressure?

The time when to determine the Minimum miscibility pressure is the nearest time to the reservoir discovery date, as soon as a PVT sample is available and analysed, other parameters need to be considered, as the reservoir dimensions, volumes of initial oil in places, the reservoir pressure, the reservoir conditions either undersaturated or saturated reservoir, recovery factors, among others.

A MMP process is not applicable for a saturated reservoir because saturated reservoirs are characterized for having initial pressure below the bubble point pressure evidenced by a primary gas cap.

To achieve a miscibility displacement in a saturated reservoir, it would be required to re-pressure the reservoir to above the bubble point pressure, which could be achieved injecting a considerable volume of gases or water while the reservoir is closed to producing, this situation is very improbable to happen because the prohibitive cost that represent injecting fluids without hydrocarbon production.

Under the current trends of switching the energy supply from fossil to renewable cleaner energies might be opportunities where the Carbon Capture and Storage (CCS) activities might supply the opportunities to use depleted oil reservoirs with low recovery factors for CO₂ storage. In those cases, dedicated geosciences and reservoir engineering studies will be required to mature every particular field case with two folds objectives, first to storage the CO₂, second to investigate how the remaining oil in the depleted structure will be affected by the injected CO₂.

For a subsaturated reservoir, the situation is different because there is higher probability to implement a miscible process with the purpose to increase the oil recovery factor and the reserves; the suggested procedure is:

1. Determine the initial Reservoir Pressure at datum, which is usually a horizontal line the gravity centre of the reservoir,

2. Determine the bubble point pressure at the reservoir datum.

3. Determine the operational pressure for the reservoir that satisfy the production objectives, considering the fluid composition, content, and onset of asphaltenes deposition, water injection ongoing operations.

4. Determine the difference between the initial reservoir pressure and the bubble point pressure, this difference determines the range of pressure available to deplete the reservoir before the start of the gas injection to achieve a miscible displacement.

5. Establish the ratio reservoir pressure depletion as function of extracted oil volumes.

6. Calculate the time to reach the bubble point pressure using the reservoir pressure depletion ratio as function of extracted oil volumes.

7. The time estimated from the above procedure will give insight of the time when initiate the gas injection to achieve a Miscible Displacement process.

This process must be based on numerical reservoir simulations using calibrated reservoir simulation models.

The MMP process are viable only when the incremental production generates enough revenue to cover the project cost implementation and generate revenues for the operator and the shareholders. In the field history cases we describe a case of multiple contact miscibility with dry gas in a subsaturated reservoir.

13. Field case: early identification of multiple contact miscibility injecting dry gas el furrial field, a case of multiple contact miscible gas injection combined with low-salt water injection EOR projects

El Furrial field is a giant structure discovered in 1986 by Lagoven s.a affiliated of PDVSA with the perforation of the Ful-1X well in Eastern Venezuela Figure 15, it encountered 854 m gross interval with 366 m net oil sandstone Figure 16, it was the more important discovery in South America in over 25 years, achieved 10 years after the nationalization in 1976, at a time when national production had declined to its lowest point since 1950; this field become the highest producing oil field in Venezuela, reaching a peak of 480,000 bbl/day in 1998. Secondary and Tertiary recovery studies to maximize the oil recovery were initiated in 1990 (Figure 17).

Figure 15.

El Furrial field location.

Figure 16.

Regional structural setting El Furrial field.

Figure 17.

Full field reservoir simulation model.

The discovery of this giant near 7.9 billion barrels of oil in place was a tremendous success of the exploration campaign undertaken by Lagoven s.a. [12] in an area where international operators exploited shallower oil reservoirs before the 1976 nationalization leaving unnoticed deeper structures containing a trend of giant light oil reservoirs.

Initially, a water injection project to inject 200,000 barrels of fresh water was designed to maintain the reservoir pressure at or above 6500 psi at reservoir datum, with the purpose to have a safety margin above the asphaltenes flocculation onset that was extensively measured to start at about 1500 psi above the bubble point pressure 4500 psi.

Immediately after the sanction of the water injection project, it was identified the feasibility of a Multiple Contact Miscible (MCM) process injecting Dry Gas [13]; the feasibility was identified from one-dimension compositional simulations, followed by experimental studies that concluded with the implementation of a project to inject 600 mmscf/d of dry gas to develop a MCM project in parallel to an increase of the water injection to 450,000 barrels/day to significantly increase the final recovery factor (Figure 18).

Figure 18.

Water and gas injection project and oil production wells map (IAGF project).

The two projects water injection and MCM gas injection were designed, planned and implemented to operate simultaneously. The gas injection in 5–6 wells located at the crest of the anticline and the water injection in near 36 water injection wells positioned at the flanks in two independent rows one for each main reservoir unit (Figure 18).

The projects were designed to achieve a combined recovery factor in range from 55 to 60%. Both projects were timely implemented and successfully operated since inception to mid project life. By end of 2021, 36 years after the field discovery the recovery factor achieved is estimated in range of 44.5% that is near 10–15% below the initial predictions; this implies that a range from 845 to 1240 million barrels were not produced.

The procedure applied to determine the Multiple Contact Miscibility displacement is summarized below:

1. A one dimension compositional model was set up to simulate the displacement of reservoir oil injecting dry gas, assuming all liquids would be extracted before the injection. The displacement was modelled at 6500 psia the minimum reservoir operational pressure predefined based on the asphaltene deposition experimental studies. The one-dimension model indicated a multiple contact miscible gas process would occur as a result of the thermodynamic effects injecting gas at pressures 2000 psi above the bubble point pressure.

2. The equilibrium constant at 6500 psi were experimentally determined by swelling tests performed in Core Laboratories in absence of correlation for pressures above 4000 psi.

3. A slim Tube Test apparatus was set up at Intevep Technology Centre, calibrated injecting soltrol, a high-purity, low-odour, low-toxicity synthetic solvent, in the porous media saturated with mineral oil at 6500 psi the reservoir operational pressure, obtaining a recovery close to 95% recovery, indicating the occurrence of miscibility.

4. The slim was saturated with crude oil samples taken from the Ful-12 well located at the crest of the structure, where the gas injection operation were planned.

5. The gas sample for the displacement in the slim tube was captured from the national gas network, because the injection displacement was planned with a dry gas; the analysed showed a minor percentage of CO₂.

6. The gas injection was executed at 6500 psi, and the recovery registered in range of 92–96% confirming multiple contact miscible displacement injecting dry gas at 6500 psi as observed in the one-dimension compositional model.

In this specific case, the slim tube tests were performed at 6500 psi to verify the occurrence of miscibility previously calculated in the one-dimension compositional simulations.

Afterwards the MMC miscible gas injection project known as IAGF (Injection de Agua y Gas Furrial) was sanctioned and implemented along with an increase in the water injection capacity; the gas injection started in 1998. The performance of the two projects is discussed below:

13.1 Field case IAGF gas injection combined with low-salt water injection El furrial production performance

The field production history of the IAGF project described in the previous section is shown in the Figure 19, the pressure history is presented in the Figure 20. The field production targets for the field were planned with the premise to maintain the reservoir pressure in range of 6500–7000 psia to ensure the gas displacement under the miscibility process and to avoid the asphaltene deposition around the wellbore of the producer wells, plugging the perforations in the well completions and damaging the formation in the wellbore zones. The asphaltene flocculation onset pressure was measured as function of the asphaltene in around 6000 psia.

Figure 19.

Production forecast plot IAGF project.

Figure 20.

Pressure performance plot IAGF project.

The Figure 20 shows pressure performance, it is observed the reservoir management activity to maintain the reservoir pressure in the predefined range 6500–7000 psia was consistent since the inception of the project until approximately the year 2008, when a drastic pressure decline occurred as a result of lack of continuity in the gas and water injection operations, that occurred in parallel with an intensive infill drilling campaign implemented in the lapse 2008–2010; such drilling campaign resulted in an increase of the production however the reservoir voidage was not maintained causing a drastic reduction of the reservoir pressure to levels below 6500 psia the operation pressure that preceded a dramatic fall in the production rates observed in the years 2013–14.

The analysis of the historic performance suggests this reservoir was capable to produce at rates higher than predicted for a longer period (after 2004), if the reservoir pressure would be maintained above 6500 psi.

The project management seems to have been disattended in the last 10 to 12 years because of the nationalization of the injection facilities, politization of the project management, and other detrimental practices of century 21 socialism regime, as a result the reservoir pressure declined to 4600 psi in 2013, below the asphaltenes flocculation onset.

At current standards of the technology with the application of best reservoir management practices the final recovery for this project should have been close to 70–75%; however, several events that affected the continuity of the gas and the water injection affected adversely its performance. Analysis of the results of the two consecutive EOR projects, are discussed below to illustrate the impact of early EOR gas and water injection studies.

The first project, a Low Salinity Water injection was designed in 1990–1991 to maintain the reservoir pressure at 6500 psi, the water injection was initiated in 1992 with a pilot test followed by the construction of the facility to inject 450,000 bbls/day of water to recover an estimate of 1277 million barrels of incremental oil (∼20 % recovery above the primary recovery factor estimated in ∼16%), it was named the Resor project. The water injection operations were initiated at reservoir pressure of near 8000 psia at 14,000 feet deep, fresh water of ∼1000 ppm from shallow aquifers was selected after screening all available sources which put this project as a Low Salinity Water Injection displacement process.

Immediately after the RESOR project was sanctioned in 1992, the gas injection feasibility studies were initiated, the experimental and engineering work were executed in 2 years, and the obtained results concluded the dry gas injection would add an important increase in the recovery, therefore it was recommended to initiate a dry gas injection with pure methane at rates of 550 mmscf/day in the crest of the structure to increase the final recovery to around 55–60%. The Miscible Displacement Injecting Dry Gas studies were done with TCA Reservoir Engineering Services a company based in Durango Colorado with cooperation from the EOR department of the Texas University and the Research Institute Intevep S.A. affiliated of PDVSA; the simulation work included the one-dimension and full field compositional simulations that demonstrated a multiple contact miscible displacement injecting pure methane, this process was corroborated with slim tube experiments executed at Intevep the Technological branch of PDVSA, and verified in Core Lab and Westport Laboratories in Houston Texas, giving the bases for the Miscible Gas Injection EOR project initiated in 1998 (IAGF).

The Miscible Gas Injection project was designed in 1994 [13] to inject 550 million standard cubic feet per day of dry gas together with an expansion of the water injection to 550,000 bbls per day, with the objective to generate reserve of 684 million barrels of incremental oil, additional to the base water injection estimated reserve in 1277 million bbls; the gas injection project was named IAGF and initiated in 1998. The project aimed to achieve a multiple contact miscible displacement injecting dry gas at 6500 psia at the top of the reservoir, with the objective to remove and displace the residual oil toward the producer wells acting in combination with the water injection at the flanks of the structure, it implied the conversion of five-six producer crestal wells to gas injectors sacrificing a substantial oil production rate (Figure 21).

Figure 21.

Cross section compositional simulation, showing near zero oil saturation in zones affected by the miscible displacement injecting dry gas.

The cross section of the compositional simulations shows the effect of the miscible gas displacement in the reservoir reducing the oil saturation to near zero in the surrounding zones to the gas injection wells, as it was observed in the slim tube tests and predicted in one-dimension compositional models.

13.2 IAGF water and gas injection project, performance review

In this section, it is described an analysis of the actual reservoir response under water and gas injection versus the predicted forecasts, to illustrate the value of the early identification and implementation of the feasibility of a MCM process, for this analysis, data from various sources was used to generate an overview of the project performance.

Both injection projects are classified as Enhanced Oil Recovery, because their intrinsic characteristics:

• The water injection at reservoir pressure of near 7500 psia at 14,000 feet deep, designed to inject fresh water places this project within Low Salinity Water Injection Displacement process.

• The Multiple Contact Miscible Gas Injection Process designed to achieve miscibility injecting dry gas at 7000 psia at the crest of the reservoir, to remove and displace residual oil toward the producer wells achieving a near zero residual oil saturation in the zones affected by the MCM displacement, acting in combination with the water injection at the flanks of the reservoir.

To evaluate the results of both projects, it was accessed the original working files and the numerical simulation models build in 1990–1997 built in house using commercial simulators with data generated in laboratories of Intevep s.a., Core Laboratories Inc, Schlumberger, and other international laboratories, as compatibility tests performed in Serk Baker labs in United Kingdom. We also used the universities Simon Bolivar and Universidad Los Andes in Venezuela, Bristol University in UK and Texas A&M University in Houston Tx. Before the project sanction, all the tests were verified by international laboratories in Houston and Dallas Texas USA.

The analysis of the production performance is based in the production forecast, actuals production profiles obtained from public domain literature, personal experiences, notes, and testimony of some of the main players.

The simulation profiles generated for the sanction of the two analysed projects were plotted along with a natural depletion case, and the actual historic production performance plots, shown in Figure 19, it shows the natural depletion and three consecutive cases corresponding to: injection water 450,000 bbls/day base case (blue dotted line), water expansion to inject 550,000 bbls/day of water (green dotted line) and the miscible gas injection of 550 mmscf/day combined with 550,000 of water injection.

The solid black line represents the actual historic production, the orange line starting at 2007 represents the PDVSA Plan at that year; the STOIIP at this year was increased to order of 7.9 B bbls.

A reservoir pressure review to the available data in the Figure 20, shows observed pressures in the first 1–2 years after the gas injection started in 1997, the actual oil rate was lower than predicted, it declines to 400,000 bbls/d and is maintained until the year 2012, then a dramatic decline started to reach the actual rate ∼60,000 bbls/d in the year 2020–21.

The overall actual production performance is superior to the forecast because of intensive infill drilling; however, the dramatic production decline started in 2012 is result of a progressive discontinuity of the gas and water injection operations.

The main conclusion is the water and gas injection operations affected favourably the production overachieving the initial forecast and generating more than planned reserves, however a more careful analysis shows the achieved actual recovery factor just reach around 45% of the updated STOIIP (7.9 MMbbl) which is near 10% bello the recovery factor obtained in the initial predictions; this deficit is a result of discontinuation of the gas and water injection operations and the over-production above the established production levels, noticeably the dramatic production decline occurred in 2012, coincides with the pressure depletion below the operational maintenance pressure defined for the reservoirs in the implementation studies in 6500–7000 psi at datum.

Currently the gas flare is common in this giant field, which is a result of the inefficient operation in the compression and injection system; the field reservoir pressure was well managed until 2012, however after 2013 the decline in the reservoir pressure coinciding with the low oil production rates reflect its effects of well productivity deterioration (Figure 22).

Figure 22.

Press Note of Gas Flaring in El Furrial Field Monagas State, March 2020.

14. CO₂ injection as EOR process

EOR CO₂ flooding consists of injecting large quantities of CO₂ in the reservoir to form a miscible flood, the injected CO₂ volume is determined from experimental and compositional studies can be from 15% or more up to 1.5 hydrocarbon pore volumes. When the CO₂ gets in contact with the oil in the reservoir, if the pressure is high enough, there will be a kind of “vaporizing gas drive” recovery mechanism:

1. The CO₂ extract the light–to-intermediate components from the contacted oil,

2. the miscibility is developed in the displacement front,

3. in the displacement front the oil viscosity is reduced when the CO₂ swells the residual oil, and

4. the mobility ratio will improve because of the oil viscosity reduction.

The CO₂ is an efficient miscible displacement solvent, it requires lower pressures to achieve miscibility compared to other gases as hydrocarbon gases, Nitrogen and flue gas, the CO₂ injection as EOR method in the oil industry is well known and has been applied in many fields.

Conversely in some fields with high CO₂ content, meaning the CO₂ is available, the CO₂ reinjection has not been implemented, the produced CO₂ is vented, or the wells have been shut in, in contrast with other fields and reservoirs where the CO₂ is not available and the required volumes for CO₂ injection for EOR purposes, had been purchased and transported from other sources. Those fields with high CO₂ content that have been under exploited because its high CO₂ content can be an excellent fit of the technology to produce the hydrocarbons with high CO₂, separate it and reinject in the reservoir displacing the total usable hydrocarbons and leaving the CO₂ reinjected volumes in the reservoir, finally used as the CO₂ captured recipient.

The Figure 23, is a schematic of a CO₂ EOR process followed by a waterflooding displacement to chase the CO₂ slug.

Figure 23.

Schematic of a CO2 EOR Displacement Followed by a Waterflood.

The Screening Parameters for a CO₂ EOR are listed below:

• Gravity >27 API Viscosity <10cp

• Composition C5–C20 (C5–C12) oil saturation >30% PV

• Formation type sandstone/carbonate Net thickness relatively thin

• Average permeability not critical

• Transmissibility not critical

• Depth >2300 ft

• Temperature < °250

14.1 EOR and CCS

Since the 1950s, the oil and gas industry has spent many billions of dollars on CO₂ EOR technologies, commercial projects, and developing operational knowledge. Most of this activity has been in land-based oil and gas fields. The first patent for CO₂ EOR was granted in 1952, the Texas Railroad Commission reports the first three projects were initiated in Osage County, Oklahoma between 1958 and 1962. These CO₂ EOR projects have steadily increased over the years based on the growing availability of CO₂ and technology advances.

In 2012 the Oil & Gas Journal EOR survey, reported the CO₂ flooding in the USA was producing more oil than EOR by Steam Injection (308,564 bbls/day vs. 300,762 bbls/day) with 41% of the output from all types of EOR. The active CO₂ EOR projects in the USA were increased to 120, representing 89% of the total 135 CO₂ EOR project globally. Furthermore, in the past years, as sources of CO₂ offshore and deep-water technology has become available new EOR CO₂ injection projects were initiated, as in the giant Lula field located deep-water in Brazil, which is the pointy end of a very long and successful industry history of CO₂ EOR.

Conversely, some onshore fields with large volumes of liquid CO₂, has not been fully developed because the high CO₂ content, which might have been produced and used to recover the hydrocarbons and leave the CO₂ storage in the reservoir.

15. Challenges and solutions injecting CO₂ for EOR

Some of the challenges for the EOR CO₂ project implementation are:

• CO₂ availability,

• Early breakthrough of CO₂ because the very low viscosity of the CO₂ results in poor mobility control, this is associated with the pressure insufficient for the CO₂ to swell and remain in the oil

• Corrosion in the producing wells

• Separating the CO₂ from saleable hydrocarbons,

• Repressuring of CO₂ for recycling, and

• Requirement of large volumes of CO₂ per incremental barrel produced.

Over the last 25 years, a small number of offshore saline aquifers and oil and gas reservoirs have successfully used many of the technologies developed through the last 58 years of land-based CO₂ EOR experience. It is possible that CO₂ is a viable means to increase hydrocarbon output from many depleted offshore reservoirs that are marginal or no longer productive; most operators are not using this technique on their reservoirs because they do not have an economical supply of CO₂, other operators because do not own the CO₂ technology. However, cost-effective supplies of CO for many of these offshore fields may become available as carbon capture from nearby electric power plants and other large, stationary sources of CO emissions becomes more common (Figure 24).

Figure 24.

Schematic CO₂ capture and injection offshore.

In the last years, it has been detected some onshore light waxy oil fields containing large amounts of CO₂, one of those fields located in Europe and another one in South America, both were not fully developed because the high CO₂ and wax content has somehow affected the wells productivity, so that their achieved recovery factor has been very low near 1% of the initial oil in place; their production operations were affected by other factors as pressure depletion, while having a large volume of liquid CO₂ dissolved in the gas cap, those CO₂ volumes instead being flared, might be compressed and injected back into the reservoir.

Challenges for offshore EOR CO₂ injection and CCS projects are more stringent because the higher development costs, the offshore surface facility space, weight and power limitations, the lack of sufficient and economical CO₂ supplies, and fewer existing wells that are more widely spaced. All these factors are added complexity that contribute to uncertain EOR performance and require longer time periods for CO₂ placement to displace oil and gas and achieve adequate sweep efficiency. However, EOR is currently being considered for several offshore developments. The prognosis is better when successful secondary recovery methods have been employed through water and natural gas injection, which make CCS and CO₂ EOR methods much more feasible and less costly to apply.

Some of the key challenges and solutions for offshore CO₂ injection for EOR and CCS projects, include the use of CCS tanker ships and barges to ensure CO₂ supplies and to provide service facilities until the construction of pipelines and construction of permanent facilities is justified. Horizontal well designs may be needed to offset a lower well density and achieve a more uniform sweep and displacement.

Transport of CO₂ from onshore sources to offshore oil and gas fields has been successfully done at several CO EOR projects using pipelines and barges. Tanker ships have successfully and safely transported CO₂ for over twenty years, are best suited for the small volumes needed for pilot CO₂ injection tests; tanker ships that deliver LNG to ports with supplies could carry CO₂ it on their return voyages to economically supply EOR projects (Figures 25 and 26).

Figure 25.

CO2 transport in LNG tankers.

Figure 26.

LNG Tanker ships for CO2 Delivery Offshore EOR projects (OTC 21984).

Some CO₂ activities that are happening in the world are the CO₂ pipeline projects in planning or in construction in several continents, as:

1. A pipeline planned between Mississippi and Texas to supply EOR projects with CO₂ from anthropogenic and natural sources,

2. Two offshore projects for permanent storage of CO, offshore Norway, the Sleipner and Snøhvit CCS projects.

There are at least three CO₂ EOR and enhanced gas recovery (EGR) projects around the world, as:

1. Gas injection in the Bay St. Elaine oil field in the Louisiana marshlands,

2. Dulang field WAG project in Malaysia’s east coast in the South China Sea.,

3. Lula CO₂ offshore Brazil

16. CO₂ capture and injection, costs, and technology

A critical element of a CO₂ capture and storage project is obtaining the CO₂, the technology for separating it from a flue gas, and the business model of who pays, it has been surprising to hear discussions about where the CO₂ is going to come from for capture and storage purposes, and its associated costs, the oil operators being obliged to do carbon capture and storage will look for the cheapest way to obtain CO₂ which would otherwise be vented to the atmosphere. I obvious should be to reinject the captured CO₂ into the depleted oil reservoirs, which should increase the reservoir pressure and in cases helps to increase the oil production and final recovery factors [14, 15].

For the natural CO₂ subsurface reservoirs, the CO₂ is already in the ground, it is not sensible to produce it to storage unless a reasonable use is determined, that can be EOR to increase the oil recovery. Gas wells with high CO₂ should be studied, although they would normally not be produced at all, an option can be to capture the CO₂ and reinject it to enhance the oil recovery and after extracting it, use the reservoir to storage the CO₂.

Flue gases from power stations and energy intensive industries, particularly concrete, steel and oil refining are potential sources. The original assumption for carbon capture and storage was targeted to coal power station flue gases. This proposition in the UK and Netherlands now have the expectation to stop using coal power, which will reduce an important source of CO emission. The UK anticipates continuing to use gas power, the Netherlands anticipates all power generation coming from renewables [16].

The focus to flue gases from energy intensive industries with typically 20 per cent CO₂, that needs to be separated from the 80 per cent of other gases, the amine technology separates the amine molecule attaches to the CO₂ in one column, and the amine is separated from the CO₂ in a second column, cost estimated were reported in range $35 to $69 per tonne of CO₂ captured from a coal power flue gas in India by 2019 [17].

The key measures to report cost of the CCS defined by the Global CCS Institute in 2017 update, defines it as the life cycle unit cost of production and cost per tonne of avoided CO₂. The cost per tonne of CO₂ avoided is a measure that enables comparison across various technology in terms of their value reducing greenhouse gas emissions. The costs for USA reported in 2017 show for flue gas from cement in cost in range 58 to101 US$/tonne; for Iron and steel the cost is reported in 95 to 370 US$/tonne [17].

There have been many efforts over the past 10 years or so to find ways to reduce these costs. One idea is for fuel to be combusted in pure oxygen, with an air separation upstream of the combustion unit, a mature technology, then the flue gas is near entirely CO₂, this option has been studied by Occidental (OXY) (Figure 27).

Figure 27.

Tanker Transporting Oil Cargos a Sources of CO Discharge to the atmosphere.

A great deal of research is going into carbon capture technology, particularly with new solvents. An example is the advances from Occidental Petroleum (OXY) to direct capture and storage CO₂ from the air (DAC): [18].

In 2019, OXY Low Carbon Ventures (OLCV) released a first look of design of the plant to capture up 500 Kt of CO₂ annually directly from air to be used in EOR projects and subsequently stored underground permanently in the Permian Basin, expected to expand to include multiple DAC plants, each capable of capturing one megaton of atmospheric CO₂ annually. If the initial plant is approved by Occidental and Carbon Engineering, construction is expected to begin in 2021, with the plant becoming operational within approximately two years.

On March 28, 2022, Oxy subsidiary (OLCV) and Weyerhaeuser Company (WY) announced an agreement for the evaluation and potential development of a carbon capture and sequestration project in Livingston Parish, Louisiana. The agreement provides OLCV with exclusive rights to develop and operate a carbon sequestration hub on more than 30,000 acres of subsurface pore space controlled by Weyerhaeuser. OLCV will use the land to permanently sequester industrial carbon dioxide (CO₂) in underground geologic formations not associated with oil and gas production, while Weyerhaeuser continues to manage the aboveground acreage as a working forest [18] (Figure 28).

Figure 28.

DAC direct air capture CCA oxy plant.

The agreement, is a pivotal step in OLCV subsidiary 1PointFive’s strategic vision to develop a series of carbon capture and sequestration hubs within the U.S.:

• 1PointFive plans to build, acquire, and operate multiple sequestration hubs on the Gulf Coast and across the U.S., some of which are expected to be anchored by Direct Air Capture (DAC) facilities, to offer storage capacity to point-source emitters, such as manufacturing sites and power plants, with a capacity to sequester up to hundreds of millions of metric tons of anthropogenic CO₂.

• 1PointFive aims to play a transformational role in combatting climate change through industrial decarbonization of the hard-to-abate industrial sector in the U.S.

17. Who pays the CO₂ capture costs?

The question of how to cover the costs of CCS are being discussed for several years, one idea has been the CO₂ utilization using electricity to make hydrogen and using this hydrogen for CO₂ activation towards methanol or methane.

In Europe, emitters of CO₂ are being hit by ever increasing regulatory pressure and costs to dis-incentivize emitting CO₂ to the atmosphere, the costs of CO₂ separation from flue gases would be paid for by emitters. This is the plan of the Rotterdam PORTHOS project, which envisages that energy intensive industries in the Port of Rotterdam would pay themselves for CO₂ capture and storage.

In Europe, the emissions trading scheme covers all land-based emissions (not shipping and aviation), the cost of emitting is not yet close to the cost of CO₂ capture and storage, and is not a stable price, so does not provide enough incentive by itself. The Netherlands and UK Governments are looking provide a subsidy or additional tax, between the carbon price and the cost of carbon capture.

18. CO₂ to enhance the oil production

Research work conducted in slim tube test experiments to investigate the recovery with injection of various gases, such as CO₂, N₂, CH₄, or flue gas, have demonstrated the CO₂ gas injection results in the highest oil recovery factor compared with injection of the other gases.

In water flood secondary recovery projects, after long periods of water injection, a significant amount of oil remains in the reservoir due to the capillary pressure between water and oil. In these cases, the oil recovery can significantly be improved by gas injection in such a way that the gas/oil front moves gravity stable through the reservoir.

If the injected gas and the displaced fluids are moving in gravity stable displacement, substantial incremental oil can be produced; the factors driving the incremental oil production are, reduced interfacial tension for miscible or near miscible displacements at reservoir conditions, gravity drainage for injection of non-miscible gases and improved sweep efficiency for attic oil with stable front moving vertically through the reservoir.

Several gases can be injected in the reservoirs, for a case when methane, CO₂ and N₂ are available, the choice of what gas will be injected depends on the prices of the gases, costs of injection and incremental oil recovery by the respective gas.

18.1 Outlook and growth potential

The current world energy market trend driving the transition to clean energies to replace fossil energies and reduce the CO₂ emissions, implies a progressive reduction of the oil and gas production; at this point some industry observers believe the EOR methods may help offset the predicted decline in oil production over the next twenty years, and the CO₂ EOR may be a substantial portion of the future EOR growth. A key factor for this growth is a sustainable economic supply of technologies and CO₂ for injection where the CCS initiatives might be an important factor.

19. CO₂ EOR field cases Lula Project Brazil

The Lula field is a supergiant ultra-deep water offshore field located in the Santos basin southeast of Brazil, it is the most significant CCS project in Brazil. And Latin America, it is a pre-salt carbonate reservoir in the Santos Basin located below a thick, 2000 m salt column trapping a light, 28–30° API oil with high solution gas ratio (200–300 m³/m³ and variable CO₂ content between 1 to 15%, with neighboured areas with up to 80% of CO₂. The Lula field was developed in phases in the prospective areas of the field defined with extended well tests, production pilots followed by large scale production developments. The pilots provided data to calibrate simulation models, select strategies to maximize recovery and profitability, for the development of other fields in the Santos basin pre-salt blocks.

Early studies showed the oil recovery factor could be greatly improved with secondary and tertiary recovery by implementing a Water-alternating-gas (WAG) injection EOR project chosen because of the availability of seawater, produced gas, and the reservoir conditions particularly suited to miscible methods mixing water and gas. The project that began in 2009 with the arrival of a floating, production, storage, and offloading vessel, followed by the WAG pilot project with three producer wells with one gas injector at about 1.0 million m³/day initiated in April 2011, the facility began exporting some gas to shore and the injection wells began to inject mostly CO₂ at rates of about 35000 m³/day. The pilot was monitored with permanent downhole pressure gauges, and gas injection tracers.

The first results were presented in the SPE155665, concluding the injection of WAG using CO₂ separated from the associated gas in the pilot project as a suitable strategy to increase the oil recovery; the 2012 production and pressure data monitoring of the WAG installation was translated into EOR expansion at the field scale. By December 2018, there were nine production systems (FPSOs) at Santos Basin, with natural gas pre-treatment and CO₂ separation systems using membranes. Since 2013, up to end 2018 around 9.8 million metric tons of CO₂ has been injected, and the projects continue in operation.

This CO₂ pilot project made the Lula field a pioneer in Deepwater CO EOR, Petrobras may set the record as the first company to successfully combine CCS and CO₂ EOR for large-scale, sustained oil production in deep-water (Figure 29).

Figure 29.

CO2 Concentration in the Eastern Bank of Brazil’s Exploration Areas. Source: EPE Empresa de Pesquisa Energetica January 2020.

20. Conclusions

1. The understanding of the feasibility to develop a Miscibility Displacement process at early stages of a field development along with the implementation and economic studies is crucial for any relatively large light oil reservoir.

2. A surveillance program to determine the pressure decline trend as function of produced oil and a sound fluid characterization are paramount to establish an optimum operational pressure aiming to achieve high oil recovery factors.

3. The typical candidate gases for injection are dry or wet natural gases, Nitrogen, CO₂ and flue gas, a product from natural gas combustion; from those gases, the CO₂ has been identified as the more efficient miscible agent based in its property to dissolve the oil.

4. The current trends of Carbon Capture and Storage (CCS) objectives pursued by the industry to reduce the green house effects can be levered with the implementation of more CO₂ miscible injection projects elsewhere the CO₂ is available, as there are several oil fields that have not developed because the hight CO₂ content.

5. The gas injection operations efficiently planned, engineered, implemented, and operated with rational criteria contributes to the reduction of CO₂ emissions.

6. The field case of a multiple contact miscible gas injection project in Venezuela is an example of value destruction by political intervention that has resulted in a large source of CO₂ emissions.

7. The actual intensive trends in Carbon Capture and reductions of CO₂ emissions worldwide are affecting the research and development activity in the oil and gas industry.

8. Brazil has more than 25 years’ experience in carbon dioxide injection for EOR operations, which provides significant experience in the technology for CCS development and deployment. The Energy and Carbon Storage Research Centre in Brazil opened in 2007 promote and explore ways to make CCS commercially viable.

Acknowledgments

Credits for the RESOR and IAGF water and miscible gas injection projects

The implementation of the RESOR water Injection project was initiative of Mss’ Juana Albornoz (deceased) supported by Dr J.P. Chalot and other Lagoven’s professionals, the RESOR team was composed by: Orlando Dumont, Jesus Nunez, Richard Alvarez, Magno Romero, Pascual Marques and Jesus Tineo, the Reservoir Engineering Team was composed by Raul Mengual, Antonio Russo, Luis Ruiz, Jose Gil, Nidia Pinto, Pablo Saavedra, and other professional. In the construction of the simulation models, it was notable the contribution of Dr Pepe Bashbush, and Richard Smith from Intera SRL.

The discovery of the multiple contact miscible injecting dry gas in El Furrial Field was done by Dr Elmond Claridge (deceased) Head of EOR Dept at the University of Houston, Dr Michael Todd and Dr Curtis Chase (deceased) both from TCA reservoir engineering services; the direction of the research project by Julio Herbas, supported by an extended team composed by geoscientist and engineers from Lagoven and Intevep s.a., and audited by a BP Exploration team: Ian Roberts, Dr Shen Tai Lee (deceased), Dr Mike Christie (fluids behaviour), Dr Neville Jones (Geoscientist), Mike Levitan (reservoir simulation), Andy Johnston (Compression Design), and Leon Miura from Lagoven s.a. in charge of the project implementation.

Conflict of interest

The authors wish to confirm that there are no known conflicts of interests associated with this publication and there has been no financial support for this work that could have influenced its outcome.

Acronyms and abbreviations

bbls/day

barrels per day

bbls

barrels

CO₂

Carbon Dioxide

CCS

Carbon capture and Storage

CO

Carbon

C1

Methane CH₄

C2

Ethane C₂H₂

C3

Propane C₃H₈

C4

Butane C₄H₁₀

C5

Pentane C₅H₁₂

C6

Hexane C₆H₁₄

C7

Heptane C₇H₁₆

EOR

Enhanced Oil Recovery

EOS

Equation of State

F

Fahrenheit

FCM

First Contact Miscibility

IAGF

Inyección de Agua y Gas Furrial

MMP

Minimum Miscibility Pressure

mmscf/day

million standard cubic feet per day

M³/m³

cubic meter/cubic meter

N₂

Nitrogen

MCM

Multiple Contact Miscibility

Psia

Pounds per square inch absolute

ppm

parts per million

PVT

Pressure Volume Temperature

Psi

Pounds per square inch

P

Pressure

STOIIP

Stock Tank Oil Initial in Place

T

Temperature