Investigation of Oil Presence and Wettability Restoration Effects on Sulfonated Polymer Retention in Carbonates Under Harsh Conditions

2021 ◽  
Author(s):  
Umar Alfazazi ◽  
Nithin Chacko Thomas ◽  
Emad W. Al-Shalabi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
High Salinity ◽  
Careful Consideration ◽  
Rock Surface ◽  
Ct Scanner ◽  
Core Samples ◽  
The Impact ◽  
Polymer Retention ◽  
Harsh Conditions

Abstract Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effect of oil presence and wettability restoration on polymer retention under harsh reservoir conditions of high temperature and high salinity (HTHS). An ATBS-based polymer was used for this study. Polymer single- and two-phase dynamic retention tests as well as bulk- and in-situ rheological experiments were conducted on Indiana limestone outcrops and in the presence of high salinity brine of 243,000 ppm at temperature of 50 °C. A total of four coreflooding experiments were conducted on core samples with similar petrophysical properties. Bulk rheology tests showed that the polymer is stable at HTHS conditions. Also, polymer retention and in-situ rheology tests highlighted the significance of oil presence in the core samples where retention was found to be around 40-50 and 25-30 μg/g-rock in the absence and presence of oil, respectively. An additional 50% reduction in retention was further observed on a restored wettability (aged) core sample. Polymer inaccessible pore volume (IPV) was found to be high in the range of 23 to 28%, which was supported by the 1D saturation profiles obtained from the CT scanner. The ATBS-based polymer shows excellent results for applications in carbonates under harsh conditions without considerable polymer loss or plugging. This paper also provides valuable insights into the impact of oil presence and wettability restoration on polymer retention. Furthermore, this study shows that careful consideration of the latter factor is necessary to avoid unrepresentative and inflated polymer retention values in oil reservoirs.

Analysis of the World's First Polymer Injectivity Test in a Carbonate Reservoir Under Extreme Harsh Conditions in ADNOC's Reservoirs

2021 ◽  
Author(s):  
Juan Manuel Leon ◽  
Shehadeh K. Masalmeh ◽  
Siqing Xu ◽  
Ali M. AlSumaiti ◽  
Ahmed A. BinAmro ◽  
...  
Keyword(s):  
High Temperature ◽  
Laboratory Experiments ◽  
High Salinity ◽  
Laboratory Data ◽  
Injection Pressure ◽  
Carbonate Reservoir ◽  
Experimental Program ◽  
Full Field ◽  
Harsh Conditions

Abstract Assessing polymer injectivity for EOR field applications is highly important and challenging. An excessive injectivity reduction during and after polymer injection may potentially affect the well integrity and recovery efficiency and consequently, injection strategy and the economics of the polymer projects. Moreover, well conditions such as skin, completion configuration, and injection water quality can significantly impact polymer injectivity. Additionally, the presence of fractures or micro-fractures may govern injection pressure. In contrast, historic field applications have shown that polymer injectivity is in general better than expected from simulations or laboratory data. In the laboratory experiments, the polymer injectivity has been evaluated by injection of significant amounts of pore volumes of polymer at relevant well-injection rates. In addition, several experiments were performed to measure the complex in-situ rheology expected to dominate the flow near the wellbore This paper presents the analysis of the the world's first polymer injectivity test (PIT) conducted in a high temperature and high salinity (HTHS) carbonate reservoir in Abu Dhabi as part of a comprehensive de-risking program for a new polymer-based EOR scheme proposed by ADNOC for these challenging carbonate reservoirs (see Masalmeh et. al., 2014). The de-risking program includes an extensive laboratory experimental program and field injectivity test to ensure that the identified polymer can be injected and propagated in the target formation before multi-well pilot and full-field implementation stages. Experimental laboratory data and the field injectivity test results are presented in earlier publications (Masalmeh et. al., 2019; Rachapudi et. al., 2020) and references therein. This PIT is the world's first polymer injectivity test in a carbonate reservoir under such harsh conditions of high salinity, high content of divalent ions and high temperature. In addition, the polymer used during the test has never been field-tested before. Therefore, the results of the PIT interpretation will help to de-risk the suitable polymer for the future inter-well pilot for the new proposed EOR Polymer-based scheme and it is a game-changer to unlock several opportunities for different Chemical EOR applications on full-field scale in other reservoirs with similar characteristics. A single well radial simulation model was built to integrate the surveillance data during PIT and the extensive laboratory experiments. Morever, multiple Pressure Fall Off Tests (PFOs) during the same periods were analyzed and intergaretd in the model.The study assessed the effect of polymer viscosity on mobility reduction, evaluated the polymer bank propagation, investigated the effect of the skin build-up, residual resistance factor (RRF) and shear effects on the well injectivity. Additionally, a comprehensive assisted history match method and robust simulation sensitivity analysis was implemented, thousands of sensitivity simulation runs were performed to capture several possible injection scenarios and validate laboratory parameters. The simulation study confirmed that the PIT could be interpreted using the laboratory-measured polymer parameters such as polymer bulk viscosity, in-situ rheology, RRF and adsorption.

An Analysis of a Method of In-Situ Thermal Properties Determination for Geologic Formations

1985 ◽  
Vol 107 (1) ◽  
pp. 122-127
Author(s):  
J. D. Lin ◽  
T. J. Love
Keyword(s):  
Thermal Conductivity ◽  
Thermal Properties ◽  
Moisture Content ◽  
Oil Recovery ◽  
Thermal Methods ◽  
Core Samples ◽  
Time Required ◽  
And Storage ◽  
Flux Probe

Geothermal investigations and thermal methods of oil recovery require the thermal properties of rock be known. The thermal conductivity of rock is normally determined by measuring the properties of core samples which have been removed from the well. The major problem with this is the fact that thermal properties are dependent on the moisture content of the rock. This moisture content is very likely altered in transportation and storage. This paper presents an analysis which serves as the basis of a transient heat flux probe measurement that may be used to determine the thermal conductivity and diffusivity in situ. Such in-situ measurements would overcome the disadvantages of core samples and may also be used when core samples are not available. This analysis also provides a method of estimating the time required in order to obtain valid results. The analysis indicates rather long test times may be required for accurate results. However, it does provide a basis for evaluating the results of measurements taken for shorter times. The effects of contact thermal resistance between the probe, the well casing, and the formation are evaluated.

scholarly journals Experimental study of in-situ W/O emulsification during the injection of MgSO4 and Na2CO3 solutions in a glass micromodel

2020 ◽  
Vol 75 ◽  
pp. 87
Author(s):  
Sepideh Palizdan ◽  
Hossein Doryani ◽  
Masoud Riazi ◽  
Mohammad Reza Malayeri
Keyword(s):  
Experimental Study ◽  
Flow Rate ◽  
Oil Recovery ◽  
Deionized Water ◽  
Water Flooding ◽  
Flow Rates ◽  
Glass Micromodel ◽  
The Impact ◽  
Emulsification Process

In-situ emulsification of injected brines of various types is gaining increased attention for the purpose of enhanced oil recovery. The present experimental study aims at evaluating the impact of injecting various solutions of Na2CO3 and MgSO4 at different flow rates resembling those in the reservoir and near wellbore using a glass micromodel with different permeability regions. Emulsification process was visualized through the injection of deionized water and different brines at different flow rates. The experimental results showed that the extent of emulsions produced in the vicinity of the micromodel exit was profoundly higher than those at the entrance of the micromodel. The injection of Na2CO3 brine after deionized water caused the impact of emulsification process more efficiently for attaining higher oil recovery than that for the MgSO4 brine. For instance, the injection of MgSO4 solution after water flooding increased oil recovery only up to 1%, while the equivalent figure for Na2CO3 was 28%. It was also found that lower flow rate of injection would cause the displacement front to be broadened since the injected fluid had more time to interact with the oil phase. Finally, lower injection flow rate reduced the viscous force of the displacing fluid which led to lesser occurrence of viscous fingering phenomenon.

scholarly journals Half a century of continuous oil production by in-situ combustion in Romania – case study Suplacu de Barcau field

2021 ◽  
Vol 343 ◽  
pp. 09009
Author(s):  
Gheorghe Branoiu ◽  
Florinel Dinu ◽  
Maria Stoicescu ◽  
Iuliana Ghetiu ◽  
Doru Stoianovici
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Oil Field ◽  
Oil Reservoir ◽  
In Situ Combustion ◽  
Cyclic Steam Stimulation ◽  
The Impact ◽  
Steam Stimulation

Thermal oil recovery is a special technique belonging to Enhanced Oil Recovery (EOR) methods and includes steam flooding, cyclic steam stimulation, and in-situ combustion (fire flooding) applied especially in the heavy oil reservoirs. Starting 1970 in-situ combustion (ISC) process has been successfully applied continuously in the Suplacu de Barcau oil field, currently this one representing the most important reservoir operated by ISC in the world. Suplacu de Barcau field is a shallow clastic Pliocene, heavy oil reservoir, located in the North-Western Romania and geologically belonging to Eastern Pannonian Basin. The ISC process are operated using a linear combustion front propagated downstructure. The maximum oil production was recorded in 1985 when the total air injection rate has reached maximum values. Cyclic steam stimulation has been continuously applied as support for the ISC process and it had a significant contribution in the oil production rates. Nowadays the oil recovery factor it’s over 55 percent but significant potential has left. In the paper are presented the important moments in the life-time production of the oil field, such as production history, monitoring of the combustion process, technical challenges and their solving solutions, and scientific achievements revealed by many studies performed on the impact of the ISC process in the oil reservoir.

scholarly journals Study on the Impact of Polymer Retention in Porous Media on Further Surfactant-Polymer Flood

2015 ◽  
Vol 8 (1) ◽  
pp. 45-50 ◽  
Author(s):  
Junjian Li ◽  
Hanqiao Jiang ◽  
Qun Yu ◽  
Fan Liu ◽  
Hongxia Liu
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Underground Water ◽  
Polymer Flooding ◽  
Polymer Flood ◽  
Good Potential ◽  
Enhance Oil Recovery ◽  
Polymer Application ◽  
The Impact ◽  
Polymer Retention

Polymer flood gains expansive popularity as a promising EOR method in various oilfields worldwide. However, there are still substantial amount of resources underground after polymer application. To further enhance oil recovery, secondary chemicals are sometimes utilized to sweep the remaining hydrocarbons to maintain the consistent development of oilfields. In this paper, a series of experiments are established and conducted to explore the feasibility of surfactant/ polymer flooding applied to a polymer flooded reservoir, and also the influence of polymer retention in porous media to enhance the oil recovery performance of subsequent chemical drive. The data of the experiments suggest that surfactant/polymer flooding owns a very good potential as a subsequent EOR technique, and that polymer retention in pores helps block underground water channels, improving greatly the sweeping efficiency of secondary chemical flood.

Sweep Improvement Options for Highly Heterogeneous Reservoirs with High Temperature and Ultra-High Salinity: A Case Study in Tarim Basin, China

2021 ◽  
Author(s):  
Chengdong Yuan ◽  
Wanfen Pu ◽  
Mikhail Alekseevich Varfolomeev ◽  
Aidar Zamilevich Mustafin ◽  
Tao Tan ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Tarim Basin ◽  
High Salinity ◽  
Mobility Control ◽  
Surfactant Flooding ◽  
High Permeability ◽  
Permeability Heterogeneity ◽  
Foam Flooding

Abstract How to control excessive water production in high-temperature and high-salinity reservoirs has always been a challenge, which has been facing many oil reservoirs in Tarim Basin (China), such as Y2 reservoir with an average temperature of 107 ℃, salinity of 213900 mg/L (Ca2++Mg2+>11300mg/L), and permeability from 2 to 2048 mD. In this work, we present experimental studies to determine the potential EOR process for Y2 reservoir from foam flooding, polymer gel/foam flooding, and microgel/surfactant flooding. To simulate the permeability heterogeneity of Y2 reservoir, a 2-D sand-pack model was used for flooding experiments. Vertically, three layers (first 0.6cm, second 0.8cm and third 1.6cm from top to bottom, respectively) were packed with different size sand to simulate permeability heterogeneity (permeability increases from first to third layer). A 0.3 cm higher permeability zone was also filled inside third layer. Horizontally, permeability gradually decreases from middle to two sides. In this model, injection well was vertical, and production well was horizontal. The effect of impermeable interlayer was also studied by isolating the second and third layer. The results show that conformance treatments using in-situ crosslinked gel or micro-gel are necessary before foam or surfactant injection under a high permeability heterogeneity. When an impermeable interlayer existed between the second and third layer, the additional oil recovery of N2 foam flooding, in-situ crosslinked gel/N2 foam flooding, and microgel/surfactant flooding was 16.34%, 20.37%, 17.50%, respectively, which was much higher than that without impermeable interlayer (9.84%, 13.62%, 12.07%). This implies that when multiple layers exist, crossflow between layers is unfavorable for improving oil recovery, which should be paid extra attention in EOR process. Foam flooding has not only a good mobility control capacity but also a good oil displacement ability (verified by visual observations of washed sand after experiments), which, together with the strong conformance control ability of crosslinked gel, makes in-situ crosslinked gel/N2 foam flooding yield the highest displacement efficiency. Generally, for high-temperature and ultra-high-salinity reservoirs with strong heterogeneity like Y2 reservoir, in-situ crosslinked gel/foam flooding can be a good candidate for EOR. This work provides a potential EOR method with high efficiency, i.e. in-situ crosslinked gel assisted N2 foam flooding, for the development of similar reservoirs like Y2 with high temperature, ultra-high salinity, high heterogeneity and multiple layers. Moreover, this work also highlights that, despite that foam has the ability of mobility and profile control, a conformance treatment is necessary to block high permeability zone before foam injection when the reservoirs has a strong heterogeneity.

scholarly journals An Elongational and Shear Evaluation of Polymer Viscoelasticity during Flow in Porous Media

2020 ◽  
Vol 10 (12) ◽  
pp. 4152 ◽  
Author(s):  
Muhammad Tahir ◽  
Rafael E. Hincapie ◽  
Leonhard Ganzer
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
Viscoelastic Properties ◽  
Mechanical Degradation ◽  
Core Flooding ◽  
Higher Temperature ◽  
Core Flood ◽  
The Impact ◽  
Harsh Conditions ◽  
Polymer Viscoelasticity

This paper uses a combination of approaches to evaluate the viscoelastic phenomenon in high-molecular-weight polymers (24–28 M Daltons) used for enhanced oil recovery (EOR) applications. Rheological data were cross-analyzed with single- and two-phase polymer flooding experiments in outcrop cores and micromodels, respectively. First, the impact of semi-harsh conditions (salinity, hardness, and temperature) was evaluated. Second, the impact of polymer degradation (sand face flow), focusing on the viscoelastic properties, was investigated. Finally, polymer viscoelastic properties were characterized, proposing a threefold rheological approach of rotational, oscillatory, and elongational behavior. Data from the rheological approaches were cross-analyzed with core flooding experiments and performed at a room temperature of 22 °C and at a higher temperature of 55 °C. The change in polymer viscoelastic properties were analyzed by investigating the effluents from core flooding experiments. Oil recovery experiments in micromodel helped our understanding of whether salinity or hardness has a dominating impact on in situ viscoelastic polymer response. These approaches were used to study the impact of mechanical degradation on polymer viscoelasticity. The brines showed notable loss in polymer viscoelastic properties, specifically with the hard brine and at higher temperature. However, the same polymer solution diluted in deionized water exhibited stronger viscoelastic properties. Multiple flow-behaviors, such as Newtonian, shear thinning, and thickening dominated flow, were confirmed through pressure drop analysis against interstitial velocity as already reported by other peer researchers. Turbulence-dominated excessive pressure drop in porous media was calculated by comparing core flood pressure drop data against pressure data in extensional viscometer–rheometer on a chip (eVROC®). In addition, a significant reduction in elastic-dominated flow was confirmed through the mechanical degradation that happened during core flood experiments, using various approaches. Finally, reservoir harsh conditions (high temperature, hardness, and salinity) resulted in a significant reduction in polymer viscoelastic behavior for all approaches.

scholarly journals Impact of Chelating Agent Salt Type on the Enhanced Oil Recovery from Carbonate and Sandstone Reservoirs

2021 ◽  
Vol 11 (15) ◽  
pp. 7109
Author(s):  
Amjed Hassan ◽  
Mohamed Mahmoud ◽  
Shirish Patil
Keyword(s):  
Contact Angle ◽  
Acetic Acid ◽  
Oil Recovery ◽  
Chelating Agents ◽  
Chelating Agent ◽  
Recovery Process ◽  
Rock Surface ◽  
Dynamic Adsorption ◽  
Sandstone Reservoirs ◽  
The Impact

In this paper, chelating agents were introduced as standalone fluids for enhancing the oil recovery from carbonate and sandstone reservoirs. Chelating agents such as glutamic acid di-acetic acid (GLDA), ethylene-diamine-tetra acetic acid (EDTA), and hydroxyl-ethylethylene-diamine-tri-acetic acid (HEDTA) were used. Chelating agents can be found in different forms such as sodium, potassium, or calcium salts. There is a significant gap in the literature about the influence of salt type on the hydrocarbon recovery from carbonate and sandstone reservoirs. In this study, the impact of the salt type of GLDA chelating agent on the oil recovery was investigated. Potassium-, sodium-, and calcium-based high-pH GLDA solutions were used. Coreflooding experiments were conducted at high-pressure high-temperature (HPHT) conditions using carbonate and sandstone cores. The used samples had porosity values of 15%–18%, and permeability values were between 10 and 75 mD. Seawater was injected as a secondary recovery process. Thereafter, a GLDA solution was injected in tertiary mode, until no more oil was recovered. In addition to the recovery experiments, the collected effluent was analyzed for cations concentrations such as calcium, magnesium, and iron. Moreover, dynamic adsorption, interfacial tension, and contact angle measurements were conducted for the different forms of GLDA chelating agent solutions. The results of this study showed that incremental oil recovery between 19% and 32% of the Original Oil in Place (OOIP) can be achieved, based on the salt type and the rock lithology. Flooding carbonate rocks with the calcium-based GLDA chelating agent yielded the highest oil recovery (32% of OOIP), followed by that with potassium-based GLDA chelating agent, and the sodium-based GLDA chelating agent yielded the lowest oil recovery. The reason behind that was the adsorption of the calcium-based GLDA on the rock surface was the highest without reducing the rock permeability, which was indicated by the contact angle, dynamic adsorption, and flooding experiments. The outcome of this study will help in maximizing the oil recovery from carbonate and sandstone reservoirs by suggesting the most suitable salt type of chelating agents.

New Insights into Geochemical Modeling of Hybrid Low Salinity/Engineered Water and Polymer Injections in Carbonates

2021 ◽  
Author(s):  
Emad W. Al-Shalabi ◽  
Waleed Alameri
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Polymer Rheology ◽  
Hybrid Polymer ◽  
Sweep Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Harsh Conditions

Abstract For decades, polymer flooding proved to be one of the most effective enhanced oil recovery (EOR) methods. In addition, low salinity/engineered water injection (LSWI/EWI) has been gaining momentum over the last few years. Both techniques seem to be cheaper than other EOR methods. This resulted in an increased interest among operators in these techniques. Moreover, low-salinity water is usually less viscous compared to formation fluids, which warrants a lower volumetric sweep efficiency, especially at high temperatures and in highly heterogeneous formations. The reduction in macroscopic sweep efficiency impairs the improvement in recovery efficiency by low-salinity water. In addition, experimental studies showed that polymer viscosity is considerably improved in less saline water. In this study, hybrid polymer and LSWI/EWI flooding performance is numerically evaluated in carbonate formations under conditions of mixed-to-oil wettability, high temperature, high salinity, and low permeability. A numerical 1D model was constructed using a commercial compositional simulator. The model captures the polymer rheology of a newly developed and commercially available synthetic polymer. Also, the effect of LSWI/EWI on polymer rheology and performance was studied. Oil recovery, pressure drop, and in-situ saturation data were history matched for seawater, polymer, and low salinity water injection cycles. Furthermore, the matched experimental data were utilized to examine the combined polymer and low salinity water effect on the improvement in microscopic displacement efficiency of linear models under reservoir flow conditions. The simulation results showed that hybrid polymer and LSWI/EWI is a viable EOR method for carbonate reservoirs under harsh conditions. Moreover, this work provides new insights into the hybrid application of LSWI/EWI and polymer flooding in carbonates under harsh conditions, the impact of low-salinity water on in-situ polymer rheology, and it promotes further field-scale applications of hybrid polymer-LSWI/EWI to improve volumetric sweep efficiency and overall recovery efficiency.

Surfactant-Polymer Formulations for EOR in High Temperature High Salinity Carbonate Reservoirs

2021 ◽  
Author(s):  
Mauricio Sotomayor ◽  
Hassan Alshaer ◽  
Xiongyu Chen ◽  
Krishna Panthi ◽  
Matthew Balhoff ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
High Salinity ◽  
Carbonate Reservoirs ◽  
Chemical Degradation ◽  
Surface Charges ◽  
High Molecular Weight Polymer ◽  
Molecular Weight Polymer ◽  
Indiana Limestone ◽  
Harsh Conditions

Abstract Harsh conditions, such as high temperature (>100 oC) and high salinity (>50,000 ppm TDS), can make the application of chemical enhanced oil recovery (EOR) challenging by causing many surfactants and polymers to degrade. Carbonate reservoirs also tend to have higher concentrations of divalent cations as well as positive surface charges that contribute to chemical degradation and surfactant adsorption. The objective of this work is to develop a surfactant-polymer (SP) formulation that can be injected with available hard brine, achieve ultra-low IFT in these harsh conditions, and yield low surfactant retention. Phase behavior experiments were performed to identify effective SP formulations. A combination of anionic and zwitterionic surfactants, cosolvents, brine, and oil was implemented in these tests. High molecular weight polymer was used in conjunction with the surfactant to provide a high viscosity and stable displacement during the chemical flood. Effective surfactant formulations were determined and five chemical floods were performed to test the oil recovery potential. The first two floods were performed using sandpacks from ground Indiana limestone while the other three floods used Indiana limestone cores. The sandpack experiments showed high oil recovery proving the effectiveness of the formulations, but the oil recovery was lower in the cores due to complex pore structure. The surfactant retention was high in the sandpacks, but it was lower in Indiana Limestone cores (0.29-0.39 mg/gm of rock). About 0.4 PV of surfactant slug was enough to achieve the oil recovery. A preflush of sodium polyacrylate improved the oil recovery.

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