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IOR 2021
- Conference date: April 19-22, 2021
- Location: Online
- Published: 19 April 2021
1 - 20 of 77 results
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In-Situ Emulsification for Enhanced Oil Recovery: A Microfluidic Study
Authors Z. Liu, Y. Li and S.H. HejaziSummarySome enhanced oil recovery processes are designed based on the ability of surface-active agents to emulsify oil the under reservoir flowing conditions. In oilfield operations, the in-situ emulsification process is unknown as some chemicals tend to emulsify oil in one field while they are ineffective in others. Hence, the role of in-situ emulsification to oil recovery seems to be different in various porous rock structures. In the present study, we mimic the flowing conditions on emulsion formations in the co-current flow of two immiscible fluids through a confined space and investigate the effect of in-situ emulsification on the oil recovery from fractured and unfractured media.
A flow focusing microfluidic device is used to study the droplet formation in the co-current flow of oil and water through a capillary constrict. The configuration represents the snap-off process when two immiscible fluids pass through a throat to a pore body. The generated droplets are accumulated and directed into a second microfluidic chip saturated with oil. Two types of microfluidic chips are used to evaluate the oil displacement process: one representing the pore-network of a homogeneous rock and the other contains microfractures resembling a matrix-fracture system.
The dripping flow regime in the flow focusing device corresponded to the emulsion formation in the reservoir. It can be manipulated based on the dimensionless numbers of the Capillary number (for the continuous phase) and the flow rate ratio. We report the contribution of in-situ emulsification to oil recoveries is not much in the relative homogeneous porous medium. But emulsions can block the fractures directing the water into the matrix, which can significantly enlarge swept areas in the fractured medium Compare to the emulsions with low interfacial tension, the emulsions with high interfacial tension may be more favorable to enhance oil recovery in the fractured-matrix medium.
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The Potential Impact of Surfactant and Polymer Production on Separated Water Quality
Authors J. Almorihil, A. Mouret, M. Marsiglia, V. Miralles and A. AlSofiSummaryIn previous work, we demonstrated that EOR chemicals had minor effect on topside processes in terms of separation, corrosion and scale inhibition. Regarding the oil/water separation, the most noticeable effect was a deterioration in separated water quality that was deemed manageable. This paper will further investigate the impact of produced polymer and surfactant on the quality of separated water.
To mimic the separation plant potential feed and operations, experimental work has been carried out by preparing oil/brine mixtures at different surfactant/polymer concentrations with oilfield additives. Three main parameters have been varied: surfactant/polymer concentration, temperature, and water cut. The final test matrix consists of 24 tests. We first assessed the impact of EOR additives on the type of generated emulsions. Then we performed bottle tests considering the different operating parameters in order to investigate the kinetics of water/oil separation. Finally, we carried out physical-chemical analyses on the separated water in order to evaluate its quality.
In terms of concentration effects, the results suggest that SP concentration had minimal impact on pH and density of the aqueous phase. Bottle tests showed that phase inversion was obtained at intermediate and high SP concentrations for both water cuts. In addition, separated water quality deteriorated in systems of intermediate SP concentration and slightly improved at high concentration at 32 °C. At 54°C, higher SP concentrations resulted in poorer water quality. Kinetics of separation accelerated with higher SP concentrations. In terms of temperature effects, a slight decrease in both viscosity and density of emulsions was observed at higher temperatures. Kinetics of separation also improved with higher temperatures, as did the quality of the separated water. In terms of water cut effects, viscosity and density of the aqueous phase were not impacted. Moreover, phase inversion of the emulsion (from water-in-oil to oil-in-water) occurred when water cut increased from 75 to 85% without SP. With SP, oil-in-water emulsions were observed for both water cuts. Kinetics of oil/water separation increased with the higher water cut; however, no clear tendency on water quality was observed. with water cut.
In conclusion, we reconfirm that SP production, at least for the investigated formulations, will have a negligible effect on separation. The result will lead to deterioration in separated water quality; however, the level of deterioration is manageable and would not affect conventional practices of disposal in oilfields for pressure maintaining purposes. At last, this study layout laboratory protocols to perform such process-assurance.
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Is Chemical EOR Finally Coming of Age?
By E. DelamaideSummaryChemical flooding is one of the classical EOR methods, together with thermal methods and gas injection. It is not a new method; indeed, the first polymer flood field pilots date back to the 1950s while the first surfactant-based pilots can be traced back to the 1960s. However, while both gas injection and thermal methods have long been recognised as field proven and are being used at a large scale in multiple fields, it is not the case for chemical EOR.
Although there have been over 500 polymer flood pilots recorded, and almost 100 surfactant-based field tests, large scale field applications are few and far between. This situation seems to be evolving however, as more and more large scale chemical projects get underway. This paper proposes to review the status of chemical EOR worldwide to determine whether it is finally coming of age.
The status of chemical EOR projects worldwide will be reviewed, focusing on recent and current large-scale field developments. This will allow to establish what is working and where the industry is still encountering difficulties. This review will cover North America, South America, Europe, the Middle East, Asia and Africa.
It is clear that polymer flooding is now indeed becoming a well-established process, with many large-scale projects ongoing or in the early stages of implementation in particular in Canada, Argentina, India, Albania and Oman in addition to China. Strangely enough, the US lags behind with no ongoing large-scale polymer flood.
The situation is more complex for surfactant-based processes. At the moment, large-scale projects can only be found in China and – although to a lesser extent – in Canada. The situation appears on the brink of changing however, with some large developments in the early stages in Oman, India and Russia. Still, the economics of surfactant-based processes are still challenging and there is some disagreement between the various actors as to whether surfactant-polymer or alkali-surfactant polymer is the way to go.
This review will demonstrate that polymer flooding is now a mature technology that has finally made it to very large-scale field applications. Surfactant-based processes however, are lagging behind due in part to technical issues but even more to challenging economics. Still there is light at the end of the tunnel and the coming years may well be a turning point for this technology.
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Maximising Oil Recovery Through Thermally-Activated Polymer Placement
Authors M. Zubia, A. Beteta and O. VazquezSummaryThe presence of a thief zone in oil reservoirs presents many complications for operators. Perhaps the most important of these issues is early water breakthrough. A solution has been presented which ameliorates sweep in the pay zone and does not exacerbate any pre-existing injectivity problems. Thermally activated polymer (TAP) is an expandable micro-particle injected at close-to-water viscosity which has been efficaciously implemented as a water flood conformance control technique.
This paper has used simulations to explore the reservoir properties, as well as various existing and innovative techniques which may improve the efficiency of this technology. An economic analysis was also carried out to determine the feasibility of a given project. A 2D conceptual model was used to investigate the reservoir conditions required for an optimal treatment before examining the polymer properties and injection techniques available to further enhance its effectiveness. The model was able to successfully simulate temperature-initiated pore blockage by the TAP particulates which diverted subsequently-injected water into the surrounding, un-swept layers.
Simulations revealed that these polymers are able to significantly improve recovery efficiency by the blockage of flow pathways in the high-permeability streak. For an effective treatment, it was found that reservoirs with a low vertical-to-horizontal permeability ratio (0.05 - 0.1) and a high permeability contrast between the thief zone and surrounding layers (1600–2000mD thief zone) are most ideal for TAP implementation. Sensitivity analyses and optimisations found that optimal treatments depend on a plethora of parameters, namely: TAP concentration; slug size; treatment start date; method of injection; and spacers.
The method of injection presents a new opportunity to explore for future TAP treatments. With appropriate design it is possible to improve oil recovery and reduce water production, leading to an improved NPV and decreased carbon footprint from reduced water handling.
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Pelican Lake: Learning from the Largest Polymer Flood Expansion in a Heavy Oil Field
By E. DelamaideSummaryPolymer has been injected continuously since 2005-06 in the Pelican Lake field in Canada, starting with a pilot rapidly followed by an expansion. At some point, 900 horizontal wells were injecting 300,000 bbl/d of polymer solution and oil production related to polymer injection reached 65,000 bopd. As a result, the Pelican Lake polymer flood is the largest polymer flood in heavy oil in the world and the largest polymer flood using horizontal wells.
Although some papers have already been devoted to the initial polymer flood pilots, very little has been published on the expansion of the polymer flood and this is what this paper will focus on.
The paper will describe the various phases of the polymer flood expansion and their respective performances as well as discuss the specific challenges in the field including strong variations in oil viscosity (from 800 to over 10,000 cp), how irregular legacy well patterns were dealt with, and how primary, secondary and tertiary polymer injection compare. It will also show the performances of polymer injection in combination with multi-lateral wells and touch upon the surface issues including the facilities.
The availability of field and production data (which are public in Canada) combined with the variability in the field properties provide us with a wealth of data to better understand the performances of polymer flooding in heavy oil. This case study will benefit engineers and companies that are interested in polymer flood, in particular in heavy oil. The paper will be a significant addition to the literature where few large scale chemical EOR expansions are described.
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An Experimental Study of Foam Trapping and Foam Mobility in a Model Fracture
More LessSummaryBy trapping gas, foam can improve the sweep efficiency in enhanced oil recovery. In this study, to understand gas trapping in fractures, we have conducted experiments in a model fracture with a hydraulic aperture of 80 μm. One wall of the fracture is rough, and the other wall is smooth. The fracture is made of two glass plates and the direct visualization of foam flow inside the fracture is facilitated using a high-speed camera. ImageJ has been used to perform image analysis and quantify the properties of the foam. We find that pre-generated foam has been further refined inside the model. Foam flow reaches local equilibrium, where the rate of bubble generation equals that of bubble destruction, within the model. Foam texture becomes finer and less gas is trapped as the interstitial velocity and pressure gradient increase. Shear-thinning rheology of foam has also been observed. The behavior of gas trapping in our model fracture is different from that in other geological porous media. The fraction of trapped gas is much lower (less than 7%). At the extreme, when velocity increases to 6.8 mm/s (pressure gradient to 1.8 bar/m), all the foam bubbles are flowing and there is no gas trapped inside the fracture.
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Results of the Second Polymer Flooding Pilot at East-Messoyakhskoe Oil Field and Future Plans
Authors I. Ilyasov and N. GlushchenkoSummaryEast-Messoyakhskoe is a giant oil field located onshore in Artic conditions with original oil reserves about 1 bln. tones. The field was discovered in 1980-s, but development started only in 2016. The main reasons, beside remote location, are geological and reservoir challenges. The main reservoir is PK 1–3 reservoir, which was formed in fluvial deposition environment, is highly heterogeneous (permeability 50–5000 mD), cold (16 °C) and unconsolidated reservoir, located at shallow depth (800 m) with viscous oil (111 cP).
The field is developed by 1 km length horizontal wells with short spacing (150 m). Waterflooding was selected as base reservoir development method with predicted recovery factor below 15%. And reservoir engineering team was not going to agree with this fact and proactive search of technologies started. After EOR screening it was obvious that polymer flooding is technology with the highest potential.
From October 2017 till June 2019 first polymer flooding pilot was made with polymer solution injection in two wells (SPE 201822). 10% pore volume was injected with surveillance program. Incremental oil of 17200 tons of oil or 43 tons of oil per 1 ton of polymer was achieved and pilot was successful. However initially selected viscosity of 60 cP was high, which lead to high injection pressure and injectivity decline, not clear pressure limits.
So it was decided to run the second field pilot in different geological zones. Polymer solution was continuously injected from July 2019 till February 2020, during which 3 % pore volume was injected. Viscosity was reduced to 10 cP, which allowed maintaining initial target injection rates. The maximum injection pressure was increased from 78 atm up to 85 atm at wellhead without fracturing with signs of stabilization. Also all 3 injection wells were selected in different geological zones and 3 different pattern were formed. Water injection history was increased from 3 to 12 months which allowed to have accurate “baseline” for comparison. Detailed analysis for each pattern was performed. Thus, incremental oil production was calculated by analytical methods and dynamic model, which was history matched on pilot injection. Economic analysis showed that pilot is economically viable.
Therefore, the second pilot was considered to be successful, although not all initially planned polymer was injected. Based on the updated dynamic model polymer injection forecast was made, which resulted in economically efficient business cases in different geological zones. Also remaining uncertainties are highlighted and future plans are discussed.
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Lessons Learned from Offshore Polymer Flooding Practices
More LessSummarySince the first single well associative polymer injection test in offshore reservoir in Bohai in 2003, ,24 injectors corresponding to 105 producers were reported as of 2019 in Bohai offshore reservoir. Incremental oil recovery factor (IORF) was 7.1% original oil in place (OOIP) and the polymer utility factor was 45 ton oil/ ton polymer powder. However, associative polymer was not widely used in many other oilfields like Daqing and Shengli in China. This raised the question that whether associative polymer is a better or not choice for polymer flooding. Thus, a critical review of polymer flooding in offshore reservoir in the past 17 years was to be presented based on many public references published. Different from previous publication which focused on positive aspects of polymer flooding achievements, both success and lessons were given to help understand the benefit and challenges of using polymers in offshore reservoirs. The plugging was reported in many wells. The produced fluid was more difficult to treat with than that from common polymer. The IORF was lower compared to laboratory core flooding tests and other similar reservoirs like Shengli. It is interesting that although water cut decrease of 41% in one producer was reported, the significantly water cut decrease in the region was not as obvious as many other onshore reservoirs. Problems and progress in produced water treatment and reinjection, oil-water separation and plugging mechanism study were discussed. Surface-active polymer largely increased the difficulty of produced water treatment, and presence of Fe2+and S2- made the emulsion more stable. Emulsification oil in produced fluids accounted for 90%, which added difficulty. Large amount of cationic chemicals are required to break the stable interface of oil-in-water emulsion. During the flocculation and sedimentation process, the oil droplets and other suspended solids are gathered, resulting in the formation of a large number of colloidal solid products, which provided plugging. The blockages in the production wells are mainly inorganic scales. The inorganic scales in the benefited oil wells and polymer injection wells are mainly Fe2O3 and CaCO3, respectively. The organic scales are partially hydrolyzed polyacrylamide and coordinate with Fe3+ under acidic conditions, resulting in insoluble water cross-linked polymer micelles. Current acid dissolution method and oxidative degradation method used in Bohai offshore increased the risk of well damage. Associative polymer partly caused the plugging which becomes a more and more difficulty issue.
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Low pH Manganese Assisted Waterflooding Processes for Enhanced Oil Recovery in Carbonates
Authors A. Alghamdi, S. Salah, M. Otaibi, S. Ayirala and A. YousefSummaryModifying the wettability of carbonate formations through divalent foreign metal incorporation can become a cost-effective practical method for enhanced oil recovery (EOR) applications. The addition of manganese ions to high salinity water (HSW) at dilute concentrations and optimized pH conditions is exploited in this study to mitigate compatibility issues at high temperature and promote water-wet conditions in carbonate reservoirs.
In this experimental investigation, the compatibility of manganese ions in high salinity water (HSW), ultra-high salinity connate water (CW) and low salinity SmartWater is studied at reservoir temperature. The results from compatibility tests showed that manganese brines prepared under low pH equilibrium conditions are homogeneous at high temperatures. The combination of maganese ions with low pH conditions was found to eliminate the aqueous stability issues by mitigating the preciptation of MnCO3 and manganese oxides that coud become a main challenge for practical field implementation. The contact angle and spontaneous imbibition tests were then carried out in carbonate chips and cores, respectively, using crude oil and low pH maganese brines at reservoir conditions. The oil-water interfacial tensions are also measured to understand the interactions of manganese ions at the oil/brine interface in low pH equilibrium.
The findings from contact angle measurments demonstrated the ability of manganese ions at low pH conditions (pH=5.5) to effectively decrease the contact angles from 162 to about 118o when added to HSW. Conversely, only marginal reductions in oil-water interfacial tensions were observed due to manganese ions. The manganese assisted spontaneous imbibition oil recoveries were increased by about 16% when compared to that obtained using high salinity injection water. By doubling the manganese ion concentration from 500 to 1,000 ppm further increased the oil recovery by about 36%. These results suggested that manganese ions at 1,000 ppm concentration and low pH conditions can become a practical recipe for both secondary and tertiary mode oil recovery in carbonates. The favorable wettability alteration towards water-wet conditions has been idenfied as the main mechanism responsible for incremental oil recovery in low pH manganese assisted water flooding processses proposed in this study.
This work for the first time identified the favorable impact of incorporating Mn+2 ions under optimized pH conditions to enhance the aqueous stability and promote the wetting transition in carbonate reservoirs. The new knowledge gained from this experimental study highlights the practical significance of Mn+2 ions as cheap wettability modifiers for EOR applications.
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A New Fluidics Method to Determine Minimum Miscibility Pressure
Authors F. Ungar, S. Ahitan, T. Yang, S. Worthing, A. Abedini and K. UlebergSummaryThe miscible gas injection has been broadly used in many oil fields as an enhanced oil recovery (EOR) method. Minimum Miscibility Pressure (MMP) is a critical parameter both for modeling and field operations. The slim-tube method is recognized as the most reliable for MMP measurement. However, conducting the experiment takes a long time (4–6 weeks), and the sample volume requirement is substantial. Therefore, the slim-tube experiment is very costly and sometimes is not possible due to a lack of sample volume. Many other methods have been proposed, like rising bubbles and vanishing interfacial tension in various versions. Due to the limitations of these methods, there is still no experimental method that can replace the traditional slim-tube for MMP measurements.
Micro and nano-fluidics devices have attracted increasing attention in the oil industry. Reduced cost and sample volume requirements, fast turnover, and visualization are clear advantages for lean operation. In this study, we designed a new slim-tube method to determine MMP on a micro-scale fluidics chip. The design is significantly different from previous efforts on fluidics chips with an open flowing tube. In the new design, we introduced porous media fillings similar as in the slim-tube method. The objective is to produce a true multi-contact process in the gas displacement. We tested the new fluidics device using three reservoir fluids, and both hydrocarbon gases and CO2 as injection gases.
For pressure lower than MMP, we observed noticeable reservoir oil remained after injection gas passed. For pressure higher than MMP, the miscible displacement front was developed. Behind the miscible displacement front, the oil saturation came down to neglectable. We used a visual sensor to detect the oil saturation after gas flooding for each pressure. MMP was detected at the intersection of miscible pressures and immiscible pressures in a similar way as in the slim-tube test after multiple measurements. All three microchip MMP tests have almost identical results as the slim-tube tests.
The new fluidics method is a miniaturization of the slim-tube method on the microchip. The study shows excellent results for the three selected reservoir oils combined with hydrocarbon gas and CO2 as injection gases. The new method has imminent business potential due to its reliability, visualization, low cost, low sample requirement, and fast turnaround. The MMP test threshold will be much lower than before, which will significantly benefit many gas-based EOR projects.
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Gravity Segregation with CO2 Foam in Heterogeneous Reservoirs
More LessSummaryFoam injection is one efficient way to mitigate gravity segregation during CO2 injection into porous media. The effect of gravity segregation on foam propagation in heterogeneous porous media is not yet fully resolved. To assess CO2 foam transport for enhanced oil recovery (EOR) and for CO2 storage processes in heterogeneous reservoirs, an accurate prediction of foam behavior is essential. In this study, we investigate the effect of heterogeneity on gravity segregation in the presence of foam. For nonlinear analysis, we use an extension of an Operator-Based Linearization (OBL) approach proposed recently. The OBL approach helps to reduce the nonlinearity of complex physical problems by transforming the discretized nonlinear conservation equations into a quasi-linear form based on state-dependent physical operators. The state-dependent operators are approximated by discrete representation on a uniform mesh in parameter space. In our study, foam in porous media is described using an implicit-texture (IT) foam model with two flow regimes.
We first validate the numerical accuracy of the foam simulation with OBL by comparing segregation length using the IT foam model with Newtonian rheology to analytical solutions. Next, the foam-model parameters are fit to foam-quality scan data for four sandstone formations ranging in permeability by an order of magnitude using a least-squares optimization approach. We then construct several hypothetical models containing two communicating layers with different permeability and thickness ratios to examine foam's effect on gravity segregation.
The numerical results of the segregation length in homogeneous domains show good agreement with analytical solutions, except in a transition zone beneath the override zone which is not included in the analytical model. Through fractional-flow theory, we find that the transition zone is not a numerical artefact, but caused by low gas relative-mobility during the transient displacement process. Permeability affects both the mobility reduction of wet foam in the low-quality regime and the limiting capillary pressure at which foam collapses. Thus the segregation length varies with permeability and foam strength. In two-layer models, the thickness of the top layer plays an important role in the ultimate segregation length. A thin top layer does not affect segregation in the bottom layer, while a thicker top layer dominates the segregation length, with less influence of the bottom layer.
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Theoretical Study on Oil Bank for Chemical Enhanced Oil Recovery
More LessSummaryDaqing Oilfield has carried out a large scale chemical flooding industrial application for more than 20 years, and the annual oil production for chemical flooding has been more than 10 million tons since 2002. All the chemical flooding projects performance exhibited very good oil bank forming processing mechanism, so far the main method to be used for revealing that whether the oil could be enriched and aggregated to form the oil bank in chemical flooding process is to observe the water cut of produced fluid, lacking of theoretical demonstration.
This paper has conducted a series of theoretical studies on the oil bank forming process for chemical enhanced oil recovery. Firstly, an oil production well surveillance method has been carried out, demonstrating that the oil saturation in the reservoir between injector and producer increased gradually with injection of chemical displacement fluid. Secondly, a set of oil recovery mechanism experiments have been conducted to obtain the relative permeability curves and capillary desaturation data for the chemical viscoelasticity fluid, providing the basic quantization relationship to characterize the process mechanism for chemical enhanced oil recovery. Finaly, based on the fractional flow theory, a kinetic mathematical model was established to reveal oil bank forming mechanism for chemical flooding process, demonstrating that, for chemical enhanced oil recovery, the oil could be enriched and aggregated gradually in displacement fluid front to form the oil bank eventually. According to the flowing properties of chemical displacement fluid in the porous media, several influence factors on the oil enrichment and aggregation have been investigated by using the kinetic mathematical model on oil bank forming, mainly including the polymer concentration gradient in the front, the relationship of polymer viscosity and concentration, the polymer solution elasticity, the permeability reduction factor causing by polymer, the interfacial tension, and the wettibility alteration.
The research results show that the chemical flooding with higher viscoelasticity, higher chemical concentration, lower interfacial tension has a big potential to increase oil recovery, providing very useful theoretical method to optimize the injection parameters for chemical flooding scenario design.
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Pushing the Envelope of Polymer Injectivity in Low Permeability Sandstones
Authors P. Ghosh, M. Ould Metidji, G. Dupuis, R. Wilton, R. Ravikiran, A. Bowers and R. SerightSummaryChemical EOR is one of the more attractive methods to improve oil recovery. Numerous successful projects including injectivity tests, pilots and full-field developments have been executed without major injectivity issues or decline. Nevertheless, this topic remains a concern among operators.
Polymer Flooding has seen more interest from the industry, and more challenging reservoirs (low permeability formations) are considered—thus raising concerns about injectivity. Filter ratio is routinely used as an injectivity screening criteria, but does it correlate with polymer injectivity and propagation during coreflood experiments, especially in the presence of crude oil? This paper provides new insights on polymer injectivity in cores considering polymer molecular weight, chemistry, rock permeability and mineralogy. The results are obtained from dedicated experiments and examination of several extensive data bases (including the literature).
State of the art commercial polymers of varying chemistry with molecular weight ranging from 5 to 27+ MDa were injected into different sandstone cores having permeabilities between 10 to 200 mD with a range of clay content. Filter ratio was also determined and compared to injectivity in cores. All the data comes from field project case studies using reservoir cores and representative outcrop cores.
For HPAM, injectivity was not a concern. It was possible to propagate up to 27+ MDa HPAM in a 100–200 mD core without significant pressure build-up. Concerning ATBS polymers, injectivity initially appeared to be constrained by the ATBS content; a 15 MDa polymer with a medium-high ATBS content poorly propagated below 200 mD. However, optimization based on molecular weight for similar ATBS content showed stable propagation in representative porous media. Finally, the filter ratio test did not always correlate to injectivity. Indeed, it was observed that several 1.2 µm FR tests (performed on high Mw polymers) failed despite successful transport in cores having permeability below 200 mD.
In addition, acrylamide-based terpolymers allowed improvement in transport of ATBS polymers - a 20 MDa polymer containing medium level of ATBS was able to propagate in less than 100-mD cores. These observations are applicable to cores having clay content below 5%. For higher clay content, injectivity should be assessed case by case using reservoir core and crude oil.
This paper establishes new references in terms of polymer transport behavior in porous media and highlights the importance of appropriate selection of polymer, polymer quality and experimental protocols to properly assess polymer injectivity in cores.
Significance of the proposed paper:
1. Extensively examines the lower limits of permeability for injection of synthetic polymers, especially as a function of polymer molecular weight, polymer composition, rock mineralogy, and the presence of residual oil.
2. Better characterizes the relations between filter ratio, permeability and polymer injectivity in low-permeability rock.
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Interpretation of World First Polymer Injectivity Test in a HTHS Carbonate Reservoir Using SW Radial Model
Authors J.M. Leon Hinestrosa and S.K. MasalmehSummaryNew polymer based EOR schemes are proposed to increase sweep efficiency and oil recovery from high temperature and high salinity carbonate reservoirs in Abu Dhabi. These reservoirs generally consists of two main geological zones, i.e., an Upper zone and a Lower zone with permeability contrast of up two orders of magnitude. The new EOR concepts rely on keeping the upper zone pressurized by continuous polymer injection and simultaneously injecting miscible gas or water into the lower zone. A lateral pressure gradient is maintained in the upper zone, providing gas or water confinement in the lower zone and improving sweep efficiency.
Accordingly, a comprehensive de-risking program for the new polymer based EOR schemes was initiated which includes an extensive laboratory experimental program and field injectivity test to ensure that the identified polymer can be injected in the target formation below fracture pressure. The comprehensive experimental program and results were described in an earlier publication ( Masalmeh et. al., 2019 ) and the field injectivity test was also described by Rachapudi et. al., 2020 .
The polymer injectivity test (PIT) consists of three main phases: water injection baseline, polymer injection with different rates and different polymer concentrations and chase water injection. The objective of this paper is to present the interpretation of the polymer injectivity test using a single well radial model. This PIT is the world first polymer injectivity test in carbonate under such harsh conditions and the polymer used in this test has never been field tested before. The model was built to integrate and assess the dynamic data collected during the PIT, incorporating laboratory experiments, and evaluating the impact of different parameters on the near-wellbore injectivity behavior.
Interpretation of the PIT using a radial simulation model allowed to confirm that the qualified polymer can be injected and propagated in the extremely harsh conditions carbonate reservoirs, below fracture pressure and without well plugging. Despite the uncertainties and operational complexities presented during the PIT, a representative history match was obtained. More than 20 thousand sensitivity simulation runs were performed through a robust iterative optimization history match method. This workflow helped to address multiple uncertainties and captured many possible scenarios and validated laboratory parameters such as polymer bulk viscosity, in-situ rheology, RRF, adsorption, etc. The results of the PIT interpretation will be further utilized in the sector model and full field simulation models to investigate and design multi-well EOR pilots and full field development plans.
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A Novel Sampling and Testing Procedure to Confirm Polymerflood Viscosity Retention at the Captain Field
Authors G. Johnson, M. Hesampour, W. Van Zeil, S. Toivonen, E. Pin, P. Carnicero, S. Hanski, S. Sihvonen and D. HallSummaryThe Ithaca-operated Captain field is located offshore in the U.K. sector of the North Sea and is made up of sandstone reservoirs of high quality and permeability. Produced water re-injection maintains pressure via water injection wells in reservoirs containing high viscosity oils (typically, ∼ 40 to 140cP). This unfavourable mobility ratio water over oil of 40 has resulted in early water breakthrough at the production wells, strong water coning and large volumes of bypassed oil. Fortunately, the clean, high net to gross Captain sands make these reservoirs good candidates for enhanced oil recovery using polymer flooding. To apply this process, Anionic polyacrylamide (HPAM) in liquid form was chosen as the preferred chemical and has been used since 2011. This application of polymer flooding has proven to be extremely successful in Captain, with significant acceleration of the waterflood bypassed reserves resulting in a substantial increase in incremental oil compared with the waterflood recovery.
Following the commercial success of these initial polymer floods, has come a desire to expand the original polymer flooding process to other areas of the field. When implementing this expansion, maintaining the target polymer viscosity is of utmost importance in order to preserve the desired mobility ratio and maintain the sweep efficiency of the process. Polymer viscosity loss may result from a number of different degradation mechanisms and the question of whether the polymer is able to retain its viscosity within the reservoir became a key uncertainty for future expansion.
To determine the degree of degradation of the polymer required a novel sampling and testing procedure. In this scheme, the sampling and measurement of produced polymer viscosity was carried out despite significant operational and technical challenges.
During execution of the sampling, the primary requirement was to enable produced polymer sampling from the sandface of a long horizontal and operational production well, without degrading the polymer during the sampling procedure. This sample then had to be maintained in anaerobic conditions to ensure no chemical degradation occurred during transfer for laboratory testing.
The laboratory testing results demonstrated that the HPAM polymer product used on Captain maintains considerable viscosity in the reservoir, having travelled for 3 years though the reservoir over a distance of more than 500 feet. These results clearly demonstrate that limited mechanical, chemical and/or biological degradation had occurred in the reservoir, giving increased confidence in our investment decisions to proceed with future polymer floods in the Captain field.
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A cognitive methodology to improve EOR/IOR choice process: from applied approaches to more generic ones
Authors D. Bossie-Codreanu and A. BouziatSummaryThe EOR (or IOR) choice problem is an involved process, often occurring in a circular manner, where information circulates between different experts several times, increasing the decision time without necessarily improving the final choice. A literature review showed that most methods used for EOR (or IOR) selection rely somehow on the statistical learning from prior projects and on the expertise of the different individuals working on the project, thus in the value of learning.
The common steps involved in an EOR (or IOR) implementation are the selection of a suitable EOR (or IOR) process, the prediction of its performance, and finally the optimization of its design. The performance estimation may include laboratory experiments, analytical calculations, correlations, and numerical simulations. Most of these suppose data is available, that estimation under uncertainty can be easily done and that somehow information is perfect. This is often not the case. Furthermore, all of the above may create a lengthy, tedious and expensive process.
Based on these observations, in this study we propose an innovative workflow to screen and rank EOR (or IOR) opportunities among a data base of producing fields. This workflow was designed to be efficient and reproducible, but without overlooking the complexity of the decision process. Notably the ranking procedure explicitly considers the uncertainties on the static properties of the fields, integrates the computation of dynamic performances from semi-analytical physical models, and balances various corporate objectives of possibly contradictory nature.
The main technical components associated are: (1) a method to quickly establish the level of knowledge concerning the various reservoirs through an ontological mapping of their situation prior to the EOR (or IOR) evaluation, (2) a double criteria module (static and dynamic) searching and classifying valid EOR (or IOR) options according to weighted reservoir properties and recovery factors, and (3) a combination of the AHP and TOPSIS techniques to choose amongst alternatives and optimize the decision towards hierarchized goals.
In this paper, examples of elements of the methodology are shown and the possibility to apply this approach in a generic manner is discussed. The innovative aspects are stressed, considering current practices of reservoir management, proposing a cognitive decision process which can integrate fuzzy information concerning EOR (or IOR) application, thus objectivizing investments and long-term commitments.
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Field Testing a Low Shear Valve Suitable for Polymer Flooding in a Mother Solution Injection Scheme
Authors R. Husveg, M. Stokka, T. Husveg, R. Albustin and S. JouenneSummaryHydrolyzed polyacrylamides are used as mobility-control agents in polymer flooding operations to improve the macroscopic sweep efficiency of the oil reservoirs. For this, very high molecular-weight polymers are often preferred to maximize their viscosifying power. In return, these long polymer chains are very sensitive to shear degradation which originates from chain stretching and breaking when the solution is subjected to a sudden acceleration.
For a mother solution injection scheme, one polymer injection pump is normally installed on each well to inject tailored viscosities. The injection system avoids viscosity loss by injecting a high concentration polymer solution downstream the choke valve. One drawback of this setup, however, is that CAPEX, maintenance and energy demands are usually higher than for a valve-based scheme.
In 2012, the development of a low shear valve suitable for polymer flooding was initiated. By employing unique spiraling flow channels with optimally designed reducer and expansion zones, machined on the surface of discs, shear forces and thereby polymer degradation is controlled. During a prototype test using a very shear-sensitive diluted polymer solution, presented in 2019, it was demonstrated that the polymer degradation through the new valve was less than 10 % at up to 45 bar pressure drop, compared with 60 % for a standard valve.
In this paper, results from a field test of the novel low shear valve are presented. The low shear valve was installed on a high-concentration mother solution flow line at the Matzen field in Austria. At a flow rate of 1.6 m³/h and polymer concentration of 11800 ppm, the low shear performance of the novel valve was investigated at up to 35 bar pressure drop. Within the design range of up to 20 bar pressure drop, the viscosity degradation through the valve was not higher than 2.7 %. In conclusion, the low footprint valve was found to be easy to connect and operate, and the low shear performance was well within the design criteria.
When employing the novel low shear valve in a mother solution application, the one-pump-per-well injection scheme can be replaced with a larger central pumping station plus one low shear valve per well to control the injection viscosity. In this case, the low shear valve has the same low shear performance as the positive displacement pumps. However, compared to the one-pump-per-well scheme, the central pumping station and low shear valves will result in significantly lower CAPEX and maintenance costs.
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Using Polymer EOR to Reduce Carbon Intensity While Increasing Oil Recovery
Authors G. Dupuis, G. Dupuis, P. Al-Khoury, J. Nieuwerf and C. FaveroSummaryReducing the carbon footprint during crude oil extraction is a growing challenge among operators and regulatory institutions. Sustainable solutions need to be implemented for reaching the net-zero production emission target by 2050. Besides the climate challenges, the industry is facing one of the worse crisis of its history. Maximizing production and reserves of existing assets in a sustainable and cost-efficient way are therefore paramount.
Polymer flooding, with more than 300 projects worldwide, is a proven and cost-efficient technique to recover more oil in a shorter timeframe; but can the technology also aid in reducing greenhouse gas emissions? This article addresses this question by comparing the GHG emissions associated with standard waterflooding operations and polymer EOR processes
Our approach is based on the determination of energy consumption related to different elements of the oil production cycle assisted by water or polymer injection. The total calculation includes water treatment, chemicals manufacturing, transport, polymer injection unit, injection pumps, artificial lift, produced fluids separation, oil heating and oilfield chemicals consumption.
GHG emissions associated with oil transport, refinery, water disposal, and gas processing were not included in the study and will simply require updating the model with more data inputs.
The emission factors of a series of industrial polymers (including partially hydrolyzed polyacrylamides, sulfonated polyacrylamides, and HT/HS polymers in both powder and emulsion forms) were calculated considering the contributions of the raw materials and energy spent during the polymerization and the conditioning processes.
The methodology was applied to different field cases available in the literature to determine the reduction of GHG emissions associated with the reduction of water cut. The results indicated that polymer flooding was able to reduce the carbon intensity of conventional oil production by a factor of 2 to 6 compared to standard waterflooding operations, thus helping save up to 80% of water use. The results are promising for an emission free future in oil and gas industry.
The model presented in this paper can complement any reservoir simulation package and can give an estimation of reduction of CO2 emissions and water consumption compared to water injection. As an illustration, the model was applied to a pilot simulation using DOE Polymer Flooding software to compare CO2 footprint of waterflooding vs polymer flooding.
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Modeling nonisothermal modified salinity water flooding of chalk reservoirs
Authors S. Hosseinzadeh, A.A. Eftekhari and H. NickSummaryModified salinity water (MSW) flooding is shown to be more effective at higher temperatures in the coreflooding tests from the chalk reservoirs. The improvement of oil production that is widely linked to wettability alteration is determined by the physicochemical interaction between potential determining ions (PDIs) in the MSW and formation water, rock surface chemistry, and crude oil components, mostly organic polar groups. These interactions can be described by the chemical reactions between the ionic species in the aqueous phase and at the water-rock and water-oil interfaces. The chemical equilibrium between these species is shown, e.g., zeta potential measurements of the chalk particles, to be heavily affected by temperature change. A large number of chemical reactions, however, makes it increasingly difficult to predict the effect of temperature on the outcome of MSW flooding since each chemical equilibrium responds differently to the change of temperature depending on the enthalpy of reaction. In chalk cores, oil recovery is improved at higher temperatures in the presence of PDIs. This has led to the view that seawater or MSW is more efficient at higher temperatures (notably higher than 70°C).
This study aims to develop a mechanistic model that can systematically and quantitatively reproduce the observed laboratory link between increasing temperature and improved oil recovery. The reactions enthalpies of the chalk surface are inferred from the work of Bonto et al. Then, we include the temperature dependence of viscosity, the dissolution of chalk, and precipitation of minerals, e.g., anhydrite. We couple the PHREEQC geochemistry package with an inhouse finite volume solver for our geochemical and nonisothermal multicomponent multiphase transport calculations. The link between the geochemistry and multiphase transport properties is established through the available adsorption sites.
We first validate the model using inhouse and literature core flooding data, with the transport parameters obtained from the work of Ciriaco et al. at different temperatures. Then we apply the model to a 2D domain that resembles a North Sea chalk field in which cold seawater is being injected. We show that the results match qualitatively with the field data demonstrating the capabilities of our improved model.
1. Bonto, M., Eftekhari, A.A., Nick, H.: Analysis of the temperature impact on the calcite surface reactivity in modified salinity water applications. Abstract submitted to EAGE IOR, 2021
2. Ciriaco, H.M., Eftekhari, A.A., Nick, H.: Estimating two-phase reactive flow model parameters from single-and two-phase modified-salinity core flooding data. Abstract submitted to EAGE IOR, 2021
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Evidence that High Polymer Viscosity Accelerates and Increases Oil Response in Grimbeek Manantiales Behr
Authors J. JURI, F. Schein, G. Pedersen, A. Ruiz, V. Serrano, P. Vazquez, P. Guillen, V. De Miranda, W. MacDonald, E. Figueroa, N. Robina, M. Vera, F. Di Pauly, W. Rojas, N. Ojeda, I. YLich, A. Lucero, J. Alonso, P. Alonso, F. Funes and J.L.S. MasSummaryIncreasing oil recovery because of induced flow from low permeability to high permeability driven by the ratio polymer viscosity/oil viscosity has been around for more than 30 years. This phenomenon occurs when there is a surface of contact and you inject polymer which creates a higher pressure drop across the polymer slug.
Does an increase in the ratio polymer viscosity/oil viscosity always increase recovery and accelerate oil response? How is this ratio affected by the combination of geological heterogeneity oil viscosity? How do multiple surfaces in fluvial systems enable the crossflow or create bypassed oil during water injection? Is there any universality that captures this phenomenon across the combination of geological heterogeneity and fluids viscosity?
Initial simulations indicated that incremental oil will start to ramp up after 6 months of stable polymer injection at the target viscosity. Two groups of polymer injection units started polymer injection between the August-2019 and September-2019. During that time, we faced problems in water supply, therefore we had to reduce the water injection rate from Qi=100 m3/d to Qj=70 m3/d. The target polymer concentration was Ci=2500 ppm which means a 0.5 polymer/oil viscosity ratio at reservoir conditions. Conceptual pore-scale simulations give the insight that increasing the polymer viscosity could make a higher pressure in the polymer zone that could induce additional crossflow. We tested this hypothesis in the simulator by compensating the rate reduction by increasing the polymer dosage. The simulations show that increasing concentration can compensate for the reduction in incremental oil production because of the injection rate reduction. Thus, we injected 70 m3/d @ 3775 ppm-polymer concentration. The increase in concentration raised also to 1.15 the polymer/oil viscosity ratio at reservoir conditions. Unpredictably, the actual oil rate was 20% higher and the response faster than simulations.
Multiscale crossflow is one of the leading recovery mechanisms in polymer injection (Sorbie, 2019). We risk saying that standard modelling lacks the level of heterogeneity needed to estimate better the remaining oil in the subsurface and we normally underpredict the polymer flooding potential especially in heavily water flooded reservoir -more than 30-year waterflooding.
Therefore, we have undertaken enormous efforts to construct very detailed models that aim to capture the many possible surfaces of contact between different facies.
The good recovery values, thus, may indicate the efficacy of the proposed higher concentration dosage mechanism for inducing additional crossflow.
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