Evaluation of modified cationic starch for impeding polymer channeling and in-depth profile control after polymer flooding

Premature polymer production in large quantities from flooding reservoirs is a serious problem commonly existing in some large oilfields in China. This is owing to polymer channeling through high permeability zones or pore passage. This paper presents a novel modified cationic starch, which can react with partially hydrolyzed polyacrylamide (HPAM) remaining in reservoir formation to form gels in-situ. The obtained gels can reduce polymer channeling and make successive injected water into mid-low permeability zones that achieve the purpose of deep profile control. The rheological property and the gel strength are examined. The singular sand-pack core-flood test results provide experimental evidence that the formed gel system is more effective in plugging high permeability pore passages. Moreover, the parallel core-flood test was conducted to simulate the process of in-depth profile modification in a heterogeneous formation. It has been found that this gel system can significantly enhance oil recovery and effectively reduce water-cut.     

Performance of PAM/PEI gel system for water shut‐off in high temperature reservoirs: Laboratory study

A polymer gel is one of the common remediate methods to either reduce or totally block excessive water production in oilfields. Some systems demonstrated an excellent performance in treating the problem like polyacrylamide tert‐butyl acrylate (PAtBA)/polyethylenimine (PEI). In this study, polyacrylamide (PAM) was introduced as a cheap alternative to PAtBA that can tolerate high salinity reservoirs. The thermal stability of the PAM/PEI polymeric gel in saline water was examined at 150°C (302F). Samples prepared in sea water showed better stability compared with distilled and field water. Dynamic rheology and core‐flooding experiments were used to evaluate the PAM / PEI gel system at high temperatures. NaCl and NH₄Cl were evaluated as a possible retarders for delaying the gelation time in order to achieve a successful placement. NH₄Cl was found to be more effective retarder. Core‐flooding tests were conducted in sandstone and carbonate cores. The subject polymer gel was injected at rates typical of those in field applications. The injectivity of PAM/PEI was tested in Berea sandstone cores with initial permeability of ～45 mD. The post‐treatment of the system showed a permeability reduction of ～94% for a period of two weeks. The injectivity in low permeability carbonate cores required more retardation compared with the injectivity in sandstone cores. The gel reduced the permeability to brine in Indiana limestone core by 99.8% for more than 5 months. Rheology of cured gel samples indicated that the gel strength needs about one day of curing in the core for the strength to stabilize. © 2015 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2015 , 132, 41869.     

VISCOMETRIC MEASUREMENT OF CHROMIUM(III)-POLYACRYLAMIDE GELS†

Gelled polymers are being used increasingly to modify the movement of injected fluids in secondary and enhaced oil recovery processes. A common gelation process involves the reduction of Cr(VI) to Cr(III) in the presence of polyacrylamide. The Cr(III) reacts or interacts with the polymer to form a gel network. Although correlations of gelation time with principal process variables have been obtained, viscometric data have not been reported during or after gelation. These data are needed for fluid flow calculations in surface equipment and estimation of flow behaviour in reservoir rocks.

A Weissenberg Rheogoniometer, with cone and plate geometry, was used to obtain viscometric data for the gelation of polyacrylamide and chromium (III). Solutions consisting of polyacrylamide polymer, sodium dichromate-dihydrate and sodium bisulfite were gelled under a steady shear field at constant temperature. The shear stress versus time profile for the galation process was interpreted to define a gelation time and to determine the apparent viscosity of the gelled fluid. The gelation time decreased as the applied shear rate increased up to about 14.25 sec^?1 and was affected by shear rate history. Viscometric properties of the gelled solutions were determined. Apparent viscosity of the gelled solutions decreased as the shear rate under which they were formed increased.

Post gelation studies indicated that gels exhibited a residual stress at zero shear rate and behaved as Bingham plastics under steady shear. Gels formed at low shear rates were more viscous than gels formed at high shear rates. However, the structure of these gels was susceptible to shear degradation.     

Effects of divalent cations,seawater, and formation brine on positively charged polyethylenimine/dextran sulfate/chromium(III) polyelectrolyte complexes and partially hydrolyzed polyacrylamide/chromium(III) gelation

Polyacrylamide crosslinked with Cr(III) is a common blocking agent that is injected into oil reservoirs to shut off the water flow to features such as fractures and high‐permeability rock to improve the volumetric sweep efficiency during water flooding. This technique is limited to situations where enough gelant can be injected to fill the high‐permeability zones before gelation occurs. Cr(III) may be encapsulated with a high entrapment efficiency in self‐assembling polyelectrolyte complex nanoparticles with effective diameters of about 100–200 nm and formed by the mixture of polyethylenimine and dextran sulfate in nonstoichiometric amounts. The electrostatic interaction between the polyelectrolytes and the Cr(III) is reversible, but diffusion out of the nanoparticles is retarded, and this results in a delay in gelation from minutes or hours to several days in deionized water. Produced and injection waters often contain salts at concentrations comparable to seawater. The effects of these salts were investigated, and we found that the delay in gelation was further extended to as much as 35 days at 40°C and 35 h at 80°C in the presence of divalent ions at seawater concentrations, either alone or in a field brine or seawater; this greatly increases their potential utility. © 2009 Wiley Periodicals, Inc. J Appl Polym Sci, 2010     

Self-healing behaviors of sulfobetaine polyacrylamide/chromium gel decided by viscosity and chemical compositions

The self-healing behaviors of sulfobetaine amphoteric polyacrylamide/chromium (SPAM/Cr) gel are investigated. The role of chemical composition, including different types of polyacrylamide, acid, and sodium sulfate, in the gel synthesis process as well as the gel's self-healing ability are studied and compared. It is found that the chemical structure with electrostatic discharge repulsion and hydrophobic interaction of amphoteric polyacrylamide play the key roles in the gelation and self-healing processes. Furthermore, lactic acid cannot only adjust the pH value of the system, but also help to form organic chromium, which can coordinate with the  COO group to form the crosslinked gel. The concentration of sodium sulfate can affect self-healing behaviors via electric charge as well. A best concentration range of 220–1600 mg/L is found to provide the maximum self-healing ability in the SPAM/Cr gel at 45 °C for 72 h. The oil field experimental results for the S5-10-P50 well group show that the viscosity recovery rate of the SPAM/Cr gel is greater than 66% after 60 days, and the average starting pressure increases about 1–3 MPa after profile control. The results demonstrate that self-healing SPAM/Cr gel is a type of high-efficiency gel that can be used for depth water plugging and profile control in oil fields. © 2018 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2019 , 136, 46991.     

GO7-23-5206井组凝胶调剖设计及效果分析

井间动态连通性是油藏动态分析的重要内容之一。孤东七区具有高孔高渗、强非均质、储层结构疏松、易出砂的特征。由于孤东油田水驱不均匀,使注入水在平面上形成水驱水流优势通道,从而有可能降低水的扫驱效率。针对这一严峻形势,先用流管图模拟出大孔道以及具有注采对应关系的注水井组。为后期调剖,选井选层提供重要的依据。并且通过连通性分析可以判别水流优势通道分布,最终达到提高采收率的目的。系统开展窜流通道定量化调剖技术提高采收率的研究。选定了一个具有代表性的典型注水井组,以凝胶为调剖剂,利用CMG软件,通过对凝胶的注入量和注入时间,从而确定注入速度,最后根据投入产出比,优选出最合适的方案,并在现场实施中获得良好的效果。     

VISCOMETRIC MEASUREMENT OF CHROMIUM(III)-POLYACRYLAMIDE GELS†

Gelled polymers are being used increasingly to modify the movement of injected fluids in secondary and enhaced oil recovery processes. A common gelation process involves the reduction of Cr(VI) to Cr(III) in the presence of polyacrylamide. The Cr(III) reacts or interacts with the polymer to form a gel network. Although correlations of gelation time with principal process variables have been obtained, viscometric data have not been reported during or after gelation. These data are needed for fluid flow calculations in surface equipment and estimation of flow behaviour in reservoir rocks.

A Weissenberg Rheogoniometer, with cone and plate geometry, was used to obtain viscometric data for the gelation of polyacrylamide and chromium (III). Solutions consisting of polyacrylamide polymer, sodium dichromate-dihydrate and sodium bisulfite were gelled under a steady shear field at constant temperature. The shear stress versus time profile for the galation process was interpreted to define a gelation time and to determine the apparent viscosity of the gelled fluid. The gelation time decreased as the applied shear rate increased up to about 14.25 sec^-1 and was affected by shear rate history. Viscometric properties of the gelled solutions were determined. Apparent viscosity of the gelled solutions decreased as the shear rate under which they were formed increased.

Post gelation studies indicated that gels exhibited a residual stress at zero shear rate and behaved as Bingham plastics under steady shear. Gels formed at low shear rates were more viscous than gels formed at high shear rates. However, the structure of these gels was susceptible to shear degradation.     

水驱后凝胶与表活剂交替注入驱油效果

针对裂缝性低渗透油藏注入水易沿裂缝突进、含水上升快、水驱效果不理想的情况,开展了水驱后凝胶与表活剂交替注入方式提高采收率室内实验研究。通过室内凝胶体系成胶特性和稳定性评价,筛选出与实际油藏区块注入水配伍的凝胶体系。选择甜菜碱两性表面活性剂用于活性剂驱,开展了双管并联岩心体系驱油效果研究。研究结果表明:凝胶与表活剂交替注入可明显提高注入压力,该体系的采收率平均值为12.03%,低渗岩心的采收率略高于高渗透岩心采收率。与表活剂驱、聚合物与表活剂交替注入相比,驱油效果更好,可以作为裂缝性低渗透油藏水驱后进一步提高采收率的技术。     

Investigation of Polymer Adsorption on Rock Surface of Highly Saline Reservoirs

Blocking or reducing water production from oil wells is a serious problem in oil industry. Two types of polymers, namely, polyacrylamide (PAA) and polysaccharides (xanthan) have been investigated in this paper. The viscosity of both polymer solutions was first evaluated at different salinities, shear rates and concentrations. Afterwards, the solutions were injected into core samples to examine the adsorption on the rock surface by calculating the resistance factor as well as the residual resistance factor. Also, the effect of the injection rate of the polymer solutions has been studied. The results show that xanthan solution is tolerant of high salinity (20 %), while PAA solution is very sensitive to salt. Both polymer solutions show a pseudoplastic flow as a function of the shear rate. The core sample experiments show that both polymer solutions suffer a reduction in the adsorption rate with salinity increase. However, xanthan shows acceptable values even with a salinity up to 20 % and a temperature of 60 °C. Therefore, xanthan can be recommended to shut off water in high salinity and high temperature reservoirs. It was also found that the lower the injection rate the higher the adsorption on the rock surface.     

下寺湾油田北沟-张岔结合区长2油藏储层特征研究

下寺湾油田北沟-张岔结合区长2油层为该区主力产层.通过扫描电镜、薄片和压汞分析等方式对研究区储层岩石学、孔喉结构、渗流特征、粘土矿物、成岩作用及敏感性评价进行了分析,研究表明,储集层成分成熟度低、结构成熟度低,填隙物含量高;储集空间以原生粒间孔为主,驱油效率低;有低渗油田油水同出特点;储层粘土矿物主要以绿泥石为主,成岩作用对储层物性影响较大,储层具中等酸敏,中等偏弱水敏特点.     

Lab simulation of profile modification and enhanced oil recovery with a quaternary ammonium cationic polymer

Long-term water flooding in oilfield exploitation generally results in a marked increase of interlayer and/or inner-layer heterogeneity of oil reservoirs and premature polymer production in large quantities from flooding reservoirs. This paper presents a novel quaternary ammonium cationic polymer (NCP), which was prepared by using maize starch and (2,3-epoxypropyl)trimethylammonium chloride as raw materials. The effect of NCP on water plugging and profile modificaton after polymer HPAM (partially hydrolyzed polyacrylamide) flooding was evaluated by laboratory simulation tests of enhanced oil recovery. The experimental results indicate that crosslinking gel system formed after HPAM-NCP alternate injection could effectively seal off the high permeability zone to force the successive liquid to flow to mid-low permeability zones and get profile control in depth. In addition, the contact angle measurements reveal that the adsorption of NCP on the montmorillonite changed its surface wettability and enhanced its hydrophilicity, which promoted enhance oil recovery significantly.     

岩心大孔道发育程度对不同调剖剂影响因素研究

渤海油田具有储层岩心胶结疏松、非均质性严重、原油黏度较高、平均渗透率较高和单井注水量较大等特点,并且随着注水开发的不断进行,岩心内大孔道不断发育。所以针对渤海油田实际情况对不同调剖剂在不同发育程度的岩心大孔道内的封堵情况进行了研究。结果表明,岩心孔道发育程度越大淀粉凝胶成胶效果越好,而岩心孔道过大会影响聚合物凝胶的成胶效果。无机地质聚合物在未发育岩心孔隙和发育不完全孔隙内注入性较差,增油效果较差。     

Sand consolidation via latex destabilization

This article investigates the use of a commercial latex dispersion for the purpose of sand consolidation in oil wells. The aim is to consolidate sand without compromising permeability and to prevent sanding during water breakthrough. This is achieved by injecting latex dispersions into a sand‐pack and relying on potassium chloride flushes, or irreducible saline water in the reservoir, to destabilize the latex onto the sand surface. This forms a latex network connecting and holding the sand grains together. The strength of the consolidation in the laboratory is determined by flowing water and oil at various flow rates and investigating the amount of sand produced. The effect of different parameters, such as the amount of latex injected, the latex salinity, and salinity of the irreducible water are discussed. © 2017 American Institute of Chemical Engineers AIChE J, 63: 2610–2617, 2017     

瓦窑堡油田羊马河区调剖技术研究

瓦窑堡油田羊马河区位于陕西省子长县境内,构造位置处于鄂尔多斯盆地陕北斜坡的中东部。主力油层为长2层。油层具有储油物性较好,油藏整装连片,油藏丰度大等特点。但油藏同样具有低孔、低渗、低含油饱和度的特点,属于地质构造活动较弱的岩性油藏。经过多年来的注水开发作业,该区已经取得不错的产量,但同时也带来了很多问题,岩石孔隙经过长年的冲刷已经形成大孔道,注入水将沿着大孔道从注水井流入采油井,其余含油孔隙将无法被驱出,使得产油量大幅度直线下降。为此,采用调剖堵水技术,将大孔道封堵,注入水进入含油孔隙,使油井达到高产、稳产的目的,进一步提高采收率。     

Preparation and characterization of nanocomposite hydrogels based on polyacrylamide for enhanced oil recovery applications

In the present work, attempts have been made to prepare nanocomposite type of hydrogels (NC gels) by crosslinking the polyacrylamide/montmorillonite (Na‐MMT) clay aqueous solutions with chromium (III). The X‐ray diffraction patterns of the NC gels exhibited a significant increase in d₀₀₁ spacing between the clay layers, indicating the formation of intercalated as well as exfoliated type of morphology. Exfoliation of the clay layers through out the gel network was found to be predominated, which evidences the high interaction between the polyacrylamide segments and montmorillonite layers. Gelation time as well as variation of viscoelastic parameters such as storage modulus (G′) of the gel network during gelation process at 75°C was studied and followed by rheomechanical spectroscopy (RMS). The NC gels prepared with lower crosslinker concentration showed higher strength and elastic modulus compared with the similar but unfilled polyacrylamide gel. This distinct characteristic of the NC gels yields a gel network structure with high resistance towards syneresis at high temperature in the presence of the oil reservoir formation water. The effects of the composition, such as clay content, crosslinker concentration, and also water salinity upon the gelation rate, gel strength as well as rate of syneresis have been investigated. To optimize the injectivity of the intercalated polyacrylamide solution before the onset of gelation with the gel strength of the final developed gel, sodium lactate was employed as retarder. This was found to be effective to balance these two characteristics of the NC gels, which are aimed to be used for water shut‐off and as profile modifier in enhanced oil recovery (EOR) process during water flooding process. The nanocomposite gels showed much more elasticity and extensibility at low crosslinker concentration compared with the similar but unfilled gel, which makes the NC gels suitable as an in‐depth profile modifier, and also as an oil displacing agent in the heterogeneous oil reservoir in chemical EOR. Effects of the clay content on the thermal stability of the gel network have also been investigated by thermogravimetric analysis (TGA). Scanning electron microscopy (SEM) has been performed upon the NC‐gel samples. © 2006 Wiley Periodicals, Inc. J Appl Polym Sci 100: 2096–2103, 2006     

Permeability reduction by asphaltenes and resins deposition in porous media

The deposition of crude oil polar fractions such as asphaltenes and resins in oil reservoir rocks reduce considerably the rock permeability and the oil production. In the present work, a crude oil and various core samples were extracted from Rhourd–Nouss (RN) reservoir rock. Afterwards, core flow experiments were carried out in the laboratory to investigate permeability reduction that causes formation damage. The core permeability damage was evaluated by flooding Soltrol, through the sample and measuring the solvent permeabilities, K_i and K_f, respectively, before and after injection of a given pore volume number of the crude oil.The data indicate that upon flooding the crude oil through the porous medium, considerable permeability reduction, expressed as the ratio (K_i − K_f)/K_i, and ranging from 72.4% to 98.3% were observed. The permeability reduction is found to result from irreversible retention of asphaltenes and resins in the porous core sample. However, no correlations could be established between the depth of the well, the core porosity, the core mineral compositions determined by X-ray analysis, and the permeability damage factors. In addition, effluents flowing away from RN wells were collected and analysed at various periods, after carrying out aromatic solvents squeezes. The amount of saturates, aromatics, resins, and asphaltenes (SARA analysis), of the crude oil, the deposited crude oil fraction, and the effluent’s residues were measured and compared. The asphaltenes weight percent was found to increase from 1.56% for the crude oil to 11.42% for the deposited oil fraction, and was in the range 1.37–2.36% for the effluent’s residues. Such results indicate that the deposited oil fraction and the effluent’s residues consist mainly of asphaltenes and resins.     

弱凝胶调驱体系性能评价研究

针对具有储层非均质性强、渗透率低和孔隙结构复杂特点的储层,在注水开发后期,含水率急剧上升,普通的水驱和聚驱方法很难将油驱替出。复合离子型聚合物凝胶有很好的储层适应性,与注入污水配伍性好,成胶时间可控,吸附、滞留能力强,抗冲刷性好。其注入能力强,波及范围大,既可以封堵储层大孔道("调"的作用),又可以驱替储层剩余油("驱"的作用),能够满足调驱体系大剂量注入的要求。本文针对复合离子型凝胶调驱体系进行配方优选并进行性能评价实验,实验结果表明,该调驱体系具有较好的抗盐性、抗剪切性、热稳定性和黏弹性。     

超低渗透油藏相渗曲线特征及其影响因素探讨

油水相对渗透率是研究油水两相渗流的基础,是油田开发中参数计算、动态分析以及油藏数值模拟等方面不可缺少的重要资料,应用范围广泛。文章以A油田长6特低渗透储层为对象,对相对渗透率曲线特征及其影响因素进行分析：该储层相对渗透率曲线受储层岩石润湿性、孔隙结构以及粘土矿物含量等因素影响较为明显。     

表面活性剂对特低渗油藏的适用性及应用

为评价表面活性剂WLW对特低渗油藏的适用性,研究了WLW的渗吸特性、乳化性能和界面张力及其在特低渗油藏物理模拟岩心驱油实验和现场中的应用。室内实验结果表明,WLW对注入水的渗吸效率有促进作用;注入质量分数0.2%的WLW溶液,可在水驱基础上提高驱油效率5%左右;WLW在特低渗岩心中提高驱油效率的幅度明显高于中低渗岩心。2011—2013年在长庆靖安油田A1和A2井组开展注WLW现场试验,累计增油4 781 t,WLW对于特低渗油藏提高采收率效果明显。     

Gelation performance of poly(ethylene imine) crosslinking polymer–layered silicate nanocomposite gel system for potential water‐shutoff use in high‐temperature reservoirs

Polymer gels have been widely used for water shutoff in mature oil fields. In this paper, polyacrylamide (PAM)–montmorillonite (MMT) nanocomposites (NC) were prepared through in situ intercalative polymerization. Fourier transform infrared spectroscopy and X‐ray diffraction were conducted to characterize the prepared PAM/MMT nanocomposites. The gelation performance of poly(ethylene imine) (PEI) crosslinking PAM/MMT nanocomposite gel system (NC/PEI gel system) was systematically investigated by bottle testing and viscosity measurement methods. The results showed that the gelation performance of the NC/PEI gel system was greatly affected by the total dissolved solids, PAM/MMT nanocomposite concentration, and PEI concentration. The NC/PEI gel system exhibited much better thermal stability and gelation performance than the PAM/PEI gel system at the same conditions. The gelation performance after flowing through porous media of the NC/PEI gel system before injection and that of the subsequently injected gel system was different. The gel strength decreased and the gelation time was delayed after the gel system before injection was flowed through porous media. However, the gel strength of the subsequently injected gel system did not decrease, and only the gelation time was delayed after flowing through porous media. This study suggests that the NC/PEI gel system can be used as a potential water‐shutoff agent in high‐temperature reservoirs. © 2016 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2016 , 133, 44243.