Heavy Oil Field Research Articles

Adaptability Study of Hot Water Chemical Flooding in Offshore Heavy Oilfields

As a new heavy oil development technology, hot water chemistry flooding has great potential in offshore heavy oil fields development. In this paper, the adaptability of hot water chemical flooding was studied based on the typical model of offshore heavy oil fields. The main controlling factors affecting the hot water chemical flooding were analyzed and evaluated by single factor analysis. The technical boundary was established for offshore heavy oil fields. In addition, the hot water chemical flooding scheme was designed by a case study of a well group oilfield D. The results indicate that crude oil viscosity and well spacing have great influences on hot water chemical flooding performance. Hot water chemical flooding is favorable when the crude oil viscosity is between 300 and 1000 mPa·s and well spacing is around 200~400 m. The hot water chemical flooding scheme of the target well group results in 40.2 × 10 4 tons of incremental oil, and 6.3% of recovery factor being enhanced, which shows strong evidence that hot water chemical flooding enables great oilfield development performance.

Laboratory experiments of in situ combustion in core samples with simulated fractures

In situ combustion is one of the oldest enhanced oil recovery methods usually applied to heavy oil fields to improve recovery. In this process, air or oxygen-enriched gas is injected into a reservoir, burning some of the oil in place and generating heat and combustion gases. A considerable fraction of heavy oil resources resides in naturally fractured systems. There is no reported successful application of in situ combustion in a field with fractured systems in the literature to date. There is a limited number of studies regarding the subject in the literature. Thus, fundamental understanding of the process in fractured systems is limited.In this study, laboratory experiments of in situ combustion in core samples with the presence of fractures were conducted. A total of 12 combustion tube experiments were conducted with 12° API heavy oil from the Bati Raman field in Turkey. These experiments differ in their configuration of fractures and oxygen concentration in the injected gas. Based on our experimental observations three distinct behaviors were observed regarding front propagation through fractured systems. The first type is strictly diffusion-limited, the second type is characterized by a thick combustion front and the last is homogenous behavior. These observations could provide a fundamental basis for possible field applications of in situ combustion in fractured systems.

Study Reviews ESP Performance in High-Viscosity Applications

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31839, “Understanding ESP Performance Under High-Viscosity Applications and Emulsion Production,” by Luiz Pastre, SPE, Jorge Biazussi, and William Monte Verde, University of Campinas, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ Despite its common use as an artificial lift method for heavy-oil developments, electrical-submersible-pump (ESP) system performance in high-viscosity applications is not fully understood. Failure to understand challenges to equipment performance in such conditions can lead to operational inefficiency and equipment failures. The complete paper presents results of single-phase and multiphase tests performed by researchers at the University of Campinas. It also presents operational data, lessons learned, and examples of failures gathered over 10 years of ESP operation in the Peregrino field, a highly viscous, heavy-oil field offshore Brazil operated by Equinor. Peregrino Field The field was discovered in 1994 in the southern part of the Campos Basin offshore Brazil. The discovery lies in shallow waters approximately 120 m deep in Block BM-C-7. Although a large amount of recoverable oil in place (300 million– 600 million bbl) was confirmed, the technology to properly develop the field was not available. A detailed development plan was created to optimize Peregrino heavy-oil production while considering drainage strategy and well design. Recovery and production are maximized in Peregrino by extending the reservoir section length. As a result, every well in Peregrino is drilled with a long horizontal section inside the reservoir and completed with openhole gravel-pack lower completions. This strategy resulted in the longest wells in Brazil, with a record of 8613 m measured depth (MD) total length, with 2272 m MD in the horizontal section. To improve the effectiveness of sand control and avoid solids production, gravel is pumped to fill the annular space between the 8½-in. openhole section and the 5½-in.-outer-diameter screens. Inside the reservoir, water flows at a much higher velocity than viscous crude does. Therefore, inflow control devices are deployed in the lower completion to limit water flow into the wellbore at selected wells. To make gravel-pack operation feasible in such a configuration, sacrificial screens are installed in the bottom of the lower completion string. An artificial lift method is required to produce the heavy and viscous oil from the field and maintain commercial rates when pressure support and production declines. ESPs proved to be the most-efficient method for this application.

Features of geological structure heavy oil field complicated palaeovalley (P-N)

The geological study of reservoirs of heavy oil confined to the deposits of the Sheshma horizon, for further involvement of deposits in pilot production, is an expensive project in itself due to the high viscosity of oil from 200 to 200,000 MPa∙s and changes in the depth of the productive formation from 100 up to 500 m. It’s advisable to exclude all kinds of factors, including geological ones, leading to additional costs in the development of heavy oil deposits in an unstable economic situation. The purpose is determining of impact palaeovalley on the efficiency of wells using the example of heavy oil deposits. For the analysis authors have applied, materials the estimation of reserves, laboratory researches and macro descriptions of the core, the results of structural and geomorphological studies, and development parameters. It is viewed heavy oil deposits of the Sheshma horizon, complicated by palevalley, and geological structure. The porosity-permeability properties and characteristics of the bedding are given. The authors’re determined areas of palaeovalley the drilled wells, a macro description of the core and cuttings in the palaeovalley part are given. Zones of deconsolidation of the Upper Permian terrigenous deposits are identified by results of structural and geomorphological studies. A comparison of the map of predictive fracturing with the map of Pliocene formations characterizing the genesis of the palevalley is made. The authors’re comparisoned the operational capabilities of wells with the location of the wellhead in the palaeovalley zone and outside the palaeovalley. Recommendations for the design of horizontal wells complicated by palaeovalleys are determined.

Reservoir Properties Alteration in Carbonate Rocks after In-Situ Combustion

Summary This study summarizes the work conducted as a part of laboratory modeling of in-situ combustion (ISC) experiments on cores from carbonate heavy oil fields. Porosity, permeability, fluid saturation, thermal, and geochemical properties are crucial characteristics of the target field defining the performance of the combustion technology. Here, we report the changes in reservoir properties, porous structure, and mineral composition of the rock samples induced by the thermal exposure and registered by a set of standard and advanced experimental techniques. Most combustion tests are conducted on the crushed core pack, which does not accurately represent the reservoir properties. In this paper, we present the results of three combustion tube tests (classic ISC and consecutive hot-water treatment ISC) involving actual field core samples. Gas porosimetry, nuclear magnetic resonance (NMR), and microcomputed tomography (μCT) revealed an increase in total porosity and pore size distribution and enabled visualizing the changes in the porous core structure at nano- and microlevels. X-ray diffraction (XRD) and scanning electron microscopy (SEM) demonstrated the change in mineral composition and lithological texture as a result of dolomite decomposition; Rock-Eval pyrolysis and elemental analysis were utilized to confirm the changes in the rock matrix. Optical scanning registered the changes in thermal conductivity (TC) of samples, which is important for numerical modeling of the combustion process. The proposed core analysis has proved its efficiency in providing a complete petrophysical description of the core of a heavy oil carbonate reservoir in the framework of evaluation of the ISC application for dolomite-rich carbonates and demonstrated the different responses of rock to the ISC technology.

Displacement Characteristics and Produced Oil Properties in Steam Flood Heavy Oil Process

Thermal recovery is one of the most effective techniques for viscous oil production, which has been widely used in the heavy oilfield development. The mechanisms and percolation characteristics of thermal recovery have attracted a lot of attention. However, the displacement characteristics and produced oil properties in the steam flood heavy oil process are rarely addressed. In this paper, steam flooding experiments with two heavy oil viscosities under the temperatures from 120 to 200 °C and velocities from 1 to 3 mL/min were carried out to examine the oil displacement efficiency and the produced oil properties. The results show that the majority of the oil is produced in the low water cut stage. Temperature increment is helpful for prolonging the water breakthrough time. The high injection velocity of steam contributes to a high recovery factor, even if it enters into the high water cut stage. The rheology of the produced oils severely changes because the SARA composition changes, and emulsification occurs during the steam flooding heavy oil process. With the increasing steam temperature, the relative content of resins in the produced oils decreases, and asphaltenes increase. With the increase in the injection volume and the injection velocity of steam, the content of resins and asphaltenes increases. This leads to an increment in the produced oil viscosities. The effect of injection velocity on the rheology properties of the produced oils increases with temperature increment. The finding of this work will provide the technical support for heavy oilfields development.

Characterization and Origin Analysis of Heavy Oil in the Western Sag of the Liaohe Basin.

This article systematically examines the physical characteristics, group composition characteristics, and geochemical characteristics of heavy oil in the Western Sag of the Liaohe Basin. The examination is based on the separation and quantitative analysis of crude oil and rock samples, as well as the analysis of test results from gas chromatography with saturated hydrocarbons and aromatic hydrocarbons. It also analyzes the generation mechanism and main controlling factors of heavy oil. The results show that heavy oil has low wax content (1.8–9.2%), a low freezing point (−19–38 °C), low sulfur content (0.28–0.5%), high colloid and asphaltene content, high density (0.926–1.008 g/cm3), and high viscosity (328–231910 mPa·s). The physical properties of the heavy oil in the same formation decrease from the depression’s edge toward its center and within the same area, and the physical properties in different formations also have an inverse relationship with burial depth. Biodegradation is the main reason for the formation of heavy oil. Based on the biodegradation degree, there are four types of heavy oil: undegraded, weakly degraded, moderately degraded, and severely degraded. The main controlling factors of biodegradation are temperature and the water environment. This study provides a method for studying the genetic mechanism of heavy oil, an approach for discovering similar genetic oil and gas, and a basis for the transformation of heavy oil field development.

Study of the applicability of foam for steam conformance control to conditions of the Karazhanbas field

Thermal enhanced oil recovery methods are a traditional approach in the primary and secondary development of heavy oil fields. Despite the effectiveness of such methods, there are breakthroughs of working fluid into production wells due to the presence of high permeability channels, resulting in a sharp increase in the watercut and an increase in the bottom hole temperature.
 The article presents a literature review of the world experience in application of various steam conformance control methods. Based on the literature review, the applicability of foam systems at the Karazhanbas field was studied; core flood experiments were carried out to determine resistance factor and displacement efficiency. Obtained results confirm the formation of foam in reservoir conditions by increase in injection resistance during its filtration through core sample and visually at the outlet, the increase in displacement efficiency was 17,41%. The scientific novelty of the work lies in the study of the applicability of steam conformance control technology based on foam, which has not been previously studied and tested at any field in Kazakhstan.

ВЛИЯНИЕ УСЛОВИЙ ФОРМИРОВАНИЯ ВОДОНЕФТЯНЫХ ЭМУЛЬСИЙ НА ИХ СТРУКТУРНО-МЕХАНИЧЕСКИЕ СВОЙСТВА

Abstract. The Republic of Kazakhstan is one of the leaders in the production of hydrocarbons. However, the oil produced in Kazakhstan, especially from the Severnye Buzachi oil and gas field, has a high viscosity and, therefore, belongs to the category of unconventional resources with a high content of metals associated with asphalt-resinous components. This problem is common to all countries producing oil in the Caspian basin. Analysis of the development of the Severnye Buzachi oil and gas field indicates a sharp increase in water availability at the initial stage of development, which is due to an excessively large difference in the rheological characteristics of reservoir oil and water. As a result, an oil-water emulsion is formed at the bottom of the well and in the trunk, which can acquire many different states with various physical, mechanical and technological properties. A significant number of works have been devoted to the study of the properties of oil-water emulsions. Oil in the Caspian basin is characterized as viscous and heavy with a high content of metals, especially vanadium and nickel, which interact in oil with asphalt-resinous components. These properties of oil reduce oil recovery. These properties and methods of optimizing oil production were considered on the basis of the North Buzach oil and gas region of the Republic of Kazakhstan. The structural and mechanical properties of water-oil emulsions of crude oil have been experimentally studied. Based on the measured parameters, the shear stress values were calculated at the shear rate of the walls, and then flow curves were constructed for different temperatures and oil-water ratios. As a result, the regularities of changes in rheological properties depending on the water content and temperature were revealed and a formula was obtained that allows determining the values of the effective viscosity complex of oil-water emulsions. Based on the results obtained, optimization of technological modes of oil preparation for further transportation and processing in different periods of operation can be carried out in this area. Keywords: oil-water emulsion, demulsification, rheology, heavy oil, oil and gas field, Northern Buzachi, resins, asphaltenes, emulsifier, reagent, turbulence, flow, experimental studies, viscosity.

Improvement of Steam Injection Efficiency in Horizontal Well with the Semi-Analytical Model: A Case Study of Liaohe Oilfield Steam Injection Well

As China’s largest heavy oil field, Liaohe oilfield encounters many problems after long-term thermal recovery, including high water percentage at early production stage, steam channelling and water cresting. To solve the above problems, the steam flow behavior and thermal characteristics in horizontal well should be understood. In this paper, a semi-analytical model is proposed to investigate the thermal properties and heat losses along the steam injection horizontal wellbore. The flow pattern is determined by the modified Beggs-Brill method and different conservation equations are incorporated to calculate the steam pressure, steam temperature and steam quality. The model shows good consistency with the field data of the horizontal steam injection well in Liaohe oilfield. The sensitivity analysis shows that the steam quality along the wellbore is strongly affected by the steam pressure, steam injection rate and steam quality at the heel. Generally, the steam injection rate does not have significant effect on steam pressure, steam temperature and steam quality. The model is then used to optimize the injection parameters of Well XH27 to improve the steam injection efficiency. After optimization, more steam is injected to the formation to heat the region near the wellbore, which leads to a higher production rate. In summary, this study presents a semi-analytical model to calculate the thermal properties of steam and the model can be used to optimize steam injection process for field application.

Waterflooding of Heavy Oil Reservoirs

Waterflooding or polymer flooding is sometimes dismissed as an ineffective process for heavy oil fields, with development plans focused on more exotic and expensive recovery mechanisms such as chemical or thermal processes. There are a number of unique mechanisms that operate in heavy oil fields under water and polymer flood. It is, therefore, possible to succesfully flood heavy oil reservoirs with viscosities up to and beyond 10,000 cp oil viscosity. This work elaborates on the unique mechanisms operating in heavy oil water and polymer floods, presents a workflow for successfull implementation and supports its conclusions with a number of case studies, namely, actual successful field examples from Canadian heavy oil fields. The hope is that, this experience can be translated to heavy oil fields in other parts of the world including Turkey.

Mathematical Modeling and Pilot Test Validation of Nanoparticles Injection in Heavy Hydrocarbon Reservoirs

Heavy-oil mobility in reservoir rocks can be improved, using nanotechnology, by reducing the viscosity of the oil and improving the rock wettability to a water-wet condition. Previous pilot studies in Colombian heavy oil fields reported that nanoparticles dispersed in an oleic carrier fluid (diesel) increased oil production rates between 120–150% higher than before the interventions. However, to optimally deploy a massive nanofluid intervention campaign in heavy oil fields, it is valuable to implement simulation tools that can help to understand the role of operational parameters, to design the operations and to monitor the performance. The simulator must account for nanoparticle transport, transfer, and retention dynamics, as well as their impact on viscosity reduction and wettability restoration. In this paper, we developed and solved, numerically, a 3D mathematical model describing the multiphase flow and interaction of the nanoparticles with oil, brine, and rock surface, leading to viscosity reduction and wettability restoration. The model is based on a multiphase pseudo-compositional formulation, coupled with mass balance equations, of nanoparticles dispersed in water, nanoparticles dispersed in oil, and nanoparticles retained on the rock surface. We simulated a pilot test study of a nanofluid stimulation done in a Colombian heavy oil field. The injection, soaking, and production stages were simulated using a 3D single-well formulation of the mathematical model. The comparison of simulation results with the pilot test results shows that the model reproduced the field observations before and after the stimulation. Simulations showed that viscosity reduction during the post-stimulation period is strongly related to the detachment rate of nanoparticles. Simulation indicates that the recovery mechanism of the nanofluid stimulation is initially governed by viscosity reduction and wettability alteration. At latter times, wettability alteration is the main recovery mechanism. The nanoparticles transferred to the residual water promote the wettability alteration to a water wet condition. The model can be used to design field deployments of nanofluid interventions in heavy oil reservoirs.

Autonomous Outflow Control Technology Used in Water/Polymer Injectors in Heavy-Oil Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207361, “Autonomous Outflow Control Technology in New Water/Polymer Injectors in Heavy-Oil Fields From South Sultanate of Oman,” by Ameera Al Harrasi, Muna Maskari, and Gerardo Urdaneta, Petroleum Development Oman, et al. The paper has not been peer reviewed. This paper summarizes the integrated technical learnings from the successful application of autonomous outflow-control device (AOCD) technology in a new long horizontal injector well. It shows the result of extending this technology to other injectors in both water and polymer phases in the field, detailing the authors’ observations and insights. Autonomously reactive control of injection fluid conformance resulted in increased sweep and ultimate oil recovery, while the total volume of injected fluid was reduced. Introduction The AOCD is a rate-limiting device that autonomously chokes flow of injected fluids into high-permeability zones to ensure effective flow distribution in fractured zones or highly heterogeneous reservoirs. It provides an autonomous rate limit to prevent excessive water injection into the fractures, thereby enabling distributed or matrix injection. AOCD technology involves a biased open valve that enables water injection at normal distributed rates but chokes once an already prescribed trigger rate is exceeded. In the choked or fused position, a high-flow restriction is applied that reduces the injection rate in that specific zone. The normally distributed rates and trigger rates are engineered for optimal performance in each application. The valve remains dynamically reactive and will reopen if the desired distributed flow can be achieved.

Technology Focus: Heavy Oil (April 2022)

Heavy oils are characterized by high density, high viscosity, and high-heavy-fraction components. Because of high viscosity and lower API gravity than conventional crude oil, primary recovery of some of these crude oil types requires thermal stimulation of the reservoirs. Most of the technologies that deal with heavy oil need to address the mobility ratio or viscous forces before any flooding. In general, poor recovery is caused by physical reasons or geological reasons. Physical reasons can be categorized as capillary forces (existence of the interfacial tension between oil and water, wettability) or viscous forces (high mobility ratio between water and oil). Geological reasons are heterogeneities in reservoir rock and exist in all petroleum oil systems. In heavy oil reservoirs, enhanced oil recovery (EOR) intends to reduce the capillary forces and interfacial tension to improve microscopic displacement efficiency or improve the sweep efficiency (macroscopic) by reducing the mobility ratio between injected fluid and displaced fluid. Improving the mobility ratio is achieved by increasing the viscosity of water using polymers or by reducing the oil viscosity using heat. In general, all technologies need to address the capillary and viscous forces to improve oil recovery. Paper SPE 207361 discusses improving of the efficiency of the flood by near-wellbore conformance and improving the vertical sweep efficiency. The use of fiber-optic sensors, as addressed in paper SPE 199023, is intended to gather better data and avoid misinterpretation during falloff tests and injectivity tests. Traditionally, for heavy oil EOR simulation, because of the addition of chemical species or heat to the flow equations as well as the need for a finer grid resolution, the use of the full-field model in most cases was limited and the use of sector models and local grid refinement to obtain a reasonable accuracy has been applied in the industry. Sector modeling conditions must be satisfied to establish the reliability and the trade-off between accuracy (sector models) and computational expediency (full-field model). Recent development of hardware and software [graphics-processing-unit (GPU) -based simulators] has provided the industry with the tools to achieve a full-field model simulation in most fields by taking advantage of GPU solvers and using a fine-grid model to predict full-field performance. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200279 - Field Application of the Autonomous Inflow Control Device for Optimized Heavy Oil Production in South Sultanate of Oman by Ali Al-Jumah, Petroleum Development Oman, et al. SPE 203012 - More Oil and Less Water: Autonomous Inflow Control Devices in New and Old Producers in Heavy Oil Fields From South of Oman by Ameera Al Harrasi, Petroleum Development Oman, et al. SPE 207684 - Game Changer in Dealing With Hard Scale Using a Slickline Torque Action Debris Breaker by Mahmoud Mohamed Koriesh, Dragon Oil, et al.

Electrical Heating Can Optimize Production in Heavy-Oil Fields With Intelligent Multilaterals

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 20134, “Production Optimization Through Intelligent Multilateral Wells in Heavy-Oil Fields by Electrical Heating,” by Cenk Temizel, SPE, Saudi Aramco; Celal Hakan Canbaz, Ege University; and Fatma Bahar Hosgor, Petroleum Software, et al. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. Electrical resistive heating provides key advantages over other thermal methods in the recovery of heavy-oil resources. However, the recovery efficiency with electrical heating is relatively lower compared with more-conventional methods such as cyclic steam stimulation, steamflooding, and steam-assisted gravity drainage (SAGD) because it does not introduce a (pressure) drive mechanism and the radius of effect is relatively small, which may result in marginal economics. In this study, the application of electrical resistance heating on multilateral wells is studied in order to illustrate the enhanced physical and economic benefits of the method in such a setting. Smart Tools in Multilateral Wells Placement of a multilateral well is a decision that must be considered carefully. The easiest method of determining whether the approach is the right one for a field is to analogize multilateral wells with the traditional single-bore wells that penetrate to the same formation area. The multilayered well has less drilling depth and reduced rig time compared with the conventional wells. Thus, multilaterals are an advantageous completion design in locations such as offshore platforms or harsh-weather areas. However, multilateral well-completion design is challenging because of its increased complexity. Most smart wells include hydraulic-control systems to satisfy a simpler, more-reliable operation. Current wellhead-control systems allow a limited number of penetrations. The indications are that smart tools controlled with electrical systems will be an emerging focal point of the industry. The cost of a multilateral well is higher because of the equipment used and operational complexity. It also includes a higher risk compared with the risk of a conventional well. Any problem that results in abandoning the well will bring a major economic loss equal to the cost of several conventional wells.

Determining correlation between reservoir thermal characteristics and poroperm properties in heavy oil fields

Determining correlation between reservoir thermal characteristics and poroperm properties in heavy oil fields

Prediction Model for the Viscosity of Heavy Oil Diluted with Light Oil Using Machine Learning Techniques

Due to the presence of asphaltene, the flow assurance of high viscosity crude oil becomes more challenging and costly to produce in wellbores and pipelines. One of the most effective ways to reduce viscosity is to blend heavy oil with light oil. However, the viscosity measurement of diluted heavy crude is either time-consuming or inaccurate. This work aims to develop a more accurate viscosity model of diluted heavy crude based on machine learning techniques. A multilayer neural network is used to predict the viscosity of heavy oil diluted with lighter oil. The input data used in the training include temperature, light oil viscosity, heavy oil viscosity, and dilution ratio. In this modeling process, 156 datasets were retrieved from the available iterature of various heavy-oil fields in China. Part of the data (80%) is used to train the developed models using Adam optimizer algorithms, while the other part of the data (20%) is used to predict the viscosity of heavy oil diluted with lighter. The performance and accuracy of the machine learning models were tested and compared with the existing viscosity models. It was found that the new model can predict the viscosity of diluted heavy oil with higher accuracy, and it performs better than other models. The absolute average relative error is 10.44%, the standard deviation of the relative error is 8.45%, and the coefficient of determination is R2 = 0.95. The viscosity predicted by the neural network outperformed existing correlations by the statistical analysis used for the datasets available in the literature. Therefore, the method proposed in this paper can better estimate the viscosity of diluted heavy crude oil and has important promotion value.

Fast History Matching and Robust Optimization Using a Novel Physics-Based Data-Driven Flow Network Model: An Application to a Steamflood Sector Model

SummaryFull-fidelity models can be computationally expensive during history matching (HM) and robust optimization as these problems typically require hundreds of simulations. Previously, we have implemented a physics-based data-driven flow network model, general purpose simulator-powered network model (GPSNet), that serves as a surrogate without the need to build the 3D full-fidelity model. In this paper, GPSNet is enhanced to GPSNet-2D to better capture thermal processes, especially gravity drainage. This enhancement successfully enables a rapid HM and robust optimization for a steamflood sector model.In GPSNet-2D, the reservoir is discretized into a series of 2D connections (x-z planes) between well completions. These connections capture the main areal/vertical flow paths, and the grid properties of each connection are interpreted with historical data. Steam segregation and heat loss are included to better represent the subsurface physics. When simulating GPSNet-2D using a commercial simulator, an equivalent 3D Cartesian model is designed where vertical slices correspond to the interwell connection planes. Thereafter, an iterative HM is conducted using the ensemble smoother with multiple data assimilation. The best-matched model is then used for steam injector control optimization.The GPSNet-2D model is first validated through a synthetic steamflood case. HM result shows that the GPSNet-2D model not only aligns closely to field-scale volumetric data but also yields good well-level matches, including bottomhole pressure (BHP)/bottomhole temperature (BHT) and phase rates. Then, GPSNet-2D is successfully applied to steamflood HM and robust optimization for a 36-well sector of a heavy oil field in the San Joaquin Valley in North America. Again, the calibrated GPSNet-2D model demonstrates its capability and reliability by generating accurate field-scale match results and reasonable matches for most of the wells. For robust well control optimization, we select nine realizations from the posterior ensemble and maximize NPV under well constraints simultaneously. The optimal case improves the average NPV by 27% over the reference case. The integration with a commercial simulator in GPSNet-2D provides flexibility to account for complex physics in the thermal recovery processes, such as steam segregation near injectors, fast steam breakthroughs at producers, and heat loss to the overburden/underburden formations. Unlike traditional simulation that relies on a detailed characterization of geological models, the GPSNet-2D model only requires well volumetric production/injection data and its approximate trajectory and can be generated and updated rapidly. In addition, GPSNet-2D also runs much faster (minutes) than a full-fidelity thermal model due to having much fewer gridblocks in the model.To our knowledge, this is the first time a physics-based data-driven network model integrated with a commercial simulator is demonstrated via a field steamflood case. Unlike approaches developed with analytic/empirical solutions or research simulators, the use of a commercial simulator makes it possible to extend flow network modeling to simulate enhanced oil recovery processes more realistically. It serves as an ideal surrogate model for both fast and reliable decision-making in reservoir management.

Feasibility Study and Technical Optimization by Implementing Steam Flooding for the Field Development Plan of A Heavy-Oil Field in Yemen

Enhanced Oil Recovery (EOR) applications are highly recommended and required in Yemen to maintain stable levels of oil production. The field selected for this research is located in Yemen, where relatively- thin sandstone reservoirs are dominant at moderate depths. The reservoir is highly undersaturated with an API gravity of 14.2 and a very low solution gas-oil ratio (GOR), initial oil viscosity (uo) of 420 cP. The reservoir is naturally producing with the support of a strong water drive at the bottom, however, the increase in water cut poses a disadvantage for this reservoir. Over time, the oil production will decline and development plans will be required to improve the oil recovery. This research aims to optimize oil recovery factor and the interest in the overall project economy by evaluating the optimization of the steam flood process based on the Stochastic analysis with the highest recovery factor (RF) and the highest net present value (NPV) objective functions. Two optimization techniques have been used to perform the data analysis, deterministic and stochastic approaches. The deterministic approach is carried out by direct analysis on the results of the technical optimization method using the CMG reservoir simulator, while the stochastic approach uses the simulation results from the deterministic approach to determine the most influencing parameter in the steam flood process as well as to optimize the infill and injection wells location, number of steam injection wells and the steam injection rate with the highest oil RF and highest NPV. In this field development using deterministic approach, two producer wells are converted into injector wells. The RF for this initial scenario is 52,34%, and the NPV is 33.10 MM$/STB. For the second scenario using Stochastic approach, CMOST optimization using the maximum RF objective function resulted in RF of 61.33%, and NPV of 43.00 MMS/STB. Finally for the third scenario using CMOST optimization with the maximum NPV objective function resulted in RF of 57.29%, and an NPV of 53.86 MMS/STB. The Stochastic approach with maximum NPV objective function provides the most favorable scenario to be used in the development of Field "AR". And the optimization using the stochastic approach also produces faster, optimum, and more accurate results than the deterministic approach since it forecast a variety of probable results by running thousands of reservoir simulations using many various estimations of economic conditions.

Enhancing vertical resolution with 4D seismic inversion

In this work, we applied a Bayesian time-lapse (4D) seismic inversion to a deep-water heavy oil field located in the Campos Basin (Brazil). In this procedure, the differences of seismic amplitudes of baseline and repeated surveys are the input to calculate the changes in acoustic impedances. To ensure the quality of the results, the parametrization of the inversion was performed by analyzing the anomalies resolution and signal-to-noise ratio with different values of input parameters, and the estimates are crosschecked with the results of a petroelastic modeling applied to the dynamic model. Results show a relevant improvement in the vertical resolution of estimated acoustic impedances in comparison to the amplitude data in a thin reservoir (with thickness ranging from 15 to 45 m). This improvement was possible because of the high-quality of acquired seismic amplitudes (permanent reservoir monitoring) and because of the data variability that is controlled in the Bayesian 4D inversion algorithm. The high resolution of Bayesian inverted results enabled a more detailed vertical zoning of the reservoir, revealing important geological features, such as channels in the main interval and below the reservoir's base, and improved the understanding of the fluid movement over time, enabling the analysis of the injection efficiency and by-passed oil zones as well as the aquifer movement. This information is important to update the static model, by improving the definition of geological features, and to calibrate dynamic models, in the future, by adding the inverted acoustic impedance maps into the data assimilation procedure.