Development and Evaluation of Locally Made Polymer for Improved Oil Recovery

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Peter Peibuluemi Emmanuel
Keyword(s):  
Oil Recovery ◽  
Chemical Properties ◽  
Cassava Starch ◽  
Water Soluble ◽  
Mobility Control ◽  
Polymer Materials ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Improved Oil Recovery ◽  
Polymer Injection

Abstract Hydrocarbons recoveries from matured fileds require enhancement. This is because matured oil fields have undergone pressure depletions. Polymer injection is a proven means of hydrocarbon recovery enhancement. Therefore, search for polymer materials and preparations of polymer, in the vicinity of matured field is the focus of this study. A lead was found in a starch and investigated to cassava tubers. Cassava starch are brine - water soluble, and are used for favorable mobility control. Laboratory tests were conducted for starch solubility and stability at predetermined saline environment and selected ‘reservoir’ temperature and pressure. Physico - chemical properties and other characteristics of the locally sourced polymer were guided by branded commercial polymers. In all, ten batches of laboratory core flooding excercises were conducted on oil-soaked cores, with five different brine concentrations, followed by another five-cassava starch polymer of concentration 0.00 g/l, 4.35 g/L, 5.13 g/L, 7.02 g/L, and 8.81 g/L. The respective polymer viscosities were 0 cp, 1.28 cp, 2.25 cp, 3.30 cp, and 4.15 cp. While the oil sample of 24.27°API at a temparture of 33°C, was used throughout. Respectively, a displacement efficiency of 51.86 %, 51.86 %, 51.85 %, 51.85 %, and 51.86 % were obtained as results.

The Combined Flooding of Dispersed Particle Gel and Surfactant for Conformance Control and EOR: From Experiment to Pilot Test

2021 ◽  
Author(s):  
Xia Yin ◽  
Tianyi Zhao ◽  
Jie Yi
Keyword(s):  
Oil Recovery ◽  
Formation Energy ◽  
High Salinity ◽  
Surfactant Solution ◽  
Pilot Test ◽  
Control Performance ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Conformance Control ◽  
And Performance

Abstract The water channeling and excess water production led to the decreasing formation energy in the oilfield. Therefore, the combined flooding with dispersed particle gel (DPG) and surfactant was conducted for conformance control and enhanced oil recovery in a high temperature (100-110°C) high salinity (>2.1×105mg/L) channel reservoir of block X in Tahe oilfield. This paper reports the experimental results and pilot test for the combined flooding in a well group of Block X. In the experiment part, the interfacial tension, emulsifying capacity of the surfactant and the particle size during aging of DPG were measured, then, the conformance control and enhanced oil recovery performance of the combined flooding was evaluated by core flooding experiment. In the pilot test, the geological backgrounds and developing history of the block was introduced. Then, an integrated study of EOR and conformance control performance in the block X are analyzed by real-time monitoring and performance after treatment. In addition, the well selection criteria and flooding optimization were clarified. In this combined flooding, DPG is applied as in-depth conformance control agent to increase the sweep efficiency, and surfactant solution slug following is used for improve the displacement efficiency. The long term stability of DPG for 15 days ensures the efficiency of in-depth conformance control and its size can increase from its original 0.543μm to 35.5μm after aging for 7 days in the 2.17×105mg/L reservoir water and at 110°C. In the optimization, it is found that 0.35% NAC-1+ 0.25% NAC-2 surfactant solution with interfacial tension 3.2×10-2mN/m can form a relatively stable emulsion easily with the dehydrated crude oil. In the double core flooding, the conformance control performance is confirmed by the diversion of fluid after combined flooding and EOR increases by 21.3%. After exploitation of Block X for 14 years, the fast decreasing formation energy due to lack of large bottom water and water fingering resulted in a decreasing production rate and increasing watercut. After combined flooding in Y well group with 1 injector and 3 producers, the average dynamic liquid level, daily production, and tracing agent breakthrough time increased, while the watercut and infectivity index decreased. The distribution rate of injected fluid and real-time monitoring also assured the conformance control performance. The oil production of this well group was increased by over 3000 tons. Upon this throughout study of combined flooding from experiment to case study, adjusting the heterogeneity by DPG combined with increasing displacement efficiency of surfactant enhanced the oil recovery synergistically in this high salinity high temperature reservoir. The criteria for the selection and performance of combined flooding also provides practical experiences and principles for combined flooding.

Flow of Hydrophobically Modified Water-Soluble-Polymer Solutions in Porous Media: New Experimental Insights in the Diluted Regime

SPE Journal ◽  
2010 ◽  
Vol 16 (01) ◽  
pp. 43-54 ◽  
Author(s):  
Guillaume Dupuis ◽  
David Rousseau ◽  
René Tabary ◽  
Bruno Grassl
Keyword(s):  
Oil Recovery ◽  
Polymer Concentration ◽  
Adsorbed Layer ◽  
Water Soluble ◽  
Water Soluble Polymer ◽  
Improved Oil Recovery ◽  
Water Soluble Polymers ◽  
Resistance Factors ◽  
Soluble Polymers ◽  
Hydrophobically Modified

Summary The specific molecular structure of hydrophobically modified water-soluble polymers (HMWSPs), also called hydrophobically associative polymers, gives them interesting thickening and surface-adsorption abilities compared with classical water-soluble polymers (WSPs), which could be useful in polymer-flooding and well-treatment operations. However, their strong adsorption obviously can impair their injectivity, and, conversely, the shear sensitivity of their gels can be detrimental to well treatments. Determining for which improved-oil-recovery (IOR) application HMWSPs are best suited, therefore, remains difficult. The aim of this work is to bring new insight regarding the interaction mechanisms between HMWSPs and rock matrix and the consequences concerning their propagation in reservoirs. A consistent set of HMWSPs with sulfonated polyacrylamide backbones and alkyl hydrophobic side chains together with an equivalent WSP was synthesized and fully characterized. HMWSP and WSP solutions were then injected in model granular packs. As expected, with HMWSPs, high resistance factors (or mobility reductions, Rm) were observed. Yet, within the limit of the injected volumes, the effluent showed the same viscosity and polymer concentration as the injected solutions. A first significant outcome concerns the specificities of the Rm curves during HMWSP injections. Rm increases took place in two steps. The first corresponded to the propagation of the viscous front, as observed with WSP, whereas the second was markedly delayed, occurring several pore volumes (PV) after the breakthrough. This result is not compatible with the classical picture of multilayer adsorption of HMWSPs but suggests that injectivity is controlled solely by the adsorption of minor polymeric species. This hypothesis was confirmed by reinjecting the collected effluents into fresh cores; no second-step Rm increases were observed. Brine injections in HMWSP-treated cores revealed high residual resistance factors (or irreversible permeability reductions, Rk), which can be attributed to the presence of thick polymer-adsorbed layers on the pore surface. Nevertheless, Rk values strongly decreased when increasing the brine-flow rate. This second significant outcome shows that the adsorbed-layer thickness is shear-controlled. These new results should lead to proposing new adapted filtration and injection procedures for HMWSPs, aimed, in particular, at improving their injectivity.

HYDROGEOLOGICAL CHARACTERISTICS OF RESERVOIR WATERS OF THE CASPIAN SEA DEPOSITS

2021 ◽  
Vol 82 (3) ◽  
pp. 33-48
Author(s):  
NABIEVA VICTORIA V. ◽  
◽  
SEREBRYAKOV ANDREY O. ◽  
SEREBRYAKOV OLEG I. ◽  
◽  
...  
Keyword(s):  
Oil Recovery ◽  
Caspian Sea ◽  
Oil And Gas ◽  
Chemical Properties ◽  
Water Area ◽  
Water Soluble ◽  
Salt Composition ◽  
The Caspian Sea ◽  
Recovery Coefficient ◽  
Hydrogeological Characteristics

Hydrogeological conditions of reservoir waters of oil and gas fields in the northern water area of the Caspian Sea characterize the geological features of the structure of the Northern Caspian shelf, as well as the thermodynamic parameters of the exploitation of productive deposits, production and transportation of oil and gas. Reservoir waters contain water-soluble gases. According to the size of mineralization, the ratio of the main components of the salt composition, as well as the presence of iodine and bromine, reservoir waters can be attributed to a relatively "young" genetic age, subject to secondary geochemical processes of changing the salt composition in interaction with "secondary" migrated hydrocarbons. The physical and chemical properties of reservoir waters are determined by PVT analysis technologies. Hydrogeological and geochemical studies of compatibility with reservoir waters of marine waters injected to maintain reservoir pressures (PPD) during the development of offshore fields in order to increase the oil recovery coefficient (KIN) indicate the absence of colmating secondary sedimentation in mixtures of natural and man-made waters.

Asphaltene Deposition Induced by Carbon Oxide and its Influence on Displacement Efficiency

2012 ◽  
Vol 594-597 ◽  
pp. 2451-2454
Author(s):  
Feng Lan Zhao ◽  
Ji Rui Hou ◽  
Shi Jun Huang
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Carbon Oxide ◽  
Viscosity Reduction ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Oil Composition ◽  
Oil Viscosity ◽  
Asphaltene Deposition ◽  
Total Oil

CO2is inclined to dissolve in crude oil in the reservoir condition and accordingly bring the changes in the crude oil composition, which will induce asphaltene deposition and following formation damage. In this paper, core flooding device is applied to study the effect of asphaltene deposition on flooding efficiency. From the flooding results, dissolution of CO2into oil leads to recovery increase because of crude oil viscosity reduction. But precipitated asphaltene particles may plug the pores and throats, which will make the flooding effects worse. Under the same experimental condition and with equivalent crude oil viscosity, the recovery of oil with higher proportion of precipitated asphaltene was relatively lower during the CO2flooding, so the asphltene precipitation would affect CO2displacement efficiSubscript textency and total oil recovery to some extent. Combination of static diffusion and dynamic oil flooding would provide basic parameters for further study of the CO2flooding mechanism and theoretical evidence for design of CO2flooding programs and forecasting of asphaltene deposition.

scholarly journals Influence of formation heterogeneity on foam flooding performance using 2D and 3D models: an experimental study

2019 ◽  
Vol 17 (3) ◽  
pp. 734-748 ◽  
Author(s):  
Ling-Zhi Hu ◽  
Lin Sun ◽  
Jin-Zhou Zhao ◽  
Peng Wei ◽  
Wan-Fen Pu
Keyword(s):  
Oil Recovery ◽  
3D Models ◽  
Reduction Factor ◽  
Mobility Control ◽  
Displacement Efficiency ◽  
Vertical Heterogeneity ◽  
Oil Displacement Efficiency ◽  
Heterogeneous Formations ◽  
Major Factors ◽  
Foam Flooding

AbstractThe formation heterogeneity is considered as one of the major factors limiting the application of foam flooding. In this paper, influences of formation properties, such as permeability, permeability distribution, interlayer, sedimentary rhythm and 3D heterogeneity, on the mobility control capability and oil displacement efficiency of foam flooding, were systematically investigated using 2D homogeneous and 2D/3D heterogeneous models under 120 °C and salinity of 20 × 104 mg/L. The flow resistance of foam was promoted as the permeability increased, which thus resulted in a considerable oil recovery behavior. In the scenario of the vertical heterogeneous formations, it was observed that the permeability of the high-permeable layer was crucial to foam mobility control, and the positive rhythm appeared favorable to improve the foam flooding performance. The additional oil recovery increased to about 40%. The interlayer was favorable for the increases in mobility reduction factor and oil recovery of foam flooding when the low permeability ratio was involved. For the 3D heterogeneous formations, foam could efficiently adjust the areal and vertical heterogeneity through mobility control and gravity segregation, and thus enhancing the oil recovery to 11%–14%. The results derived from this work may provide some insight for the field test designs of foam flooding.

scholarly journals MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

2018 ◽  
Vol 40 (2) ◽  
pp. 85-90
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing ◽  
Usman Usman
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Viscosity ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

A New Hybrid Improved and Enhanced Oil Recovery IOR/EOR Process Using Smart Water Assisted Foam SWAF Flooding in Carbonate Rocks; A Laboratory Study Approach

2021 ◽  
Author(s):  
Anas. M. Hassan ◽  
Mohammed Ayoub ◽  
Mysara Eissa ◽  
Hans Bruining ◽  
Abdullah Al-Mansour ◽  
...  
Keyword(s):  
Aqueous Solution ◽  
Oil Recovery ◽  
Type A ◽  
Crude Oils ◽  
Residual Oil ◽  
Type B ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Smart Water ◽  
Surfactant Aqueous Solution

Abstract Given the increasing demand for energy globally and depleting oil and gas resources, it is crucial to increase the production from existing reservoirs by introducing new technologies for Improved/Enhanced Oil Recovery (IOR/EOR). This contribution presents a novel hybrid IOR/EOR method, which combines smart water (SW) and foam flooding, known as Smart Water Assisted Foam (SWAF) flooding. The optimal conditions of the SWAF technology will be interpreted using experimental laboratory design (i.e., experimental data). The experimental design was divided into three main steps. The first step is obtaining rock wettability measurements using contact angle measurements. This step aims to select the optimum SW composition that changes the carbonate rock's wettability from oil-wet towards more water-wet and faster oil recoveries. The water-wet condition leads to high residual oil saturations and low end-point permeabilities. This is conductive to favourable mobility ratios and efficient water-oil displacement. However, high residual oil saturations are unfavourable to the high ultimate oil recovery as much oil stays behind. Secondly, the chemical screening follows, where two tests were performed, viz., (i) an Aqueous Stability Test (AST), (ii) and a Foamability and Foam Stability Tests (FT/FST). This step aims to generate a stable foam (i.e., surfactant aqueous solution + gas) in the absence and presence of crude oil with different TAN (Total Acid Number) and TBN (Total Base Number), viz., crude oils Type-A and Type-B. Favourable mobility ratio is achieved by the presence of foam, which leads to excellent displacement efficiency. Thirdly, core flooding tests are performed. This step aims to select the best formulations through SWAF core flooding tests to obtain the ultimate recovery factor under different injection scenarios. The optimal SWAF condition combines high ultimate recovery with the best displacement efficiency. It is shown that the enormous changes in wettability were seen for SW (MgCl2) solution at 3500 (ppm) for both crude oils Type-A and Type-B. It has been shown that the use of a cationic surfactant CTAB (i.e., cetyltrimethylammonium-bromide) in the positively charged carbonates (with an isoelectric point of pH = 9) is more effective than the use of anionic surfactant, e.g., Alpha Olefin Sulfonate (AOS). The aim is to create an optimum surfactant aqueous solution (SAS). The SAS stability is considerably affected by the concentration of both the SW (MgCl2) and surfactant (CTAB). In the absence of oil, the strength of foam (SAS and Gas) is highly dependent on the concentration and composition of the SW in the SAS. In the presence of oil, foam generation and stability are better when the crude oil has a low TAN and high TBN. From the core flooding tests for crude oils Type-A and Type-B, the ultimate residual oil recovery was achieved by the MgCl2 - foam injection combination (i.e., incremental oil recovery of 42%, which is equivalent to a cumulative oil recovery of 92%). In summary, SWAF under the optimum conditions is a promising method to increase the oil recovery from carbonate reservoirs.

Laboratory Investigations of Factors Influencing Polymer Flood Performance

1975 ◽  
Vol 15 (04) ◽  
pp. 338-346 ◽  
Author(s):  
M.T. Szabo
Keyword(s):  
Oil Recovery ◽  
Polymer Solutions ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Mobility Control ◽  
Sweep Efficiency ◽  
Experimental Conditions ◽  
Polymer Injection ◽  
Polymer Flood

Abstract Numerous polymer floods were performed in unconsolidated sand packs using a C14-tagged, cross-linked, partially hydrolyzed ployacrylamide, and the data are compared with brine-flood performance in the same sands. performance in the same sands. The amount of "polymer oil" was linearly proportional to polymer concentration up to a proportional to polymer concentration up to a limiting value. The upper limit of polymer concentration yielding additional polymer oil was considerably higher for a high-permeability sand than for a low-permeability sand. It is shown that a minimum polymer concentration exists, below which no appreciable polymer oil can be produced in high-permeability sands. The effect of polymer slug size on oil recovery is shown for various polymer concentrations, and the results from these tests are used to determine the optimum slug size and polymer concentration for different sands. The effect of salinity was studied by using brine and tap water during polymer floods under similar conditions. Decreased salinity resulted in improved oil recovery at low, polymer concentrations, but it had little effect at higher polymer concentrations. Polymer injection that was started at an advanced stage of brine flood also improved the oil recovery in single-layered sand packs. Experimental data are presented showing the effect of polymer concentration and salinity on polymer-flood performance in stratified reservoir polymer-flood performance in stratified reservoir models. Polymer concentrations in the produced water were measured by analyzing the radioactivity of effluent samples, and the amounts of retained polymer in the stratified models are given for each polymer in the stratified models are given for each experiment. Introduction In the early 1960's, a new technique using dilute polymer solutions to increase oil recovery was polymer solutions to increase oil recovery was introduced in secondary oil-recovery operations. Since then, this new technique has attained wide-spread commercial application. The success and the complexity of this new technology has induced many authors to investigate many aspects of this flooding technique. Laboratory and field studies, along with numerical simulation of polymer flooding, clearly demonstrated that polymer additives increase oil recovery. polymer additives increase oil recovery. Some of the laboratory results have shown that applying polymers in waterflooding reduces the residual oil saturation through an improvement in microscopic sweep efficiency. Other laboratory studies have shown that applying polymer solutions improves the sweep efficiency in polymer solutions improves the sweep efficiency in heterogeneous systems. Numerical simulation of polymer flooding, and a summary of 56 field applications, clearly showed that polymer injection initiated at an early stage of waterflooding is more efficient than when initiated at an advanced stage. Although much useful information has been presented, the experimental conditions were so presented, the experimental conditions were so variable that difficulties arose in correlating the numerical data. So, despite this good data, a systematic laboratory study of the factors influencing the performance of polymer flooding was still lacking in the literature. The purpose of this study was to investigate the effect of polymer concentration, polymer slug size, salinity in the polymer bank, initial water saturation, and permeability on the performance of polymer floods. The role of oil viscosity did not constitute a subject of this investigation. However, some of the data indicated that the applied polymer resulted in added recovery when displacing more viscous oil. The linear polymer-flood tests were coupled with tests in stratified systems, consisting of the same sand materials used in linear flood tests. Thus, it was possible to differentiate between the role of polymer in mobility control behind the flood front in each layer and its role in mobility control in the entire stratified system through improvement in vertical sweep efficiency. A radioactive, C14-tagged hydrolyzed polyacrylamide was used in all oil-recovery tests. polyacrylamide was used in all oil-recovery tests. SPEJ P. 338

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