NO20230174A1 - EPS Extended Production System - Google Patents

Description

METHOD AND APPARATUS FOR EXTENDING THE PRODUCTION OF OIL WELLS

Gilberto Toffolo, Theodor Dahlsvei 4B leil nr.103 seks.20, 4355 Kverneland, Norway

Index

• Main field of the innovative idea

• General description of the problem

• Solutions usually used in the main field of application (Known art)

• Technical problem: criticality of the known art resolved by the innovative idea

• Technical aspects characterizing the innovative idea that distinguishes it from the known art • Description of the idea in its general form

• Detailed description of the invention

• Resume of the general concept

• Brief description of the drawings

• Claims

Main field of application of the innovative idea

The present invention has the objective of reducing the amount of hydrocarbon that cannot be directly produced through conventional wells due to uncertainties related to the well planning process, to the structural complexity of the reservoir or different properties of the productive formation. These uncertainties cause volumes of oil to remain undrained and the proposed solution represents a possibility to produce them.

The proposed solution applies primarily, but not limited to, oil reservoirs with pressure support from movable aquifers, with oil-water contact moving towards the wells until the complete flooding of the production well.

The present invention can also be considered applicable, with a different configuration, to oil reservoirs with a gas cap, when the end of the production life of the well is not caused by water arrival from below, but instead by gas arrival from above.

For general description, the situation primarily described in this patent refers to an oil reservoir supported by an active water drive, with an oil-water contact gradually reaching the well until complete flooding of the same.

General description of the problem

During the production life of every well the oil is gradually replaced by the formation water and the same progresses gradually towards the producing wellbore. At the end of the life of any well, the water in some points gradually enters the wellbore therefore slowly reducing the quantity of oil produced and gradually increasing the water produced, until the oil produced is so low that the operating costs of the well become higher than the economic value of the oil still produced. At this stage, the well is closed and operators normally proceed with the plug and abandonment of the same.

Confidential Page 1 When a hydrocarbon reservoir is discovered, production wells are normally placed at a safe distance from a possible water-oil contact, to maximize the quantity of hydrocarbon produced, because, due to gravity, the light oil placed above the wells, often called Attic Oil, cannot normally be produced.

The amount of oil between the well and the caprock is never known precisely because the structural traps containing the hydrocarbon have a different and often unpredictable shape; before drilling the only information on the position of the top of the reservoir is given by the seismic interpretation, which is always conditioned by an important degree of uncertainty. To make sure that the well, which typically will be drilled horizontally, will stay safely below the caprock, the same will be drilled several meters below the caprock.

Moreover, there are also geological situations as the ones known as Injectites that represent sandy permeable bodies with vertical paths that are difficult to locate with precision therefore placemen of the wells become more uncertain.

During the drilling process, often called Geosteering, relevant information from the logging tools can be gathered only several meters behind the drilling bit. As an example, a well-drilled horizontally in a 30 m thick reservoir should keep safely at approximately 5 meters from the top of the reservoir, and in this case, this would mean that 16% of the reservoir section would be above the wellbore.

Therefore, the position of the horizontal production well will be chosen as far as possible from the water table, clearly below the caprock providing the sealing trap, but well inside it to minimize the risk of drilling some sections inside the cap rock itself. Therefore, once the water will have reached the well an important volume of hydrocarbon will still be trapped above the well.

Apart from the hydrocarbon that geometrically lay above the wellbore, there is also a quantity often defined as Bypassed Oil that, that, even if it lays below the well, is not recovered due to uneven distribution of permeability in the productive layers or simply due to the higher mobility of water in respect to the mobility of the hydrocarbon, particularly in case of higher viscosity oil. The water is moving towards the well faster than the oil in what can be also called “channelling”. Fractures and faults can also enhance the problem and therefore, the water could arrive at the wellbore before an important part of the hydrocarbon could be produced.

Low production rates could reduce the problem; however, the recovery of hydrocarbon would be so slow that it would not be economical.

The combination of both Attic Oil and Bypassed Oil represents an important part of the initial hydrocarbon volume that will remain undrained with conventional wells and solutions.

A representation of the Attic Oil concept is reported in fig.1. The drawings are illustrative and show only a cross-section, the actual reservoir will have a 3d shape with volumes difficult to quantify that could be lower than what the cross-section represents but could also be much higher.

Confidential Page 2

Fig. 1 – Three different types of oil traps that can create a quantity of residual Attic Oil (Black). In A, a conventional reservoir whit an uncertain caprock position. In B a faulted reservoir creating a cap rock of complex geometry. In C a more complex reservoir created by “Injectites” with permeable bodies of uncertain position and uncertain top that must be produced by the same well. For all examples the oil-water contact is gradually moving towards the wells until complete flooding will prevent any further oil production, leaving the oil between the well path and the caprock inside the reservoir.

In fig.2 instead is represented the concept of Bypassed Oil.

There are technical solutions that allow to reduce the water or close some sections of the wellbore that produce water, however, in the end, all its sections will be flooded, and oil production will not be possible anymore.

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Fig. 2 – Example of bypassed oil due to higher mobility of the water. Bypassed Oil is not placed above the well but could be around or below the well path. Given the gravity forces, bypassed oil could progress towards the wellbore very slowly.

At this stage, the “Attic oil” and what will be left of the “Bypassed Oil” are completely lost, unless new wells are drilled to complete the drainage of all volumes placing the targets in the undrained volumes.

Even if this is technically possible it is almost never done because the costs are too high and the uncertainty on the actual volume to be drained and its position is too high.

The object of the present invention is exactly the possibility to recover an important part of this Attic Oil and the Bypassed Oil through the same initial well, without any further intervention. In other words, place some draining points far from the main wellbore from the beginning.

Solutions usually used in the main field of application (Known art)

There could be some solutions to produce at least a part of the Attic Oil, and much would depend on the shape of the stratigraphic trap, or better the shape of the caprock. The most common solution is the minimization of the distance between the well and the caprock, gathering information while drilling, a process often called “Geosteering”.

Another possible solution to produce the Attic Oil could be the injection of lighter fluid as for example natural gas or nitrogen that would displace the oil by gravity pushing the same towards the wellbore. Finally, the most logical solution could be drilling a new well or a lateral branch from the existing well towards the part of the reservoir comprised between the original well and the caprock. In respect to the Bypassed Oil, the main solution is to control the flowrate and divide the production interval into several independent sections each one hydraulically isolated by sealing elements often called packers. There are several solutions, either operated or automatic, that are able to close completely or partially each of these sections once the amount of water is considered too high.

Confidential Page 4 Technical problem: criticality of the known art resolved by the innovative idea.

The first solution to drill as close as possible to the cap rock meets the technical limitation given by the drilling process. There is a clear need to simplify the well path to reduce risks and costs. The wellbore must be smooth and continuously growing in angle, an angle that normally should not be higher than 90 deg. Given that the formation top instead could have a much more irregular shape it becomes impossible to follow continuously its shape. Moreover, to get good well productivity it is necessary for the well path to lay at a certain distance from the top, to have a regular flow from all directions around the well and minimize the risk of drilling outside the reservoir. Therefore, a certain volume associated with the attic oil will always be present.

The second solution of injecting gas is somehow ideal, however, the cost in most instances would be too high, for the need of having to drill injection wells and the cost associated with the injection system, also requiring all surface facilities. This solution could be useful and is used at a reservoir level when big sections of the reservoir would remain undrained and the injection of gas at the top could help pushing the oil towards several production wells. Drilling a new well or a lateral branch is instead complex and costly and should be made only when it is proven that there are important reserves to be drained, a thing that due to the uncertainties previously described is rarely possible.

So, there are currently no simple and economical solutions to produce the attic and bypassed oil and the final recovery factor of most fields, therefore, is reduced.

Technical aspects characterizing the innovative idea that distinguishes it from the known art.

The basic idea of the proposed solution is to create a system that could produce the attic oil and at least part of the bypassed oil through the initial well, without further intervention at the end of its production life. This could be possible if the well would not produce from the main wellbore only, but also from several points placed at a certain distance from the main wellbore.

Fig. 3 – Drawing to describe the general concept. The well will produce mainly from the main wellbore; however, it can produce also from several drainage points placed at a given distance from the main wellbore. If the external draining points will be equally distant from the main wellbore, they would lie on an ideal cylindrical surface.

Confidential Page 5 In this way, even when the water will have reached the main wellbore and theoretically its production life would normally end, oil could still flow from the other draining points connected to the main bore by independent channels.

In this way, with a single well it might be possible to access oil reserves from points that are not only laying along the main wellbore but within a cylinder having the same length of the main horizontal well and diameter given by the length of the laterals multiplied by two. A tentative description is given in fig.3. The well will produce mainly from the main wellbore; however, it can produce also from several drainage points placed on an ideal cylindrical surface with a diameter twice the length of each lateral. It is clear that drainage points above the production liner could be useful to extend the life of the well in case of premature water arrival, while the drainage points placed below to extend the life of wells exposed to the risk of premature gas arrival.

In this way, if the flow from different sections of the main wellbore and from every lateral could be automatically closed, in case of water arrival, it might be possible to continue the production of hydrocarbon until the last draining section of the main wellbore or the last external draining point will keep on producing.

So, the main idea that distinguishes the current proposal from the existing technology is the capability with a single well to access a quite larger volume of formation with the possibility to control the flow from different point inside this volume, not along the main wellbore only, reducing in this way the impact of structural uncertainties and uncertainties over the properties of the formations as permeability or porosity within the same volume.

In this way most of the Attic and at least partly of the Bypassed oil could be produced.

While this to a certain extent is possible with multilateral solutions, or with multi-stage fracturing, this solution presents several advantages, the main being that in respect to a multilateral solution there would be many more draining points at a lower cost and placed in ideal and planned spots and in respect to multistage fracturing there would be a higher degree of control.

Description of the idea in its general form

A general description is reported in fig. 4 that represents a case of a vertical draining channel to recover the Attic Oil, even if the configuration could be valid also for laterals in other directions to recover Bypassed Oil. During its production life, the well will produce mainly from the main wellbore. Once the water will have reached its level, valves along the same will close, however, the flow will still be possible from the inner part of the lateral pipe. The lateral channel will be used in both phases. In the first phase, oil could flow both inside the lateral pipes as well as in the annular between the laterals and the formation. During this second phase instead, the sealing element will prevent any water from bypassing the system and oil will be able to flow only through the inner part of the lateral pipe from its top.

Since the vertical laterals could also reach and enter the caprock, which is impermeable, virtually all the attic oil above the well could be produced.

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Fig.4 – Drawing representing the general concept for attic oil.

A similar concept could be possible also in the case of Bypassed Oil, as reported in fig.5. In this case, the lateral wells would be horizontal and would be useful in the conventional configuration or in case of water coning as in fig 6 that represents also a more general configuration that would have both horizontal and vertical laterals to reduce at the same time Attic and Bypassed Oil. Fig.6 is also relevant for possible premature water arrivals through faults or fractures that normally intersect the mail wellbore in specific sections. In this case, water could progress along the external part of the main wellbore, but oil could still flow from the extreme points of the laterals.

Fig.5 – Drawing representing the general concept for bypassed oil.

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Fig.6 – General configuration to increase the recovery of both Attic and Bypassed Oil.

Fig.7 represents a better description of increased recovery from the attic in case of faulted reservoir and water drive support, while fig. 8 represents a similar solution that could instead increase the recovery factor of oil when the drive mechanism for the production is not the pressure of the water, but instead the expansion of a gas cap. In this case, the oil trapped would be the oil between the well and the bottom of the reservoir. In this case, a reservoir containing gas above and oil or condensate below, without a water drive mechanism could be produced even when the gas reaches the wellbore. In case a water layer would be present below the oil or condensate, the lateral wells could automatically close when the water would arrive at the well.

Fig.7 - General description of the proposed solution to recover the attic oil.

The two examples previously described representing situations with only two phases, oil produced with the support of gas expanding gradually towards the wellbore or oil produced with the support of formation water gradually rising towards the wellbore. In both examples, the end of the well’s life is when the gas or the formation water breakthrough in the wellbore.

These two specific examples represent each a particular situation of a more generic three phases reservoir. In many wells there is both the presence of a gas cap and of a strong water drive, therefore the end of the well or just a section of the well could arrive with either a gas breakthrough or a water breakthrough. The two events could also happen in two different parts of the same well and at different times. This represents a typical situation in the case of thin reservoirs often called “Oil rims”.

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Fig.8 – General description of the proposed solution in case of expansion of a gas

cap without water support.

Fig.9 – General description of the contact movement versus time in three phases reservoir.

In fig.9 is reported a general description of a three phases reservoir. A represents a general situation when a well is placed inside the oil zone, at an optimal distance from the gas-oil contact (Above) and the Oil Water contact below. During the production life, the two contacts move towards the horizontal well until one of the two will finally reach the wellbore. From that moment on that specific section of the reservoir will produce either water (C) or gas (D) leaving in both cases unproduced oil. Figure B represents an ideal situation when both gas and water reach the well at the same time, maximizing the oil recovery. In this way, all the oil would be drained but this is clearly impossible, and one of the two contacts will breakthrough before the other. When the water breaks through first, there will be some oil left above the well, which can be called Attic Oil. When the gas breaks through first then some oil below the wellbore will be lost, this oil could be called “Basement Oil”.

Confidential Page 9 In the reality, given that wells could be long several thousand meters, these events could happen in some sections only, or begin in some sections and slowly progress until all the well is flooded by water or by gas. The well will produce oil, gas, and water for some time until its very end when due to the high percentage of the two fluids oil will not be lifted anymore.

At that time there will be a quantity of Attic Oil or Basement Oil distributed along the wellbore that will not be produced anymore and can be considered lost.

This effect can be enhanced by what is called gas or water coning, an often-irreversible localized arrival of gas or water due to a high drawdown. In this case, larger volumes of Attic or Basement Oil could be lost. The simultaneous breakthrough along the whole horizontal hole is impossible, due also to the specific geometry of the well, uneven distribution of properties and therefore the quantity of oil left unproduced could be considered always relatively high.

In summary, the proposed idea is aiming at maximizing the recovery factor for any new well and produce as much as possible of the movable oil that surrounds the well, without the limiting factor of a possible premature ending of its life due to water or gas coning or the arrival of water or gas along the whole main wellbore.

To achieve this the production can be considered divided into two phases. The first is the common production through the main wellbore (or an independent section of the same) and the annular section between the lateral channels and the formation. Once this phase is over and the undesired fluid (Being it the water of gas) reaches the main wellbore inside that specific section, production through the conventional path will end due to the automatic or manual closure of specific valves. At this stage, however, an important part of the oil above or below the wellbore that has been bypassed by the undesired fluid could still be produced through the inner section of the lateral wells departing from the main wellbore in the vertical direction either pointing upward (To recover the Attic Oil) or pointing downward (To recover the Basement Oil). Therefore, the oil will all be produced through the main wellbore, but through different paths according to the different moments in the well’s life.

It will be possible to deploy systems for the three main situations of

• Oil production with gas expansion and no water support

• Oil production with water drive and no gas cap

• Oil production with both water drive and gas expansion

This last case is particularly relevant if the oil is present in thin columns, often called Oil Rims. This type of reservoir is particularly difficult to produce because the oil section itself could move during the production life. In other words, the oil layer is not only thin, but it is also moving with time under the evolving pressure of the gas cap and the water, causing uncertainty on where to place the production wells to maximize the recovery.

The present invention can be used also for the different purpose of injecting a fluid rather than producing a fluid. Considering that attic oil can be displaced with the injection of gas, one possible solution could be the injection of gas from the same well producing the oil. If the point or points of injection are high enough above the main horizontal wellbore and the same points are properly sealed without the risk of bypass through the formation towards the main horizontal wellbore, in that case with a controlled gas injection rate, the gas pressure would push the oil towards the main horizontal

Confidential Page 10 well bore. Many variables are possible, like injecting only in the uppermost part of the wellbore while producing from the lower part, injecting the gas not continuously following a specific injection sequence or injecting different gas as for example natural gas, nitrogen, or CO2. A description of the solution is reported in fig.10. There are two possibilities, one using a conventional well and alternating period of injection with periods of production, and the other, using a different completion design, having inside the main horizontal wellbore one more pipe (106) that would carry the oil produced, while at the same time the gas would be injected through the annular between the original wellbore and the inner pipe.

Fig.10 – General description of the solution for the injection of gas.

Detailed Description of the Invention

The proposed technology is based on three elements. The first is the creation of several lateral drains departing from the main wellbore that will have an inner pipe able to allow the production of fluid internally as well as along the annular space between the pipe and the formation. The pipes, in some

Confidential Page 11 applications, might have a sealing element to prevent the flow in the annular section, but only in a limited part of the lateral bore.

The second is represented by sealing elements, often called packers, to divide the mail wellbore into several independent sections.

The third is represented by valves able to close the flow inside a single independent section of the main wellbore in case the produced fluid being unwanted as for example water or in some instances gas.

All these three elements can be considered part of the known art and therefore available, however not combined as proposed in the present invention.

With respect to the first requirement, there are technologies that can provide lateral holes from a single main wellbore to increase production or to explore other areas around the wellbore. Later, inside the lateral, can also be run tubing to produce oil. These technologies are also called Multilateral Solutions and have several different alternatives. The laterals can be drilled with conventional drill pipes or with coiled tubing. The main issue with this solution is that every lateral well requires time, particularly if an inside pipe or liner must be accommodated inside the lateral. When the number of laterals is high the cost becomes therefore excessive and not justified. The main purpose of these solutions is to drain a different area inside the reservoir and their number is normally limited. To the current invention, it would be mandatory that a pipe should be inserted in any of the lateral holes to provide communication between the extreme part of the pipes and the wellbore.

One technology that could be used is also the Fishbones Technology (Patent US2016/0097239 A1) that provide a high number of lateral channels created with a jetting action in case of Limestone Formation or with small drill bits, in case of Sandstones Formations). In both cases, a pipe of small diameter is left inside the channels and the produced fluid can flow either internally or preferably in the annular space between the needles and the drilled formation that would have a larger flow area.

This second alternative is more consistent with the needs of the present invention since it can provide in a short time and at a lower price several laterals each with an internal liner for the flow of the oil, however for the scope of the present invention, any solution could be considered.

To divide the main wellbore into a high number of independent sections several technologies are available, the most common and economic being the technology often called Swell Packers that consist of special elastomers that, once placed in the main wellbore, would swell providing a reliable seal between independent sections of the main wellbore.

As far as the need of closing any access to the undesired fluid is concerned there are several technologies with different degrees of automation. The simplest and most common solution would be to place several valves often called Sliding Sleeves that could be closed with specific operations as for example with wireline or coiled tubing. This solution has proved reliable, but it is convenient for a relatively low number of applications in the same well and closing would require knowing with precision which valve to close therefore recording dedicated logs to identify the proper valve to be closed. These operations would require a temporary shutdown of the production and the cost could be relatively high. Moreover, with this solution, the valves would remain closed, even if they could be opened again the cost of such operation would not be justified.

Confidential Page 12 A better solution could be the use of valves, also called Inflow Control Valves, that are electrically operated from the surface. In this case, the wireline or coiled tubing operations would not be necessary. Another important advantage of this alternative could be that the valves could be reopened in case the front of the undesired fluid, for example, due to gravity, might temporarily move from the wellbore, allowing for more oil to be produced. The main problem could be the cost of the completion and the risk that after several activations the valves might fail.

A third solution is represented by a new generation of systems often called AICD (Autonomous Inflow Control Devices) or AICV (Autonomous Inflow Control Valves) that can autonomously and temporarily reduce or stop the undesired fluid any number of times opening and closing according to the type of fluid reaching the well. In respect to AICDs, AICV has the important advantage that the flow is almost completely closed, while the AICD will only reduce the amount of undesired water or gas.

A general description of the system is reported in fig.11, where a typical elementary section of a lower completion with sealing elements (Swell packers), one sand screen, and one inflow control valve is represented. There are three main paths for the flow: the main flow through the screens and the valve (A), a secondary flow from the annular of the laterals that would enter the screens (C), and a third flow flowing inside the lateral pipes (B).

Fig. 11 – Schematic representation of a single element of the proposed solution. Every element includes a base production liner, a protection screen with a larger diameter that creates an annular space for the flow of oil externally to the liner and, two sealing elements, a valve allowing the flow of hydrocarbon to enter the main production liner and, most important, one or more pipes extending from the main bore. The valve would allow the oil to pass but would close in case a different fluid, like water or gas, would enter the screens. Three paths for the produced fluid are possible, the main from the formation to the screens (A), the flow from the annular between the lateral pipes and the formation (B), and the flow inside the lateral pipes (C).

In fig 12 instead, a global view of a longer reservoir section is divided into independent elements. Every element is isolated from the others by the sealing elements, therefore is an independent section.

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Fig.12 – One example of the whole reservoir section divided into independent elements.

If unwanted fluid would appear in one section only, this section will close while others might continue the production.

Once the section is closed along the main wellbore the section will continue the production only from the top, or extreme, of the lateral channels. In this case, according to the pressure difference between the main wellbore and the top of the laterals, there might be the risk that the water that reached the main wellbore could flow up to the top of the lateral channels and enter the main wellbore through the lateral channels.

In case of needing to also stop an undesired flow from the internal part of the lateral pipes, a possible solution could be as reported in fig.13 where a second automatic valve is placed at the bottom of the lateral pipes. In this case, the second valve should close in case of water or gas but should be able to open again should some more oil enter the laterals. To achieve this the valve should not close completely but leave some minimum fluid to flow allowing the unwanted fluid to exit while being replaced by oil inside the lateral pipe. This will prevent the lateral to become permanently plugged and allow other oil to enter, when, due to the lower flow the level of the water around will decrease and leave some more oil inside.

Inside every section, once the automatic valve on the main wellbore will be closed, the water, due to a pressure differential, could flow along with the annular space in the lateral channels towards the top of the channels and enter the same. Given the different densities, this should not happen, however, for an important pressure differential this could happen at least at a later stage when the level of the water will approach the top of the laterals.

To prevent this from happening, (Fig. 14) in the final part of the metallic pipe one or more sealing elements will be placed around the metallic pipe somehow dividing the annular section into two parts, an upper part able to flow only towards the top and an inner part able to flow only towards the main wellbore. In this way, the lower part of the annular flow could be used positively to increase the flow towards the main wellbore during most of the production life. Once water will reach the main wellbore

Confidential Page 14 the lower part of the annular flow will not contribute anymore, while the upper will still contribute from the inner of the metallic laterals.

Fig.13 – A solution to control the fluid produced through the lateral metallic pipes. This would be independent from the valve preventing the flow of undesired fluid through the main wellbore.

Fig.14 – A solution to prevent the undesired fluid from flowing up to the top of the lateral channels.

The type of section and lateral channel described is the most complete, however, simpler solutions are possible within a single independent section. The lateral channels in one section of a production well

Confidential Page 15 (Between two packers) might be different according to the pipe and type of flow control required, at least four different types could be envisaged:

1. Type A: Conventional lateral pipes without the internal flow to increase reservoir contact. In this case, production from the lateral would be possible only along with the annular space between the pipes and the formation. Once the undesired fluid will flow along the laterals, valves will possibly close the access to the main wellbore and the specific section will stop the production. In presence of moving contacts, these types of laterals will be particularly beneficial if departing horizontally, with a maximum increase of the reservoir contact and minimum risk of premature water or gas breakthrough.

2. Type B: Lateral pipes with inner flowing capabilities to produce from a distant point when the undesired fluid has reached the main wellbore. This could be used for example to access Attic Oil, Basement Oil, or Bypassed Oil. The flow along the annular between pipes and formation will normally join the conventional flow around the main wellbore and they both might be stopped by specific valves once the undesired fluid will have reached the main wellbore. In the highest or extreme point of the pipe, the flow could continue entering the inner part through a slotted section at the end to prevent clogging with fines. This would be also the symmetric solution of producing the Basement Oil with a gas drive. These types of laterals would normally be directed upward in the case of Attic Oil and downwards in case of Basement Oil but could have also different directions in case of Bypassed Oil. Flow inside the pipes will enter directly inside the production liner without any control, therefore once the undesired fluid will have reached access to the lateral, it will enter the main production liner.

3. Type C: Lateral pipes with inner flowing capabilities to produce from a distant point and sealing elements close to their end to prevent the flow along the annular in one or more specific points. This solution is the same as the previous one, however, the sealing capability in the annular between pipes and formation will prevent any undesired fluid from entering the extreme points of the laterals.

4. Type D: Lateral pipes with inner flowing capabilities to produce from a distant point, sealing elements to prevent the flow along the annular, and valves to prevent undesired fluid flowing internally from entering the main wellbore. In this case, if undesired fluid will enter the lateral, a valve could close the access to the main wellbore.

The correct choice will be critical to meet the requirements for the different types of situations.

An important characteristic of the proposed system is that valves would be autonomously activated and reversible. In other words, if they close after the water or gas breakthrough, as soon as more oil slips up, they will be able to open again letting more oil in, until water will appear again.

The set of lateral channels could be realized with a three-dimensional geometry by making the channels departing orthogonally to the main axis but in different directions. Following are some examples.

No risk of water or gas premature arrival

In this case, the main purpose of the laterals would be to increase the reservoir contact therefore any direction could be considered equally important and the number of laterals chosen according to the required increase of productivity. This solution is actually already available and commercial.

Confidential Page 16 Reservoirs producing by water support and gas expansion.

In this case, instead, both water or gas arrival would sign the end of the production life of the well and a system able to extend its production life after the undesired fluid will have reached the main wellbore would be the solution to extend their production life.

The typical configuration could be the one presented in fig.15, with sets of three lateral channels for every section, two of them contained in a horizontal plane to increase the reservoir contact and reduce the drawdown and one vertical, directed towards the cap rock that will allow production until the water will breakthrough along the main wellbore. After water or gas will have arrived at the well, valves allowing the flow along the main wellbore will close, but production will still be possible through the internal part of the pipes. In the case of a gas drive with an expected end of production life due to the gas arrival at the main wellbore, the geometry and concept would be symmetrical, with two series of channels placed on a horizontal plane and one pointing downward.

The laterals are represented without sealing elements to prevent a bypass of flow through the annular and without any system to stop the flow of unwanted fluid inside the laterals. This solution is represented in fig.16. In this case, given the sealing elements and the secondary valves, production could continue until water will have reached not only the main wellbore but also the extreme points of every single lateral.

Fig.15. In this example a water coning is induced by a high localized drawdown, forcing the valves along the main wellbore to close the direct access to the main bore. In this situation, however, with the well configuration shown in the figure, the oil can still be produced by the upper extreme channel, taking in this way advantage of the attic oil, but also by the two lateral extremes of the horizontal laterals.

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Fig. 16. This drawing represents a general layout in the case of movable water towards the main wellbore. Given the sealing elements and the secondary valve, production could continue until water will have reached not only the main wellbore but also the extreme points of every lateral.

The layout in case of gas expansion would be basically the same, but with the vertical laterals pointing downwards.

More solutions are possible according to the actual needs, just as an example in fig.17 is reported a solution to access both Attic as well as part of the Bypassed Oil.

Fig.17 – Possible solutions to access both Attic and part of the Bypassed Oil.

Confidential Page 18 The decision of whether to use sealing elements along the laterals will depend on the type of reservoir.

Given the relatively little difference in density between oil and water, sealing elements might be

recommended to prevent the water from reaching the top or the extreme point of the lateral,

particularly in the case of viscous oil with much lower mobility. In the case of a reservoir with the gas

expansion, the situation would be exactly the opposite, having the gas much lower density in case of

production of a basement oil the sealing elements might not be necessary.

Thin Oil Rims

Thin-oil rims represent a case with a higher degree of complexity and where attic, basement, and

bypassed oil could represent such a high percentage of the recovery factor that many times oil rims

are not considered producible.

In this case, the oil volumes are originally contained within two plane boundaries, the initial Gas Oil

Contact, and the initial Oil Water Contact, and the thickness of the oil column could be between 0,5

to 10-15 m. The thinner the reservoir the lower will be the recovery factor.

The added complexity, in this case, is that the two contacts, during the production life, might move

not only towards the well as expected due to the oil production but also under the differential

pressure between the gas cap and the water. In other words, even without production, the whole

volume of oil could slowly move upwards or downwards according to the pressure of the gas cap or

the pressure of the water.

It should be possible to know in advance which directions the two planes will follow, however placing

the wells to maximize the recovery factor could be difficult, particularly considering that planes would

slowly become surfaces with unpredictable shapes according to the different conditions in different

parts of the reservoir and the local drawdown applied.

For this reason, a system able to improve the recovery factor could be extremely valuable. Commented [gt1]:

In front of this uncertainty, to maximize the recovery factor, it will be necessary to have lateral

channels able to extend the production life of the well when both contacts would move towards the

main wellbore and in an unpredictable way. Given that solutions have been identified for both Attic

Oil and Basement Oil, one possible answer could be the combination of these two solutions, with the

difference that given the length of the laterals and the limited thickness of the oil rim, the laterals

should have only a limited inclination and limited length in respect to the horizontal plane of the

contacts.

In an ideal situation, the two contacts should slowly move towards the horizontal well and meet there

once the whole oil section has been drained. In the reality, they will move towards the well, but one

will arrive first, leaving some attic or basement oil undrained. The amount of the undrained oil will

depend on the position initially chosen for the well and the ability to predict how the contacts will

move. An extended production system might reduce the impact of these uncertainties since

production could continue in both directions even after the main wellbore would be flooded by

unwanted fluid.

Confidential Page 19

Fig.18 – Possible solutions to increase the recovery in a thin oil rim.

Fig.18 represents a possible layout of the laterals in an ideal case with an oil rim of limited thickness. The comparison with a single well is clearly showing that laterals placed in a horizontal plane, increasing the reservoir contact would decrease gas and water coning therefore delaying their arrival of unwanted fluid to the main wellbore and increasing the recovery factor. This practice is commonly used with multilateral solutions, however in this case the sealing elements on the laterals would further increase the recovery factor preventing the arrival of undesired fluid to the main wellbore with valves able to close or strongly limit the arrival of undesired fluid from the inner parts of the laterals.

Thin oil rim moving

The rim could also move because pressures above the oil gas contact and below the oil-water contact might change versus time. This could be due to several reasons, a general depletion of the reservoir, the expansion of both the gas cap and the gas released in the process of depressurization of the oil. Also, in many instances, the gas cap is also produced therefore the oil rim could migrate upwards consequently. The water instead could be in communication with a strong or weak aquifer, and this would have an important impact on the recovery factor, but also on the position of the oil rim itself.

Because of these uncertainties in a conventional well, the position of the main wellbore must be chosen properly, not only according to the initial position of the rim but also to the expected position it might have during the production life.

Confidential Page 20 In conclusion, apart from the coning of water or gas towards the oil rim, the same oil rim or partially in some areas, could move up or down. In these conditions it becomes quite challenging to obtain a high recovery factor and therefore lower thickness oil rims could not be considered for production.

With a system able to produce from points at different levels this uncertainty may be reduced.

In fig.19 is represented a possible layout of the laterals in case the whole oil rim would be expected to move upward during its life. In respect to a conventional horizontal well, there are two advantages, the first is the increase of the reservoir contact given by the laterals that would decrease the drawdown and therefore also the risk of both water and gas coning. The second is that having draining points at slightly different levels will allow continuing the production even when part of them will be flooded, including the main wellbore. What is important is that every draining point in the section, including the main wellbore, will have the capability to close the flow in case of water or gas arrival without affecting the production from other points. The length of the laterals, their direction and the number and position of the sealing elements inside the laterals will be chosen with a specific analysis.

Fig.19 – Possible solutions to increase the recovery in a thin oil rim expected to move upward. Having draining points at different levels will give the possibility to increase the recovery. Position of one or more sealing elements along the laterals can be chosen according to the needs

In fig 20 is represented a possible layout of the laterals in case the movement of the rim could be unpredictable. In this case, some of the laterals could be directed upward and some downward, possibly alternating the independent sections along the main wellbore.

As a general concept, it can be said that placing independent draining points around the main wellbore can give the possibility to extend the production even after the main wellbore itself will be flooded with undesired fluid increasing in this way the recovery factor in several different situations not limited to the examples here presented in case of Oil rims, Attic Oil and Bypassed Oil.

Confidential Page 21 In other words, it would be like having not only a single well (Being it vertical, deviated, or horizontal) but a well with several other independent draining points placed within an ideal cylinder surrounding the well, with the possibility of closing independently the flow from any of these points in case of premature arrival of undesired fluid.

Fig.20 – Possible solutions to increase the recovery in a thin oil rim expected to move, but without knowing in advance the direction of the movement.

Resume of the general concept

A reservoir is a volume of rock containing a certain amount of hydrocarbon that, given its permeability, could be produced through a well-drilled inside it. The geometry of the reservoir and its volume is not normally known with high precision and the production well is drilled in a point or along a line that is considered optimal to maximize the quantity of oil produced, considering all the possible uncertainties. However, not only the geometry of the reservoir contains uncertainties, but also the premature arrival of undesired fluids like gas or water can reduce the quantity of the oil that can be recovered from the well during its production life.

Because of these uncertainties, the quantity of oil recovered is always lower than the original oil in place. To reduce the quantity of undrained oil it could be possible to drill several wells instead, however, the cost would not be justified and the single well remains the only option to recover the oil, with all its uncertainties.

The proposed technology changes the traditional concept of a well with a given well path through a reservoir in the sense that has the ambition to recover oil not only through the main wellbore but also from independent drainage points at a certain distance from the main wellbore. If the points would be equally distant from the wellbore, they would lie on a cylindrical surface. The diameter of the cylinder or the distance of the draining points could reasonably be in the order of 10-20 m, however for the description of the concept this is not relevant.

The value of this solution would be that when the undesired fluid will have reached the main bore (In this situation the production of a conventional well would be ended) the production of hydrocarbon

Confidential Page 22 could continue from any of the other drainage points until finally, the undesired fluid reaches all of them as well. What is important is that every section of the main wellbore and every drainage point would be able to stop their contribute once water or gas will have arrived with proper devices as for example the Inflow Control Valves.

In general, the diameter of the cylinders could be higher or lower, however, most of the reservoirs have a thickness comparable with 20 m therefore most of them could be produced with an improved recovery factor, this also considering that wells are normally placed less than ten meters below the caprock.

The one described represents the base concept, however, several variables are possible, for example in one variation the valves could not be automatic, but rather mechanically operated with specific systems as wireline or coiled tubing. The number of laterals wells departing from the main bore could be variable, according to the maximum flowrate that a pipe can provide. Higher diameter pipes would allow for a higher flowrate, however, would require also a more complex drilling solution to create the lateral sections.

Given that the proposed solution allows extending the production life of a well, it might be called EPS or “Extended Production System”.

BRIEF DESCRIPTION OF THE DRAWINGS

The following drawings illustrate by way of example and are included to provide a further understanding of the invention for illustrative discussion of the embodiments of the invention. No attempt is made to show structural details of the embodiments in more detail than is necessary for a fundamental understanding of the invention, the description taken with the drawings making apparent to those skilled in the art, how the several forms of the invention may be embodied in practice. Identical reference numerals do not necessarily indicate an identical structure. Rather, the same reference numeral may be used to indicate a similar feature of a feature with similar functionality. In the drawings:

FIG. 1 Represents three different types of oil traps that can create a quantity of residual Attic Oil (Black). In A a conventional reservoir whit an uncertain caprock position. In B a faulted reservoir creating a cap rock of complex geometry. In C a more complex reservoir created by “Injectites” with permeable bodies of uncertain position and uncertain top that must be produced by the same well. For all examples, the oil-water contact is gradually moving towards the wells until complete flooding will prevent any further oil production, leaving the oil between the well path and the caprock inside the reservoir.

FIG.2 Represents an example of bypassed oil due to higher mobility of the water. Bypassed Oil is not placed above the well but could be around or below the well path. Given the gravity forces, bypassed oil could continue progressing towards the wellbore, but very slowly and represent a minimal percent of the total flowrate.

FIG. 3 Represent a description of the general concept. The well will produce mainly from the main wellbore; however, it can produce also from several drainage points placed at a given distance from

Confidential Page 23 the main wellbore. If the external draining points will be equally distant from the main wellbore, they would lie on an ideal cylindrical surface.

FIG. 4 Represents a case of a vertical draining channel to recover the Attic Oil, even if the same configuration could be valid also for laterals in other directions to recover Bypassed Oil. The figure represents a frontal view of a producing horizontal liner (101) inside a wellbore (100). Several lateral pipes (103), inside lateral holes (102) depart from the liner. At the extreme part of the lateral pipe a sealing element (104) prevents any flow from the upper part along the annulus between the lateral pipe and the formation in that specific point, however, contribute from the production and its flow is still possible below the sealing element. Above the sealing element a part of the lateral pipe has a slotted section (105) to help the flow of hydrocarbon to enter the inner part of the lateral pipes (103). During its production life, the well will produce mainly from the main wellbore. Once the water will have reached its level, valves along the same will close, however, the flow will still be possible from the inner part of the lateral pipe. The lateral channel will be used in both phases. In the first phase, oil could flow both inside the lateral pipes as well as in the annular between the laterals and the formation. During this second phase instead, the sealing element will prevent any water from bypassing the system and oil will be able to flow only through the inner part of the lateral pipe from its top.

FIG.5 Drawing representing the general concept for bypassed oil. In this case, the lateral wells would be horizontal and would be useful in the conventional configuration to increase the production from the annular between lateral pipe and formation as well as to produce from the extreme of the lateral inside the lateral pipes.

FIG. 6 Represented is a more general configuration that would have both horizontal and vertical laterals to reduce at the same time Attic and Bypassed Oil. The layout could be also relevant for possible premature water arrivals through faults or fractures that normally intersect the mail wellbore in specific sections. In this case, water could reach the main wellbore, but oil could still flow from the extreme points of the laterals.

FIG.7 General description of the proposed solution to recover the attic oil in case of faulted reservoir and water drive support.

FIG.8 General description of the proposed solution in case of expansion of a gas cap without water support and the risk of premature water arrival. In this case, the oil trapped would be the oil between the well and the bottom of the reservoir. With the proposed solution, a reservoir containing gas above and oil or condensate below, without a water drive mechanism could be produced even when the gas reaches the wellbore.

FIG. 9 General description of the contact movement versus time in three phases reservoir. A represents a general situation when a well is placed inside the oil zone, at an optimal distance from the gas-oil contact (Above) and the Oil Water contact below. During the production life, the two contacts move towards the horizontal well until one of the two will finally reach the wellbore. From that moment on that specific section of the reservoir will produce either water (C) or gas (D) leaving in both cases unproduced oil. Figure B represents an ideal situation when both gas and water reach the well at the same time, maximizing the oil recovery. In this way, all the oil would be drained but this is clearly impossible, and one of the two contacts will breakthrough before the other. When the

Confidential Page 24 water breaks through first, there will be some oil left above the well, which can be called Attic Oil. When the gas breaks through first then some oil below the wellbore will be lost, this oil could be called “Basement Oil”.

FIG. 10 – This figure represents a layout of the proposed solution in case the lateral pipe would be used to inject fluid continuously or during specific periods. The main difference in this case is that inside the main wellbore (100) there are one external liner (101) and one internal liner (106). Between the two liners flows the fluid to be injected through the lateral pipes. To prevent a bypass along the annular space between the lateral pipes and the annulus formed with the lateral holes, one or more sealing elements (104) are placed inside the lateral holes. The final part of the lateral pipes might have a slotted section (105) for a better injection of the fluid.

FIG.11 Schematic representation of a single element of the proposed solution. Every element includes a base production liner (101) inside a wellbore (100), a protection screen (107) connected to the liner with a larger diameter that creates an annular space for the flow of oil externally to the liner but protected by the screen, two sealing elements (109), a valve allowing the flow of hydrocarbon to enter the main production liner (108) and, one or more pipes extending from the main bore (103) inside lateral holes (102). The valve would allow the oil to pass but would close in case a different fluid, like water or gas, would enter the screens. Three paths for the produced fluid are possible, the main from the formation through the screens and into the liner (A), the flow from the annular between the lateral pipes and the formation (B) that would enter the liner through the same valves, and the flow inside the lateral pipes (C) that would enter the liner independently from the valve.

FIG.12 One example of the whole reservoir section divided into independent elements. A production liner (101) is run inside a wellbore (100) with sealing elements (109) that divide the liner in hydraulically independent sections. The liner is secured inside a production casing (110) with a packer and hanger (111). In every section the oil enters the liner through protection screens (107) and control valves (108). If water will arrive in a specific section, the valve will automatically close, but flow could continue from the inner section of lateral pipes (103) placed inside lateral holes (102). In this case being the lateral drilled vertically the oil could flow regardless from the water that reached the main wellbore.

FIG. 13 The figure represents a solution to control the fluid produced through the lateral metallic pipes. The oil normally enters the lateral pipes (103) placed inside the lateral channels (102) through the slotted section (105). Before entering the production liner, the flow enters a small annular chamber through the holes (113) and a sealing element (114). In the annular chamber there is also a valve (112) able to close partially or completely the flow in case the fluid would be water or gas.

FIG.14 A solution to prevent the undesired fluid from flowing up to the top of the lateral channels. One or more sealing elements (104) are placed along the lateral pipes. In this figure, the proposed solution is presented together with the fluid control for the inner part of the lateral pipes, but it could be independent of the same.

FIG. 15 In this example a water coning is induced by a high localized drawdown, forcing the valves along the main wellbore to close the direct access to the main bore. In this situation, however, with the well configuration shown in the figure, the oil can still be produced by the upper extreme channel,

Confidential Page 25

Claims (1)

1. taking in this way advantage of the attic oil, but also by the two lateral extremes of the horizontal laterals.

   FIG.16 This drawing represents a general layout of one section with three lateral channels in the case of movable water towards the main wellbore. The fluid from the formation enters the main wellbore (100) and the protection screens (107) before entering the production liner (101) through the main valve (108). In this phase oil can flow directly to the main wellbore but also through the lateral channels (102). Once the water has arrived at the main wellbore in each section, the valve will close but the flow will still be possible through the lateral pipes (103) entering the slotted section (105) placed at the extreme point of the lateral pipes. A sealing element (104) in every lateral channel will prevent the water from entering inside the lateral pipes. Once the water will have also entered the lateral channels their flow could be closed also with different valves (112) placed at the end of every channel.

   FIG.17 Possible solutions to access both Attic and Bypassed Oil.

   FIG.18 Possible solutions to increase the recovery in a thin oil rim.

   FIG.19 Possible solutions to increase the recovery in a thin oil rim expected to move upward. Having draining points at different levels will give the possibility to increase the recovery. Position of one or more sealing elements along the laterals can be chosen according to the needs

   FIG. 20 Possible solutions to increase the recovery in a thin oil rim expected to move, but without knowing in advance the direction of the movement.

   What is claimed is:

   1 - A method and apparatus for extending the production life of a well after the arrival of undesired fluid at the same well, comprising:

   • A production liner placed inside a motherbore productive formation, divided, but not necessarily, into several hydraulically independent sections by means of sealing elements; the sealing elements being placed externally of the production liner and seal against the productive formation to isolate the section of the liner and prevent undesired fluid to flow into the same section along the annular space between the liner and the formation.

   • At least one point in every section for the produced fluid to enter the liner.

   • For every entry point, one valve interrupting or decreasing the flow if formation produces undesired fluid.

   • At least one lateral pipe departing from the production liner inside a lateral well towards a part of the reservoir where the undesired fluid is not present or expected to arrive at a later stage.

   2 – The system of claim 1, further comprising at least one sealing element placed externally to the lateral pipe preventing the free flow, along the annular between the lateral pipe and the lateral channel, from a point above the sealing element and below the sealing element.

   Confidential Page 26 3 – The systems of claim 1 and 2, further comprising a valve able to close the flow through the inner part of the lateral pipe after the arrival of undesired fluid inside the same lateral pipe.

   4 – A system combining claims 1, 2 and 3 with at least three lateral holes containing three lateral pipes for every elementary section, placed two horizontally and one vertically upward, extending the production life of the well in case of premature water arrival from below and without the risk of gas arrival from above. (Fig.16)

   5 – A system combining claims 1, 2 and 3 with at least three lateral holes for every elementary section, placed two horizontally and one vertically downward, extending the production life of the well in case of premature gas arrival from above and without the risk of water arrival from below.

   6 – A system combining claims 1, 2 and 3 with at least two lateral holes for every elementary section, placed horizontally or with a little upward inclination, extending the production life of the well in case of premature water arrival from below with the risk also of gas arrival from above. (Fig.18, 19).

   7 – A system combining claims 1, 2 and 3 with at least two lateral holes for every elementary section, placed with a little downward inclination, extending the production life of the well in case of premature gas arrival from above with the risk also of water arrival from below.

   8 – A system combining claims 1, 2 and 3 with at least four lateral holes for every elementary section, placed two with a little downward inclination, and two with a little upward inclination, extending the production life of the well in case of premature gas arrival from above or premature water arrival from below. (Fig.20)

   9 – A method and apparatus for the injection of a fluid in a point at a distance from the motherbore of a well, to displace the hydrocarbon towards the motherbore, comprising:

   • a production liner placed inside a motherbore in a productive formation.

   • at least one lateral pipe departing from the production liner inside a lateral well, preferably created upwards if the injected fluid is lighter than the hydrocarbon or created downwards if the injected fluid is heavier than the hydrocarbon, to inject the fluid at a distance from the motherbore.

   • A sealing element placed externally to the main liner in the motherbore to divide the annular section in two parts, the lower dedicated to the production of hydrocarbon and the upper dedicated to the injection of the lighter fluid that is hydraulically connected to the surface by means of a dedicated gas line or simply connected to the annulus when this is filled with gas as in the gas lift solution.

   10 – The system of claim 9, further comprising an independent liner along the main motherbore, coaxial to the liner, but not limited to, to transport the fluid to be injected independently from the flow of the hydrocarbon produced.