SUBSEA SYSTEM AND METHOD FOR INTERCONNECTING PRODUCING AND INJECTING WELLS IN PAIRS TO AN AGGREGATING COMPONENT

Description

CROSS-REFERENCE

This application claims priority to Brazilian patent application Ser. No. 1020240037618, filed Feb. 26, 2024, which is incorporated herein in its entirety by reference thereto.

FIELD OF THE INVENTION

The present invention relates to the technical fields of oil production, lifting and flow and oil recovery technologies. More specifically, the present invention relates to a subsea system and method for interconnecting producing and injecting wells in pairs to an aggregating component.

BACKGROUND OF THE INVENTION

The subsea production system has become increasingly complex and the number of lines required to be installed is increasing, given the increase in the water depth of newer fields. This increasingly demands more from the stationary production unit (SPU) counter in terms of load capacity and, sometimes, connection positions (slots) for subsea pipelines, as well as requiring more complex subsea pipelines. These needs have led to increased costs and greater design difficulties, including difficulty in supplying pipelines, installation resources, commissioning and ramp-up time for wells and production systems. The stationary production unit is also often the critical path for the development of new fields.

Most producing wells are interconnected in a satellite fashion, containing two lines, one for production and one for service, which connect the WCT (wet Christmas tree), installed in the well, through static and dynamic pipeline sections to aggregating components, such as the pipeline connection counter to the SPU, or production or injection distribution (e.g., manifolds), or other aggregating equipment. The number of service line connection positions (slots) on the counter of the stationary production unit (SPU) affects the costs and time of naval resources for installation, as well as the construction time of the SPU.

The difficulties of interconnecting producing wells to production or injection distribution equipment (manifolds) and SPU are well known. Some of these are: the length of lines required for its design (noting that, for a single well, there are production/injection and service lines), the challenge of supplying these lines in a heated market scenario, the large number of submarine pipelines required, the costs (of acquiring pipelines and installations), the scarcity of resources available for installation, in addition to impacts on the design of the stationary production unit (SPU), such as the size of the pipeline support counter that comes from the wells and the number of PIG launchers that derive from the number of service pipelines, and impacts on the dimensioning of the manifolds, such as the increase in the structure to accommodate pipeline receptacles.

STATE OF THE ART

The state of the art includes the publication of some documents that teach about oil production technologies.

The document BR 112019015166-4 discloses a subsea system and method for pressurizing a subsea oil reservoir through injection of at least one water and gas well. The document BR 102017021444-3 discloses a subsea method for pressurizing a subsea oil reservoir through independent injection of water and gas. The digital document https://jpt.spe.org/it-hard-make-money-deep-water-even-billions-barrels-produce comprises an interconnection between two WAG injecting wells and a SPU. In these cases, the system mentioned in these documents comprises at least two subsea injecting wells, each subsea injecting well being interconnected to a production unit by means of an individual subsea line that connects to the respective subsea injecting well through a main injection mandrel and at least one jumper, each jumper hydraulically connecting two of the at least two adjacent subsea injecting wells through annular or service mandrels.

In this sense, the document BR 112019015166-4, the document BR 102017021444-3 and the aforementioned digital document deal with the interconnection of two injecting wells with the basic function of alternating injection fluids, according to the reservoir management strategy.

Although at first glance the idea of interconnecting injecting wells may resemble that of interconnecting a producing well with an injector, there is a big difference. Injecting wells, by their nature, inject fluid instead of producing, which means that the flow comes from the source, usually from the stationary production unit (SPU), towards the well. In the case of subsea systems, the wells are underwater, which means that the flow is downward between the SPU and the well. In this scenario, there is a factual need for only one pipeline or interconnection between the source and the well, precisely the conductor of the fluids to be injected. In this case, the service pipelines connected to injecting wells have a secondary, and not essential, function of facilitating the flow guarantee.

In its turn, producing wells, also by force of their nature, produce instead of injecting. In the context of subsea wells, this means having to overcome the gravitational forces contrary to the flow so that the fluid from the well can reach the SPU and these forces reduce or make the production of the wells unfeasible in some cases.

The methods used to overcome this challenge are known as artificial lift methods. The most commonly used method among these is gas lift, in which a gas flow stream is used to reduce the hydrostatic fluid column and change the flow parameters of the production stream in order to make production viable or achieve higher flow rates. The gas lift method requires a second connection to the well from a pressurized gas source to the well, which requires an interconnection or pipeline from the source (usually the SPU) to the well.

A second method, currently less common, is the use of subsea pumping. Although, at first glance, it does not seem necessary to have a service pipeline connected to the well in this case, its need arises from the limitations of the operating envelope of the pump, which may eventually be exceeded by variations in production flow parameters that may diverge significantly from forecasts or even by the extension of useful life. In addition, the high investment cost of this alternative in relation to gas-lift means that the risks of flow assurance are even greater due to the impact on economic analyses. A third aspect also occurs in this method, the still relatively high failure rate of subsea pumps, which implies low availability of the pumping system, which may mean a large intermittency of production, something that implies greater risks of flow assurance and lower potential viability of producing wells without an artificial lift alternative.

These characteristics of this second artificial lift method imply the high importance of a service pipeline, whether simply to improve flow assurance or to establish an alternative artificial lift method through gas lift.

Added to this is the fact that the fluids produced vary over time in their composition and flow parameters, often in an unpredictable manner, impacting the flow regime and, consequently, the risks of flow assurance. Thus, the service pipelines connected to the producing wells acquire an even greater importance than those service pipelines that are connected to the injecting wells.

Thus, the lack of a service pipeline associated with a producing well drastically reduces its potential viability, especially in contexts of high water depths.

The interconnection between a producing well through the interface that would receive a service pipeline from the SPU is, therefore, normally understood as something that can make the motivations for its existence unfeasible, something that does not occur for the interconnection between a pair of injecting wells. In this context, the existence of a WAG Loop is more easily conceivable than the existence of a pair between a producing well and an injecting well, so much so that the aforementioned documents BR 112019015166-4 and BR 102017021444-3 are limited to talking about the interconnection of injecting wells.

The document US2010307765 discloses a method for improving crude oil recovery from a crude oil-bearing formation and utilizes an integrated sour gas injection system that injects a first fraction of an available volume of sour gas through a sour gas injecting well into the formation and a second fraction of the available volume of sour gas as a lift gas to a crude oil producing well traversing the formation at a selected distance from the sour gas injecting well to inhibit early passage of sour gas from the formation to the producing well. The solution proposed by US2010307765 is related to improving oil recovery through sour gas injection (wells rich in H2S and CO2) through the interconnection between wells producing H2S and CO2, which differs from the invention being proposed.

The document US20100307765 differs from the present invention in that it refers to a method of injecting acid gas for Enhanced Oil Recovery (EOR). Furthermore, the solution proposed by US20100307765 is related to improving oil recovery through injection of acid gas (wells rich in H2S and CO2) through interconnection with wells that produce H2S and CO2. Additionally, the solution proposed in US20100307765 has a series of limitations for offshore applications, including solutions for cleaning production lines (PIG), the possibility of exchanging the fluid injected by the injecting well (Water or Gas), and facilities for combating hydrate in production or injection lines (bilateral depressurization).

The document BR 112021011258-8 discloses a subsea manifold for a subsea production system comprising at least one removable module, and methods of installation and use. The removable module is configured to perform a function selected from the group comprising: fluid control, fluid sampling, fluid divergence, fluid recovery, fluid injection, fluid circulation, fluid measurement and/or fluid dosing.

The document BR 112021011258-8 concerns the patent for a new subsea manifold model, which controls fluid, measures fluid and allows intervention through removable modules. The solution aimed to reduce the complexity of pre-existing subsea manifolds, eliminate the need for total recovery of the manifold in case of need for intervention through the inclusion of removable modules, mitigating the impacts on the availability of the subsea system. However, the application of this new manifold model still implies the need for additional equipment such as the Manifold itself, PLETs and Spools, in the event of new discoveries. Depending on the positioning of the new wells, this may lead to a non-optimized or even unfeasible subsea layout.

On the other hand, the present invention does not concern the manifold, but rather, as a system, the interconnection between a producing well and an injecting well. In addition, the present invention does not require additional equipment and enables optimization of the subsea layout by reducing CAPEX, without increasing OPEX or increasing the complexity of the system, guarantees high reliability, availability and maintainability of the system, allows the use of already standardized equipment (WCTs), and ensures greater flexibility to the project by being more suitable for the case of new discoveries.

Therefore, there are still evident deficiencies in the state of the art. In view of these deficiencies, the characteristics and advantages of the present invention will clearly emerge from the detailed description below and with reference to the attached drawings, which are provided only as preferred and non-limiting embodiments.

BRIEF DESCRIPTION OF THE INVENTION

The present invention discloses a subsea system for interconnecting producing and injecting wells in pairs to an aggregating component, which comprises: at least one production line, which connects the aggregating component to an oil, gas or oil and gas producing well, at least one water, gas or alternating water and gas injection line, which connects the aggregating component to an injecting well, and at least one service line, which connects the producing well and the injecting well. Furthermore, the present invention discloses a method for interconnecting producing and injecting wells in pairs to an aggregating component, characterized by comprising the steps of: interconnecting a producing well with the production aggregating component, interconnecting an injecting well with the injection aggregating component, and interconnecting the injecting well with the producing well.

BRIEF DESCRIPTION OF THE FIGURES

The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee.

In order to complement this description and obtain a better understanding of the characteristics of the present invention, the following figures are shown.

FIG. 1 illustrates a schematic of a satellite well from the state of the art.

FIG. 2 illustrates, according to the state of the art, a subsea system and method for pressurizing a subsea oil reservoir.

FIG. 3 illustrates a simplified example of a subsea system for interconnecting producing and injecting wells in pairs to an aggregating component.

FIG. 4 illustrates, in greater detail, an example of a subsea system for interconnecting producing and injecting wells in pairs to an aggregating component.

FIGS. 5A and 5B illustrate a simulation of a subsea arrangement and respective arrangement of risers on a counter without the implementation of the present invention.

FIGS. 6A and 6B illustrate a simulation of a subsea arrangement and respective riser arrangement on a counter with the implementation of the present invention.

FIG. 7 illustrates a comparison of the lengths of lines resulting from the use of a non-crossing assumption in a simulation compared to the absence of this assumption.

DETAILED DESCRIPTION OF THE INVENTION

The present invention relates to a subsea system and method for interconnecting producing and injecting wells in pairs to an aggregating component. More specifically, as illustrated in FIG. 3, a preferred embodiment of the invention consists of interconnecting a pair of wells composed of an injecting well (water and/or gas) and a producing well (oil and/or gas). The interconnection of the producing well to the injector occurs in a fluid manner through a connection interface of both wells. An example of this fluid form is the use of pipelines/lines (jumper). This interconnection can be done through the Christmas tree (WCT) of the respective injecting and producing wells or other well flow control equipment.

During the basic design of a project in the pre-salt region with rigid pipelines, it was observed that there was a need to interconnect a producing well that would later become a WAG injecting well. When studying the alternatives with the aim of reducing costs, it was proposed to interconnect it in advance to a WAG injecting well, in the same way as would be the case for a WAG Loop. As detailed in the prior art section, this was not a trivial proposition, as it involved a series of issues that needed to be addressed, the solutions for which were not available.

The issues then began to be addressed one by one to make this type of interconnection viable. From the point of view of subsea engineering, the following issues were evaluated, among others.

The pressure class of the lines: which should be able to handle the pressures of the activities not only of the well as a producer, but also with the pressures that would come from the other well, in the event of a containment failure, as well as with the pressures derived from the fluid exchange, hydrate mitigation and cleaning procedures. This led to the understanding that, in a conservative way, this could be addressed by considering intrinsically safe pipelines at operating pressures, increasing the pressure class of the production pipeline. Production pipelines often have lower pressure classes than the pressure classes of the injection pipelines. Given that each project would have a different range of pressure classes for its pipelines, the possibility of increasing the pressure class of the production pipelines would depend on the availability of pipelines with an adequate pressure class and their type. Typically, rigid pipelines also allow the pressure class of the production pipelines to be increased to match that of the injection pipelines.

Pipeline pressure classes typically vary according to specific project variables. As an example for illustrative purposes, we can imagine two different projects (A and B). The first project (A) has a producing well and an injecting well in the same permeable reservoir with communication. The production pressure is derived from the fluid flow from the pressure of the producing zones, which are similar to those of the injecting zones in this case; thus, with the pressure drop and pressure loss due to gravity between the producing zones and the wellhead, the producing well sees a lower pressure from the wellhead to the aggregating component, which have higher elevations than the elevation of the producing zones, which is the pressure that a priori defines the pressure class of the production line; in the case of injection pressures, there is a need for the injection pressure in front of the injecting zones to be higher than the reservoir pressures (without this there would be no injection). This implies that the pressure at the wellhead needs to be higher than the pressure at the front of the injection zone in this project (A) and from there to the aggregating component as well, due to the same phenomena that affect the production flow, but in the opposite direction, causing the pressures defining the pressure class of the injection lines to be higher than the pressures defining the pressure classes of the production lines. The application of an interconnection between the two producing wells in project (A) must take into account a potential increase in the pressure class of the production lines. In the hypothetical project (B), there is a similar situation, but with segregated reservoirs with the pressure in the injecting well reservoir below the pressure in the producing well reservoir. In this case, the pressures that a priori would define the pressure class of the injection pipeline would be lower than the pressures that would define the pressure class of the production pipeline. In both hypothetical projects, the recommendation would be to match the pressure class of the pressure ducts with the pressure class of the production ducts to form the interconnected producer and injector pair. In project (A), this would mean increasing the pressure class of the production ducts while in project (B) this would mean increasing the pressure class of the injection ducts.

Gas supply for gas lift: this was one of the most important challenges, given the economic issue, which motivated the proposed change. Three different solutions were proposed for this issue: simply not using gas lift, using gas lift without injection in the WAG injecting well through the injection circuit and service pipeline that would connect both wells, and using a choke valve in the injecting well in order to share the injection gas with the gas to be used for gas lift. For the historical case, the alternative of not using gas lift was preferable in light of the production parameters of the well and the costs of handling the subsea system to an alternative of interconnecting two satellite wells (one producer and one injector).

Fluid migration was also a concern, since, if there was an interconnection between the producing and injecting wells, process fluids from one could migrate through the circuit to the other. In this case, a strategy of differential pressurization of the shut-off valves of adjacent circuits was adopted in order to prevent the propagation of fluids from one well to the other when inopportune. This was necessary given the small window of non-tightness that some valves present at low pressure differentials (something in the order of 5% of the nominal design pressure value of the valve, but which depends on the specific project and may be less). By deliberately pressurizing the side opposite to the unwanted fluid to a pressure whose differential exceeded this window, not only would there be a seal, but also, in the event of seal failure, migration of the pressurized fluid to the process fluid. By periodically monitoring the inventory of pressurized fluid, it was possible to ensure that this propagation was prevented.

Hydrate mitigation was an important concern, given the abstraction of the main means from which hydrate remediation and circulation of fluids for commissioning and decommissioning of wells for hydrate prevention would be carried out. However, such circulations could be carried out through the circuit formed between the wells, and commissioning and decommissioning procedures could be carried out even independently of the presence of the complete circuit with the addition of diesel injection, for example, and hydrate inhibitors at points of greater risk. However, the availability of the system for production and injection should be reviewed due to the greater risks in the latter cases and the need to use the closed circuit through the paired well in the event of the need for hydrate remediation, especially in the case of hydrate in the injecting well.

The PIG passage, whether for inspection or cleaning, could be carried out through the circuit formed by the pair of wells and, depending on the circuit, it could be considered doing so without stopping simultaneous injection and production. The different geometry of the circuit did not differ significantly from the case of satellite wells from the point of view of the PIG.

Injection Fluid Exchange is a typical procedure for water and gas injecting wells, and could require stopping production in the producing well in order to prevent hydrate in the injection circuit when exchanging water for gas. However, it could still be done in the case of the present invention, taking care to prevent hydrate and mitigate fluid migration. SCC—CO2—Stress Corrosion Cracking by CO2 (SCC—CO2) was something that could not be forgotten. With rigid pipelines in the lines that connected the wells to the SPU, the focus was on the one that connected the pair of wells, which would be flexible. The treatment to prevent fluid migration served as a mitigating factor for the SCC—CO2 phenomenon since it allowed a reduced partial pressure in the annulus of the flexible pipelines. Furthermore, by applying the same strategy to prevent fluid migration, the effect of SCC—CO2 could be mitigated for the lines between the well and SPU, as they were flexible. The case of the present invention distinguishes from the state of the art due not only to the different well configuration but also to the fluid exchange procedures and flow assurance that this fact entailed.

Closing the Circuit was initially understood as problematic, given that it would be necessary to close the entire circuit before the start of production and injection of the pair of wells. However, two ways of getting around this situation were discovered. The first is to make a prior interconnection between the wells, if they were already constructed when one of them was interconnected, in order to gain a section of the circuit through which some operations could be carried out. This scenario would be quite unprecedented and restricted, however, given the need for previously established control in both wells. The second would be through commissioning the wells only with their own line, which could be done with a diesel injection procedure, for example, and hydrate inhibitors at points of greater risk.

To overcome the challenge of forming a pair of a producing well with an injecting well, therefore, a series of iterations had to be carried out, of analyses, formulation of hypotheses, consultations with specialized areas and development of solutions for the specific case. The result of this work was understood as extensible to other projects, given the high similarity with several other subsea systems of the initial configuration before the proposal for the interconnection of the pair of producing and injecting wells.

It will be appreciated that the invention can be generally applied to the development of pre-salt and post-salt fields, and other fields with producing and injecting wells. More specifically, the invention is applicable to any oil and/or gas production field development project that foresces water and/or gas injection and has the potential for greater gains in cases where there is a high oil and gas ratio (OGR) or a lower probability of using artificial oil lift with gas injection in the well column (gas-lift).

By applying the system and method of the present invention, the number of service line connection positions (slots) on the counter of a stationary production unit (SPU), for example, can be reduced in proportion to the number of wells that adopt the configuration (for example, if there are 12 wells, 12 fewer connection positions (slots), the number of service pipelines is substantially reduced and most of the subsea service pipelines are eliminated. This reduces costs with the purchase of pipelines, reduces the supply bottleneck, reduces the time of naval resources for installation and substantially relieves the project as a whole, including reducing the counter of the stationary production unit (SPU), which directly translates into the weight of the unit and manufacturing costs.

Furthermore, this innovation would make it possible to reduce the connection positions (slots) of the arrival pipeline counter at the stationary production unit, bringing, among other benefits, in addition to those mentioned above, a reduction in the construction time of the stationary production unit (SPU), which is usually a bottleneck in production development projects. There is no increase in production test restrictions, control complexity, reduction in the potential of the wells, nor exposure of the producing wells to some risks associated with other producing wells, as in the case of adding intermediate production distribution or injection equipment (manifold) as an alternative solution.

Nevertheless, it will be appreciated that the SPU or FPU can be replaced, from the architectural point of view of the subsea system of the present invention, by another set of components that aggregate production, injection and fluid exchange operations, such as a subsea manifold, for example, without prejudice to the applicability of this invention.

Furthermore, it will be appreciated that there is no restriction on the type of Christmas tree (WCT) that is installed in the wells, as long as they have the capacity to be interconnected with each other. Therefore, an additional cross-over valve upstream of a Christmas tree (WCT) block is not even necessary for the system and method of the present invention to be applicable. However, if a cross-over valve is used, this may bring additional gains.

It will be appreciated that the interconnection of the pair of injecting wells and producing well of the present invention can be carried out by means of the annular hubs or service of the respective wells. Furthermore, it will be appreciated that activities related to commissioning for the start-up of the wells, cleaning, eventual fluid changes, passage of PIG, depressurization and other subsea and flow assurance operations can be carried out by the interconnection (pipeline) of the pair of injecting wells and producing well.

Furthermore, the interconnections between the producing well, the injecting well and the aggregating element and the interconnection between the pair of production and injecting wells must, preferably, have a pressure class compatible with the pressure requirements of a production line and injection line, and also physical and chemical stability in relation to the fluids of the production line and injection line, for example, resistance to corrosion and erosion. These requirements can be waived by introducing control and safety elements, such as safety instrumented systems (SIS).

FIG. 4 illustrates in greater detail possible components of an embodiment of the system of the present invention for better understanding through a hypothetical concrete case, with the elements highlighted here being: connection interface of the producing well (PROD) with the aggregating component (1) for production (P), illustrated with an optional flow blocking valve (P), connection interface of the producing well with the injecting well (2) for injection (I), connection interface of the injecting well (INJ) with the aggregating component (3), illustrated with an optional flow blocking valve (P), connection interface of the injecting well with the producing well (4), connection interface of the aggregating component with the producing well (5) and connection interface of the aggregating component with the injecting well (6). In FIG. 4, typical components of a well completion are also illustrated for merely illustrative purposes: a pigging valve (PXO) in each well, master production valves and access to the well annulus (M1 and M2, respectively), cross-flow valve (XO), intervention valves (S1 and S2), flow block valves (W1 and W2). For merely illustrative purposes, in FIG. 4 a typical well completion sensor (PDG) is illustrated.

In an alternative embodiment of the present invention, a configuration is provided that allows the injecting well to be the gas provider for the gas lift of the producing well. In this configuration, in case of need for artificial oil lifting with gas injection into the well column (gas lift), one can consider using subsea flow control valves (subsea chokes) to partially divert the gas from the injecting well to the producing well through the interconnection line between them (loop).

In another alternative embodiment of the present invention, it is envisaged to perform artificial lifting oil with gas injection into the well column (gas-lift) through umbilicals integrated with service pipelines (ISU-Integrated Service Umbilical) or a dedicated line in the electro-hydraulic umbilical (EHU) of smaller diameter than the umbilical integrated with the service pipeline (ISU-Integrated Service Umbilical), if possible.

In another alternative preferred embodiment of the present invention, a different model of production adapter base (PAB) with four hubs is envisaged to allow artificial lifting of oil with gas injection into the well column (gas-lift). This would be an intermediate case, with reduced gain, but being able to combine this with a subsea gas injection distribution equipment (MSIG) or gas-lift ring for injecting gas into the well column (gas-lift) or artificial oil lift trunk line with gas injection into the well column (gas-lift), or another aggregating production and/or injection and/or fluid exchange system.

The present invention also discloses a method for interconnecting producing and injecting wells in pairs to an aggregating component comprising at least the steps of:

• • a) interconnecting an interface of a producing well (1) with a production aggregating component (e.g., SPU or Manifold) (5);
  • b) interconnecting an interface of an injecting well (3) with the injection aggregating component (e.g., SPU or Manifold) (6); and
  • c) interconnecting the injecting well interface (4) with the producing well interface (2).

It will be appreciated that the above method comprises a series of steps that can be rearranged among themselves as long as the logical and physical precedences of the system previously discussed are respected.

A person skilled in the art will appreciate the advantages arising from the subsea system and method for interconnecting producing and injecting wells in pairs to an aggregating component of the present invention. In a non-exhaustive manner, some of these advantages will be addressed below.

Depending on the characteristics of the interconnected wells (one producer and one injector), the results of this interconnection are directly associated with benefits to the subsea system, the topside, the reservoir management and drainage strategy, and the subsea operation itself.

Notably, the proposed configuration directly impacts optimizations in the subsea project. This configuration brings greater flexibility to the subsea system, since the solution can be implemented using both rigid and flexible lines or some other combination. According to the simulation performed using a typical arrangement design and tabular calculation software, there is a significant gain resulting from the use of the system and interconnection method of the present invention for several aspects, which are better than or exceed those shown by systems and methods of the state of the art.

The present invention enables, among other advantages, the following.

Reduction in the number of dynamic pipelines (risers) of around 50% compared to a project with only satellite wells to the SPU.

Reduction in the number of supports in the SPU of around 50% for pipelines compared to the project with only satellite wells. The reduction in supports allows the optimization of the SPU design by reducing the structure required to support the submarine pipelines interconnected to it.

Reduction in the number of static pipelines of around 30% compared to the project with only satellite wells.

Reducing the limitation on pipeline and umbilical crossings can increase the gains with the reduction of static pipelines.

Reduction in the acquisition costs of pipelines in the case of adopting the system and method of the present invention in the same order as the reduction in the quantities of dynamic and static pipelines.

Reduction in interconnection times for the interconnection method in the same order as the reduction in the quantities of dynamic and static pipelines.

Reduction in interconnection costs for the interconnection method of the present invention in the same order as the reduction in the quantities of dynamic and static pipelines.

Reduction in the amount of diving required for interconnection activities in the case of adopting the interconnection method of the present invention due to the reduction of supports in the SPU and in proportion to the order of magnitude of the reduction of supports to the connection of the pipelines in the SPU.

Reduction in the time for wells to start operating, given that the interconnections between the pairs of producing and injecting wells can be made without the presence of the aggregating component, without competing with the operations of interconnecting the pipelines to this aggregating component and not limited to WAG injecting wells.

Reduction in pipeline inventory, reducing the potential environmental impact of oil and gas leaks in proportion to the reduction in pipeline lengths. Not limited to WAG wells or to the gas inventory.

Reduction in dynamic failure points due to the reduction in the number of dynamic pipelines, resulting in greater reliability and less exposure to environmental risks due to failure in them.

Furthermore, it will be appreciated that the use of the system and method of the present invention would also bring savings in the abandonment of wells, due to the reduction of their scope.

Results of Gain Simulations

Gain simulations were performed to illustrate the potential of implementing the system and method of the present invention, comprising the interconnection of producing and injecting wells in pairs through a simulation in a virtual environment.

The simulation took into account a typical case of a production development project with a stationary production unit (SPU) of the FPSO (Floating Production Storage and Offloading) type at Petrobras in a water depth (WDL) of 2,000 meters with rigid and flexible pipelines. It is important to note that the application of the system and method of the present invention in the simulation universe is merely for illustrative purposes of the gains, does not consider gas export and, since it is a simulation, the data are approximate.

Initially, the characteristics of the project to be simulated were defined as follows.

The project for this simulation has an FPSO producing 180 thousand barrels of oil per day, in a field with a high GOR (gas-oil ratio), which means that there is no need to use gas lift as an artificial lifting method. The oil is not very viscous and the distance to the wells is not long, so artificial pumping methods (e.g., boosting) are not required. The field is being developed with 12 wells, 6 of which are producers and 6 are WAG injectors.

For a 2000-meter LDA, the rigid pipelines should have a dynamic pipeline length of approximately 3300 m (riser), both for water and gas injection and for oil production. The service pipelines and umbilicals would have a dynamic pipeline length of 2800 m (riser).

The application of the design practice of avoiding pipeline and umbilical crossings was also considered. It is important to note that this practice, although recommended, leads in many scenarios to an increase in the length of static pipelines due to the need to contour structures to avoid crossings.

An initial simulation, without using the present invention, was performed as a control. In this simulation, current standard circumstances were used in which the WAG injecting wells are connected in pairs and the producing wells are connected in satellite fashion with the FPSO.

In this simulation, the subsea arrangement would be as illustrated in FIG. 5A. In this figure, the green spheres indicate producing wells and blue spheres indicate WAG injecting wells. Furthermore, green lines indicate rigid oil production pipelines, blue lines indicate umbilicals and orange lines indicate flexible service pipelines.

With such an arrangement, the counter of the unit would look like this, with 30 necessary positions, without considering reserve positions, as seen in FIG. 5B.

On the other hand, in a simulation with the implementation of the system and method of the present invention, in which the injecting wells are connected to the producing wells in pairs, a subsea arrangement as illustrated in FIG. 6A was obtained. In said figure, the green spheres indicate producing wells and blue spheres indicate WAG injecting wells. Furthermore, green lines indicate rigid oil production pipelines, blue lines indicate umbilicals and orange lines indicate flexible service pipelines.

An important observation regarding the subsea arrangement in FIG. 6A is that the arrangement considers the non-crossing of static pipelines and umbilicals. This implies a configuration that considerably increases the lengths between wells P6 and I2, as illustrated in the comparison in FIG. 7. Such a condition limits the potential simulated gains with material reduction, which would be greater if such a condition were not necessary for the simulation.

However, with such an arrangement, the counter of the unit would be as illustrated in FIG. 6B, with 24 necessary positions, without considering reserve positions.

Based on these results, immediate and derived gains can be observed with the implementation of the system and method of the present invention. Below we summarize the gains, classifying them according to the following aspects:

• • Economic/Productivity;
  • Health/Safety;
  • Reliability;
  • Environmental.

The immediate gains in the case of using the present invention are derived from the submarine arrangement itself.

Reduction of dynamic pipelines (risers), in quantity and length, going from 33.6 km to 16.8 km in length of pipelines and umbilicals, reducing the quantity and length of dynamic pipelines (risers) (from 16.8 km to zero) in service. This implies a percentage reduction of around 50% in length.

Reduction in the number of positions required in the SPU pipeline support counter, with these positions being less likely to motivate a reduction in the dimensions of the counter or an addition of reserve positions to the project, or both, in inverse proportion to each other.

Reduction in the number of static pipelines (flowlines) for most pairs of wells. Since the design is conceptual, the length variations with the route are approximate. The approximate gain was around 30% in length reduction. It is important to note that this gain could have been even greater if the non-crossing premise had not been used, as previously explained. The approximate variation for each set of wells is:

• • P2, P3, I3, I4: reduction of around 40% (8.5 units of length to 5 units of length);
  • P1, P6, I1, I2: increase of around 80% (4.5 units of length to 8 units of length);
  • P4, P5, I5, I6: reduction of around 60% (12 length units to 5 length units).

Furthermore, in addition to these immediate gains, there are other first and second order gains.

Reduction in interconnection times of at least 30%, with a greater reduction in the case of the reduction of dynamic pipelines (risers) which typically take longer to be launched due to several characteristics of these differentials, especially flotation accessories (e.g., buoys), which take a significant amount of time to be installed.

Reduction in costs due to the reduction in the quantity of materials required to execute the project in the same order as the reduction in the length of the pipelines.

Reduction in pipeline inventory, reducing the potential environmental impact of oil and gas leaks in proportion to the reduction in pipeline lengths.

Reduction in dynamic failure points by reducing the quantity of dynamic pipelines (risers), resulting in greater reliability and less exposure to environmental risks of leaks due to falling dynamic pipelines (risers).

Reduction in the amount of diving required for connection and disconnection activities (pull-ins and pull-outs) of dynamic pipelines (risers), resulting in reduced exposure of HH to this risky activity, one of the most dangerous in the industry.

Reduction of risks associated with the supply of pipelines for the execution of the project.

Reduction in the time taken for wells to start operating, since the interconnections between them can be made without the presence of the production unit and without competing with operations to interconnect the pipelines to the production unit.

Therefore, although there are some potential specific increases in pipeline length, the system and method of the present invention show significant gains in the overall calculation and in several aspects for the typical subsea project shown. The economic aspect of these gains is quite significant, although there are also non-negligible gains in other aspects, such as environmental, reliability and safety aspects.

Preferred Embodiments of the Invention

A preferred embodiment discloses a subsea system for interconnecting producing and injecting wells in pairs to an aggregating component, which comprises:

• • at least one production line, which connects the aggregating component to an oil, gas or oil and gas producing well;
  • at least one water, gas or alternating water and gas injection line, which connects the aggregating component to an injecting well; and
  • at least one service line, which interconnects the producing well and the injecting well.

Wherein the production line, injection line and service line have a pressure class compatible with the pressure requirements of the production line and injection line, and also physical-chemical stability against the fluids of the production line and injection line.

The aggregating component may be a production unit or a subsea manifold.

The injecting well may comprise a set of flow control valves for partitioning the gas flow between the producing well and the injecting well.

There is at least one service line interconnecting the injecting well and the producing well by means of respective annular or service hubs. In addition, the service line circuit may comprise a blocking mechanism, such as a gate valve, to isolate the fluids inside the service line in relation to the producing well and the injecting well.

Another preferred embodiment discloses a method for interconnecting producing and injecting wells in pairs to an aggregating component comprising at least the steps of:

• • interconnecting a producing well with the production aggregating component,
  • interconnecting an injecting well with the injection aggregating component, and
  • interconnecting the injecting well with the producing well.

Wherein the method may further comprise a step of partitioning a flow between the producing well and the injecting well by means of a set of flow control valves of the injecting well.

Wherein the method may further comprise a step of isolating fluids in the service line in relation to the producing well and the injecting well by means of actuating a blocking mechanism in the service line circuit.

Those skilled in the art will value the knowledge being shown and will be able to reproduce the invention in the modalities shown and in other variants, covered by the scope of the attached claims.