Water Breakthrough Research Articles

MODELING TOOLS USED FOR OPERATIONAL FIELD DEVELOPMENT MANAGEMENT

The increase in the share of hard-to-recover reserves increases the need to use modern technologies in the development of oil fields to increase the efficiency of reserves development. One of the tools for identifying zones with hard-to-recover reserves is the geological and hydrodynamic model, which allows simulating various geological and technical measures carried out on production and injection wells. It is possible to lay down both predicted and already carried out measures for testing hypotheses and making decisions on field development. In this work, we have considered the area where the problem of premature water flooding of products has been identified from a certain period of time. After an analytical review of the site, a theory was put forward about the source of water flooding. In the analyzed area there is also a horizontal well, which is not currently in operation. The well was fractured immediately after drilling. The well was put into operation with a high water cut and shut down, and no crossflows were detected during additional field geophysical surveys. In terms of indirect parameters (properties of produced water, pressure, parameters during hydraulic fracturing), the created fracture overcame the clay bridge and created a hydrodynamic connection with the underlying aquifer. Based on the analysis, a theory was put forward that the formation water of the lower aquifer along the fracture of the frac migrated to the zone of extraction of the productive oil formation due to the large difference in the current formation pressure between the facilities. The hypothesis is confirmed by calculations on the hydrodynamic model. Several options were proposed at the end of the site to slow further water breakthrough to the production wells. Among them, the injection of various polymer-based compositions into a horizontal well is a «source».

Experimental Investigation on Layer Subdivision Water Injection in Multilayer Heterogeneous Reservoirs.

Layer subdivision is currently one of the principal techniques employed to solve interlayer contradictions during water injection in multilayer heterogeneous reservoirs, but experimental research on the mechanism and the corresponding implementation plans is lacking. In this study, a multilayer heterogeneous core model was designed, and physical simulation experiments with different subdivisions and variation coefficients were conducted. Furthermore, the influence of the subdivision degree on the water injection development effect was analyzed, and the dynamic characteristics of the oil displacement of each sublayer were compared. Finally, the boundary standard of the layer subdivision was discussed. The results demonstrate that the water breakthrough appears rapidly in the high-permeability layer, and water channeling is easily formed after water flooding. The remaining oil is mostly retained in the low-permeability layer. Layer subdivision water injection can effectively reduce the high water cutoff and improve the oil recovery. The oil recovery increases with the layer subdivision degree, while the incremental rate decreases gradually. The low-permeability layer is observed to be the main layer contributing to the increase in the total recovery of multilayer reservoirs, with a contribution rate that initially increases and subsequently decreases with the increasing subdivision degree, from 0.9 to 11.9, and 29.8%, and subsequently drops to 15.1% during the general water injection with 2-, 4-, and 8-layer subdivision mining. The heterogeneity variation coefficient of 0.55 is used as the subdivision standard to divide different permeability layers to be developed as 1 layer in the multilayer heterogeneous reservoir.

A New Method to Predict Water Breakthrough in Intelligent Completion Horizontal Well

A New Method to Predict Water Breakthrough in Intelligent Completion Horizontal Well

Research on Segmentation Methods of Horizontal Wells

To equalize the inflow profile of horizontal well and reduce the influence of water breakthrough, the horizontal well should be divided into several sections. The problem of horizontal well segmentation can be classified into two types. The first one is how to segment with sufficient data, and the second one is how to segment with insufficient data. For the former, three segmentation methods have been proposed, named uniform segmentation method, ordered clustering segmentation method, and optimization segmentation method. In this study, for further indicate the application scope and condition of these three methods, the advantages and disadvantages of each method are fully studied. For the latter, the influence of reservoir parameter uncertainty should be considered. In this study, the segmentation method based on robust optimization is proposed to solve this problem. Assume that the horizontal well could be divided into 5 segmentations. For horizontal wells with sufficient data, three segmentation methods are discussed and compared through reservoir simulation. Results show that, in terms of cumulative oil production, the optimization segmentation method is the highest, followed by the ordered clustering segmentation method, and the uniform segmentation method is the lowest. In terms of simulation time, the optimization segmentation method is the longest because the optimal segmentation scheme will be found after iterative simulation. The ordered clustering segmentation method and the uniform segmentation method do not need iterations, so the segmentation scheme could be determined quickly. Therefore, if the computational cost is available, the optimization segmentation method is recommended; if not, the ordered clustering segmentation method is recommended. For horizontal wells with insufficient data, the segmentation method based on robust optimization proposed in this study has been proven to be effective, because the cumulative oil production of this method is greater than that of the uniform segmentation method. In conclusion, the segmentation strategies for horizontal wells with sufficient or insufficient data are presented and discussed. It will contribute to the completion design of horizontal well. Meanwhile, it will also help to delay water breakthrough and enhance oil production.

Исследование неоднородности упругих свойств массива горных пород в подземных условиях по глубине методом ультразвукового каротажа

In recent decades, in the world practice there is an increased interest in conducting mining operations in the fields using a combined mining method. This approach allows for more efficient extraction of minerals from the depths of the earth, and helps reduce environmental damage to our planet. Despite such obvious advantages, one should not lose sight of the fact that the risk of unforeseen hazardous situations arising due to complex natural geological, geomechanical and mining conditions of deposit development also increases, as well as the mutual influence and technological interrelation of open-pit and underground mining. Neglecting these factors can even lead to a technogenic disaster, as happened at the world notorious kimberlite deposit of the Mir pipe. At this deposit, in the process of underground mining, the cracks formed in the safety pillar, through which an uncontrolled breakthrough of water subsequently occurred into the underground mine workings from the quarry. Monitoring the condition of rocks in the area of the safety pillar and taking preventive measures in advance will reduce the risk of recurrence of such catastrophic events in fields with difficult development conditions. Analysis of scientific and technical literature showed the prospects of using geophysical methods to study the characteristics of rocks and identify weakened zones in the massif. The main advantages include the ability to study the environment without violating its integrity and the efficiency of conducting research. The problem being solved is to predict possible zones of disturbance in the massif, which affect the efficiency and safety of mining operations, while traditional studies are often insufficient for such analysis. The use of ultrasonic logging for local depth studies in the vertical wells provides reliable results due to the high accuracy of determining the elastic properties of rocks, sufficient to identify heterogeneities in the massif and predict possible zones of feeding cracks.

Identifying the influence of basalt fiber reinforcement on the deformation and strength characteristics of cement stone

The object of the research is the quality of cementing oil and gas wells with increasing the strength and deformation capacity of cement stone using basalt fibers. Cement slurry used in cementing oil and gas wells faces the problem of failure under the influence of hydraulic fracturing and perforation procedures. This failure leads to the formation of cracks and may require remedial cementing, which increases operating costs and complicates the process of oil and gas production. Moreover, this problem can lead to premature well water breakthrough and cause serious damage such as oil and gas shows and blowouts, which poses a threat to the environment and safety. To solve the problem of the destruction of cement stone under external influences, the study proposed the approach of reinforcing with basalt fiber. During the study, a cementing material based on Portland cement, reinforced with various concentrations of basalt fibers (0.1 %, 0.5 %, 1 % and 2 %), was developed and tested. Cement strength tests at 2, 7, and 14 days, along with deformation monitoring under load, were performed. The addition of basalt fibers to cement stone significantly improved its strength characteristics. The most successful results were achieved with the addition of 0.5 % basalt fibers, resulting in an 11 % increase in compressive and flexural strength. Basalt fibers complement the structure of cement stone, increasing its ability to deform. One of the key features of the obtained results is the possibility of improving the strength of the cement stone without losing its fluidity as a cement slurry. The results obtained are applicable in the development and production of cement materials based on basalt fibers. This will improve the quality of well cementing and reduce the risks of complications

Oilfield sustained-release tracers based on different binding forms and their controlled-release mechanism

The problem of water breakthrough in horizontal wells is serious, so it is urgent to use sustained release tracers predict and monitor the time and position of horizontal wells. In this paper, the physically bonded epoxy resin-based slow-release tracer and the chemically bonded isocyanate-linked sustained release tracer were prepared using sulfosalicylic acid as the core material. The release and key characteristics of the two sustained-release tracers at different temperatures and salinities were discussed by observing the morphological changes and release curves. The results showed that both the sustained release rate and cumulative release were positively correlated with temperature and salinity, and the epoxy resin-based sustained release tracer had obvious burst release phenomenon due to physical blending. Isocyanate-linked slow-release tracers greatly reduce burst release. The cumulative release of the isocyanate-linked slow-release tracer at 85 °C is about 1%, while the cumulative release of the epoxy resin-based slow-release tracer is about 3%. Obviously, the chemical combination is better than the physical combination. At the same time, the possible controlled release mechanism was confirmed, and the controlled release mechanism of the epoxy resin sustained-release tracer was mainly tracer diffusion. The controlled release mechanism of the isocyanate slow-release tracer is the synergistic effect of polymer degradation and tracer diffusion, and its explanation is helpful for the sustained release tracer system required for horizontal well effect monitoring.

Hybrid Framework for Enhanced Dynamic Optimization of Intelligent Completion Design in Multilateral Wells with Multiple Types of Flow Control Devices

Multilateral wells (MLWs) equipped with multiple flow control devices (FCDs) are becoming increasingly favored within the oil sector due to their ability to enhance well-to-reservoir exposure and effectively handle unwanted fluid breakthrough. However, combining various types of FCDs in multilateral wells poses a complex optimization problem with a large number of highly correlated control variables and a computationally expensive objective function. Consequently, standard optimization algorithms, including metaheuristic and gradient-based approaches, may struggle to identify an optimal solution within a limited computational resource. This paper introduces a novel hybrid optimization (HO) framework combining particle swarm optimization (PSO) and Simultaneous Perturbation Stochastic Approximation (SPSA). It is developed to efficiently optimize the completion design of MLWs with various FCDs while overcoming the individual limitations of each optimization algorithm. The proposed framework is further enhanced by employing surrogate modelling and global sensitivity analysis to identify critical parameters (i.e., highly sensitive) that greatly affect the objective function. This allows for a focused optimization effort on these key parameters, ultimately enhancing global optimization performance. The performance of the novel optimization framework is evaluated using the Olympus benchmark reservoir model. The model is developed by three intelligent dual-lateral wells, with inflow control devices (ICDs) installed within the laterals and interval control valves (ICVs) positioned at the lateral junctions. The results show that the proposed hybrid optimization framework outperforms all industry-standard optimization techniques, achieving a Net Present Value of approximately USD 1.94 billion within a limited simulation budget of 2500 simulation runs. This represents a substantial 26% NPV improvement compared to the open-hole case (USD 1.54 billion NPV). This improvement is attributed to more efficient water breakthrough management, leading to a notable 24% reduction in cumulative water production and, consequently, a 26% increase in cumulative oil production.

Insights into the intimate link between nonlinear rheological characterization and the rupture behavior of polymer gel in model fractures

A deep understanding of how fluid flows through the polymer gels has significant implications for achieving effective gel treatments in fractured reservoirs. This study aims to investigate the behavior of brine breakthrough from the gels in model fractures and relate the rupture behavior to the rheological properties of the gels. The underlying mechanisms for different gel rupture behavior are also elaborated. The effect of the injection rates, the aperture of tubes, and the gel properties on the rupture pressure of the gel were also studied. The results show that the rupture pressure of gel is highly dependent on the flow rates, and the rupture pressure is decreased with increasing the aperture sizes. It is also found that the polymer gel with a higher amount of crosslinkers has a high G’ value yet exhibits a low rupture pressure. From the visualization experiments, we found that brine is more likely to penetrate through the gel along the weak network structures, and a narrower channel would be formed at a higher injection rate. Moreover, various rheological measurements were conducted to characterize the gel properties. The results reveal that the maximum differential pressure the gel can withstand is highly dependent on the microstructure and the toughness of the gel. The defect structures, such as large cavities or cracks, would lead to a low yield stress of polymer gel, which is more susceptible to fracturing. The texture properties of the polymer gel can be interpreted by the shapes of Lissajous curves. The flexible gel shows a “banana-shaped” curve at high strain, a typical response for rubber-like materials. The toughness of the gel can significantly improve the pressure for water breakthrough. The degree of the brittleness of the polymer gels can be characterized by the reduction rate of the maximum elastic stress. The results presented in this study allow us to select an appropriate gel for water shutoff in fractured reservoirs by rheological methods, which are more robust and cost-effective.

Retrofitted Autonomous Inflow Control Devices Optimize Completions Design

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31301, “Optimized Completions Design Using Retrofit Autonomous Inflow Control Devices,” by Ezinne A. Nnebocha, Schlumberger; Akinola Akinbola, NPDC; and Omagbemi G. Kayakor, First Hydrocarbon Nigeria, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ Discovered in 1964, the Beta Field in the Niger Delta sedimentary basin consists of 25 stacked hydrocarbon-bearing reservoirs between 5,500 and 12,000 ft true vertical depth subsea (TVDSS). Oil production peaked at 8,900 STB/D shortly after field startup and has been on the decline. Two horizontal wells, Beta 7 and Beta 8, were planned in the field, but a production forecast of the planned wells showed potential early water breakthrough and high water cut. Autonomous inflow control devices (AICDs) were deployed successfully in the Beta Field for the purpose of minimizing water production and maximizing oil recovery. Introduction After history matching, the two new horizontal wells were simulated to target the sweet spots in the reservoir using constraints of oil saturation, porosity and permeability limits, and distance to the oil/water contact (OWC). The history-matched model was then used in forecasting the production profile for the new wells using a target liquid production rate of 2,000 STB/D. The production forecast without inflow control showed water breakthrough in the new wells within the first month of production, reaching to 45% within 3 months of production. Cyclonic AICD completions then were simulated for Beta-7 and Beta-8 horizontal wells, which showed improved oil production and delayed water production. AICD Retrofit Design Cyclonic AICDs were selected for application in the Beta Field to improve production performance. However, the short lead time required for the job execution and border closures caused by the COVID-19 pandemic created restrictions in mobilizing personnel and equipment from outside the country. It did not appear that the equipment could arrive in time for the job. The conventional nozzle-based passive ICD joints were available in country. Therefore, leveraging engineering skills and operational knowledge, a solution to retrofit AICD nozzles in existing ICD screen joints was conceived. The engineering team developed a design of machined components that could be quickly manufactured at the facility of the original equipment manufacturer (OEM) and shipped to the location. Failure-mode and effects-analysis assessment, and subsequent risk-management procedures, became useful to manage the process locally with the help of the remote OEM team. A step-by-step procedure on the retrofit was devised. Fig. 1 shows a flow chart used to guide the retrofitting process and the retrofitted AICD joints after modification. Upon completion of the screen retrofit, the joints were quality-checked and inspected to verify their preparedness for well completion.

The Water Problems and Treatment Strategies of Volcanic Gas Reservoir in Daqing

In order to realize the development strategy of “stabilizing oil and increasing gas and simultaneously boosting oil and gas”, Daqing Oilfield has continuously strengthened the exploration and development of deep natural gas resources since the discovery of Xushen gas Field. The volcanic gas reservoir is the main gas producing area of Songliao Basin. Through “internal excavation and external expansion”, natural gas production has maintained a trend of growth for 12 consecutive years. However, due to the development of fractures and bottom water in volcanic gas reservoir, the development contradiction caused by gas well water is increasingly prominent as the gas field development enters the end of stable production stage. Therefore, on the basis of the understanding of four types of effluent water in volcanic rock reservoir, this paper carries out the analysis of the production dynamic characteristics of typical gas wells, and identifies the difficulties faced by gas wells with different types of effluent water. Through field tests, economic and feasible treatment measures are explored, including continuous circulation gas lift of strong water breakthrough gas well in fracture vertical direction, intelligent foam drainage gas production of weak water breakthrough gas well in fracture vertical direction, and deep water unlocking of gas well in pore vertical water cone and gas reservoir with high water saturation gas reservoir effluent water, which provides technical support for the sustainable and efficient development of volcanic gas reservoir.

Clogging of induced fracture to increase waterflood sweep efficiency

Waterflooding of low-permeable reservoirs with high pressure is often accompanied by formation of induced fracture. The positive side of this process is an injectivity increase and oil production rise. However, when these fractures approach producing wells, an early water breakthrough occurs, and high productivity channels are formed between the injection and producing wells. The technology of fracture clogging, for example, by suspension composition injection into an injection well, allows reducing the length of the fracture. The paper considers the problem of the fracture size reducing process on the waterflood sweep efficiency. The example of a reverse five–point waterflood pattern was investigated. In the basic calculation run, fracture length was constant during all process. The run with transformable fracture length is compared with the basic one. The results of calculations showed that the process of waterflooding after fracture impact could be divided into the following stages. The first one, which follows immediately after the fracture clogging, demonstrates a water cut decrease and an oil production rate increase. The second, in which the oil production declines below the base variant. On the third stage, there is a low, but long-term increase in oil production due to increased waterflood sweep efficiency. The authors established that monitoring of induced fractures length is relevant, since timely fractures clogging allows to increase oil production after the well treatment and to incline the oil recovery coefficient through increasing waterflood sweep efficiency.

Prediction of water breakthrough during waterflooding under unstable water displacement front conditions

Unsteady modifications of waterflooding technologies are usually used as the main technique of reservoir pressure maintenance and enhanced oil recovery in the development of hydrocarbon fields. The disadvantages and imperfections of the conventional approach remain even after wide application of geological and hydrodynamic mathematical modeling and its truncated modifications, including proxy models, synthetic models and other simplified versions. At this stage it was not possible to achieve a fullfledged unification of waterflooding technology, because the theory of two-phase flow filtration created by Buckley-Leverett does not allow taking into account the influence of instability of the displacement front and its negative consequences, provoking a jump change and triple water saturation. This study attempts to return to the solution of this problem and proposes an alternative concept of monitoring and optimization of unsteady waterflooding of oil deposits, taking into account the consequences of instability of the front of oil displacement with water. Keywords: water flooding; water saturation; instability of the displacement front; optimization; catastrophe theory; phase plane.

CRM-Aquifer-Fractional Flow Model to Characterize Oil Reservoirs with Natural Water Influx

Summary This work presents a new flow model that uses production data to characterize conventional undersaturated oil reservoirs with natural water influx in primary production. The main application is to estimate the original oil in place (OOIP), but the model also calculates the productivity index (PI), water influx, and heterogeneity factor. Aquifers are common to many reservoirs and their diagnosis is relevant because they can serve as an important drive mechanism but can also affect well productivity. Discerning between the reservoir and aquifer volumes is also a major challenge in many oil fields. Reservoir-aquifer systems have been investigated with various dynamic characterization techniques such as the material balance equation (MBE), pressure transient analysis, and production/rate transient analysis. These methods have limitations, for example, requiring shut-in wells and/or very large production histories and high mobility and compressibility ratios to yield distinguishable responses in the diagnostic plots. The new flow model couples the producer-based capacitance resistance model (CRMP) with the Fetkovich aquifer model (CRMPA). It enables calculating the total instantaneous production flow rate from a well as a function of three mechanisms—reservoir depletion, changes in bottomhole pressure (BHP), and water influx. In addition, CRMPA is coupled with the Koval fractional flow model (capacitance resistance aquifer-fractional flow model, CRMPAF) to calculate the individual oil and water rates and to enhance the OOIP estimation for wells with two-phase production caused by water breakthrough from the aquifer. The capacitance resistance model (CRM) is a production analysis technique that uses rate and pressure data from typical field surveillance (no dedicated tests) to characterize reservoir properties. It has been widely used to study reservoirs under secondary and tertiary recovery. There are a few applications for primary recovery, and only one reference investigated natural water influx. There are important differences between the previously published and the new CRMPA formulations. The former estimated the individual water influx to each well in a multiwell reservoir associated with an aquifer. The calculations were performed assuming the reservoir pore volume (PV) was known, whereas the present approach simultaneously calculates the PV and the water influx. The former approach also required a priori knowledge of the average pressure, obtained from buildup tests, whereas the new method uses production data, (i.e., it does not require shut-in wells). In the new approach, CRMP (without aquifer) is first used to calculate the capacitance/resistance (CR) parameters of the equivalent (reservoir-aquifer) medium. It provides the correct OOIP for volumetric reservoirs; however, CRMPA is used when the PV significantly differs from volumetrics and water influx is detected. CRMPA calculates the reservoir CR parameters using simple relationships between the equivalent and composite mediums. For wells with two-phase production, the Koval factor is an additional parameter. The CRMPA/F solution is obtained by minimizing the errors between the calculated and measured rates over a time window. The new CRMPA/F approach is compared and validated with several models of single and multiwell synthetic reservoir-aquifer systems with different properties and geometries. It is also used to characterize a field case.

Performance Analysis of Water Injection Well BEL-13 and Production Well BEL-01 Using Hall Plot and Buckley-Leverett Methods

At first, the FLO field had an ability to flow fluids to the surface in a natural flow, but the production capacity decreased with time. Therefore, production is increased using the waterflooding method. The purpose of this study was to analyze the performance of waterflooding carried out on injection well BEL-13 and production well BEL-01. There are two methods used in this study to achieve the desired aims and objectives, namely the Hall Plot method and the Buckley-Leverett method. The Hall Plot method was used to see the connectivity conditions between injection and production wells after being injected with water periodically. Whereas the Buckley-Leverett method was used to estimate the time of water breakthrough, production amount (Np), the injection rate (Wi), water cut value (WC), and recovery factor (RF). Based on the Hall Plot method, it was found that the waterflooding carried out was stable or normal because there was no negative skin or positive skin. In addition, based on relative permeability curve, rock wettability of the reservoir rock is water wet. Analysis using Buckley-Leverett shows that the cumulative production at the time of water breakthrough from the injection well BEL-13 to the production well BEL-01 is 364,733.64 STB. When the water breakthrough occurs, the predictions of WOR, water cut, and recovery factor are 2.13, 68.08%, and 29.76%.

Research on numerical simulation of water breakthrough characteristics and influencing factors after oil reservoir plugging to determine the variation pattern of water cut in such reservoirs: a case study of Y oilfield

This study focused on the water breakthrough issue that still occurred after water shutoff using gel plugging agents. Taking the heavy oil reservoir with edge-bottom water in the Y oilfield as an example, the study investigated the water cut variations after water shutoff and analyzed the types of water breakthrough characteristics in the wells of this reservoir. The CMG numerical simulation software was used to study the influence of geological parameters on the water cut variations after water shutoff. The research findings revealed that the water breakthrough characteristics in all the treated horizontal wells were classified into low water cut breakthrough, pulse-type breakthrough, step-type breakthrough, and high water cut breakthrough. Additionally, it was observed that horizontal wells in different geological conditions exhibited distinct water breakthrough characteristics under the same water shutoff process conditions. Through numerical simulation and statistical analysis of field data, the main factors influencing the variation of water cut after water shutoff were identified as reservoir permeability, oil saturation, interlayer position, water avoidance height, injection-production well distance, oil viscosity. The research findings allowed for the prediction of water breakthrough characteristics after water shutoff or the analysis of reservoir structure configuration based on known water breakthrough characteristics.

Evaluation of Effects of Waterflooding-Induced Bilayer Fractures on Tight Reservoir Using Pressure-Transient Analysis Method

Summary Waterflooding will open natural fractures to form induced fractures, which differ from hydraulic fractures because the hydraulic fracture is filled with proppant but the induced fracture is not. Natural fractures are connected by waterflooding. However, because the waterflooding pressure is limited, induced fractures cannot run through the entire reservoir but instead form multiple parallel induced-fracture bands in the vertical direction. Currently, using conventional finite-conductivity methods to match field data will obtain unreasonable results, especially the half-length, conductivity of fracture, and reservoir permeability, which lead to the water breakthrough, which cannot be found in time. This paper presents the waterflooding-induced bilayer fracture (WIBF) model, considering induced-fracture dynamic closure (IDC), dynamic induced-fracture storage (DIS), and induced-fracture radial flow (IRF) effects. Two innovative flow regimes are interpreted, which are dynamic induced-fracture flow and early radial flow regimes. Five innovation parameters are introduced into the WIBF model to describe the IDC, DIS, and IRF effects. The WIBF model is calculated and solved by the Green equation and Newman product methods. Induced-fracture storage coefficient and half-length closure equations are derived to characterize the unique induced-fracture properties. Analytical and numerical methods verify the model’s accuracy. The WIBF model matches a type field case to prove its practicability. Results show that compared with the conventional finite-conductivity model, the proposed model matches the field case well and the interpreted parameters are consistent with the water injection profile and actual field data. The pressure derivative curve shows an early horizontal line, identified as a pressure response of bilayer-induced fractures. If the flow regime is misidentified as pseudoradial flow, some obtained parameters will be absurd, and permeability will be amplified many times. In conclusion, physical and mathematical models are established to describe induced fracture. Induced-fracture storage coefficient and half-length equations are derived. Model matching and equation calculation methods are mutually validated to improve the accuracy of the obtained parameters. Dynamic induced-fracture half-length is interpreted quantitatively to make the engineer take action before the water breakthrough. The model in this paper also provides some parameters for infilling well patterns or determining well spacing economically.

Water alternative gas (WAG) optimization for a heterogeneous Brazilian pre-salt carbonate reservoir

Abstract Water alternating gas (WAG) is a cyclical process that involves alternating water and gas injections with the primary goal to improve sweep efficiency by maintaining initial high pressure, slowing water and gas breakthrough, and lowering oil viscosity. The objective of this work is to apply and optimize a WAG strategy on a carbonate field with light oil, compare it to the initially planned water-flooding strategy, and investigate the capability of WAG to improve field production. In this research, a compositional reservoir simulator was used to model a WAG process by injecting produced gas into the reservoir, using the same well structure as an optimized water-flooding strategy. Subsequently, a WAG strategy was created, optimizing the number and locations of wells, to facilitate a comparative analysis of the two recovery methods. The WAG optimization involved a detailed assessment of variables such as bottom hole pressure (BHP), WAG cycle duration, maximum gas oil ratio (GOR), and well positioning, to achieve a high net present value (NPV). The study focuses on the application of WAG optimization modeling in unconventional reservoirs, specifically pre-salt carbonate reservoirs, and investigates its implications on production strategy and forecast, emphasizing its potential for maximizing NPV and oil recovery in a recently producing field. The results showed that WAG improved reservoir performance when compared to water injection and produced a greater amount of oil. This solution showed potential to be tested under uncertainties (reservoir heterogeneity, faults, fractures, karsts, vugs, etc.) as future steps.

Characterization of Extra Low-Permeability Conglomerate Reservoir and Analysis of Three-Phase Seepage Law

The micro distribution of residual oil in low-permeability sandstone reservoirs is closely related to pore structure, and the differences in pore structure often determine the reservoir’s productivity and development effectiveness from a macro perspective. On the basis of in-depth research, this paper analyzes the distribution law of the remaining microscopic oil, establishes the digital core multi-stage pore network modeling of the strongly sorted heterogeneous conglomerate reservoir in the Lower Wuerhe Formation of Block 8 of the Karamay Oilfield, the three-phase seepage simulation method considering the release of dissolved gas, and the three-phase permeability curve test. The research results are as follows: (1) Conventional physical property analysis shows that the permeability of core samples exhibits an inverse rhythmic distribution with layer depth. (2) CT core analysis and mercury injection experiments indicate that the area with porosity ranging from 9% to 21% accounts for 79% and is the main seepage channel area. Larger pores play an important role in seepage. (3) Through comparative experiments on cores with different permeability, it was found that the degassing phenomenon of low-permeability rock samples is more severe. In the actual process of reservoir development, it is necessary to reasonably handle the impact of water injection on development effectiveness, select appropriate water injection methods and cycles, and avoid premature water breakthrough in ultra low-permeability reservoirs.

Pressure-Transient Behavior of Vertical Wells Considering Dynamic Water Hammer and Dynamic Induced Fracture: Theory and Case Studies.

Water injection can result in the creation of induced fracture by connecting natural fractures. The induced fracture penetrates the entire reservoir, leading to the interconnection of injection and production wells and ultimately resulting in water breakthrough and the abandonment of production wells. During well work, the induced fracture exhibits dynamic behavior characterized by extension and closure, known as the dynamic-induced fracture phenomena. During the shut-in process, fracture closure phenomena are often accompanied by water hammer phenomena, which can be detected bottom hole pressure data. However, numerical simulation methods are difficult to describe their dynamic processes. Therefore, we urgently need a mathematical model to fill this gap. In this work, we developed a waterflooding-induced dynamic fracture (WIDF) model. Dynamic water hammer phenomena, multi-dynamic closure phenomena, and fracture storage phenomena are introduced into the WIDF model to describe the induced fracture dynamic behavior. Field cases demonstrate that the WIDF model can improve the accuracy of interpreted parameters and correct incorrect model selection. Green function and Newman product method are used to characterize single-phase water flows within tight reservoirs. Then, the induced fracture is discrete into N segments through the boundary element method. Discrete-induced fractures are divided into n parts. Based on the induced fracture bending property, conductivity variation is independent in each part. The feature line method is used to solve the pressure response of the dynamic water hammer. The Duhamel principle is applied to couple the storage effects and reservoir pressure response. The Laplace transform method transforms the model into Laplace space so that it can be solved easily, and the Stehfest numerical inversion method transforms the model into real space to obtain the final solution. Our results show that the dynamic water hammer flow (DWH) regime with an oscillation curve and the multi-dynamic closure flow (MDCF) regime with peaks exist on the type curve. Resistance coefficient (f) and inertia coefficient (I) control the DWH regime. Fracture storage coefficient (Cf), dynamic fracture closure rates (Delpatm), and induced fracture closure half-lengths (xdfm) control the MDCF regime. It is worth noting that the peak position can be adjusted by the Delpatm and xdfm parameters, achieving a more accurate match to the field cases. The Cf is identified, which corrected for the amplified wellbore storage coefficient. Obtained permeability is also in a reasonable range of permeability for tight reservoirs. In summary, a series of mathematical methods are used to develop and solve an injection well model to identify the dynamic behavior of the induced fracture. Numerical simulation methods are used to verify the accuracy of the WIDF model. Two field cases from X Oilfield demonstrate the practicability of the WIDF model. Dynamic identification of the induced fracture would help engineers develop appropriate injection schemes to prevent water breakthroughs.