High Water Cut Research Articles

Mechanism of formation of chromium acetate(Cr3+)/ phenol-formaldehyde resin prepolymer(PRP) complex and its compound cross-linking reaction with polymer for conformance control

For the heterogeneous oil reservoir with high water cut, the conformance control by using polymer gels is good for increasing oil production and decreasing excessive water. However, facing the current situation of low oil prices, how to improve the exploitation efficiency and reduce the production cost in the maximum extent are still drawing the attention of petroleum engineers. Therefore, it is necessary to further study the polymer gels to achieve this purpose. Among the polymer gels, the polymer/Cr3+ system and polymer/phenolic-formaldehyde compounds system are the most common used, which are suitable for the low temperature reservoir and high temperature reservoir, respectively. Based on the properties of each other, the combination of Cr3+ and phenol-formaldehyde resin prepolymer (PRP) as a type of cross-linking agent can not only improve the thermal stability of polymer/Cr3+ gel, but also enable polymer/PRP gel to be applied to low-medium temperature reservoirs, which can further improve the application effect of polymer gels. However, the mechanism of compound cross-linking reaction of Cr3+-PRP and polymer is still unclear. In this paper, the properties of Cr3+-PRP solution is first tested and then the process of crosslinking reaction of Cr3+-PRP and polymer is study. In the Cr3+-PRP solution, a new polynuclear olation complex ion of chromium (Cr3+-PRP complex) is formed, of which the properties is different from PRP solution or chromium acetate solution. The cross-linking reaction of Cr3+-PRP complex and polymer is compound. During the compound reaction at the temperature of 45 °C, the reaction of Cr3+ and polymer has an impact on that of PRP and polymer, so that the reaction of Cr3+-PRP complex and polymer is different from the superposition of the two reaction processes of Cr3+/polymer system and PRP/polymer system. The formed Cr3+-PRP complex can resist salt to 70,000 mg/L. The experimental results can provide a theoretical guidance for the high efficient practical application of conformance control by using polymer/Cr3+ system or polymer/phenolic-formaldehyde compounds system.

Hydrate formation management simulations with anti-agglomerants and thermodynamic inhibitors in a subsea tieback

The rapid formation of gas hydrates in subsea tiebacks is regarded as one of the most challenging problems in flow assurance. Due to economic reasons, the hydrate controlling strategy has moved from hydrate avoidance to hydrate management. Efficient design of hydrate management techniques requires a better understanding of hydrate formation kinetics, as well as a robust transient hydrate simulation tool. In this work, we use a transient hydrate simulation tool with the ability of predicting hydrate formation in oil- and water-dominated systems simultaneously to capture complicated multiphase flow scenarios expected in oil and gas flowlines. This modeling tool can be applied to estimate hydrate formation in flowlines exhibiting both water- and oil-dominated environments at different locations, which is especially useful in modeling transient shut-in/restart operations as well as high water cut scenarios. This simulation tool can track the concentration of multiple thermodynamic inhibitors and consider the injection of anti-agglomerants through the cohesive force change between hydrate particles. This paper presents modeling results of a real black oil subsea tieback system, considering its geometry, production data and fluid properties. The hydrate formation rates and plugging risks at different water cuts, gas-oil ratios and liquid holdups were estimated both during steady state operation and shut-in/restart conditions. A hydrate blockage formed in the real field at 49 vol% water cut was successfully predicted using the transient hydrate prediction model. This simulation tool can be applied to predict the hydrate formation rate and amount under the complicated multiphase flow scenarios in oil/gas fields, and could be useful for the design and optimization of hydrate management approaches in flowlines.

Experimental study of horizontal two- and three-phase flow characteristics at low to medium liquid loading conditions

An experimental study is conducted using a 0.075-m ID pipe to investigate characteristics of two- and three-phase stratified flow in a horizontal pipeline. Experiments are conducted under low to medium liquid loading conditions which is common in wet-gas and long transportation pipelines. The flow characteristics investigated include flow pattern, liquid holdup and pressure drop. The experimental range covers superficial gas Reynolds numbers from 6314 to 200,734, superficial liquid Reynolds numbers from 160 to 4391 and water-cut values from 0 to 90%. Differential pressure transducers, quick closing valves and a high-speed camera are utilized to obtain the relevant data and the trends investigated. The observed flow patterns are stratified smooth, stratified wavy and stratified-annular flow. The transitions between flow patterns vary as a function of water-cut. The effect of water-cut on liquid holdup and pressure drop were relatively negligible especially at low water-cut conditions and the fine mixing of the oil-water mixture may be partially responsible for this. As a result, with the exception of flow pattern transitions, the performances of classical two-phase flow models (for the prediction of liquid holdup and pressure drop) appear unaffected when applied to air–oil–water 3-phase flows especially at high water-cuts.

A new organic fiber composite gel as a plugging agent for assisting CO2 huff and puff in water channeling reservoirs

The utilization of CO2 for enhancing oil recovery is an environmentally friendly way to dispose the industrial CO2 emissions. CO2 utilization ratio is defined as the volume ratio of produced oil to injected CO2. CO2 huff and puff technology can further improve oil recovery in high water cut reservoirs. However, as the huff and puff cycle increase, gas channeling is easy to happen and the utilization ratio of CO2 is reduced. Organic fiber composite gel is an effective plugging agent for gas channel. The major objective of this paper is to study the mechanisms of increasing CO2 utilization by injecting organic composite gel as the plugging agent. A large scale (40 cm*40 cm*3 cm) natural rock model with grooves is used to simulate the experimental conditions such as channeling channel and horizontal well. Two groups of experiments of direct CO2 huff and plugging agent assisted CO2 huff and puff were conducted. By comparing the pressure changes during the experiments, the mechanism of blocking the channel, balancing the CO2 displacement front and improving the utilization ratio of CO2 were analyzed. The experimental process was fitted by reservoir numerical simulation, and the remaining oil distribution, plugging agent distribution and CO2 distribution in CO2 huff and puff under different conditions were further demonstrated. Results show that compared with direct CO2 stimulation, the distribution of remaining oil saturation and reservoir pressure become more uniform and the utilization ratio of CO2 is greatly increased after injecting organic fiber composite gel. It is mainly due to the fact that the injected plugging agents flow preferentially into high water saturation region along the high permeability channels. Then, they can generate the organic fiber composite gel and remain in the channeling paths. As a result, the following injected CO2 will be forced to flow towards oil-rich regions radially and uniformly. Thereby, more CO2 can contact and react with the in-situ oil, resulting much higher oil recovery. In other words, the utilization ratio of CO2 is greatly improved. Taking Jidong oilfield as an example, it has been injected 19.2 × 104 t CO2 with the total oil production by 21.1 × 104 t. The utilization ratio of CO2 is calculated as high as 1.09. The observations of this study provide the theoretical basis for future application of organic fiber composite gel before CO2 flooding in the water channeling reservoirs.

A novel method of bidirectional displacement with artificial nitrogen gas cap and edge water for enhanced oil recovery: Experimental and simulation approaches

The fault block hydrocarbon reservoirs developed by water flooding in Shengli Oilfield have entered into the period of high water cut and low oil recovery. The residual oil to be recovered is chall...

Permian Operators Squeezed by Growing Water Pressure

The rising tide of produced water in the Permian Basin is requiring operators to re-engineer how they manage water. One big difference in the Permian is that water production from unconventional reservoirs exceeds output from most other plays, particularly in the Delaware Basin. Prolific water production has long been a given in conventional fields there, but most of that could be reinjected to maintain production, which is not an option in the ultratight rock. Instead, billions of gallons of produced water have been pumped into saltwater disposal wells in shallow formations, such as the San Andres, significantly increasing the pressure drillers encounter, creating a hazard for drillers moving in and out of them from lower-pressure zones. To isolate the higher-pressure zones passed on the way to the Wolfcamp, operators have increased the number of strings of casing used from three to four. The increase adds about $600,000 to the cost per well, said Andrew Hunter, drilling manager for Guidon Energy, which uses the added string to isolate two underpressure zones. To maximize produced water use for fracturing, Cimarex has streamlined filtration and chemical treatments of the water in the pipeline system en route to fracture sites, limiting the need for fixed facilities, said Rita Behm, Permian exploration engineering project manager for Cimarex. Occidental Petroleum is working to manage water production while picking drilling targets. It has developed a detailed evaluation system based on a large company database that predicts production of hydrocarbons and water. High water cuts are a negative in the grading system used to choose where to spend, said John Polasek, vice president of geoscience at Occidental. All three mentioned the water issue in their presentations at the recent AAPG Global Super Basins conference on the Permian. The comments reflected the importance of dealing with water issues for operators that need to minimize fresh water use and manage injections of produced water. ExxonMobil’s XTO Energy arm is building a system to “treat produced water and reuse it again and again” to reduce its demand for fresh or brackish water wells, said Staali Gjervik, senior vice president for Permian Integrated Development at XTO. A Big Shift Addressing the problem will require an industrywide shift. Even if an operator is reusing all of its water, “they can get hammered” by the injections of a nearby commercial saltwater disposal well by an operator that is not finding other uses, Hunter said. “The only way to deal with this is to work cooperatively with other operators,” he said. When drilling through higher pressures, Hunter said drillers increase mud weight to counter the higher pore pressure in that layer, and promptly adjust it back when the pressure drops.

Microscopic Determination of Remaining Oil Distribution in Sandstones With Different Permeability Scales Using Computed Tomography Scanning

To investigate the characteristics of oil distribution in porous media systems during a high water cut stage, sandstones with different permeability scales of 53.63 × 10−3 μm2 and 108.11 × 10−3 μm2 were imaged under a resolution of 4.12 μm during a water flooding process using X-ray tomography. Based on the cluster-size distribution of oil segmented from the tomography images and through classification using the shape factor and Euler number, the transformation of the oil distribution pattern in different injection stages was studied for samples with different pore structures. In general, the distribution patterns of an oil cluster continuously change during water injection. Large connected oil clusters break off into smaller segments. The sandstone with a higher permeability (108.11 × 10−3 μm2) shows the larger change in distribution pattern, and the remaining oil is trapped in the pores with a radius of approximately 7–12 μm. Meanwhile, some disconnected clusters merge together and lead to a re-connection during the high water cut period. However, the pore structure becomes compact and complex, the residual nonwetting phase becomes static and is difficult to move; and thus, all distribution patterns coexist during the entire displacement process and mainly distribute in pores with a radius of 8–12 μm. For the pore-scale entrapment characteristics of the oil phase during a high water cut period, different enhance oil recovery (EOR) methods should be considered in sandstones correspondent to each permeability scale.

Measurement of water holdup in vertical upward high water-cut oil-in-water flows using a high frequency sensor

In the present study, we propose a high frequency sensor (HFS) for water holdup measurement in high water-cut oil-in-water flow with low velocity. Through analyzing amplitude-frequency characteristics and phase-frequency characteristics of HFS in different working frequencies using the finite element method, the optimal working frequency of HFS is determined, and the relationship between the phase output of HFS and the water holdup is analyzed. With the designed HFS measurement system, an experiment of vertical upward high water-cut oil-in-water two-phase flow with low velocity is conducted in a 20 mm inner diameter (ID) pipe, through which the relationships among phase output signals of HFS, water-cut and total flow rate are obtained under the dispersed oil-in-water flow (D O/W). In addition, the variations of sensor output for changing water salinity are investigated. The results show that HFS possesses high water holdup measurement resolution which can substantially overcome the limitation that traditional conductance and capacitance method exhibit extremely low resolution in oil-in-water flows with both high water-cut and high water salinity. Based on drift-flux model, water-cut can be predicted with high accuracy.

MODELING OF WATER-ISOLATING SYSTEM GEL TIME FOR OIL WELLS

Currently, a high water cut in wells is one of the main problems of the oil industry. Its presence leads to a decrease in the flow rate of wells, an increase in the volume of work connected with the dewatering and trans- portation of products, an increase in the number of annular flows in wells, the destruction of bottom-hole formation rocks and the formation of sand plugs. One of the available and effective ways to solve this prob- lem is the use of methods for limiting water inflow, and in particular, technologies for leveling the injectivity profile in injection wells. During these works fulfilling, an important characteristic is water isolat- ing system gel time, which is affected by various parameters. This is the time required for the gel to transition from a free fluid into a solid or semi-solid, after which its transfer becomes difficult. In this work, an organically crosslinked system containing an acrylate copolymer crosslinked with a polyamine was chosen as a water insulat- ing material. Different formulations were developed using 2 % and 5 % potassium chloride (KCl), used as an acidic agent. The gel time of vari- ous compositions was determined at temperatures of 60 °C and 88 °C. According to the research results, the corresponding dependencies were established. To quantify the degree of influence of these parameters on the gel time, factor analysis was performed, which showed that the temperature parameter had the greatest effect. Also based on the results of the research, a mathematical model was developed for predicting the gel time, which describes the mechanism by which the three parameters considered are affected: the concentration of the crosslinker, the concen- tration of the acidic agent, and temperature.

IMPROVEMENT OF TECHNIQUES FOR PREDICTED OIL PRODUCTION AT MATURE OIL FIELD

Background Despite the high water cut of the extracted products and the depletion of reservoirs, the share of recoverable oil reserves in some fields of the Republic of Bashkortostan remains quite large. For the most complete oil recovery, constant refinement and improvement of previously adopted technological solutions and regulatory documents is required. The paper discusses the reasons for the failure to meet the current planned targets for oil production, presents the calculation of the bottomhole pressure of oil deposits before the end of operation in accordance with the pressure on the discharge line. Aims and Objectives To analyze the change in parameters depending on the initial density of the grid based on a wide array of information on changes in water cut, current oil recovery, grid density of wells and oil and water factor. To establish the reasons for the discrepancy between design and actual development indicators over time using the Tuymazinsky, Shkapovsky and Arlansky fields as an example. Results It is shown that one of the main ways to improve the projects quality is to increase the iteration when setting the geological and physical parameters on the grid model nodes of the ROXAR software package. The analysis of the causes of possible errors identified during the analysis of design documents for the development of Tuymazinsky, Shkapovsky and Arlansky oil fields, and ways to correct them are presented.

Study on enhanced oil recovery by multi-component foam flooding

To obtain a foam system with better stability and oil resistance, this paper starts with the mechanism of enhanced oil recovery by foam flooding and makes use of a combination of surfactants to make foam more stable. A foam system with strong stability can be obtained by combining anionic surfactants with nonionic surfactants. Based on this idea, a new type of multi-component foam flooding system (system 1) is developed. The main molecule is zwitterionic surfactant with a concentration of 0.7% fourteen alkyl sulfonated fluorobetaine (SFN). The auxiliary surfactants are present at a concentration of 0.3% of Sodium Dodecyl Sulfate (SDS), a concentration of 1.8% of potassium chloride (KCL) and a concentration of 3.0% of anhydrous ethanol (C2H6O). In addition, adding a 1000 mg/L solution of partially hydrolyzed polyacrylamide (HPAM) into the system can enhance the strength of the interfacial film, increase the surface dilatation modulus and extend the equilibration time, thereby enhancing the stability of the foam. The comparative evaluation experiment results show that the foaming capacity, foam stability and comprehensive performance of system 1 are better than those of other common foam systems under the condition of 30% Sor and a 1:1 ratio of gas to liquid. For system 1, the number of bubble films L (lamella number) is less than 7, the boundary between the foam and crude oil is clear, and the interaction is small. The foam of system 1 has good oil resistance. The results of oil displacement show that the oil recovery using system 1 increases by 16.8 percentage points after polymer flooding, which is 4–6 percentage points higher than that of an ordinary foam system. The results of the oilfield test show that the development effect of polymer flooding in the B block is poor. In January 2017, system 1 was injected into the reservoir. The 23 wells in the B block responded well, and the effective ratio reached 92%. Compared with the previous stage, the daily fluid production increased by 215 m3, the daily oil production increased by 141.0 t, the water cut decreased by 9.2 percentage points, and the reservoir effect was obvious. This result provides a new idea for the later development of high water cut reservoirs.

Interference testing model of multiply fractured horizontal well with multiple injection wells

High water-cut has been observed for many multiply fractured horizontal wells (MFHWs) in China soon after water flooding begins. Available well-testing models of single well ignored the effect of adjacent wells on the MFHW, and they are unable to evaluate whether MFHW (producer) and surrounding vertical wells (injectors) are in good pressure communication. To fill this gap, this work presents a multi-well interference testing (MWIT) model to consider the interference of injectors and further match the interference pressure data of the MFHW.The MWIT model is established to investigate the effect of multiple injection wells on transient-pressure behavior of the MFHW. Due to the interferences from injectors, the pressure and pressure-derivative curves of MWIT move down beginning with the biradial flow regime for single MFHW model, and pseudo-radial flow (horizontal line with the value of 0.5 on pressure-derivative curve) disappears. Sensitivity analysis was conducted to discuss the effects of crucial parameters on the pressure response, including total injection rates, unequal injection rates of injectors, well spacing, injector distribution, number and production of hydraulic fractures. When total injection rates are lower than the production rate, the pressure derivative will eventually stabilize at 0.5*(1-Σ(qIncjD)) during the interference-flow regime on the log-log type curves. Since only the positive number can be shown in the log-log graph, semi-log curves are introduced to fully characterize the flow regimes of MWIT. A novel finding is that pressure derivative also ultimately behaves as a horizontal line with the value of 0.5*(1-Σ(qIncjD)) when total injection rates are equal or higher than production rates on the semi-log curves. The total injection rates and well spacing between the MFHW and injectors have a significant effect on middle and late pressure behaviors, whereas the number and production of fractures mainly affects the pressure responses during early to middle period. Type curves indicate that the effect of surrounding injectors is significant and cannot be ignored, and the novel characteristics provide potential application of the MWIT model to estimate formation parameters. Case studies highlight the application of the proposed method in effectively matching the interference pressure data.

Three-dimensional structural modeling of a low permeability reservoir in the Banqiao formation of the Maxi Oilfield

This paper presents a three-dimensional geological modeling method for low permeability reservoirs based on core, logging, seismic, and dynamic data. Matrix and fractures are two types of reservoir space. This method includes two-step modeling methods, and different methods are used to establish a matrix model and fracture model. As a low permeability reservoir, Maxi Oilfield has entered the high water cut stage, and developing a precise three-dimensional structural model that can reflect the spatial distribution of the reservoir is an urgent task. First, the gravity flow channel deposition was determined by core observations and the characteristics of gravity flow reservoirs are described. On this basis, a three-dimensional quantitative geological model of the matrix is established using the sequential indicator simulation. The ant-tracking technique is used to identify the fracture development in Maxi Oilfield, and two groups of fractures, 50°–100° in an NE direction and 30°–35° in an NE direction, are identified as the main reservoirs. The discrete fracture distribution model is established deterministically, and then, the fracture model is modified by the distribution of fractures reflected comprehensively by the water flooding front, microseismic, and dynamic data. This three-dimensional structural model can guide the development of water injection wells in Maxi Oilfield.

Achievements and future work of oil and gas production engineering of CNPC

Abstract This paper summarizes the latest achievements and technological progress in oil and gas production engineering of China National Petroleum Corporation (CNPC) and discusses the main four challenges faced: developing low quality resource at low oil price; keeping stable production of mature oilfields when well oil production drops year by year; low systematic efficiency, high cost, prominent environmental protection issue and short of technological strategy for high water cut ratio and high oil recovery ratio oilfields; and lacking of high level horizontal well drilling and completion technology to develop unconventional and deep reservoirs. Three technological development directions to address these challenges are put forward: developing fracture controlling stimulation and well factory to produce low quality resource economically, developing re-fracturing technology for old wells in mature oilfields, promoting the fourth generation separate layer water injection technology to stabilize the production of mature oilfields; innovating new technologies of water flooding with nano-material, injecting and producing through one well.

High Water Content Prediction of Oil-Water Emulsions Based on Terahertz Electromagnetically Induced Transparency-like Metamaterial.

This work aims to investigate the electromagnetically induced transparency-like (EIT-like) metamaterial for high water cut emulsions’ detection in the terahertz band. The electromagnetic responses of the selected metamaterial covering emulsions exhibit red-shifted resonant frequency with increasing water volume from 60 to 98%. Three numerical models coinciding with theory analysis were built based on the extracted resonant frequencies at the transmission peak and dips to predict water concentration. The results show that the built models accurately predicted the water content with absolute errors less than 0.26, 0.41, and 0.24%, respectively. The EIT-like resonance is introduced by coupled bright and dark modes, making it similar to a weakened plasma resonance. Consequently, the permittivity-dependent frequency would help develop both economically feasible and socially beneficial sensors for high water content prediction.

Experimental Investigation on the Effects of CO2 Displacement Methods on Petrophysical Property Changes of Ultra-Low Permeability Sandstone Reservoirs Near Injection Wells

The petrophysical properties of ultra-low permeability sandstone reservoirs near the injection wells change significantly after CO2 injection for enhanced oil recovery (EOR) and CO2 storage, and different CO2 displacement methods have different effects on these changes. In order to provide the basis for selecting a reasonable displacement method to reduce the damage to these high water cut reservoirs near the injection wells during CO2 injection, CO2-formation water alternate (CO2-WAG) flooding and CO2 flooding experiments were carried out on the fully saturated formation water cores of reservoirs with similar physical properties at in-situ reservoir conditions (78 °, 18 MPa), the similarities and differences of the changes in physical properties of the cores before and after flooding were compared and analyzed. The measurement results of the permeability, porosity, nuclear magnetic resonance (NMR) transversal relaxation time (T2) spectrum and scanning electron microscopy (SEM) of the cores show that the decrease of core permeability after CO2 flooding is smaller than that after CO2-WAG flooding, with almost unchanged porosity in both cores. The proportion of large pores decreases while the proportion of medium pores increases, the proportion of small pores remains almost unchanged, the distribution of pore size of the cores concentrates in the middle. The changes in range and amplitude of the pore size distribution in the core after CO2 flooding are less than those after CO2-WAG flooding. After flooding experiments, clay mineral, clastic fines and salt crystals adhere to some large pores or accumulate at throats, blocking the pores. The changes in core physical properties are the results of mineral dissolution and fines migration, and the differences in these changes under the two displacement methods are caused by the differences in three aspects: the degree of CO2-brine-rock interaction, the radius range of pores where fine migration occurs, the power of fine migration.

АНАЛИЗ ЭФФЕКТИВНОСТИ ПРИМЕНЕНИЯ ВЯЗКОУПРУГОГО ПОВЕРХНОСТНО-АКТИВНОГО СОСТАВА НА МЕСТОРОЖДЕНИЯХ ЗАПАДНОЙ СИБИРИ

Актуальность исследования определена тем, что современное состояние многих нефтяных месторождений характеризуется массовым их вступлением в позднюю стадию разработки. Cкважинная продукция сопровождается увеличением обводненности скважин при сохранении достаточного количества остаточных извлекаемых запасов нефти. При воздействии на пласт заводнением не все пропластки вовлекаются в разработку. Причинами являются неоднородность пласта, как по вертикали, так и по латерали, высокое соотношение вязкостей добываемой нефти и нагнетаемой воды. При этом процессы в пласте также сопровождаются преждевременным прорывом воды и, следовательно, снижением коэффициента нефтеотдачи. В связи с этим многие нефтяные компании уделяют большое внимание использованию методов регулирования фильтрационных потоков. Одной из таких эффективных технологий, с потокоотклоняющим действием, является применение сшитых полимерных составов. Их преимущества: более высокая вязкость раствора, чем у обычного полимера, создание высокого фактора остаточного сопротивления и способность проникать на более дальние расстояния от ствола нагнетательной скважины. Цель: оценка технологической эффективности от закачки вязкоупругого поверхностно-активного состава на одном из месторождений Западной Сибири. Объектом исследования является участок пласта с невовлекаемыми в разработку запасами и высокой обводненностью. Методы исследования основаны на анализе работы участка проведения обработки, построении карт, оценки запасов. Результаты. Расчитана эффективность обработки нагнетательной скважины на основе интегральной характеристики вытеснения и результатов промысловых геофизических исследований. Выявлено, что технология использования вязкоупругого поверхностно-активного состава успешно была применена и может быть в дальнейшем использована на других месторождениях Западной Сибири.

Best Practices for Waterflooding Optimization Improve Oil Recovery in Mature Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186431, “Waterflooding Optimization: A Pragmatic and Cost-Effective Approach To Improve Oil Recovery From Mature Fields,” by X.G. Lu, SPE, and J. Xu, C&C Reservoirs, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed. Most mature sandstone reservoirs feature natural aquifer drive, artificial water drive, or a combination of the two. These mature fields generally are characterized by high water cut and high recovery efficiency. This paper presents technologies and best practices to improve oil recovery in mature fields through waterflooding optimization. These technologies have proved practical and cost-effective. Introduction Although chemical enhanced-oil-recovery (EOR) technologies such as polymer flood and alkali/surfactant/polymer (ASP) flood can improve oil recovery by 10 and 20%, for waterflooded sandstone reservoirs, respectively, they are expensive and are not applicable in most mature fields at a low oil price. A major problem for waterflooded fields is that, with increased water/oil ratio (WOR), the cost of processing produced fluid soars to exceed the breakeven mark. As a result, many wells are forced to be shut in; in some instances, the entire field may be suspended. Waterflooding-Optimization Methods The technologies discussed in this section are effective generally for multilayer, heterogeneous sandstone reservoirs with high permeability contrast. Zonal Water Injection. This is the most widely applied water-injection-optimization technology. In a multilayered reservoir, early water encroachment along thief zones often occurs. During the mature stage, when the field produces at high water cut, commingled water injection usually leads to ineffective water cycling from the injectors, flowing preferentially through the high-permeability thief zones and back to the surface from the producers. Using the same injecting wellbore, zonal water injection can enhance water-injection rate arbitrarily in low-permeability, low-production, and low-water-cut production zones while reducing the water-injection rate of medium-high permeability, high-water-cut production zones. Thus, the application of this technology can achieve the goal of expanding sweeping efficiency in order to improve oil recovery. Changing the Direction of Fluid Flow. The basic principle is to change the originally fixed injection/production-fluid-flow direction to sweep the remaining oil in bypassed high-oil-saturation areas. This goal is achieved through converting injectors into producers or vice versa. In practice, some injectors are shut in while others are left inactive or regular conversion between injectors and producers is conducted in order to change fluid-flow direction, achieving expanded sweep efficiency. Water Shutoff To Improve Areal Sweeping Volume. This application addresses the challenge of lateral heterogeneities resulting from the permeability contrast of various facies sands. This technique seeks to change the original areal waterflooding direction to constrain ineffective water injection by shutting in the high-fluid-production, high-water-cut wells. The change in liquid-flow direction will benefit the injected water turning to the poorly swept region or bypassed remaining oil to expand sweep volume, achieving the goal of improved ultimate recovery.

Enhanced Nitrogen Foams Injection for Improved Oil Recovery: from Laboratory to Field Implementation in Viscous Oil Reservoirs offshore Bohai Bay China

Foam injection has been a proven technique for IOR in light oil reservoirs, while for heavy oil reservoirs, enhanced foams are needed. In this study, a polymer enhanced foam system was evaluated via comprehensive laboratory experiments and a field pilot testing. Water flooding has been applied in the targeted oilfield (featured with high oil viscosity and severe heterogeneity), but low recovery factor (<20%) and high water cut (over 85%) has been observed. The pilot testing of the foam injection indicates that nearly all producers around the injector exhibited good response with incremental oil recovery and the average water cut dropped by 6.3%. The experimental and field pilot data are presented to demonstrate the effectiveness of the enhanced nitrogen foam injection technique, which can be an effective IOR method for the targeted oilfield and other similar viscous oil reservoirs. [Received: January 2, 2017; Accepted: November 18, 2017]

Investigating the Propagation of the Colloidal Dispersion Gel (CDG) in Thick Heterogeneous Reservoirs Using Numerical Simulation

Over the last few decades, there has been a dispute regarding the ability of colloidal dispersion gels (CDG) to improve sweep efficiency more than polymer flooding. In this study, a numerical model was built using the CMG-STARS simulator to investigate the behavior of injecting 0.1 PV of CDG slug into one quarter of inverted nine-spot pattern. This slug was composed of 0.1 wt. % HPAM polymer solution with a polymer-to-crosslinker ratio (P/X) of 50/1. The model was represented by a thick heterogeneous reservoir with high water cut caused by high heterogeneity and adverse mobility ratio. Different experimental results from published literatures have been implemented in the numerical model to study the effect of these parameters on the propagation of the CDG. The results confirmed that CDG could propagate deep into the thief zones and reduce their permeability more than polymer solution. Moreover, the results showed that the shear-thinning behavior of CDG could assist the selective penetration into the high-permeability streaks only, thus reducing the cost of isolating the thief zones by mechanical methods. In addition, the results showed that the wettability had tremendous effects on the treatment. Therefore, the water-wet system yielded higher results with less damage to the low-permeability layers compared to the oil-wet system. The results showed an overestimation of the performance of post-treatment water when considering irreversible adsorption of CDG. However, the prolonged injection of post-treatment water would not remove the permeability reduction caused by CDG flooding, even with reversible adsorption. The results revealed that the higher the degradation of the CDG, the lower the recovery factor. The results showed the importance of considering a combination injection of polymer and CDG. The results also revealed that the higher the salinity of the reservoir brine and/or the makeup water, the lower the recovery factor. In addition, as the polymer/crosslinker ratio increases, the recovery factor decreases, while as the polymer hydrolysis increases, the recovery factor and residual resistance factor increases.