The optimization and economic evaluation of oil production using low salinity polymer flood: a case study for EOR 26

AbstractTrinidad and Tobago (TT) have been producing crude oil commercially since 1908. For the past few decades, TT’s crude oil production has been in steady decline because most of the oil reservoirs are beyond the primary phase of their production. This situation coupled with lower energy prices have resulted in a shortfall in TT’s energy revenues and presents TT with major economic challenges. The objective of this study was to optimize a field simulation model of a combined Low Salinity Polymer Gel flood to highlight the possibility that Enhanced Oil Recovery (EOR) can boost crude oil production especially from heavy oil reserves and mature fields. A field simulation model of the EOR 26 Upper Forest Sands was built using the CMG Builder software. The EOR 26 Upper Forest Sand reservoirs of the Forest Reserve field are delineated by shale-outs, faults and water–oil contacts. The entire Forest Reserve is bordered by the Fyzabad anticline to its north-west and the Los Bajos fault to its south-west. A dynamic field simulation model of the combined Low Salinity Polymer Gel flooding of EOR 26 Upper Forest Sands was created using CMG STARS software and the optimum parameters of polymer gel concentration, salinity concentration and injection rates and pressure for the highest oil recovery were investigated. The highest oil recovery was obtained using a polymer gel concentration of 500 ppm with a salinity of 1000 ppm and an injection rate of 900 bbls/day during continuous polymer gel injection for a period of 545 days. The polymer gel injection was preceded by pre flush water injection for 180 days and followed by water injection for the duration of the ten (10) year period. The predicted oil recovery for the project is an additional 14.52% of OOIP and is considered economically feasible at a crude oil price of US$50 per barrel with a payback period of two years and an IRR of 63.53%.

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Effect of ionic strength in low salinity water injection processes

CT&F - Ciencia Tecnología y Futuro ◽

10.29047/01225383.269 ◽

2020 ◽

Vol 10 (2) ◽

pp. 17-26

Author(s):

Gustavo Maya Toro ◽

Luisana Cardona Rojas ◽

Mayra Fernanda Rueda Pelayo ◽

Farid B. Cortes Correa

Keyword(s):

Ionic Strength ◽

Interfacial Tension ◽

Crude Oil ◽

Oil Recovery ◽

Water Injection ◽

Spontaneous Imbibition ◽

Low Salinity ◽

Low Salinity Water ◽

Salinity Water ◽

Low Salinity Water Injection

Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks. The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions. Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies. Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.

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Screening of waterflooding, hot waterflooding and steam injection for extra heavy crude oil production from Tatarstan oilfield

IOP Conference Series Earth and Environmental Science ◽

10.1088/1755-1315/931/1/012002 ◽

2021 ◽

Vol 931 (1) ◽

pp. 012002

Author(s):

A Pituganova ◽

I Minkhanov ◽

A Bolotov ◽

M Varfolomeev

Keyword(s):

Crude Oil ◽

Oil Recovery ◽

Water Injection ◽

Oil Production ◽

Steam Injection ◽

Hot Water ◽

Heavy Crude Oil ◽

Oil Viscosity ◽

Heavy Crude ◽

Bulk Model

Abstract Thermal enhanced oil recovery techniques, especially steam injection, are the most successful techniques for extra heavy crude oil reservoirs. Steam injection and its variations are based on the decrease in oil viscosity with increasing temperature. The main objective of this study is the development of advanced methods for the production of extra heavy crude oil in the oilfield of the Republic of Tatarstan. The filtration experiment was carried out on a bulk model of non-extracted core under reservoir conditions. The experiment involves the injection of slugs of fresh water, hot water and steam. At the stage of water injection, no oil production was observed while during steam injection recovery factor (RF) achieved 13.4 % indicating that fraction of immobile oil and non-vaporizing residual components is high and needed to be recovered by steam assisted EORs.

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The Decisive Role of Microdispersion Formation in Improved Oil Recovery by Low-Salinity-Water Injection in Sandstone Formations

SPE Journal ◽

10.2118/197067-pa ◽

2019 ◽

Vol 24 (06) ◽

pp. 2859-2873 ◽

Cited By ~ 3

Author(s):

Pedram Mahzari ◽

Mehran Sohrabi ◽

Juliana M. Façanha

Keyword(s):

Crude Oil ◽

Oil Recovery ◽

High Salinity ◽

Quartz Substrate ◽

Water Injection ◽

Improved Oil Recovery ◽

Low Salinity ◽

Low Salinity Water ◽

Salinity Water ◽

Low Salinity Water Injection

Summary Efficiency of low–salinity–water injection primarily depends on oil/brine/rock interactions. Microdispersion formation (as the dominant interfacial interaction between oil and low–salinity water) is one of the mechanisms proposed for the reported additional oil recovery by low–salinity–water injection. Using similar rock and brines, here in this work, different crude–oil samples were selected to examine the relationship between crude–oil potency to form microdispersions and improved oil recovery (IOR) by low–salinity–water injection in sandstone cores. First, the potential of the crude–oil samples to form microdispersions was measured; next, coreflood tests were performed to evaluate the performance of low–salinity–water injection in tertiary mode. Sandstone core plugs taken from a whole reservoir core were used for the experiments. The tests started with spontaneous imbibition followed by forced imbibition of high–salinity brine. Low–salinity brine was then injected in tertiary mode. The oil–recovery profiles and compositions of the produced brine were measured to investigate the IOR benefits as well as the geochemical interactions. The results demonstrate that the ratio of the microdispersion quantity to bond water is the main factor controlling the effectiveness of low–salinity–water injection. In general, a monotonic trend was observed between incremental oil recovery and the microdispersion ratio of the different crude–oil samples. In addition, it can be inferred from the results that geochemical interactions (pH and ionic interactions) would be mainly controlled by the rock's initial wettability, and also that these processes could not affect the additional oil recovery by low-salinity-water injection. To further verify the observations of geochemical interactions, a novel experiment was designed and performed on a quartz substrate to investigate the ionic interactions on the film of water between an oil droplet and a flat quartz substrate, when the high–salinity brine was replaced with the low–salinity brine. The results of the flat–substrate test indicated that the water film beneath the oil could not interact with the surrounding brine, which is in line with the results of the core tests.

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Experimental Investigation of the Impact of Crude Oil and Rock on Improved Recovery by Low Salinity Water Injection

10.2118/206118-ms ◽

2021 ◽

Author(s):

Mohamed Alhammadi ◽

Shehadeh Masalmeh Masalmeh ◽

Budoor Al-Shehhi ◽

Mehran Sohrabi ◽

Amir Farzaneh

Keyword(s):

Crude Oil ◽

Oil Recovery ◽

Water Injection ◽

Core Sample ◽

Reservoir Rock ◽

Low Salinity ◽

Low Salinity Water ◽

Reservoir Conditions ◽

Salinity Water ◽

Low Salinity Water Injection

Abstract This study aims to compare the roles of rock and crude oil in improving recovery by low salinity water injection (LSWI) and, particularly, to explore the significance of micro-dispersion formation in LSWI performance. Core samples and crude oil were taken from two carbonate reservoirs (A and B) in Abu Dhabi. The oil samples were selected such that one of them would form micro-dispersion when in contact with low salinity brine while the other would not. A series of coreflood experiments was performed in secondary and tertiary modes under reservoir conditions. First, a core sample from reservoir A was initialized and aged with crude oil from reservoir A and a core sample from reservoir B was initialized and aged with crude oil from reservoir B. The cores were then swapped, and the performance of low salinity injection was tested using rock from reservoir A and crude from reservoir B, and vice versa. For the first set of experiments, we found that the crude oil sample capable of forming micro-dispersion (we call this oil "positive", from reservoir A) resulted in extra oil recovery in both secondary and tertiary LSWI modes, compared to high salinity flooding. Moreover, in the secondary LSWI mode we observed significant acceleration of oil production, with higher ultimate oil recovery (12.5%) compared to tertiary mode (6.5%). To ensure repeatability, the tertiary experiment was repeated, and the results were reproduced. The core flood test performed using "negative" crude oil that did not form micro-dispersion (from reservoir B) showed no improvement in oil recovery compared to high salinity waterflooding. In the "cross-over" experiments (when cores were swapped), the positive crude oil showed a similar improvement in oil recovery and the negative crude oil showed no improvement in oil recovery even though each of them was used with a core sample from the other reservoir. These results suggest that it is the properties of crude oil rather than the rock that play the greater role in oil recovery. These results suggest that the ability of crude oil to form micro-dispersion when contacted with low salinity water is an important factor in determining whether low salinity injection will lead to extra oil recovery during both secondary and tertiary LSWI. The pH and ionic composition of the core effluent were measured for all experiments and were unaffected by the combination of core and oil used in each experiment. This work provides new experimental evidence regarding real reservoir rock and oil under reservoir conditions. The novel crossover approach in which crude oil from one reservoir was tested in another reservoir rock was helpful for understanding the relative roles of crude oil and rock in the low salinity water mechanism. Our approach suggests a simple, rapid and low-cost methodology for screening target reservoirs for LSWI.

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Novel Insights Into Mechanisms of Oil Recovery by Use of Low-Salinity-Water Injection

SPE Journal ◽

10.2118/172778-pa ◽

2016 ◽

Vol 22 (02) ◽

pp. 407-416 ◽

Cited By ~ 42

Author(s):

M.. Sohrabi ◽

P.. Mahzari ◽

S. A. Farzaneh ◽

J. R. Mills ◽

P.. Tsolis ◽

...

Keyword(s):

Crude Oil ◽

Oil Recovery ◽

Water Injection ◽

Wettability Alteration ◽

Low Salinity ◽

Low Salinity Water ◽

Salinity Water ◽

Low Salinity Water Injection ◽

Fluid Interactions

Summary The underlying mechanism of oil recovery by low-salinity-water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature, but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct-flow-visualization investigations (Emadi and Sohrabi 2013) have revealed that a physical phenomenon takes place when certain crude oils are contacted by low-salinity water, leading to a spontaneous formation of micelles that can be seen in the form of microdispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude-oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include direct-flow (micromodel) visualization, crude-oil characterization, coreflooding, and spontaneous-imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface-active components of crude oil, and the improvement in oil recovery because of LSWI. We present the results of a series of spontaneous- and forced-imbibition experiments carefully designed with reservoir cores to investigate the role of the microdispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing an LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared with high-salinity-water injection (HSWI) in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude-oil/brine-interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicate that the natural surface-active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research can be applied to oil recovery from both sandstone and carbonate oil reservoirs because they are mainly derived from fluid/fluid interactions that control wettability alteration in both sandstone and carbonate rocks.

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