Patent Application
20250223894
The present disclosure pertains to the technical field of oil exploration and production (E&P), more specifically to the oil recovery technologies.
The present disclosure relates to embodiments of methods of injecting water, whether captured or produced during the primary processing, into oil reservoirs with geomechanical stimulation by pressure pulse.
The oil industry seeks to continually increase the oil recovery factor in the reservoirs, and the most widely used supplementary recovery method is water injection. This water can come from the sea and aquifers, as well as from the producing reservoir itself. Currently, reinjecting produced water is necessary in several production systems, mainly due to the new requirements of the environmental legislation. However, in order to reinject this water, it must undergo a prior treatment to minimize damage to the wells and reservoir. In addition, it is always advisable to optimize the reinjection process, so that this method results in greater oil and gas production.
The Term of Commitment (TC), signed between Petrobras and IBAMA on Jan. 23, 2018, in accordance with its attributions, updated the requirements for the disposal of produced water into the sea. As a result, eight production platforms in the Campos Basin were unable to meet these new water quality parameters. Petrobras then committed to adopting technical solutions to mitigate the environmental problem and, in some stationary production units (SPUs), the solution adopted was the reinjection of produced water. In the laboratory and field tests, it was observed that the high levels of solids, oils, and greases in the reinjected water have an impact on the increase in formation damage in the injection wells, with a consequent drop in injectivity, since these particles contribute to the blockage of the pore space.
Typically, formation damage occurs in regions close to the well and is the result of the degradation of the permeability of the porous medium. A direct consequence of the increase in formation damage is the need to increase the injection pressure to maintain the injection quota, and this scenario poses risks to the integrity of the cap rock in shallow reservoirs. To mitigate these risks, the wells begin to operate with limited pressure, with a consequent loss of injection flow rate and worsening of the reservoir drainage. To restore the injectivity of the wells in the Campos Geological Basin, the already known technique of well stimulation by acidification is usually used to remove the damage, as described in patent application WO 2020/086097. This technique can be used with a dedicated vessel or remotely (from the SPU), requiring special equipment.
When the frequency of acidifications in injection wells is high, there may be some level of degradation of the subsea equipment and the structure of the wells in the medium and long term due to corrosion, potentially impacting the useful life of this equipment.
Acidification with a dedicated vessel is usually expensive and demands critical resources from the company. When an injection well is severely damaged and it is not possible to restore its injectivity due to the impossibility of immediate acid treatment, there may be a restriction on the oil production, either due to a drop in reservoir pressure or the need to reduce the stream of water and oil produced.
In this context, there is interest in developing and applying new techniques that are less expensive and do not require special equipment and critical company resources.
Based on this premise, the present disclosure proposes embodiments of methods for temporarily mitigating injection losses resulting from damage caused by water injection or reinjection of produced water. This disclosure alternately combines moments of low and high pressure in the well to promote improvements in its permeability by means of the mechanical stimulation of the unconsolidated rock formation.
As is already known, the water injection into reservoirs introduces changes in the state of stresses that can lead to fracturing of the rock in tensile mode (Mode I) and/or shear plastification. Tensile fracturing, with concomitant fluid flow through the generated fracture, is a well-known technique called hydraulic fracturing and is widely used in the oil industry to stimulate wells.
In turn, the mechanical stimulation by plastic shear is less studied, but may play an important role in the hydromechanical behavior of friable reservoirs. The plasticity theory for rocks states that the shear plastic deformation results in plastic dilation proportional to the dilation angle of the material, that is, when the shear strength of the porous medium is exceeded, the material plastically dilates, which can increase its porosity and permeability. Additionally, friable formations disaggregate when their shear strength is exceeded, resulting in the rearrangement and transport of solids, which can contribute to the mobilization of particulate agents responsible for blocking the porous medium.
Further, the importance of poromechanical phenomena during the water injection must be taken into account. Porous media with reduced pore pressure present lower fracture initiation and propagation pressures. Based on this technical aspect, the operational procedure of the present invention is designed to begin with a phase of reducing pore pressure around the well, in order to facilitate the initiation and propagation of the hydraulic fracture, maximizing mechanical stimulation.
The elastoplastic component of the shear deformation also provides an irreversible character to the mechanical stimulation. In this way, the well stimulation is supported even after the pressure reduction.
Based on the geomechanical principles described above, the proposed technique includes performing a procedure to vary the pressure and flow rate in the injection well for a certain period of time (operation referred to herein as pressure pulse), with the purpose of inducing fractures and plastic dilation in the rock formation, contributing to an increase in injectivity in the well. The operation does not require specific equipment or other process, which is a differential when compared to already known technologies.
Thus, embodiments of the disclosure act to restore the injectivity of the injection wells and the injection potential of a SPU, increasing oil and gas production. The developed technique can be applied autonomously by the SPU, therefore, with greater readiness, and without the need for dedicated equipment, support vessels or chemical products. The proposed technique also reduces the frequency or eliminates the need for acidification operations, thus mitigating potential damage to the production equipment, such as submarine pipelines, Christmas trees and injection strings.
The present disclosure provides embodiments of methods of injecting water, whether collected from the sea or produced during oil processing, into oil reservoirs with geomechanical stimulation by pressure pulse, comprising the steps of reducing the reservoir pore pressure in the vicinity of the injection well; applying a pressure pulse with the aim of inducing, in a controlled manner, fractures and plastically mobilized regions in the reservoir rock; and adjusting the flow rate and pressure of the injection well to the regular operating situation.
The wells targeted for reinjection of produced water in the Campos Basin showed a strong decline in injectivity over time. This loss of injectivity is due to at least two factors: the presence of suspended solids in the injected water and liquid particles. Both contribute to the blockage of the pore space, hindering the flow of the injected fluid.
The technique disclosed is directed to embodiments of methods that include, for example, injecting water under high pressure in a pulse of relatively short duration, compared to the injection period of the well. This technique resembles injection with fracture propagation; however, the injection time interval with fracturing of the formation (pulse) is defined in order to mitigate the risk of loss of integrity of the cap rock.
The disclosed technique involves three steps: the depressurization of the region around the well; the application of the pressure pulse; and the adjustment of the pressure and flow rate of the well for a regular operating situation.
The first step includes reducing the reservoir pore pressure in the vicinity of the injection well. Each reservoir has a different value of pressure that depends on its depth and permoporous characteristics. Such a pressure reduction can be achieved by completely shutting in the well or by reducing the injection flow rate to a pre-established minimum value, in cases where completely shutting in the well causes operational difficulties for the SPU.
The total time for shutting in or reducing the injection flow rate depends on the permoporous characteristics of the reservoir rock, and can be determined based on the history of previous injection stops.
The initiation pressure of the formation fracturing depends on the fluid pressure in the porous medium (pore pressure). The objective is to reduce the minimum total stress in the reservoir in the vicinity of the injection well, thus facilitating the subsequent geomechanical stimulation of the reservoir. Usually, in permeable sandstones (>1 Darcy) of deep water depth in the Campos Basin, a sufficient pressure drop is obtained within 1 to 3 hours of shutting in of the injection well, and in the applications carried out to date, approximately two hours of shutting in or reduction in flow rate have proven sufficient.
The second step includes applying a pressure pulse with the aim of inducing fractures and plastically dilated regions in the reservoir rock, in a controlled manner. Fracture propagation scenarios are modeled using a Geomechanics simulator in order to predict the stimulated reservoir volume. The pulse, for example, can be a rapid and controlled increase in injection flow rate and pressure for a period of time pre-established in the studies, typically in the range of 10 to 60 minutes, depending on the permoporous and geomechanical characteristics of the reservoir.
Two pulse possibilities were assessed and applied in the present disclosure, namely:
The hypothesis formulated, based on computer simulations, is that during the high pressure pulse a hydraulic fracture is created and propagated and the friable formation develops shear plastic deformation, promoting the mechanical dilation of the porous medium and transport of solids. Both combined mechanisms result in an increase in the equivalent permeability of the porous medium and, consequently, in the injectivity of the well, and in the case of the low-pressure pulse, only the shear plastic deformation and solids transport mechanisms should occur. The pressure pulse generally lasts from 30 min to 1 hour and is defined in such a way as to mitigate the risk of propagation of the hydraulic fractures to the cap rock, that is, preserving the rock cover between the hydraulic fracture and the top of the reservoir. The effect of increasing permeability lasts for a few days due to the nonlinear nature (hysteresis) of the phenomena described above.
Once the application of the pressure pulse is complete, in an embodiment of a method, the final step includes adjusting the injection well to the regular operating situation, especially with regard to the well's injection limit pressure. In this step, pressure and flow rate are adjusted according to the operational restrictions and reservoir management needs. More generally, the applicability of the low or high pressure pulse technique is defined by a specific geomechanical study for the well that assesses the risks to the integrity of the cap rock.
The graph in
This procedure has the advantage over chemical treatment using acid in that it does not require critical resources (dedicated vessel) and preserves the integrity of production equipment.
The application of the pressure pulse technique allowed an increase in flow rate in several wells while maintaining fundamental integrity requirements for the cap rocks of the reservoirs. In the first cases of application of the technique in two sandstone reservoirs in the Campos Basin, increases in injection flow rate were observed in wells that reinjected produced water. The table below shows the increments of injection flow rate for these wells after the application of the pressure pulse in procedures similar to those performed in the case of
Therefore, the average increment in injection flow rate observed was 3080 m3/d in the wells of the field 1 and 3010 m3/d in the wells of the field 2. Such increases in flow rate contributed to meeting the produced water reinjection quotas of the referred SPUs, improving their operational efficiencies and mitigating the risk of production restrictions due to a deficit in injection potential.
The technique was successfully applied in reservoirs with friable rock formations of high porosity and permeability in two offshore fields to increase the injection potential of SPUs that recently began reinjecting produced water.
Based on the obtained results, several benefits were proven by the application of the disclosure, with positive economic and production impacts for reservoir drainage, such as those listed below: i) Maintaining the reinjection quota impacts the production capacity of the SPUs. Studies conducted in deepwater fields in the Campos Geological Basin indicate increases in the flow rate of producing wells of up to 17% of the increment in water injection flow rate; therefore, the increments in water flow rate obtained with the application of the Pulse resulted in an immediate gain in oil production; ii) Savings generated by reducing the demand for acidification operations to restore well injectivity, which have high costs associated with chemical products and a vessel dedicated to the operation. The use of the technology also brings indirect gains to E&P operations, namely: i) Release of critical resources for the Company (dedicated vessels) for other operations; ii) Adequate maintenance of the injection quota and its implications field management and risk mitigation; iii) Enabling the reinjection of produced water with lower operating costs and, consequently, reducing environmental impacts resulting from the disposal of produced water at sea; iv) Maintaining the integrity of injection equipment (pipelines, WCT and well structure) by promoting a reduction in the number of acidification operations.
| Number | Date | Country | Kind |
|---|---|---|---|
| 1020240004388 | Jan 2024 | BR | national |
