Waterflood Recovery Research Articles

A Study on the Residual Oil Distribution in Tight Reservoirs Based on a 3D Pore Structure Model

A tight reservoir is characterized by low porosity and permeability as well as a complex pore structure, resulting in low oil recovery efficiency. Understanding the micro-scale distribution of residual oil is of great significance for improving oil production and water flooding recovery rates. In this study, a 3D pore structure model of tight sandstone was established using CT scanning to characterize the residual oil distribution after water flooding. The effects of displacement methods and wettability on residual oil distribution at the micro-scale were then studied and discussed. Moreover, increasing the displacement rate has little effect on the distribution area and dominant seepage channels. Microscopic residual oil is classified into five discontinuous phases according to the oil–water–pore–throat contact relationship. The microscopic residual oil exhibits characteristics of being dispersed overall but locally concentrated. Under water-wet conditions, the injected water tends to strip the oil phase along the pore walls. Under oil-wet conditions, the pore walls have an improved adsorption capacity for the oil phase, resulting in a large amount of porous and membranous residual oil retained in the pores, which leads to a decrease in the overall recovery rate.

Why gravity improves waterflood recovery in oil-wet and mixed-wet reservoirs

Most past experimental and numerical research on water flooding has demonstrated a reduction in oil recovery in gravity dominated flow: gravity leads to the water slumping to the bottom of the reservoir with earlier water breakthrough and poor sweep efficiency. However, these studies were all performed on strongly water-wet systems: wherever the water has gone, the oil is at residual saturation so a reduction in sweep efficiency gives a reduction in recovery. In reality few if any reservoirs are strongly water-wet. If the rock is mixed or oil-wet, gravity improves the local displacement efficiency. Gravity reduces the mobility of injected water forcing downward water movement and better oil displacement laterally. When gravity dominates, once water reaches the bottom of the reservoir, it moves upwards in a gravity-stable displacement, with improved local displacement efficiency that can be quantified by linear Buckley-Leverett analysis. We show, using fine-grid simulations of water flooding in a two-dimensional homogeneous vertical cross-section with typical fluid and rock properties, that the overall recovery after ∼0.3 pore volumes of water injected is higher than without gravity for heavy oil-wet (unfavourable mobility) applications. This improvement is greater in light oil-wet (favourable mobility) applications and occurs even before water breakthrough counteracting the negative effect of poor sweep efficiency. Simulations on a heterogeneous reservoir model representing an oil field from the Middle East confirmed the significance of gravity on improving the displacement and overall oil recovery. The same considerations should pertain in reverse for gas storage: storage efficiency improves in gravity dominated flow.

Mechanisms of surfactant improving water injection huff and puff efficiency in tight reservoir

Water injection huff and puff is an economical and effective method to enhance the recovery of tight oil reservoir, in which the addition of suitable surfactants is critical, but its mechanism needs to be further studied. In this paper, the huff and puff process is divided into replenishment, imbibition and water flooding stages. This study compared and analyzed the effects of various surfactants on interfacial tension, wettability, flow resistance, and oil washing efficiency, using mineralized water as the control group. The relationships between different surfactants and imbibition recovery efficiency, water flooding recovery efficiency, and flooding pressure were investigated. The mechanisms by which surfactants influence the imbibition and flooding processes were also explored. The results show that, the effect of permeability on imbibition and water flooding recovery efficiency in natural cores can be ignored. During the imbibition stage, the maximum recovery efficiency with mineralized water is 18.33 %, while with surfactants it is 21.40 %. In the water flooding stage, the maximum recovery efficiency with mineralized water is 3.89 %. The addition of surfactants significantly increases the water flooding recovery efficiency to 19.82 %. Furthermore, surfactants can reduce the water flooding pressure by approximately 7.00 MPa and increase the total recovery rate by about 5.00 %. The primary mechanisms by which surfactants improve the water injection huff and puff effect include reducing interfacial tension, altering wettability, facilitating crude oil detachment from rock surfaces, and enhancing oil washing efficiency. Reduction of flow resistance, leading to a decrease in the pressure required for flooding. The research results provide a theoretical basis for the practical application of surfactants in water injection huff and puff in tight reservoirs.

Numerical simulation of residual oil distribution characteristic of carbonate reservoir after water flooding

Carbonate reservoirs are characterized by abundant reserves and are currently focal points for development in oil and gas producing regions such as the Ahdab oilfield, Tarim Basin, Sichuan Basin, and Ordos Basin. The primary method for exploiting carbonate reservoirs is waterflooding. However, due to the complex pore structure and pronounced heterogeneity of carbonate rocks, the waterflooding process often leads to an unclear distribution of remaining oil and low waterflooding recovery efficiency, significantly impacting the stable and high production of carbonate reservoirs. This paper presents a two-phase flow model of oil and water in distinct pore structures by integrating fluid flow equations and interface tracking equations. It visually represents the waterflooding process at the pore scale, elucidates the distribution and formation mechanism of remaining oil, and discusses the mechanism of microscopic displacement efficiency change. The study reveals that: 1) After waterflooding, the distribution patterns of remaining oil can be categorized into dead-end remaining oil, pressure balance remaining oil, wall-bound remaining oil, Jamin effect remaining oil, and water-encapsulating remaining oil, which are governed by microscopic pore structure, wettability, and preferential flow paths; 2) From the perspective of actual reservoir displacement efficiency, intergranular pores > intergranular dissolved pores > visceral foramen > mould pore, with this trend being more pronounced under hydrophilic wetting conditions; 3) Given the oil-wet to strong oil-wet wettability characteristics of these carbonate rocks, capillary forces pose significant resistance during waterflooding. The conclusion underscores the importance of leveraging the reservoir’s microscopic pore structure and wettability characteristics for actual oil wells, elucidating the evolutionary law of the mechanical mechanism of oil-water interface advancement, clarifying oil-water percolation characteristics at the pore scale, and understanding the microscopic displacement physical mechanism, all of which are crucial for guiding the design of schemes aimed at enhancing reservoir recovery efficiency.

Increasing Oil Recovery by Varying Surfactant Concentrations and Expanding the Well Drainage Area

Surfactant flooding plays a crucial role in advanced techniques for boosting oil recovery. There remains a significant volume of unrecovered oil in reservoirs, particularly in carbonate reservoirs. These reservoirs often face challenges with low primary and water-flood recovery due to inadequate sweep efficiency, resulting in the presence of bypassed or trapped oil. Chemical flooding approaches, including surfactant flooding, have demonstrated their effectiveness in the retrieval of this trapped oil. The fundamental concept of surfactant flooding involves injecting a surface-active agent, known as a surfactant, to reduce the interfacial tension and mobilize the residual oil saturation. Surfactants have been widely utilized for various purposes in the petroleum industry since its early years, owing to their capacity to modify interfacial interactions between two immiscible fluids in contact with one another. Interfacial phenomena play a significant role in rock-fluid interactions and the interactions between fluids from the reservoir to distribution pipelines. Consequently, surfactants find application in a variety of activities within the petroleum industry. Laboratory experiments, pilot-scale projects, and field-scale initiatives worldwide have yielded diverse outcomes regarding the use of surfactants for enhancing oil recovery. Multiple types of surfactants have been investigated to determine highly effective chemical formulations for enhanced oil recovery, with anionic and non-ionic surfactants being commonly employed in sandstone reservoirs.

Development of Novel Delayed Swelling Polymer Gel Particles with Salt Resistance for Enhanced In-Depth Permeability Control

Summary Prolonged waterflooding or polymer flooding in oil fields often exacerbates reservoir heterogeneity, leading to premature water breakthrough and high water cut, which significantly hinders efficient oilfield development. To address this issue, polymer gel particles have been prescribed to enhance sweep efficiency and augment waterflooding recovery by plugging preferential pathways within the reservoir. However, inherent weaknesses of polymer gel particles, such as fast water absorption and expansion rates in the initial stage and low post-expansion rates, make it difficult to balance in-depth transportation and plugging performance. Additionally, these gel particles are sensitive to ions in the formation water, resulting in reduced expansion rates under high-salinity conditions. Therefore, there are still challenges in the application of polymer gel particles for in-depth permeability control. In this study, a new type of delayed swelling and salt-resistant polymer gel particle was synthesized through inverse emulsion copolymerization. To achieve delayed swelling, we use a degradable crosslinker and hydrophobic monomer to enhance the crosslinked network density and hydrophobicity of gel particles. Our double crosslinked gel particles keep their original size until Day 2, then gradually swell up to 20 days in NaCl solution with a concentration of 15×104 mg·L−1 at 90°C. In comparison, the traditional single crosslinked gel particles show significant disparities in swelling behaviors and quickly swell when just dispersed in a 15×104 mg·L−1 NaCl solution at 90°C, maintaining roughly the same size over the testing period. Coreflooding experiments demonstrate that the residual resistance before and after aging increases from 2.37 to 6.82. The newly synthesized delayed swelling and salt-resistant polymer gel particles exhibit promising potential for overcoming the challenges associated with reservoir heterogeneity and high salinity.

New Mathematical Technique for Step Rate Test Analysis Aids Determination of Fracture Pressure and Overcomes the Uncertainty of Conventional Analysis.

Experience in the oil industry has shown that it is challenging to sustain successful long-term matrix injection, as injection water quality cannot be maintained rigorously due to facility hiccups and membrane clogging. Most oil field operators have resolved this problem of injectivity decline by increasing the surface injection pressure to part the formation and inject just above the fracture gradient with strict offtake management for zonal conformance. This is not an easy task as injection much above fracture opening pressure can lead to water fingering and poor sweep that results in uneconomical waterflood recovery. The operators, thus, strive to inject at a pressure just above the fracture opening pressure so that the fracture opens near the wellbore but does not extend and then maintain the pressure just above the fracture closing pressure. Therefore, determination of the fracture opening pressure and fracture closing pressure has remained critical data for the success of waterflood projects. The most reliable industry approach to estimating fracture opening and fracture closing pressures comes from the step rate test (SRT). This traditional approach of Cartesian analysis of pressure-rate plot fits straight lines through the data in a plot of injection pressure against injection rate and then estimates the fracture pressure from the intersection of these lines having different slopes. The data received often do not exhibit one clear change in slope, thus resulting in multiple possible solutions, making it difficult for the operator to use the data for high CAPEX facilities design. Most past studies indicate the subjectivity of this Cartesian slope fitting technique. Alternative solutions through multirate superposition analysis found limited application in the analysis of SRT data due to considerable sensitivity to the value of initial pressure used for superposition and lack of stability of rate and pressure data. In this article, a new technique of SRT analysis is presented, which provides a unique solution for fracture opening and fracture closing pressures. It helps to overcome the limitations of the traditional technique of arbitrary fitting of straight lines. It uses the mathematical understanding of cumulative derivatives to recognize that the matrix opens when the cumulative growth of the rate of injectivity shows a change. It estimates the derivative of the injection rate with respect to injection pressure at each step. Then, it estimates the fracture pressure from the plot of the cumulative of this derivative against pressure at each step. It helps to overcome the challenge SRT solutions posed by the nonlinear trend of pressure data at each injection step both before fracture and after fracture is initiated. It also overcomes the limitations of the multirate superposition technique, as it is not sensitive to the value of initial pressure used for superposition.

A novel profile modification HPF-Co gel satisfied with fractured low permeability reservoirs in high temperature and high salinity

Conformance control and water plugging are a widely used EOR method in mature oilfields. However, majority of conformance control and water plugging agents are unavoidable dehydrated situation in high-temperature and high-salinity low permeability reservoirs. Consequently, a novel conformance control system HPF-Co gel, based on high-temperature stabilizer (CoCl2·H2O, CCH) is developed. The HPF-Co bulk gel has better performances with high temperature (120 °C) and high salinity (1×105 mg/L). According to Sydansk coding system, the gel strength of HPF-Co with CCH is increased to code G. The dehydration rate of HPF-Co gel is 32.0% after aging for 150 d at 120 °C, showing excellent thermal stability. The rheological properties of HPF gel and HPF-Co gel are also studied. The results show that the storage modulus (G′) of HPF-Co gel is always greater than that of HPF gel. The effect of CCH on the microstructure of the gel is studied. The results show that the HPF-Co gel with CCH has a denser gel network, and the diameter of the three-dimensional network skeleton is 1.5–3.5 μm. After 90 d of aging, HPF-Co gel still has a good three-dimensional structure. Infrared spectroscopy results show that CCH forms coordination bonds with N and O atoms in the gel amide group, which can suppress the vibration of cross-linked sites and improve the stability at high temperature. Fractured core plugging test determines the optimized polymer gel injection strategy and injection velocity with HPF-Co bulk gel system, plugging rate exceeding 98%. Moreover, the results of subsequent waterflooding recovery can be improved by 17%.

CO2-induced viscoelastic fluids based on a C22-tailed tertiary amine under different pressure and temperature

CO2-switchable viscoelastic surfactant solutions have gained much attention over the last decade; however, large-scale application and the impact of temperature and pressure on such soft colloidal materials have not been explored yet. Here in this work, the impact of environmental parameters including shear rate, pressure, temperature, and salinity on CO2-thickening behavior of aqueous dispersion of N-erucamidopropyl-N,N-dimethylamine (UC22AMPM) was assessed rheologically. Preliminary immiscible water-alternating-CO2 (CO2-WAG) flooding tests with and without UC22AMPM were conducted to highlight the potential of CO2-switchable surfactants in the process of improved oil recovery. The results demonstrated that the dispersion can be viscosified by CO2 15 times higher at 60 °C and 5 MPa, and such thickening power can be switched “on” and “off” upon bubbling and removal of CO2. A universal double-plateau viscosity profile was found as a function of CO2 bubbling time irrespective environmental condition, but the higher the shear rate or the pressure, the shorter the time is needed to reach the plateau viscosity; the higher the temperature, the longer the time is needed to get to the second plateau viscosity. UC22AMPM is first protonated into a long-chain cationic surfactant to form wormlike micellar solution, then the first viscosity plateau; expansion of the viscoelastic solution with CO2 attributes to the second viscosity plateau. Under the simulated oil reservoir of Daqing oilfield, immiscible CO2-WAG flood alone produced an additional 10.5% oil over the initial waterflood recovery, while the addition of 2.1 wt% UC22AMPM in the water slug could recover incremental 5.1% oil relative to pure CO2-WAG. These unique features suggest that coupling injection of CO2 and UC22AMPM dispersion holds great promise for recovering oil during the immiscible CO2-WAG process.

Status and Prospect of Improved Oil Recovery Technology of High Water Cut Reservoirs

The high water cut stage is an important stage of the water injection development of oilfields because there are still more oil reserves available for recovery in this stage. Most oilfields have experienced decades of waterflooding development and adjustment. Although waterflooding reservoirs face the problems of the seriously watered-out and highly dispersed distribution of remaining oil, they remain dominant in waterflood development. This paper investigates the current situation of high-water content reservoirs and the methods available to improve oil recovery and elaborates on the fine reservoir description. Furthermore, it analyzes the main technical measures taken during the high water cut period, namely, secondary oil recovery waterflooding technology (including layer system subdivision, well pattern infilling, strengthening of water injection and liquid extraction, closure of high water cut wells, cyclic waterflooding technology, and water injection profile control) and tertiary oil recovery technology (represented by chemical flooding and gas flooding). In addition, this study reveals the mechanisms and effects of these methods on improving waterflooding development. Finally, this paper summarizes improved oil recovery technology and discusses the key directions and development prospects of this technology in enhancing the oil recovery rate.

Technology Focus: EOR Operations (November 2022)

Among the different enhanced-oil-recover techniques, waterflooding is still commonly practiced in part because of its economic potential. During the past 2 years, many papers presented at SPE meetings have dealt with different aspects of waterflooding design, optimization, monitoring, and low-salinity applications. Understanding the injected-water preferential paths is a key aspect of waterflood optimization in reservoirs characterized by strong vertical and areal heterogeneities. Devising specific work flows for such applications is important. These can be easy but powerful tools for visualizing the complex dynamic connections between injectors/producers and aquifer influence areas. They can enable improving the business-time decision-making cycle, resulting in increased operational performance and lower waterflood operating costs by consolidating end-to-end optimization work flows in one platform. Using artificial intelligence (AI) and machine-learning (ML) approaches with reduced-physics models can reduce the time required for this task. Also, ML allows for fast screening of waterflood performance at diverse levels (e.g., reservoir, sector, pattern, and well), enabling prompt identification of opportunities for immediate uptake into an opportunity-management process and for evaluation in AI-driven production forecasting or in a reservoir simulator. As part of waterflood optimization, changing the chemistry of the injected water has been under investigation since early 2000. This process has been named differently in different laboratories (e.g., smart water and low-salinity waterflooding, or LoSal). The new studies are related to its field application. It is interesting that new hybrid applications such as low-salinity water with surfactant flooding and carbonated smart water injection are showing up in the literature. As we move forward, it is expected that the waterflooding recovery factor will increase with additional technology advancements. Recommended additional reading at OnePetro: www.onepetro.org SPE 209426 - Impact of Brine Chemistry on Waterflood Oil Recovery: Experimental Evaluation and Recovery Mechanisms by Behdad Aminzadeh, Chevron, et al. SPE 205426 - Pump Up the Volume—Massive Water-Injection Increase Through Open-Water Stimulations by Alistair Roy, BP, et al. SPE 210154 - Middle East Giant Carbonate Field: Integrated Water-Injection-Optimization Work Flow by Stefano Del Fraro, Eni, et al.

Experimental investigation of N-lauroyl sarcosine and N-lauroyl-L-glutamic acid as green surfactants for enhanced oil recovery application

The vast deployment of surfactants worldwide in various industries has an intense impact on the environment. This led to the quest for surfactants with high performance but less environmental footprint. Therefore, bio-based surfactants derived from renewable sources have evolved as greener alternatives to conventionally deployed surfactants. Amino acid-based surfactants (AAS) prove to be a promising class of biodegradable and biocompatible surfactants with better safety profiles that meet both physiological and ecological requirements. Nevertheless, they are yet to be deployed in enhanced oil recovery (EOR) application due to limited investigation into their EOR potential. Owing to the recent report on the satisfactory performance of sodium cocoyl alaninate in terms of its EOR potential, this current study investigates the EOR potential of N-lauroyl sarcosine (NLS) and lauroyl glutamic acid (LGA). The study encompasses their surface and aggregation behavior, interfacial tension reduction and wettability alteration capability, emulsification, adsorption behaviour and oil displacement test. NLS proved to be more surface-active than LGA due to the additional carboxylate in the head group of LGA. Both surfactants showed high tolerance to salt and hardness, especially at high-temperature conditions. Furthermore, NLS showed superior IFT reduction capability with a minimum IFT of 0.07 mN/m while LGA only attained a minimum IFT of 0.14 mN/m. This results in better emulsifying power of NLS, yet LGA yielded more stable emulsions. In agreement to their high salt tolerance both surfactants exhibited improved performance in IFT reduction at high salinity condition. NLS and LGA also showed good wetting power on the quartz surface, hence altering rock surface wettability. Both surfactants achieved significant oil recovery after waterflooding, with NLS attaining additional oil recovery of 43% and LGA attaining 25%. The optimistic recoveries are due to the low waterflood recovery. NLS and LGA, therefore, prove to be superb alternatives to conventionally deployed EOR surfactants due to satisfactory performances coupled with their environmentally benign nature.

Mangala Polymer Flood Performance: Connecting the Dots Through In-Situ Polymer Sampling

Summary The Mangala field contains medium-gravity viscous crude oil. Notably, it is the largest polymer flood in India and 34% of the stock tank oil initially in place (STOIIP) has been produced in 11 years. Mangala was put on full field polymer flood in 2015, 6 years after the start of field production on waterflood in 2009. Polymer flood added nearly 93 million barrels above the anticipated waterflood recovery in 6 years. Reservoir simulation models could replicate the initial Mangala polymer flood performance. However, the performance of the lower layers of Mangala (FM-3 and FM-4) continued to progressively deviate from modeling estimates. Importantly, the observed polymer breakthrough deviated significantly from predictions. As the polymer flood matured, the trend of field water cut with time indicated that in-situ polymer viscosity was equivalent to only 50 to 60% of the surface polymer viscosity. For better predictions and corrective actions, it was necessary to understand the nature of degradation, the progressively deteriorating field performance, especially of the lower layers, and the deviation of polymer breakthrough trends from predictions. Carefully designed in-situ polymer sampling, laboratory studies, and reservoir modeling studies helped connect the dots to understand the field performance. There are several excellent publications on accelerated aging studies and some on polymer sampling. This paper offers an opportunity to directly compare experimental results with field data. The procedures used and lessons learned during field sampling can be useful for other operators for management of polymer floods.

Fine Geological Modeling of Complex Fault Block Reservoir Based on Deep Learning

Nowadays, people’s demand for underground mineral resources is increasing, and geological disasters have occurred frequently in recent years. Geological disasters refer to geological effects or geological phenomena that are formed under the action of natural or man-made factors, causing loss of human life and property, and damage to the environment; such as landslides, collapses, mudslides, and ground subsidence. Under such a background, people must accelerate the exploration of complex geological structures. This paper is aimed at using the methods and concepts of deep reinforcement learning. Deep learning is to learn the inherent laws and representation levels of sample data. The information obtained during these learning processes is of great help to the interpretation of data such as text and images. In this way, the fine geology of complex fault-block reservoirs is modeled and studied. Geological structures and phenomena are discussed through convolutional neural network models and computer techniques. At the same time, the multitask bird recognition network is used to extract and classify geological images, so as to construct geological model maps with different spatial structures. Finally, the quality of the fault reconstruction model, the calculation of reservoir geological simulation reserves, and the evaluation of the water injection development effect of complex fault blocks are analyzed. In the evaluation of the development effect of water injection in complex fault blocks, comparing the relationship curve between the actual comprehensive water content and the oil recovery factor with the standard curve, the comprehensive water content of the initial block increased rapidly. Through timely and dynamic water allocation and comprehensive management, the water cut rising speed is controlled. The current comprehensive water cut of the reservoir is between 60% and 80%, the actual curve is between 25% and 35%, and the estimated waterflooding recovery is about 30%.

CO2-Low Interfacial Tension Viscoelastic Fluid Synergistic Flooding in Tight Reservoirs.

Tight oil reservoirs have poor physical properties, insufficient formation energy, and low natural productivity. CO2 flooding is an important technical mean that enhances the oil recovery of dense reservoirs and achieves effective CO2 sequestration, but strong heterogeneity of the tight oil reservoir usually results in gas channeling and poor enhanced oil recovery effect. The existing methods to prevent gas channeling are mainly to use the small-molecule amine system and the polymer gel system to plug fracture and high permeability channels. The small-molecular amine system has low flash points and pollutes the environment and the polymer gel has poor injectivity and great damage to the formation, which limit their large-scale application. Therefore, a new viewpoint of CO2-low interfacial tension viscoelastic fluid synergistic flooding for enhanced oil recovery in a tight oil reservoir was made. The performance of low interfacial tension viscoelastic fluid (GOBT) was studied. The injectivity and oil displacement effect of CO2-GOBT synergistic flooding were evaluated, and the mechanism of CO2-GOBT synergistic flooding was discussed. The experimental results showed that 0.4% GOBT is a low interfacial tension viscoelastic fluid, which has strong adaptability to the salinity water of tight oil reservoirs (6788–80,000 mg/L), good viscosity stability at different pHs, excellent capacity to emulsify crude oil, and the ability to improve reservoir water wettability. CO2 alternating 0.4% GOBT flooding has good injection ability in cores (Ka = 0.249 mD), and injecting 0.4% GOBT can effectively increase the injection pressure of subsequent CO2 flooding. CO2 alternating 0.4% GOBT flooding can effectively improve water flooding recovery in tight sandstone reservoirs, which is better than CO2 flooding and 0.4% GOBT flooding in both homogeneous and heterogeneous conditions. The mechanisms of CO2 alternating 0.4% GOBT flooding to enhance the oil recovery include that GOBT and CO2 foam block high permeability layers, shunt and sweep low permeability layers, and GOBT emulsify and wash oil. CO2 partially dissolving in GOBT synergistically enhances the core water wettability, which improves GOBT injectability, emulsification, and stripping ability to residual oil.

Analysis of low permeability reservoir development technology

As an important energy source for social production and development, oil is non-renewable. In the process of development and utilization, attention should be paid to continuously improve the exploitation technology, enhance the ability of oil exploration, and strengthen the development of low permeability reservoir resources, so as to provide sufficient oil resources for social production and development. However, low permeability reservoir resources have their own characteristics and are limited by multiple factors in the process of exploitation. It is difficult to improve the exploitation efficiency of low permeability reservoir resources without adopting corresponding exploitation technology. This it is scientific and reasonable exploitation of low permeability oil reservoir resources technology are analyzed and discussed, in the comprehensive analysis based on the characteristics of low permeability oil reservoirs, mining characteristics, puts forward the well pattern optimization, waterflood recovery, fracturing technology and mining method, working for the effective implementation of the low permeability reservoir development provides the technical support, also need to continue well technology application in the construction process in the future.

Modeling of low salinity waterflooding in carbonates: Effect of rock wettability and organic acid distribution

Carbonate reservoirs hold a substantial amount of our existing oil reserves. However, waterflood recovery from these reservoirs is often low due to their oil-wet nature. Recent studies have shown that oil recovery from oil-wet carbonate reservoirs can be increased by wettability alteration using low salinity brines having carefully modified ionic compositions. In this study, we developed a multiphase, multicomponent, finite-difference reservoir simulator and incorporated an improved mechanistic model to model low salinity waterflood in carbonates. The model considers key geochemical reactions relevant to low salinity waterflooding as reported by many authors recently. However, our modeling approach differs in two ways. Firstly, our model assumes that geochemical reactions of injected brines with the rock take place only on water-wet surfaces of these rocks and at the three-phase contact line; compared to other existing models that consider reactions to occur on the entire rock surface for oil-wet rocks. Secondly, previous models consider organic acids as a single species. In reality, oil is likely to have a mixture of different organic acids of different polarity, chain length, etc. In our model, we consider the oil to have a mixture of different organic acids and studied its impact on wettability alteration and oil recovery. Using this model, single phase and oil recovery experiments reported in the literature were modeled. The effect of rock wettability on geochemical reactions of low salinity brines with carbonate rocks was studied. Similarly, the effect of organic acid distribution on wettability alteration and oil recovery was investigated. Our simulation results showed that the extent of reaction of low salinity brines with carbonate rocks decreased as the rock became more oil-wet due to a decrease in reactive surface area. For example, less delay in effluent sulfate ions was observed in case of oil-wet rocks. The water-wet regions grew as a result of wettability alteration at the three-phase contact line. The initial wettability, extent of wettability alteration, and oil recovery profiles were dependent on the organic acid distribution. Furthermore, the inclusion of only key geochemical reactions (dolomitization, sulfate adsorption, and anhydrite dissolution/precipitation) were found to be reasonable for modeling various experiments reported in the literature. The proposed model will help in improving our understanding of mechanisms responsible for wettability alteration.

W/O emulsions generated by heavy oil in porous medium and its effect on re-emulsification

Water/hot water flooding and steam stimulation are usually used for heavy oil recovery. However, W/O emulsions are generated when heavy oil and water flow in porous medium of formations, which can seriously restrict the recovery effect in the middle or late stage. First, the influence of the W/O emulsion on efficient heavy oil recovery is analyzed by the production dynamics and produced fluid emulsified states of oilfields. Then, the W/O emulsion generation process during heavy oil entrapment and water flooding recovery was simulated. The effects of permeability, porous medium shearing distance and heavy oil viscosity on the emulsified state of W/O emulsions were studied. The properties of W/O emulsions were tested. Before reaching the final emulsified state, the lower the permeability and the longer the porous medium shearing distance, the more fully emulsified of the W/O emulsion. In the final emulsified state, the droplet sizes of the W/O emulsions generated by different viscosities of heavy oil are basically the same at the same water content. As the water content increases, the W/O emulsion droplet size grows first, then tends to stabilize, and finally stabilizes at between 2 and 3 μm. The viscosity of the W/O emulsion increases as water content increases and its viscosity increases significantly at high water contents. The lower the viscosity of dehydrated heavy oil is, the greater the increase of the viscosity of W/O emulsion increase. The viscosity of 70% the water content W/O emulsion is more than 15 times that of the dehydrated heavy oil. Finally, the effects of the water content, surfactant concentration, oil–water ratio on the emulsified state, droplet size distribution and its fluidity in porous medium were studied by simulating the re-emulsification process of W/O emulsion and surfactant solution. A W/O/W emulsion would formed by re-emulsification of the W/O emulsion and surfactant solution. As the water content of W/O emulsion increases, the droplet size of the W/O/W emulsion formed by re-emulsification increases, and its fluidity in porous medium decreases. The average emulsion droplet size (50% water content) after re-emulsification is 6.29 times that of emulsions formed by dehydrated heavy oil, and the apparent viscosity in porous medium is 15.05 higher. This study provides significant information for understanding the key issues in the efficient development of heavy oil reservoirs throughout their life time and the research and development of high-efficiency emulsion flooding systems.

Application of spectral element method in simulation of fractured porous media domains modeled by fracture-only technique

In this paper, a new application of the spectral element method (SEM) is proposed, which is combined by the features of the fracture-only reservoir simulation technique. This method has been examined with the numerical simulation of waterflooding recovery mechanism. The effect of co-current imbibition is exhibited by a fracture flow analysis with an impermeable porous media. This analysis has been then repeated to study counter-current imbibition effect considering a homogeneous porous media. The capability of the fracture-only technique has been demonstrated more by analyzing fracture flow with heterogeneous porous media. All the presented SEM's results have shown a closeness agreement with the valid results obtained by analytical and streamline-based formulations. The SEM presented 36% higher accuracy when compared to the solution obtained by the finite element method (FEM).

Effect of Well Orientation on Oil Recovery from Waterflooding in Shallow Green Reservoirs: A Case Study from Central Africa

Recovery efficiency is a key factor in decision-making in oil and gas projects. Although structural setup and well type considerably influence waterflood recovery, few studies have explored the performance of highly deviated wells during the waterflooding of complex shallow reservoirs. Here, we applied numerical simulations to investigate the performance of vertical, horizontal, multilateral, and highly deviated wells during waterflooding of complex shallow reservoirs using the J1 Oilfield as a case study. Recovery efficiencies of 31%, 33%, 31%, and 26% could be achieved for vertical, horizontal, multilateral, and highly deviated wells, respectively. The gas production rate was 39% higher in the vertical wells than in the other types. Highly deviated wells yielded the highest water-cut (80%) over a short period. Highly deviated wells delivered the least production, and, despite branching laterals, multilateral wells were also not the most productive. Our results provide insights into the performance of different well types during the waterflooding of green heterogeneous non-communicating reservoirs and present an example of the successful practical application of waterflooding as an initial recovery mechanism when oil is near the bubble point. This study indicated that multilateral wells are not a panacea in reservoir development. Highly deviated wells are the ideal choice for the shallow, heterogeneous non-communicating reservoirs when economic and environmental impact are considered in decision-making. Well design should be a case-by-case study considering reservoir characteristics, economics, and environment impact.