Workflow for Oil Recovery Design by Polymer Flooding

2018 ◽  
Author(s):  
Vitor Hugo de Sousa Ferreira ◽  
Rosangela B. Z. L. Moreno
Keyword(s):  
Data Integration ◽  
Oil Recovery ◽  
History Matching ◽  
Large Scale ◽  
Laboratory Data ◽  
Polymer Flooding ◽  
Laboratory Simulation ◽  
Laboratory Model ◽  
Heavy Oils ◽  
Production Forecast

Polymer flooding dates from the 1960s. Early applications targeted onshore medium-to-heavy oils up to 100 cP, with limited reservoir temperature and water formation salinity. The number of implemented polymer flooding projects followed oil prices. Since its early days, polymer flooding had overcome many technical obstacles. Advances in polymer manufacturing technology, cost reduction and the use of horizontal wells have pushed polymer flooding as a feasible EOR method. A better understanding of the physical phenomena associated with polymer flow through porous media and technology advancement have extended polymer flooding applications to more viscous oil, higher salinity, and temperature level, as well as to offshore prospects. Meaningful advantages of polymer flooding over conventional methods are consolidated in the literature, such as oil recovery anticipation, incremental oil recovery and reduced volumes of injected and produced water to reach a target recovery factor. Despite all technological advances, polymer flooding needs to be tailored for the specific conditions of the target reservoir. Collect and integrate laboratory, simulation, and field information are essential for a successful polymer flooding application. This paper aims to correlate critical information to the various stages necessary for polymer flooding evaluation and production forecast. First, successfully implemented field cases allow the establishment of ranges for the method application. Once the applicability of polymer flooding is certified, the polymer solution to be injected is designed according to the reservoir characteristics and target conditions. Laboratory tests are performed to determine phase mobilities, polymer retention, and polymer degradation. These parameters are assessed through different experiments, and normalized variables provide data integration. Once the required parameters are determined, it is possible to build a base simulation model. History matching this base model to the laboratory data certifies its validity. An upsized analysis of this model is required to include some degradation phenomena. The 1D laboratory model is extended to a 3D model that incorporates permo-porosity distributions to analyze well characteristics in their radius of influence. The final step is large scale simulation and production forecast. Data integration along each stage and among then all allow the tailoring of the polymer flooding to EOR. The use of normalized parameters to evaluate the results is useful for analysis at different scales, from the laboratory to the reservoir. The proposed workflow can contribute to the design, planning, evaluation, and implementation of polymer flooding in a target field.

Experiments on surface deformation arising from a subsurface fracture

1995 ◽  
Vol 32 (6) ◽  
pp. 1024-1034 ◽  
Author(s):  
Gang Wang ◽  
Maurice B. Dusseault ◽  
Jerzy T. Pindera
Keyword(s):  
Large Scale ◽  
Surface Deformation ◽  
Scale Effects ◽  
Model Simulation ◽  
Laboratory Data ◽  
Nonlinear Problems ◽  
Laboratory Simulation ◽  
Scale Model ◽  
Laboratory Model ◽  
Hydraulic Fractures

Laboratory model simulation of large-scale earth processes is rarely undertaken because of scale effects, nonlinearity, and questions of representativeness with respect to the real case. Hydraulic fractures generate distortion fields that can be measured with high precision both in the laboratory and in the field. A combination of field and laboratory data allows us to test our ability to measure displacements, make forward predictions, and invert real measurements; thus it is important to have some means of simulation, other than purely numerical simulation. This paper contains the results of a set of experiments on the surface deformation arising from a pressurized fracture, using laser holography and Fizeau interferometry of noncontacting techniques to precisely sample the displacement field above a scale model. The results are remarkably accurate and consistent, and compare reasonably well with analytical and numerical model predictions. The techniques have potential applications in geomechanics and geotechnical engineering for laboratory study of various linear and nonlinear problems. Key words : laboratory simulation, holographic, Fizeau interferometry, hydrofractures.

LARGE-SCALE SIMULATION OF OIL RECOVERY BY SURFACTANT-POLYMER FLOODING

2016 ◽  
Vol 4 (1) ◽  
pp. 12-31 ◽  
Author(s):  
D.Zh. Akhmed-Zaki ◽  
T.S. Imankulov ◽  
B. Matkerim ◽  
B.S. Daribayev ◽  
K.A. Aidarov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Polymer Flooding ◽  
Large Scale Simulation

Treatment Technology on Polymer Flooding Wastewater in Henan Oilfield

2016 ◽  
Vol 719 ◽  
pp. 74-78
Author(s):  
Chao Tang ◽  
Jiao Jiao Guan
Keyword(s):  
Water Quality ◽  
Oil Recovery ◽  
Large Scale ◽  
Quality Standard ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Treatment Technology ◽  
Water Quality Standard ◽  
Injection Water ◽  
Solid Foundation

Polymer flooding has became one of the most important oil recovery technologies with Chinese oilfields coming into tertiary recovery, which lays a solid foundation for high and stable yields in oilfields. But with it’s large-scale industrial production, polymer flooding technology also brings difficulties for the disposal and treatment of polymer flooding wastewater. Compared with conventional water flooding wastewater technology, polymer flooding wastewater not only contains oil but also lots of polymer. “Old three sets” process cannot meet the national discharge standard or the injection water quality standard. Relied on HeNan oilfield united station, this paper studied on the treatment of polymer flooding wastewater, a kind of efficient flocculant was selected for the treatment of polymer flooding wastewater and a set of reasonable technological process was recommended, making the wastewater after disposal meet the injection water quality standard.

scholarly journals Recent Advances of Surfactant-Polymer (SP) Flooding Enhanced Oil Recovery Field Tests in China

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-16
Author(s):  
Chen Sun ◽  
Hu Guo ◽  
Yiqiang Li ◽  
Kaoping Song
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Large Scale ◽  
Petroleum Industry ◽  
Field Tests ◽  
Industrial Applications ◽  
Polymer Flooding ◽  
Commercial Application ◽  
Surfactant Adsorption ◽  
Asp Flooding

Recently, there are increasing interests in chemical enhanced oil recovery (EOR) especially surfactant-polymer (SP) flooding. Although alkali-surfactant-polymer (ASP) flooding can make an incremental oil recovery factor (IORF) of 18% original oil in place (OOIP) according to large-scale field tests in Daqing, the complex antiscaling and emulsion breaking technology as well as potential environment influence makes some people turn to alkali-free SP flooding. With the benefit of high IORF in laboratory and no scaling issue to worry, SP flooding is theoretically better than ASP flooding when high quality surfactant is available. Many SP flooding field tests have been conducted in China, where the largest chemical flooding application is reported. 10 typical large-scale SP flooding field tests were critically reviewed to help understand the benefit and challenge of SP flooding in low oil price era. Among these 10 field tests, only one is conducted in Daqing Oilfield, although ASP flooding has entered the commercial application stage since 2014. 2 SP tests are conducted in Shengli Oilfield. Both technical and economic parameters are used to evaluate these tests. 2 of these ten tests are very successful; the others were either technically or economically unsuccessful. Although laboratory tests showed that SP flooding can attain IORF of more than 15%, the average predicted IORF for these 10 field tests was 12% OOIP. Only two SP flooding tests in (SP 1 in Liaohe and SP 7 in Shengli) were reported actual IORF higher than 15% OOIP. The field test in Shengli was so successful that many enlarged field tests and industrial applications were carried out, which finally lead to a commercial application of SP flooding in 2008. However, other SP projects are not documented except two (SP7 and SP8). SP flooding tests in low permeability reservoirs were not successful due to high surfactant adsorption. It seems that SP flooding is not cost competitive as polymer flooding and ASP flooding if judged by utility factor (UF) and EOR cost. Even the most technically and economically successful SP1 has a much higher cost than polymer flooding and ASP flooding, SP flooding is thus not cost competitive as previously expected. The cost of SP flooding can be as high as ASP flooding, which indicates the importance of alkali. How to reduce surfactant adsorption in SP flooding is very important to cost reduction. It is high time to reevaluate the potential and suitable reservoir conditions for SP flooding. The necessity of surfactant to get ultra-low interfacial tension for EOR remains further investigation. This paper provides the petroleum industry with hard-to-get valuable information.

scholarly journals Enhanced Oil Recovery by Polymer Flooding: Direct, Low-Cost Visualization in a Hele–Shaw Cell

2019 ◽  
Vol 9 (3) ◽  
pp. 186
Author(s):  
Yukie Tanino ◽  
Amer Syed
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Team Work ◽  
Petroleum Engineering ◽  
Laboratory Model ◽  
Oil Reservoir ◽  
Laboratory Exercise ◽  
Hele Shaw Cell

We designed a hands-on laboratory exercise to demonstrate why injecting an aqueous polymer solution into an oil reservoir (commonly known as “polymer flooding”) enhances oil production. Students are split into three groups of two to three. Each group is assigned to a packed Hele–Shaw cell pre-saturated with oil, our laboratory model of an oil reservoir, and is given an aqueous solution of known polymer concentration to inject into the model reservoir to “push” the oil out. At selected intervals, students record the oil produced, take photos of the cell using their smartphones, and demarcate the invading polymer front on an acetate sheet. There is ample time for students to observe the experiments of other groups and compare the different flow patterns that arise from different polymer concentrations. Students share their results with other groups at the end of the session, which require effective data presentation and communication. Both the in-session tasks and data sharing require team work. While this experiment was designed for a course on Enhanced Oil Recovery for final year undergraduate and MSc students in petroleum engineering, it can be readily adapted to courses on groundwater hydrology or subsurface transport by selecting different test fluids.

A Numerical Simulation Comparison of Five-Spot vs. Line Drive in Micellar/Polymer Flooding

1982 ◽  
Vol 22 (01) ◽  
pp. 69-78
Author(s):  
H. Kazemi ◽  
D.J. MacMillan
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Large Scale ◽  
Plug Flow ◽  
Recovery Process ◽  
Field Application ◽  
Polymer Flooding ◽  
Spot Pattern ◽  
Injection Wells ◽  
Production Wells

Abstract The work presented in this paper was undertaken to study the effect of pattern configuration on oil recovery by the Maraflood oil-recovery process. The patterns studied are the five-spot and the 4 × 1 line drive. These patterns are obtained by placing infill wells in an existing 10-acre (40 469-m2) waterflooded five-spot pattern to obtain the 2.5-acre (10 117-m2) patterns. The number of infill wells is the same for both the new five-spot and new line-drive configurations and is about three times the number of existing wells. Both patterns have been used successfully in field applications by Marathon before this study. For instance, a line-drive pattern was used in Project 119-R and a five-spot pattern was used in Project 219-R. This work shows that the line drive produces more tertiary oil than the five-spot under otherwise identical reservoir conditions. Breakthrough times and oil rates for line-drive production wells are nearly the same. Meanwhile, five-spot production wells have vastly differing oil breakthrough times and oil rates. Both of the latter effects result from a nonuniform distribution of waterflood residual oil saturation in the field. Our study also shows that if producing wells in each line-drive row are connected by a perfect vertical fracture and if the same is true of the injection wells, the line-drive efficiency will improve very little. Introduction The Maraflood oil-recovery process is a viable enhanced oil-recovery technique. An appraisal of this process and other surfactant-enhanced oil-recovery schemes was reported by Gogarty. Three significant field tests of the Maraflood process were reported by Earlougher et al. In addition, a large-scale field application of this process was presented recently by Howell et al. in field applications of the Maraflood process, both line-drive and five-spot configurations have been used. In our field experience, an existing five-spot waterflood pattern is convened to another five-spot or 4 × 1 line-drive configuration by adding infill wells. The new five-spot or line-drive pattern has an area-per-well spacing of one-fourth of the original waterflood spacing. In practice, the number of infill wells required for both cases is somewhat greater than three times the number of existing wells. As the total number of wells increases, this ratio approaches the theoretical limit of three. In addition to the preceding arrangements of infill wells, many others are possible. In some arrangements, fewer infill wells are required than in our five-spot and 4 × 1 line drive. In such cases, the area per well increases, which generally causes these problems:required injectivity per injection well increases and may not be attainable because of the high viscosity of the injected fluids andthe breakthrough time is delayed. As an example, consider the case where no infill wells are drilled. In addition to the two problems just listed, the micellar/polymer flooding scheme will sweep only those regions that already have been swept well by the waterflood. The regions left unswept by the waterflood also will be left essentially unswept by the micellar/polymer flood. This means that a substantial amount of oil is left in place. Therefore, these types of undesired patterns were not considered in this study. Patterns with more infill wells than those in this study were not considered because of current economic limitations. Because of the likelihood of economic and technical merits, we also considered the placement of long vertical fractures to connect existing waterflood wells in place of infill wells. The fractures were arranged to form a more effective line drive. We emphasize that the patterns studied in this paper are those usually used in micellar/polymer flooding applications. Muskat has reported breakthrough waterflood sweep efficiencies of 72% and 88% for five-spot and 4 × 1 line drive patterns when the mobility ratio is unity. Muskat's results are for ideal plug flow displacement of red water by blue water in a perfectly homogeneous reservoir. SPEJ P. 69^

Design and Demonstration of New Single-Well Tracer Test for Viscous Chemical Enhanced-Oil-Recovery Fluids

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1075-1085 ◽  
Author(s):  
Robert Fortenberry ◽  
Pearson Suniga ◽  
Mojdeh Delshad ◽  
Bharat Singh ◽  
Hassan A. AlKaaoud ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Reactive Transport ◽  
History Matching ◽  
Pore Space ◽  
Laboratory Data ◽  
Chemical Flooding ◽  
Oil Saturation ◽  
Single Well ◽  
Partitioning Tracers

Summary Single-well-partitioning-tracer tests (SWTTs) are used to measure the saturation of oil or water near a wellbore. If used before and after injection of enhanced-oil-recovery (EOR) fluids, they can evaluate EOR flood performance in a so-called one-spot pilot. Four alkaline/surfactant/polymer (ASP) one-spot pilots were recently completed in Kuwait's Sabriyah-Mauddud (SAMA) reservoir, a thick, heterogeneous carbonate operated by Kuwait Oil Company (KOC). UTCHEM (Delshad et al. 2013), the University of Texas chemical-flooding reservoir simulator, was used to interpret results of two of these one-spot pilots performed in an unconfined zone within the thick SAMA formation. These simulations were used to design a new method for injecting partitioning tracers for one-spot pilots. The recommended practice is to inject the tracers into a relatively uniform confined zone, but, as seen in this work, that is not always possible, so an alternative design was needed to improve the accuracy of the test. The simulations showed that there was a flow-conformance problem when the partitioning tracers were injected into a perforated zone without confinement after the viscous ASP and polymer-drive solutions. The water-conveyed-tracer solutions were being partially diverted outside of the ASP-swept zone where they contacted unswept oil. Because of this problem, the initial interpretation of the performance of the chemicals was pessimistic, overestimating the chemical residual oil saturation (ROS) by up to 12 saturation units. Additional simulations indicated that the oil saturation in the ASP-swept zone could be properly estimated by avoiding the post-ASP waterflood and injecting the post-ASP tracers in a viscous polymer solution rather than in water. An ASP one-spot pilot using the new SWTT design resulted in an estimated ROS of only 0.06 after injection of chemicals (Carlisle et al. 2014). These saturation values were obtained by history matching tracer-production data by use of both traditional continuously-stirred-tank (CSTR) models and compositional, reactive-transport reservoir models. The ability of the simulator to model every phase of the one-spot pilot operation was crucial to the insight of modified SWTT design. The waterflood, first SWTT, ASP flood, and the final SWTT were simulated using a heterogeneous permeability field representative of the Mauddud formation. Laboratory data, field-ASP quality-control information, and injection strategy were all accounted for in these simulations. We describe the models, how they were used, and how the results were used to modify the SWTT design. We further discuss the implications for other SWTTs. The advantage of mechanistic simulation of multiple aspects of a one-spot pilot is an important theme of this study. Because the pore space investigated by the SWTTs can be affected by the previously injected EOR fluids (and vice versa), these interactions should be accounted for. This simulation approach can be used to identify and mitigate design problems during each phase of a challenging one-spot pilot.

scholarly journals Evaluation of Polymer Flooding in a Highly Stratified Heterogeneous Reservoir. A Field Case Study

2020 ◽  
Vol 16 ◽  
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Lower Layer ◽  
Polymer Flooding ◽  
Economic Life ◽  
Water Flooding ◽  
Base Case ◽  
Sweep Efficiency ◽  
Sector Model ◽  
Reservoir Simulator

Oil and gas companies are looking for proven hydrocarbon reserves from their mature drained reservoirs to extend the production and economic life of these fields. The chemical enhanced oil recovery (CEOR) is an attractive water-based EOR method for these mature fields. The polymer flooding (PF) is a widely applied process in reservoirs with low sweep efficiency after the water flooding (WF). The target Colombian field has one of the first polymer pilots in the region with positive results of oil recovery in “A” sands. Thus, the operator is interested in the expansion of PF for the same reservoir and even in deeper reservoir sands. This paper focuses in the evaluation of different scenarios of PF for the producer in layers A and B with a mechanistic simulation model, thus obtaining new recommendations for the recovery strategy in the field. A sector model was constructed from a full field model using a commercial reservoir simulator to the in-house chemical flooding reservoir simulator: UTCHEMRS. This sector model was also migrated to a second commercial simulator allowing a performance comparison for these three simulators. UTCHEMRS model results were compared with the commercial simulators through the history matching (HM) phase. The primary and waterflood history match was in agreement with the field data. Simulation results suggested that PF for the base case in “A” sands presented an incremental oil recovery of up to 12% additional to water flooding. Additionally, PF was extended to the lower layer “B” sand to investigate the potential of polymer injection. The PF injection in both reservoirs simultaneously loses sweep efficiency and decreases the oil recovery to about 3%. However, a hypothetical case of new infill producer wells with the objective of testing the individual reservoir performance has revealed that PF is having significant upside from B sands as well.

scholarly journals Investigation of Injection Strategy of Branched-Preformed Particle Gel/Polymer/Surfactant for Enhanced Oil Recovery after Polymer Flooding in Heterogeneous Reservoirs

Energies ◽  
2018 ◽  
Vol 11 (8) ◽  
pp. 1950 ◽  
Author(s):  
Hong He ◽  
Jingyu Fu ◽  
Baofeng Hou ◽  
Fuqing Yuan ◽  
Lanlei Guo ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Oil Prices ◽  
Polymer Flooding ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Injection Strategy ◽  
Simultaneous Injection ◽  
Heterogeneous Reservoirs ◽  
Incremental Oil Recovery

The heterogeneous phase combination flooding (HPCF) system which is composed of a branched-preformed particle gel (B-PPG), polymer, and surfactant has been proposed to enhance oil recovery after polymer flooding in heterogeneous reservoirs by mobility control and reducing oil–water interfacial tension. However, the high cost of chemicals can make this process economically challenging in an era of low oil prices. Thus, in an era of low oil prices, it is becoming even more essential to optimize the heterogeneous phase combination flooding design. In order to optimize the HPCF process, the injection strategy has been designed such that the incremental oil recovery can be maximized using the corresponding combination of the B-PPG, polymer, and surfactant, thereby ensuring a more economically-viable recovery process. Different HPCF injection strategies including simultaneous injection and alternation injection were investigated by conducting parallel sand pack flooding experiments and large-scale plate sand pack flooding experiments. Results show that based on the flow rate ratio, the pressure rising area and the incremental oil recovery, no matter whether the injection strategy is simultaneous injection or alternation injection of HPCF, the HPCF can significantly block high permeability zone, increase the sweep efficiency and oil displacement efficiency, and effectively improve oil recovery. Compared with the simultaneous injection mode, the alternation injection of HPCF can show better sweep efficiency and oil displacement efficiency. Moreover, when the slug of HPCF and polymer/surfactant with the equivalent economical cost is injected by alternation injection mode, as the alternating cycle increases, the incremental oil recovery increases. The remaining oil distribution at different flooding stages investigated by conducting large-scale plate sand pack flooding experiments shows that alternation injection of HPCF can recover more remaining oil in the low permeability zone than simultaneous injection. Hence, these findings could provide the guidance for developing the injection strategy of HPCF to further enhance oil recovery after polymer flooding in heterogeneous reservoirs in the era of low oil prices.

History matching of experimental polymer flooding for enhanced viscous oil recovery

2020 ◽  
Vol 42 (4) ◽  
Author(s):  
M. F. Zampieri ◽  
V. H. S. Ferreira ◽  
C. C. Quispe ◽  
K. K. M. Sanches ◽  
R. B. Z. L. Moreno
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Polymer Flooding ◽  
Viscous Oil
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