WO2021186202A1

WO2021186202A1 - Method for assessing an enhanced oil recovery process

Info

Publication number: WO2021186202A1
Application number: PCT/IB2020/000287
Authority: WO
Inventors: Arnaud Lager
Original assignee: Total Se
Priority date: 2020-03-19
Filing date: 2020-03-19
Publication date: 2021-09-23

Abstract

The invention relates to a method for assessing an enhanced oil recovery process based on the injection of at least one enhanced oil recovery fluid,in a subterranean formation, said method comprising: - providing a well in the subterranean formation; - injecting an aqueous solution into the subterranean formation from an injection location in the well; - injecting the at least one enhanced oil recovery fluid into the subterranean formation from the injection location in the well, so as to displace at least part of the aqueous solution; - coring the subterranean formation from the injection location in the well, so as to collect a core comprising a flood front of the at least one enhanced oil recovery fluid and a flood front of the displaced aqueous solution and to create a cored hole in the subterranean formation; and - analyzing the collected core, so as to obtain core data,and/or logging the subterranean formation from the cored hole, so as to obtain logging data.

Description

Method for assessing an enhanced oil recovery process

Technical field

The present invention relates to a method for assessing an enhanced oil recovery process in a subterranean formation.

Technical background

Hydrocarbons in an underground reservoir can be recovered or produced by means of one or more wells drilled in the reservoir. Before production begins, the formation (a porous medium) is saturated with hydrocarbons.

The initial recovery of hydrocarbons is generally carried out by techniques of “primary recovery", in which only the natural forces present in the reservoir are relied upon. In this primary recovery, only part of the hydrocarbons is ejected from the pores by the pressure of the formation. Typically, once the natural forces are exhausted and primary recovery is completed, water or gas is injected for maintaining the pressure in the reservoir and recovering more hydrocarbons as “secondary recovery’. Usually there is still a large volume of hydrocarbons left in the reservoir, generally more than two thirds, at the end of the “secondary recovery’.

This phenomenon has been known for a long time and has led to the development of many techniques of enhanced oil recovery (EOR). Many of these techniques rely on the injection of a fluid into the underground reservoir (or subterranean formation) in order to produce an additional quantity of e.g. crude oil. The fluid used can be water, steam, carbon dioxide, natural gas, nitrogen, etc.

However, each subterranean formation is unique and its behavior in response to a particular EOR process may not be predictable. Therefore, before implementing an EOR technique in a subterranean formation, it is necessary to carry out tests to evaluate its effectiveness in said subterranean formation.

Such tests are generally performed in multi-well pilots. The EOR fluid to be tested is injected in an injection well of the pilot and oil is retrieved in a production well of the pilot several years after the injection. Such tests are thus very time- consuming (for example, it may take 2 years to prepare the pilot and 3 to 5 years to carry out the test). Moreover, the building of these pilots is expensive and may cost from tens to hundreds of millions of dollars. Some test methods using a single well have also been disclosed.

Document US 4,168,746 describes a method for evaluating an EOR process comprising determining hydrocarbon saturation near a well bore, injecting a mobilizing fluid to move hydrocarbons and determining the hydrocarbon saturation by a tracer method, said tracer method comprising injecting two slugs of water containing a primary tracer separated by a slug of water without any tracer.

Document WO 2014/022611 describes a method for evaluating the effectiveness of an EOR agent in a formation, from a well comprising a non vertical portion, comprising injecting an EOR agent into a subterranean formation in an injection interval of the well, producing fluid from a production interval of the well and obtaining logging data regarding the formation, the EOR agent or the produced fluid.

Document US 7,784,539 describes a method for testing a formation treatment in a subterranean formation wherein a treatment fluid is injected in an injector borehole and production fluids are produced in a producer borehole, said injector borehole and producer borehole being two horizontal branches of a single well. Downhole devices are used to determine the effectiveness of the sweep between the boreholes.

Document US 8,593,140 describes a method for evaluating a formation comprising lowering a downhole tool in a wellbore, injecting a fluid into the formation using the downhole tool, and using a formation evaluation sensor to perform measurements close to the injection zone. The downhole tool may comprise a drilling or coring tool for perforating an impermeable mudcake that may isolate the wellbore from the formation, for example over a length of 15 cm. In such a method, only a very small amount of fluid is injected into the formation.

There is a need for an efficient method for assessing an enhanced oil recovery process based on the injection of at least one enhanced oil recovery fluid, in a subterranean formation, that is simpler, more economical and quicker.

Summary of the invention

It is a first object of the invention to provide a method for assessing an enhanced oil recovery process based on the injection of at least one enhanced oil recovery fluid, in a subterranean formation, said method comprising:

- providing a well in the subterranean formation;

- injecting an aqueous solution into the subterranean formation from an injection location in the well; - injecting the at least one enhanced oil recovery fluid into the subterranean formation from the injection location in the well, so as to displace at least part of the aqueous solution;

- coring the subterranean formation from the injection location in the well, so as to collect a core comprising a flood front of the at least one enhanced oil recovery fluid and a flood front of the displaced aqueous solution and to create a cored hole in the subterranean formation; and

- analyzing the collected core, so as to obtain core data, and/or logging the subterranean formation from the cored hole, so as to obtain logging data.

In some embodiments, the step of providing a well in the subterranean formation comprises drilling a well in the subterranean formation.

In some embodiments, the aqueous solution has a salinity higher than or equal to 0.1 g/L.

In some embodiments, the aqueous solution is produced water or sea water.

In some embodiments, the at least one enhanced oil recovery fluid is selected from the group consisting of brines having a different composition from that of the aqueous solution, surfactant formulations, polymer compositions, gas, foams, steam, microbial broths, and combinations thereof.

In some embodiments, logging the subterranean formation comprises measuring the resistivity of the subterranean formation; and/or measuring neutron absorption by the subterranean formation; and/or analyzing the collected core comprises washing the collected core with a solvent so as to retrieve the fluids contained in said core and measuring the amount of hydrocarbons and/or EOR fluids.

In some embodiments, the well comprises an essentially vertical part extending in the subterranean formation from the surface of the subterranean formation and an essentially horizontal part extending in the subterranean formation from the essentially vertical part.

In some embodiments, the essentially horizontal part of the well is a barefoot hole.

In some embodiments, the step of coring the subterranean formation is carried out in an essentially horizontal direction.

In some embodiments, at least 100 m³, preferably from 1 ,000 to 20,000 m³, of the aqueous solution are injected into the subterranean formation from the injection location in the well. In some embodiments, at least 100 m³ preferably from 1 ,000 to 20,000 m³, of the at least one enhanced oil recovery fluid are injected into the subterranean formation from the injection location in the well.

In some embodiments, the collected core has a diameter of from 5 to 40 cm and/or a length of from 5 to 60 m.

In some embodiments, the core comprises an end corresponding to the well wall and analyzing the collected core comprises analyzing a first part of the core, comprised between the flood front of the at least one enhanced oil recovery fluid and the flood front of the displaced aqueous solution, so as to obtain core data for said first part of the core, and analyzing a second part of the core, comprised between the end of the core corresponding to the well wall and the flood front of the at least one enhanced oil recovery fluid, so as to obtain core data for said second part of the core.

In some embodiments, logging the subterranean formation comprises logging a first part of the subterranean formation from a portion of the cored hole comprised between the flood front of the at least one enhanced oil recovery fluid and the flood front of the displaced aqueous solution, so as to obtain logging data for said first part of the subterranean formation, and logging a second part of the subterranean formation from a portion of the cored hole comprised between the well wall and the flood front of the at least one enhanced oil recovery fluid, so as to obtain logging data for said second part of the subterranean formation.

In some embodiments, the method further comprises comparing the core data for the first part of the core with the core data for the second part of the core and/or comparing the logging data for the first part of the subterranean formation with the logging data for the second part of the subterranean formation.

In some embodiments, the step of coring the subterranean formation is carried out using a low invasion coring process.

In some embodiments, during the step of coring the subterranean formation, the core is collected in a plurality of individual core sections, wherein preferably each core section has a length of from 1 to 15 m.

The present invention enables to meet the abovementioned need. In particular the invention provides a simple method for assessing an enhanced oil recovery process based on the injection of at least one EOR fluid, in a subterranean formation, that may be performed using a single well. Moreover, this method is relatively economical (it may cost less than one million dollars) and may be carried out over a short period of time, such as over from a few weeks to a few months. The invention also provides an efficient assessing method making it possible to determine the residual oil saturation (SOR) in the formation zone swept by the EOR fluid, the injectivity of the EOR fluid, the adsorption of potential chemicals contained in the EOR fluid in the rock of the formation and/or the longitudinal dispersion of the EOR fluid flood front.

This is achieved by injecting an aqueous solution into the formation and then at least one EOR fluid so as to displace at least part of the aqueous solution and by coring the formation through at least the zone swept by the EOR fluid and by the displaced aqueous solution so that the core contained both the flood front of the at least one EOR fluid and the flood front of the displaced aqueous solution.

Brief description of the drawings

Figure 1 illustrates a step of an example of method according to the invention.

Figure 2 illustrates another step of the example of method according to the invention.

Figure 3 illustrates another step of the example of method according to the invention.

Figure 4 illustrates another step of the example of method according to the invention.

Detailed description

The invention will now be described in more detail without limitation in the following description.

The invention relates to method for assessing an enhanced oil recovery process based on the injection of at least one enhanced oil recovery fluid, in a subterranean formation, said method comprising: providing a well in the subterranean formation; injecting an aqueous solution into the subterranean formation from an injection location in the well; injecting the at least one enhanced oil recovery fluid into the subterranean formation from the injection location in the well, so as to displace at least part of the aqueous solution; coring the subterranean formation from the injection location in the well, so as to collect a core comprising a flood front of the at least one enhanced oil recovery fluid and a flood front of the displaced aqueous solution and to create a cored hole in the subterranean formation; and analyzing the collected core, so as to obtain core data, and/or logging the subterranean formation from the cored hole, so as to obtain logging data.

When injecting an aqueous solution into the subterranean formation, a zone of the subterranean formation is swept by said aqueous solution. This zone swept by the aqueous solution is delimited by the flood front of the aqueous solution, i.e. the flood front of the aqueous solution is the interface between the zone of the subterranean formation that is swept by the aqueous solution and the subterranean formation that is not swept by the aqueous solution.

When the enhanced oil recovery fluid is injected into the subterranean formation, a zone of the subterranean formation is swept by said enhanced oil recovery fluid and at least part of the aqueous solution in the subterranean formation is displaced by the enhanced oil recovery fluid. The zone of the subterranean formation swept by the enhanced oil recovery fluid is delimited by the flood front of the EOR fluid, i.e. the flood front of the EOR fluid is the interface between the zone of the subterranean formation that is swept by the EOR fluid and the subterranean formation that is not swept by the EOR fluid. The displacement of at least a part of the aqueous solution by the EOR fluid results in the formation of a new flood front of the aqueous solution, called herein the flood front of the displaced aqueous solution.

The coring step is carried out from the injection point through a zone swept by the EOR fluid and by the displaced aqueous solution, until reaching a zone of the subterranean formation that was not swept by either the EOR fluid or the aqueous solution, so as to recover a core comprising a flood front of the at least one enhanced oil recovery fluid and a flood front of the displaced aqueous solution.

EOR process

The method of the invention aims at assessing an EOR process in a subterranean formation. The EOR process is a process for extracting hydrocarbons from a subterranean formation. The EOR process is based on the injection of at least one enhanced oil recovery fluid into the subterranean formation, i.e. said process comprises a step of injecting said EOR fluid into the subterranean formation, wherein the EOR fluid makes it possible to displace hydrocarbons present in the subterranean formation. The EOR process also comprises a step of collecting displaced hydrocarbons from the subterranean formation. Hydrocarbons in gaseous and/or liquid phase may be recovered from the subterranean formation. Preferably, hydrocarbon recovery includes oil recovery .

The subterranean formation may be a carbonated reservoir.

The temperature within the subterranean formation may range from 25 to 140°C, preferably from 80 to 140°C and more preferably from 100 to 120°C.

Step of providing a well

The step of providing a well may comprise drilling a well in the subterranean formation. Alternatively, an existing well may be used.

The well may be drilled totally or partially, that is to say the well may be drilled form the surface of the subterranean formation or an additional hole may be drilled from an existing well.

Preferably, the well comprises an essentially vertical part (i.e. an essentially vertical hole) extending from the surface of the subterranean formation.

Advantageously, the well also comprises an essentially horizontal part (i.e. an essentially horizontal hole) extending from said essentially vertical part. The essentially horizontal part may extend from the bottom end of the essentially vertical part or from any depth in the essentially vertical part. The well may comprise several essentially horizontal parts (or branches) extending from the essentially vertical part but, preferably, contains only one essentially horizontal part. The presence of an essentially horizontal part has the advantage of making it possible to inject a fluid in higher amounts: for a given pressure of injection, more fluid will be injected into the subterranean formation from an essentially horizontal part of a well than from an essentially vertical part of a well (be it the aqueous solution or the EOR fluid). Moreover, it is easier to perform the coring step from an essentially horizontal part of a well than from an essentially vertical part of a well.

Advantageously, the well consists of an essentially vertical part extending from the surface of the subterranean formation and an essentially horizontal part extending from said essentially vertical part.

The essentially horizontal part may have a length of from 10 to 300 m.

In less preferred embodiments, the well may be essentially vertical.

The well may comprise a completion. By “completion" is meant any installation or element installed into the well that connects the reservoir to the surface so that the reservoir fluids can be produced from or injected into the reservoir whilst at the same time protects the integrity of the reservoir and isolate the producing reservoir from other permeable zones. The well may comprise an uphole completion or/and a downhole completion.

The completion may include tubing, casings, liners, cement and/or smart completions.

The well can comprise a completion on its whole length or only on a section of said well.

The well may alternatively be a barefoot hole, or the well may comprise a barefoot section (that is to say, a section that is a barefoot hole).

By “barefoot hole" is meant that the hole does not comprise any completion.

Preferably, the well comprises at least a section comprising a completion and at least a barefoot section.

When the well comprises, or consists of, an essentially vertical part extending from the surface of the subterranean formation, this essentially vertical part may comprise a completion, on the whole length of the essentially vertical part or on a section of the essentially vertical part, and/or may comprise a barefoot section or be a barefoot hole.

When the well comprises an essentially horizontal part, this essentially horizontal part may comprise a completion, on the whole length of the essentially horizontal part or on a section of the essentially horizontal part, and/or may comprise a barefoot section or be a barefoot hole.

Preferably, when the well comprises, or consists of, an essentially vertical part extending from the surface of the subterranean formation and an essentially horizontal part extending from said essentially vertical part, the essentially vertical part comprises a completion, preferably on the whole length of the essentially vertical part, and the essentially horizontal part comprises a barefoot section, preferably is a barefoot hole.

Injection of an aqueous solution

The method of the invention comprises a step of injecting an aqueous solution into the subterranean formation.

Preferably, the aqueous solution has a salinity higher than or equal to 0.1 g/L, and more preferably up to 300 g/L. Such an aqueous solution may also be called “high salinity aqueous solution" in the present text.

Salinity is defined herein as the total concentration of dissolved inorganic salts in the aqueous solution, preferably in water, including e.g. NaCI, CaC , MgCl2 and any other inorganic salts. The salinity of all fluids mentioned in the present text may be measured using a conductivity probe and is expressed as g/L of Total Dissolved Solids. The aqueous solution (for example the high salinity aqueous solution) may be a brine, such as produced water and/or sea water (in particular if the well is an offshore well).

By “produced water^*’ is meant water that is recovered from one or more production wells after injection of water (preferably in the liquid form and optionally in combination with chemicals) into a subterranean formation via one or more injection wells in order to produce an additional quantity of hydrocarbons, e.g. crude oil.

Preferably, the aqueous solution has a salinity from 0.1 to 300 g/L, more preferably from 35 to 200 g/L. For example, the aqueous solution may have a salinity from 0.1 to 5 g/L; or from 5 to 10 g/L; or from 10 to 15 g/L; or from 15 to 20 g/L; or from 20 to 25 g/L; or from 25 to 30 g/L; or from 30 to 35 g/L; or from 35 to 40 g/L; or from 40 to 45 g/L; or from 45 to 50 g/L; or from 50 to 55 g/L; or from 55 to 60 g/L; or from 60 to 65 g/L; or from 65 to 70 g/L; or from 70 to 75 g/L; or from 75 to 80 g/L; or from 80 to 85 g/L; or from 85 to 90 g/L; or from 90 to 95 g/L; or from 95 to 100 g/L; or from 100 to 105 g/L; or from 105 to 110 g/L; or from 110 to 115 g/L; or from 115 to 120 g/L; or from 120 to 125 g/L; or from 125 to 130 g/L; or from 130 to 135 g/L; or from 135 to 140 g/L; or from 140 to 145 g/L; or from 145 to 150 g/L; or from 150 to 160 g/L; or from 160 to 170 g/L; or form 170 to 180 g/L; or from 180 to 190 g/L;, or from 190 to 200 g/L; or from 200 to 220 g/L; or from 220 to 240 g/L; or from 240 to 260 g/L; or from 260 to 280 g/L; or from 280 to 300 g/L.

The aqueous solution may comprise ions such as sodium and/or calcium and/or magnesium, mostly in the form of bicarbonates, sulfates and chlorides.

Therefore, the aqueous solution may comprise equal to or more than 60 ppm by weight of Ca²⁺, preferably equal to or more than 80 ppm by weight of Ca²⁺, more preferably equal to or more than 100 ppm by weight of Ca²⁺, more preferably equal to or more than 120 ppm by weight of Ca²⁺, more preferably equal to or more than 140 ppm by weight of Ca²⁺, more preferably equal to or more than 180 ppm by weight of Ca²⁺, more preferably equal to or more than 200 ppm by weight of Ca²⁺, more preferably equal to or more than 250 ppm by weight of Ca²⁺, more preferably equal to or more than 500 ppm by weight of Ca²⁺, and even more preferably equal to or more than 1000 ppm by weight of Ca²⁺.

Furthermore, the aqueous solution may comprise equal to or more than 60 ppm by weight of Mg²⁺, preferably equal to or more than 80 ppm by weight of Mg²⁺, more preferably equal to or more than 100 ppm by weight of Mg²⁺, more preferably equal to or more than 120 ppm by weight of Mg²⁺, more preferably equal to or more than 140 ppm by weight of Mg²⁺, more preferably equal to or more than 180 ppm by weight of Mg²⁺, more preferably equal to or more than 200 ppm by weight of Mg²⁺, more preferably equal to or more than 300 ppm by weight of Mg²⁺, and even more preferably equal to or more than 400 ppm by weight of Mg²⁺.

The aqueous solution may comprise equal to or more than 60 ppm by weight of Na⁺, preferably equal to or more than 80 ppm by weight of Na⁺, more preferably equal to or more than 100 ppm by weight of Na⁺, more preferably equal to or more than 120 ppm by weight of Na⁺, more preferably equal to or more than 140 ppm by weight of Na⁺, more preferably equal to or more than 180 ppm by weight of Na⁺, more preferably equal to or more than 200 ppm by weight of Na⁺, more preferably equal to or more than 300 ppm by weight of Na⁺, and even more preferably equal to or more than 400 ppm by weight of Na⁺.

The injection is carried out from an injection location in the well that may be any location in the well. Preferably, the injection location is located near or at an end of the well. In particular, when the well comprises an essentially horizontal part, said essentially horizontal part comprises a proximal end (i.e. an end on the side of the part of the well from which the essentially horizontal part extends) and a distal end (i.e. an end distant from the part of the well from which the essentially horizontal part extends) and the injection location is located near or at the distal end of the essentially horizontal part.

The aqueous solution may be injected into the subterranean formation by any means making it possible to inject a fluid into a reservoir. Such means are well known to the skilled person. In particular, the aqueous solution may be injected using a rig, such as the rig used to drill the well, or a pumping installation.

The aqueous solution may be conveyed to the injection location in the well by any means, for example by any piece of tubing.

Advantageously, the aqueous solution is injected into the subterranean formation in an amount of at least 100 m³, preferably in an amount of from 1 ,000 to 20,000 m³ such as from 1 ,000 to 2,000 m³. The amount of aqueous solution injected into the subterranean formation may be from 100 to 300 m³; or from 300 to 500 m³; or from 500 to 800 m³; or from 800 to 1 ,000 m³; or from 1 ,000 to 1 ,200 m³; or from 1 ,200 to 1 ,500 m³; or from 1 ,500 to 1 ,800 m³; or from 1 ,800 to 2,000 m³; or from 2,000 to 2,500 m³; or from 2,500 to 3,000 m³; or from 3,000 to 3,500 m³; or from 3,500 to 4,000 m³; or from 4,000 to 4,500 m³; or from 4,500 to 5,000 m³; or from 5,000 to 5,500 m³; or from 5,500 to 6,000 m³; or from 6,000 to 6,500 m³; or from 6,500 to 7,000 m³; or from 7,000 to 7,500 m³; or from 7,500 to 8,000 m³; or from 8,000 to 8,500 m³; or from 8,500 to 9,000 m³; or from 9,000 to 9,500 m³; or from 9,500 to 10,000 m³; or from 10,000 to 12,000 m³; or from 12,000 to 15,000 m³; or from 15,000 to 18,000 m³; or from 18,000 to 20,000 m³.

Preferably, the injected aqueous solution will displace hydrocarbons present in the subterranean formation (and more particularly present in the zone of the subterranean formation swept by the aqueous solution).

Injection of an EOR fluid

The method of the invention comprises a step of injecting at least one enhanced oil recovery fluid into the subterranean formation. According to the present invention, this step is performed after the step of injecting an aqueous solution.

Preferably, the EOR fluid is selected from the group consisting of brines having a different composition from that of the aqueous solution described above, surfactant formulations, polymer compositions, gas, foams, steam, microbial broths, and combination thereof.

The EOR fluid may be a brine having a different composition from that of the aqueous solution, in particular if the aqueous solution is a high salinity aqueous solution. Thus, the brine may have one or more components that are different from those of the aqueous solution, and/or the brine may have one or more components in an amount different from that of the same components in the aqueous solution and/or the brine may have a salinity different from that of the aqueous solution, preferably a lower salinity.

The EOR fluid may be a brine having a salinity lower than or equal to 40g/L, preferably from 0.1 to 40 g/L, more preferably from 1 to 10 g/L. In particular, the salinity of the EOR fluid may be from 0.1 to 1 g/L; or from 1 to 2 g/L; or from 2 to 5 g/L; or from 5 to 10 g/L; or from 10 to 15 g/L; or from 15 to 20 g/L; or from 20 to 25 g/L; or from 25 to 30 g/L; or from 30 to 35 g/L; or from 35 to 40 g/L. The salinity of the EOR fluid may be at least 10 g/L below that of the aqueous solution ; or at least 20 g/L; or at least 30 g/L; or at least 40 g/L; or at least 50 g/L; or at least 60 g/L; or at least 70 g/L; or at least 80 g/L; or at least 90 g/L; or at least 100 g/L below that of the aqueous solution.

The EOR fluid may be a surfactant formulation, preferably an aqueous solution comprising at least one surfactant. The surfactant formulation may lower the interfacial tension between crude oil and water down to or lower than 0.01 mN/m. The surfactant formulation may also comprise one or more additives. Such additives may include one or more polymers, such as those described below and/or mobility control polymers, salts, sacrificial agents, pH adjustment agents, solvents and mixtures thereof. The EOR fluid may be a polymer composition, preferably an aqueous solution comprising at least one polymer. The polymer may be chosen from hydrolyzed polyacrylamide, partially hydrolyzed polyacrylamide, poly-N,N- dimethylacrylamide, polyvinyl pyrrolidone, poly(vinylamines), poly(2-acrylamido- 2-methyl-1-propanesulfonic acid), biopolymers such as scleroglucans and xanthan gum, hydrophobically-modified associative polymers, co-polymers of polyacrylamide, 2-acrylamido 2-methylpropane sulfonic acid, and N-vinyl pyrrolidone. Preferably, the total concentration of polymers in the polymer composition is from 100 to 10000 ppm, preferably from 500 to 2500 ppm (w/v). The polymer composition may also comprise one or more additives. Such additives may include one or more surfactants, salts, sacrificial agents, mobility control polymers, pH adjustment agents, solvents and mixtures thereof.

The EOR fluid may be a gas, preferably selected from the group consisting of carbon dioxide, natural gas, nitrogen, hydrogen sulfide and combination thereof.

The EOR fluid may be a foam. By “foam" is meant a dispersion of a gas in a continuous water phase. Preferably the foam is a carbon dioxide/water emulsion or nitrogen/water emulsion. The foam may also comprise one or more additives, including salts, sacrificial agents, mobility control polymers, pH adjustment agents, solvents and mixtures thereof.

The EOR fluid may be a microbial broth. By “microbial broth" is meant a liquid medium containing one or more microorganisms and nutrients for the culture of said microorganisms.

The EOR fluid is preferably injected from the injection location in the well. Therefore, the EOR fluid is injected from the same location as was the aqueous solution.

The EOR fluid may be injected into the subterranean formation by any means, such as a rig or a pumping installation. The means for injecting the EOR fluid may be the same as the means for injecting the aqueous solution.

The EOR fluid may be conveyed in the well, preferably to the injection location in the well, by any means, for example by any piece of tubing, in particular by the same pieces of tubing as the aqueous solution.

Preferably, the EOR fluid is injected into the subterranean formation in an amount of at least 100 m³, more preferably in an amount of from 1 ,000 to 20,000 m³ such as from 1 ,000 to 2,000 m³. The amount of EOR fluid injected into the subterranean formation may be from 100 to 300 m³; or from 300 to 500 m³; or from 500 to 800 m³; or from 800 to 1 ,000 m³; or from 1 ,000 to 1 ,200 m³; or from 1 ,200 to 1 ,500 m³; or from 1 ,500 to 1 ,800 m³; or from 1 ,800 to 2,000 m³; or from 2,000 to 2,500 m³; or from 2,500 to 3,000 m³; or from 3,000 to 3,500 m³; or from

3.500 to 4,000 m³; or from 4,000 to 4,500 m³; or from 4,500 to 5,000 m³; or from

5,000 to 5,500 m³; or from 5,500 to 6,000 m³; or from 6,000 to 6,500 m³; or from

6.500 to 7,000 m³; or from 7,000 to 7,500 m³; or from 7,500 to 8,000 m³; or from

8,000 to 8,500 m³; or from 8,500 to 9,000 m³; or from 9,000 to 9,500 m³; or from

9.500 to 10,000 m³; or from 10,000 to 12,000 m³; or from 12,000 to 15,000 m³; or from 15,000 to 18,000 m³; or from 18,000 to 20,000 m³.

The amount of EOR fluid injected into the subterranean formation may be the same as the amount of aqueous solution injected into the subterranean formation, or may be higher, or may be lower than the amount of aqueous solution injected into the subterranean formation.

The injected EOR fluid will displace at least part of the aqueous solution in the subterranean formation. The injected EOR fluid preferably also displaces hydrocarbons present in the subterranean formation (and more particularly present in the zone of the subterranean formation swept by the EOR fluid).

The method of the invention may comprise injecting into the subterranean formation more than one EOR fluid (preferably different EOR fluids), such as at least 2 EOR fluids, or at least 3 EOR fluids, or at least 4 EOR fluids, or at least 5 EOR fluids, for example from 2 to 3 EOR fluids, or from 3 to 4 EOR fluids, or from 4 to 5 EOR fluids, or from 5 to 6 EOR fluids, or from 6 to 7 EOR fluids, or from 7 to 8 EOR fluids, or from 8 to 9 EOR fluids, or from 9 to 10 EOR fluids, or from 10 to 12 EOR fluids, or from 12 to 15 EOR fluids, or from 15 to 20 EOR fluids. Preferably, the EOR fluids are injected into the subterranean formation one after the other, preferably from the injection location in the well, thus from the same location as was the aqueous solution. Each of the EOR fluid may independently be as described above. When more than one EOR fluid are used, each of the EOR fluids may independently be injected in the amounts described above, or the totality of the injected EOR fluids may be in the amounts described above.

When more than one EOR fluid are injected, each EOR fluid injection will result in a zone swept by said EOR fluid delimited by the flood front of said EOR fluid. In addition, each EOR fluid injection subsequent to the first EOR fluid injection will displace at least part of the EOR fluids that were previously injected and at least part of the aqueous solution and will displace the flood front of these fluids. Each injected EOR fluid preferably also displaces hydrocarbons present in the subterranean formation (and more particularly present in the zone of the subterranean formation swept by said EOR fluid).

Coring of the subterranean formation The method of the invention comprises a step of coring the subterranean formation from the injection location in the well.

Advantageously, the coring is carried out in an essentially horizontal direction.

When the well comprises an essentially horizontal part, the coring is preferably carried out from the distal end of the essentially horizontal part. More preferably, the coring is carried out as the continuation of the essentially horizontal part, i.e. the coring is carried out starting from the distal end of the essentially horizontal part, in the same direction as the main direction of the essentially horizontal part.

A coring from a horizontal (or essentially horizontal) part of a well is easier than from a vertical (or essentially vertical) part of a well.

However, the coring may alternatively be carried out from an essentially vertical part of the well, in particular if the well is essentially vertical. The coring step may thus be carried out from a sidewall of the well by making a sidetrack.

The coring step may be carried out, for example, by using a core barrel equipped with a core bit and a core catcher. The core may thus be collected into the core barrel and brought to the surface of the subterranean formation. A coring fluid may also be used in the coring step.

The coring step may be carried out using a low invasion coring process. This makes it possible to reduce the contamination of the core by drilling mud, especially the coring fluid. As an example of low invasion coring process, the coring step may be performed such that the pressure of the drilling mud (the coring fluid) is close to the pressure in the formation. Thus, the differential pressure between the mud and the formation is low and the mud is not pushed into the formation and remains in the well.

The collected core consists of a sample of rock of the subterranean formation. Preferably, it has a cylindrical shape. The core collected from the coring step may be a single piece or may be constituted of several individual pieces of core, for example from 2 to 10. Indeed, depending of the total length of the core that has to be collected, it can be more convenient to retrieve the core in a plurality of individual core sections, the core being collected section by section. Each individual core section may independently have a length of from 0.5 to 20 m, preferably from 1 to 15 m, more preferably from 5 to 12 m, such as about 10 m. The individual core sections may all have the same length, or essentially the same length, or may have different lengths.

The core (in its entirety) has advantageously a length of from 5 to 60 m, preferably from 10 to 50 m, for example from 5 to 10 m; or from 10 to 20 m; or from 20 to 30 m; or from 30 to 40 m; or from 40 to 50 m; or from 50 to 60 m (with the understanding that if the core is divided into several individual core sections, these lengths represent the sum of the lengths of the individual core sections forming the core).

The core (or each individual core section) may have a diameter of from 5 to 40 cm, preferably form 5 to 20 cm, for example from 5 to 10 cm; or from 10 to 15 cm; or from 15 to 20 cm; or from 20 to 25 cm; or from 25 to 30 cm; or from 30 to 35 cm; or from 35 to 40 cm.

The coring step is performed from the injection location in the well, through the zone of the subterranean formation swept by the different fluids, optionally displaced, that were injected into the subterranean formation (i.e. the one or more EOR fluids and the aqueous solution), until reaching a non-swept zone in the formation. The coring step is thus performed through the whole swept zone of the formation extending from the injection location along the direction of the coring.

The core which is collected therefore contains a flood front of each injected (and optionally displaced) EOR fluids and a flood front of the displaced aqueous solution. The core which is collected has a first end corresponding to the well wall.

The retrieval of the core from the subterranean formation leaves a hole in said subterranean formation (called “cored hole" in the present text).

Logging of the core

The method of the invention comprises a step of analyzing the collected core, so as to obtain core data.

Alternatively, or in addition, the method of the invention comprises a step of logging the subterranean formation from the cored hole, so as to obtain logging data.

Preferably, before being analyzed, the core, or the individual core sections, are cut into slices. Preferably, core data are separately obtained for each slice. The slices may have a length of from 1 m to 5 m.

The core might comprise a zone on its periphery damaged by the coring step, for example contaminated by drilling muds. This zone may be disregarded for the recording of the core data.

The analyzing step may comprise washing the collected core (be it cut into slices or not) with a solvent so as to retrieve fluids contained in the core. Preferably, the core is cut into slices and each slice is individually washed with the solvent. By “washing the core with a solvent’ is meant that a solvent is introduced into the pores of the core so as to displace the fluids contained therein out of the core.

The fluids retrieved from the core may in particular be hydrocarbons and/or EOR fluid(s) (or part of them) and/or the aqueous solution (or part of it).

Then, the amount of hydrocarbons in the retrieved fluids is measured. Preferably, the amount of the retrieved fluids other than the hydrocarbons is measured. Preferably, these amounts are measured for each slice of core. The smaller the amount of hydrocarbons contained in the retrieved fluids is, the larger the amount of hydrocarbon displacement by the other fluids in the subterranean formation is.

When the at least one EOR fluid that is injected into the subterranean formation contains at least one chemical, such as one or more surfactants and/or one or more polymers, the analyzing step may comprise measuring the concentration of said chemical in the fluids, in particular water, retrieved after washing the core with a solvent, as described above, so as to obtain chemical concentration core data, in particular for portions of the core at and/or near the flood front of the EOR fluid.

When the at least one EOR fluid that is injected into the subterranean formation contains at least one chemical, such as one or more surfactants and/or one or more polymers, the analyzing step may comprise measuring the amount of said chemical that is adsorbed in the core. This logging step may comprise a step of extracting the chemical that is adsorbed in the core after washing the core with a solvent to retrieve the fluids contained in the core, as described above. The measurement of the amount of chemical is carried out after this extracting step.

The measurement of the amount of adsorbed chemical may be carried out by Dean Stark extraction or Soxhlet extraction.

When the at least one EOR fluid that is injected into the subterranean formation is a brine, the analyzing step may comprise measuring the salinity of the fluids, in particular water, retrieved after washing the core with a solvent, as described above, so as to obtain salinity core data, in particular for portions of the core at and/or near the flood front of the EOR fluid.

This measurement may be carried out using a resistivity logging tool.

The logging step may comprise measuring the electrical resistivity of the subterranean formation, preferably from the cored hole, so as to obtain resistivity logging data.

The measurement of the resistivity in the subterranean formation makes it possible to assess the amount of hydrocarbons in the portion of the subterranean formation the resistivity of which is measured. Indeed, hydrocarbons are poor conductors of electricity and therefore exhibit high resistivity whereas water, in particular salty water, is a good conductor of electricity and exhibits low electrical resistivity. Thus, for a formation having a given rock composition, the more hydrocarbons the formation contains, the more resistive the formation is; and the more water it contains, the less resistive it is.

The resistivity of the subterranean formation may be measured using a dielectric logging tool.

The logging step may comprise measuring neutron absorption by the subterranean formation, so as to obtain neutron absorption logging data.

The measurement of neutron absorption by the subterranean formation makes it possible to assess the amount of hydrocarbons in the portion of the subterranean formation the neutron absorption of which is measured. For a formation having a given rock composition, the more hydrocarbons the formation contains, the higher neutron absorption is.

The neutron absorption by the subterranean formation may be measured using a pulse neutron logging tool.

Only one logging or analyzing process, such as those described above, may be carried out or any combination of various logging and/or analyzing processes, such as those described above, may be carried out. If several logging and/or analyzing processes are performed, they may be performed in any order.

Advantageously, the analyzing step comprises analyzing a first part of the core, comprised between the flood front of the at least one EOR fluid and the flood front of the displaced aqueous solution, so as to obtain core data for said first part of the core, and analyzing a second part of the core, comprised between the end of the core corresponding to the well wall and the flood front of the at least one EOR fluid, so as to obtain core data for said second part of the core. Thus, the first part of the core corresponds to a part of the core that was swept by the (displaced) aqueous solution and the second part of the core corresponds to a part of the core that was swept by the EOR fluid.

Said first and second parts of the core may independently consist of one or more slices of core.

When more than one EOR fluid are injected into the subterranean formation, the analyzing step may comprise analyzing a first part of the core, comprised between the flood front of the first injected EOR fluid and the flood front of the displaced aqueous solution, so as to obtain core data for said first part of the core, analyzing a part of the core comprised between each of the flood fronts of the injected EOR fluids, so as to obtain core data for these parts, and analyzing a part comprised between the end of the core corresponding to the well wall and the flood front of the last injected EOR fluid, so as to obtain core data for said part of the core. Therefore, the first part of the core corresponds to a part of the core that was swept by the (displaced) aqueous solution and the other parts correspond to a part of the core swept by an EOR fluid. All these parts of the core may independently consist of one or more slices of core.

The logging step may comprise logging a first part of the subterranean formation from a portion of the cored hole comprised between the flood front of the at least one enhanced oil recovery fluid and the flood front of the displaced aqueous solution, so as to obtain logging data for said first part of the subterranean formation, and logging a second part of the subterranean formation from a portion of the cored hole comprised between the well wall and the flood front of the at least one enhanced oil recovery fluid, so as to obtain logging data for said second part of the subterranean formation. Thus, the first part of the subterranean formation corresponds to a part of the subterranean formation that was swept by the (displaced) aqueous solution and the second part of the subterranean formation corresponds to a part of the subterranean formation that was swept by the EOR fluid.

When more than one EOR fluid are injected into the subterranean formation, the logging step may comprise logging a first part of the subterranean formation, comprised between the flood front of the first injected EOR fluid and the flood front of the displaced aqueous solution, so as to obtain logging data for said first part of the subterranean formation, logging a part of the core comprised between each of the flood fronts of the injected EOR fluids, so as to obtain logging data for these parts, and logging a part comprised between the well wall and the flood front of the last injected EOR fluid, so as to obtain logging data for said part of the subterranean formation. Therefore, the first part of the subterranean formation corresponds to a part of the subterranean formation that was swept by the (displaced) aqueous solution and the other parts correspond to a part of the subterranean formation swept by an EOR fluid.

Evaluation of the effectiveness of the EOR process

The effectiveness of the enhanced oil recovery process may be evaluated based on the core data and/or the logging data.

The injection of the aqueous solution (for example the high salinity aqueous solution) enables to set up a baseline to which the injection of the EOR fluid could be compared, in order to evaluate the effectiveness of said EOR fluid. That is to say, the part of the core that was swept by only the aqueous solution is representative of what occurs when no EOR technique is carried out.

The method of the invention may comprise comparing the core data for the first part of the core with the core data for the second part of the core (the first and second parts of the core being as described above). When more than one EOR fluid are injected into the subterranean formation, the method of the invention may comprise comparing the core data for the first part of the core with the core data for one or more parts corresponding to a part of the core swept by an EOR fluid, preferably with each part corresponding to a part of the core swept by an EOR fluid.

The method of the invention may comprise comparing the amount of hydrocarbons, and preferably the amount of fluid other than hydrocarbons, retrieved in the first part of the core, with the amount of hydrocarbons, and preferably the amount of fluid other than hydrocarbons, retrieved in the second part of the core (preferably the fluids retrieved by washing the parts of the core with a solvent, as described above).

The method of the invention may comprise comparing resistivity logging data for the first part of the subterranean formation with resistivity logging data for the second part of the subterranean formation.

The method of the invention may comprise comparing neutron absorption logging data for the first part of the subterranean formation with neutron absorption logging data for the second part of the subterranean formation.

The abovementioned comparisons may also be made, when more than one EOR fluid are injected into the subterranean formation, between the first part of the core, or the first part of the subterranean formation, and each part corresponding to a part of the core, or a part of the subterranean formation, swept by an EOR fluid and/or the parts corresponding to parts of the core, or parts of the subterranean formation, swept by respective EOR fluids may be compared to one another.

When an EOR fluid contains at least one chemical, the effectiveness of said EOR fluid may depend on the capability of the chemical not to be adsorbed in the rock of the subterranean formation. Indeed, if the chemical leaves the EOR fluid and is adsorbed in the rock of the formation, it will not be able to help displace the hydrocarbons of the formation and the EOR fluid may lose part of its efficiency. Moreover, the chemical, in particular if it is a polymer, when adsorbed in the rock of the formation, may clog the pores of the formation and prevent the EOR fluid from invading said pores and thus from displacing hydrocarbons contained in said pores. On the contrary, if the chemical is not adsorbed in the rock of the formation, it may be recycled and reused in another EOR process. Therefore, the method of the invention may comprise evaluating the effectiveness of the EOR process based on the quantity of chemical from the EOR fluid absorbed in the rock of the core.

The method of the invention may comprise determining the longitudinal dispersion of the EOR fluid flood front, preferably based on salinity or chemical concentration core data for portions of the core at and/or near the flood front of the EOR fluid. By “longitudinal dispersion" is meant the quantifying of the spreading of the EOR fluid flood front during transport in the reservoir due to adsorption of the EOR fluid on the reservoir rocks.

The method of the invention may comprise determining the residual oil saturation in at least a part of the core. By “residual oil saturation" is meant the portion of hydrocarbons remaining in the formation after carrying out the oil recovery processes, in particular the EOR processes. The residual oil saturation may be measured by the Dean Stark method which consists of distillation extraction. The fluid extracted may then be analyzed by routine chromatography analysis.

The method of the invention may comprise determining the injectivity of the EOR fluid. By “injectivity of the EOR fluid" is meant the rate and wellhead pressure at which the EOR fluid may be injected into the subterranean formation.

The following embodiment illustrates the invention without limiting it.

Making reference to figure 1, a well 1 is provided in a subterranean formation. Said well 1 comprises an essentially vertical part 2 extending from the surface 12 of the subterranean formation and an essentially horizontal part 3 extending from the bottom end of the essentially vertical part 2.

Making reference to figure 2, an aqueous solution, for example an aqueous solution having a salinity higher than or equal to 0.1 g/L, is injected into the subterranean formation from an injection location 4 located at the distal end of the essentially horizontal part 3 of the well 1. As an example, about 1 ,600 m³ of said aqueous solution may be injected into the subterranean formation. The injected aqueous solution invades (or sweeps) the subterranean formation over a zone 5 of the formation and displaces at least part of the hydrocarbons contained in said swept zone 5. The flood front 6 of the aqueous solution is the interface between the zone 5 swept by the aqueous solution and the rest of the formation.

Making reference to figure 3, an EOR fluid is injected into the subterranean formation from the injection location 4. As an example, the EOR fluid may be injected into the subterranean formation in an amount of about 1 ,600 m³. The injected EOR fluid invades the subterranean formation over a zone 7 of the formation and the flood front 8 of the EOR fluid is the interface between the zone 7 swept by the EOR fluid and the rest of the formation. When invading the zone 7 of the subterranean formation, the EOR fluid displaces at least part of the aqueous solution contained in said swept zone 7 so that a zone 9 of the subterranean formation extending from the zone 7 swept by the EOR fluid is swept by the aqueous solution. This zone 9 swept by the aqueous solution, and in particular the displaced aqueous solution, is delimited by the flood front 10 of the displaced aqueous solution. The EOR fluids may also displace at least part of the hydrocarbons contained in said swept zone 7. Making reference to figure 4, a core 11 is drilled in the subterranean formation from the injection location 4. The coring is carried out in an essentially horizontal direction, as an extension of the essentially horizontal part 3 of the well 1. The coring is carried out over a length longer than the dimension (in the direction of the coring) of the combined zones 7 and 9 so that the core contains both the portion of the flood front 8 of the EOR fluid and the portion of the flood front 10 of the displaced aqueous solution that are on the path of the coring. The core may be drilled as a single piece or section by section. As an example, the total length of the core may be about 12 m and its diameter may be about 20 cm.

The core may then be brought to the surface 2 of the subterranean formation so that a analyzing step is performed on the core to obtain corresponding core data and to evaluate the effectiveness of the EOR fluid injection based on these core data. Alternatively, or additionally, a logging step may be carried out from the cored hole made after the core is drilled to obtain corresponding logging data and to evaluate the effectiveness of the EOR fluid injection based on these logging data.

Claims

1. A method for assessing an enhanced oil recovery process based on the injection of at least one enhanced oil recovery fluid, in a subterranean formation, said method comprising: providing a well in the subterranean formation; injecting an aqueous solution into the subterranean formation from an injection location in the well; injecting the at least one enhanced oil recovery fluid into the subterranean formation from the injection location in the well, so as to displace at least part of the aqueous solution; coring the subterranean formation from the injection location in the well, so as to collect a core comprising a flood front of the at least one enhanced oil recovery fluid and a flood front of the displaced aqueous solution and to create a cored hole in the subterranean formation; and analyzing the collected core, so as to obtain core data, and/or logging the subterranean formation from the cored hole, so as to obtain logging data.

2. The method of claim 1, wherein the step of providing a well in the subterranean formation comprises drilling a well in the subterranean formation.

3. The method of claim 1 or 2, wherein the aqueous solution has a salinity higher than or equal to 0.1 g/L

4. The method of any one of claims 1 to 3, wherein the aqueous solution is produced water or sea water.

5. The method of any one of claims 1 to 4, wherein the at least one enhanced oil recovery fluid is selected from the group consisting of brines having a different composition from that of the aqueous solution, surfactant formulations, polymer compositions, gas, foams, steam, microbial broths, and combinations thereof.

6. The method of any one of claims 1 to 5, wherein logging the subterranean formation comprises measuring the resistivity of the subterranean formation; and/or measuring neutron absorption by the subterranean formation; and/or analyzing the collected core comprises washing the collected core with a solvent so as to retrieve the fluids contained in said core and measuring the amount of hydrocarbons and/or EOR fluids.

7. The method of any one of claims 1 to 6, wherein the well comprises an essentially vertical part extending in the subterranean formation from the surface of the subterranean formation and an essentially horizontal part extending in the subterranean formation from the essentially vertical part.

8. The method of claim 7, wherein the essentially horizontal part of the well is a barefoot hole.

9. The method of any one of claims 1 to 8, wherein the step of coring the subterranean formation is carried out in an essentially horizontal direction.

10. The method of any one of claims 1 to 9, wherein at least 100 m³, preferably from 1 ,000 to 20,000 m³, of the aqueous solution are injected into the subterranean formation from the injection location in the well.

11. The method of any one of claims 1 to 10, wherein at least 100 m³ preferably from 1 ,000 to 20,000 m³, of the at least one enhanced oil recovery fluid are injected into the subterranean formation from the injection location in the well.

12. The method of any one of claims 1 to 11 , wherein the collected core has a diameter of from 5 to 40 cm and/or a length of from 5 to 60 m.

13. The method of any one of claims 1 to 12, wherein the core comprises an end corresponding to the well wall and wherein analyzing the collected core comprises analyzing a first part of the core, comprised between the flood front of the at least one enhanced oil recovery fluid and the flood front of the displaced aqueous solution, so as to obtain core data for said first part of the core, and analyzing a second part of the core, comprised between the end of the core corresponding to the well wall and the flood front of the at least one enhanced oil recovery fluid, so as to obtain core data for said second part of the core.

14. The method of any one of claims 1 to 13, wherein logging the subterranean formation comprises logging a first part of the subterranean formation from a portion of the cored hole comprised between the flood front of the at least one enhanced oil recovery fluid and the flood front of the displaced aqueous solution, so as to obtain logging data for said first part of the subterranean formation, and logging a second part of the subterranean formation from a portion of the cored hole comprised between the well wall and the flood front of the at least one enhanced oil recovery fluid, so as to obtain logging data for said second part of the subterranean formation.

15. The method of claim 13 or 14, further comprising comparing the core data for the first part of the core with the core data for the second part of the core and/or comparing the logging data for the first part of the subterranean formation with the logging data for the second part of the subterranean formation.

16. The method of any one of claims 1 to 15, wherein the step of coring the subterranean formation is carried out using a low invasion coring process.

17. The method of any one of claims 1 to 16, wherein, during the step of coring the subterranean formation, the core is collected in a plurality of individual core sections, wherein preferably each core section has a length of from 1 to 15 m.