- Home
- Conferences
- Conference Proceedings
- Conferences
IOR 2021
- Conference date: April 19-22, 2021
- Location: Online
- Published: 19 April 2021
77 results
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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
-
-
-
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.
-
-
-
Organic Oil Recovery - Resident Microbial Enhanced Production Pilot in the Scott Field (UKCS)
Authors R. Findlay, A. Bostock, C. Hill, C. Venske and M. CarrollSummaryIntroduction:
CNOOC has been involved in a pilot study to determine the efficacy of Organic Oil Recovery (OOR, a unique form of microbial enhanced oil recovery) as a means of maximising oil recovery from its Scott field. CNOOC’s operated Scott asset came on stream in 1993 and produces crude oil and natural gas from the Scott, Telford and Rochelle fields. Scott is located approximately 188 kilometers northeast of Aberdeen in 142 meters of water.
Methods, Procedures & Process:
Organic Oil Recovery harnesses microbial life already present in an oil-bearing reservoir to improve oil recovery through changes in interfacial tension increasing the oil’s mobility and improving recovery rates and reservoir wettability. These changes could increase recoverable reserves and extend field life through improved oil recovery with negligible topsides modifications. The pilot injection is implemented by injecting a specific nutrient blend directly at the wellhead with ordinary pumping equipment. The well is then shut-in for an incubation period and thereafter returned to production.
Results, Observations & Conclusions:
During initial laboratory testing of two Scott target wells the reservoir showed a diverse and abundant resident ecology which has been proven capable of undergoing the necessary characteristic changes to facilitate enhanced production. A pilot test was completed on well J17 in July 2020 and due to this application, both an ecology and production response has been proven. In addition to this response a drop in H₂S in both the Oil and Gas phase has been observed. The full method of implementation of the pilot test will also be discussed in detail and will include any challenges and/or successes in this area. The initial starting ecology of the wells will be demonstrated and compared to the ecology post-pilot. Additionally, a comparison of production and H₂S figures prior to and post the pilot implementation will be detailed. A correlation will be demonstrated between changes in ecology and an increase in production and a reduction in H₂S.
-
-
-
Reservoir Simulation of Low Salinity Impact on Polymer Flooding and Evaluation of Electrodialysis Reversal Benefits
Authors U. Umoh, P. Cordelier, M. Bourgeois, O. Garnier, C. Prinet and S. JouenneSummaryThe objective of polymer flooding is to improve macroscopic sweep efficiency and oil recovery by increasing the viscosity of the displacing water thereby decreasing the water/oil mobility ratio. One major parameter that determines polymer flood performance is therefore the in-situ polymer solution viscosity, which is dependent on several factors such as formation temperature, polymer concentration, shear rate and salinity (salt concentration).
Rheological polymer properties such as bulk viscosity variation with polymer concentration for a given water salinity have been derived from laboratory measurements. Generally, a higher solution salinity yields less viscosity for a given polymer concentration. Such relationship between salinity and polymer solution viscosity needs therefore to be implemented in dynamic simulations to consider the mixing effect of different water salinities (injected, connate, aquifer, etc.) in order to obtain representative in-situ polymer viscosities for polymer flood evaluation.
This paper describes the implementation of salt-dependent polymer viscosity functions in reservoir models and the evaluation of simulation results in order to provide answers related to the impact of salinity variations on polymer flood performance. Evaluation of results shows variation of low salinity and polymer flood fronts within the reservoir when a lower salinity (e.g. <1 g/l) viscous solution encounters the in-situ formation water at higher salinity (5 – 15 g/l), and how this leads to improved macroscopic sweep efficiency and oil recovery. Overall, low salinity viscous fluid injection resulted in a higher oil recovery (up to 6% incremental OOIP) given the same polymer concentration, or a similar recovery with lower polymer concentration (up to 50% less polymer consumption).
The above results proved useful in evaluating the business case of using low salinity water (desalting using Electrodialysis Reversal (EDR) technology) for polymer solution preparation. Chemical savings and polymer concentration reduction are the main advantages for a polymer flooding project. Preliminary evaluations show that significant OPEX and CAPEX savings could be achieved by using EDR on an onshore field with moderate reservoir salinity, which is linked to increased operational efficiency and reduction of chemicals consumption.
-
-
-
Acceleration of Thermodynamic Computations in Fluid Flow Applications
Authors S. Sheth, M. Heidari, K. Neylon and J. BennettSummaryReservoir simulators model the highly nonlinear partial differential equations that represent flows in heterogeneous porous media. The system is made up of conservation equations for each thermodynamic species, flash equilibrium equations and some constraints. With advances in Field Development Planning (FDP) strategies, clients need to model highly complex Improved Oil Recovery processes such as gas re-injection and CO2 injection, which requires multi-component simulation models. The operating range of these simulation models is usually around the mixture critical point and this can be very difficult to simulate due to phase mislabeling and poor nonlinear convergence. We present a Machine Learning (ML) based approach that significantly accelerates such simulation models.
One of the most important physical parameters required in order to simulate complex fluids in the subsurface is the critical temperature (Tcrit). There are advanced iterative methods to compute the critical point such as the algorithm proposed by Heidemann and Khalil (1980) but, because these methods are too expensive, they are usually replaced by cheaper and less accurate methods such as the Li-correlation (Reid and Sherwood (1966)).
In this work we use a ML workflow that is based on two interacting fully connected neural networks, one a classifier and the other a regressor, that are used to replace physical algorithms for single phase labelling and improve the convergence of the simulator. We generate real time compositional training data using a linear mixing rule between the injected and the in-situ fluid compositions that can exhibit temporal evolution. In many complicated scenarios, a physical critical temperature does not exist and the iterative sequence fails to converge. We train the classifier to identify, a-priori, if a sequence of iterations will diverge. The regressor is then trained to predict an accurate value of Tcrit. A framework is developed inside the simulator based on TensorFlow that aids real time machine learning applications.
Applying this ML workflow to real field gas re-injection cases suffering from severe convergence issues has resulted in a 10-fold reduction of the nonlinear iterations in the examples shown in this paper, with the overall run time reduced 2- to 10-fold, thus making complex FDP workflows several times faster. Such models are usually run many times in history matching and optimization workflows, which results in compounded computational savings. The workflow also results in more accurate prediction of the oil in place due to better single phase labelling.
-
-
-
Polymer Injectivity Learned From 20 Years’ Polymer Flooding Field Practices
Authors [J. Zong, H. Guo], [S. He, K. Song], X. Li, F. Huang, J. Chen, H. Fu, Z. Wang, K. Song and H. GuoSummaryMany people are interested in injecting high-viscosity polymers, the injectivity of polymers remains a challenging issue. Since polymer flooding has been used in Daqing since 1996 commercially, lessons learned can be helpful. When the injected polymer solution’s viscosity is increased 10-60 times compared to that of water, the injectivity was not reduced by the same extent. Several reasons account for this.
First, fractures near injectors were induced and extended toward producers without much attention. This well explains the not so high injection pressure in high-concentration polymer flooding in Daqing. However, this explanation was based on a homogeneity formation assumption, which may hold for thick formation layers. For multi-layers with a high-permeability streak channeling often occurs.
Second, the injected polymer viscosity was reduced due to high shear rate in near injectors regions. A reduction factor of 50% and 30% was reported from back-produced fluids sampling in Daqing and Shengli oilfield respectively. The permeability, the clay content and composition may also play great role in reducing oxidation effect. Polymer type may also affect injectivity.
Third, the flow pattern differs between the lab and field. In many laboratory studies to evaluate polymer resistance factor (RF) or residual resistant factor (RFF), a linear flow is conduced. However, in actual fields, both linear and radical flow happens. The later produced a lower pressure increase than the former. The skin factor can be an important issue.
Finally, due to the heterogeneity, formation parting-pressure varied from place to place. This makes the average injection pressure between injectors not a good indicator. In many field practices, the injection pressure was controlled to be lower than a general formation parting-pressure, actual injection pressure can be either high or lower than actual formation parting-pressure. Besides, uncontrolled pressures can form without being noticed. This also caused significantly problems, such as well casing damage and poor injectivity. In some blocks in Daqing, all wells were damaged in a certain block with much higher injection pressure than water flooding. Survey of overall oilfield pressure indicated that the higher the injection pressure, the higher well casing damage.
The measures such as hydraulic fracturing and acidification widely adopted in Daqing can alleviate the blocking but cannot solve the problems completely. Some field tests were observed Hall plot for polymer very similar to water flooding, indicating that a larger Hall plot with a slope larger than 1 may be reflection of poor polymer injectivity or blockage.
-
-
-
A study of Residual Oil and Wettability Effects on Polymer Retention
More LessSummaryThe propagation rate of polymer solution through reservoir rock is significantly affected by the magnitude of polymer retention, and consequently, impacting oil recovery and chemical consumption. Therefore polymer retention is a critical parameter for both the numerical prediction and the actual performance of a polymer flood. A clear understanding of the magnitude and influencing factors is still desired for polymer flooding in carbonates.
In this study, we investigate the retention of a sulfonated polyacrylamide polymer in carbonate cores. The impacts of residual oil and wettability on polymer retention are studied by performing coreflooding experiments at reservoir conditions. Representative reservoir fluids and core samples are used for both experiments of single phase displacement and in the presence of residual oil. Two slugs of polymer with KI tracer are injected, and effluent polymer and tracer concentrations are analyzed for determining polymer retentions and inaccessible pore volumes (IPV).
Results show that the retention of the tested polymer in carbonate cores is relatively low, ranging from 26.0 to 60.8 µg/g-rock. In the presence of residual oil the polymer retention has more than 50% reduction. This indicates that the oil in reservoir environment has positive impact on polymer consumption, and the studied polymer has a potential for carbonate reservoir applications. Compared to the significant effect of the oil presence, it was observed that wettability change caused a slight variation in polymer retention results. This suggests that wettability has small impact on polymer retention estimates. Furthermore, the polymer IPV results obtained in the presence and in the absence of oil are very close, ranging from 11.0% to 12.0% of pore volume (PV). This indicates that the presence of oil has insignificant effect on polymer IPV. This study shows that evaluating polymer retention using single phase displacement experiment tends to give an overestimated result, which may lead to a conservative estimate in polymer consumption.
-
-
-
Best Practices for Pressure Maintenance and Recovery in Reservoirs with Gas Caps
Authors A. AlQasim, M. Alabdullateef, K. Katterbauer and S. KokalSummaryGas cap reservoirs are a special class of hydrocarbon reservoirs that have segregated gas caps and are examples of reservoirs that are at their saturation pressures. The gas and the oil are in equilibrium at reservoir pressure and temperature. Producing a gas-cap reservoir requires special engineering skills. Waterflooding is generally not an option because the gas-cap acts as a pressure buffer (due to gas compressibility) and increasing the pressure by injecting water is difficult. Other production schemes are generally deployed to extract the oil and gas efficiently.
One such method is to produce the oil and reinject the gas back into the gas cap. As reservoir pressure depletes, the gas cap expands, pushing the underlying oil toward the producing oil zone, and wells will begin to produce increasing amounts of gas and ultimately only gas. To maintain the reservoir pressure, gas has to be injected into the gas-cap. The amount of injected gas depends on the size of the gas cap and other reservoir properties.
Some options of injected gases includes the produced gas, lean gas, inert gas or any other gas that may be locally available. Produced or lean gas have been the primary gases for maintaining reservoir pressure in gas cap fields. These gases have no adverse effect on facilities and recovery. Another advantage of this practice is that it relies entirely on gravity drainage, especially in the case of negligible water encroachment.
Other options to consider include CO2 and acid gases. This paper summarizes several methods for pressure maintenance in fields with gas cap. The injectants that were considered include CO2, flue gas, acid gas (H2S and CO2), sour gas (CH4 and H2S). The main motivation is to inject the produced CO2 as a mechanism of mitigating Co2 emissions. This is part of the oil and gas industry’s sustainability options and part of the framework of the circular carbon economy. The advantages and disadvantages of each method on some typical gas-cap reservoirs are investigated. This includes the interplay of recovery, impact on facility and metallurgy, sustainability and economic impact for these options. For CO2 that may be miscible with the oil the option of injecting it into the oil rim is also considered. The long-term contamination of the gas cap is also evaluated.
-
-
-
Surface Complexation Modeling of SmartWater Synergy with EOR in Carbonates
Authors M. Abu-alsaud, A. Al-Ghamdi, S. Ayirala and A. Al-SofiSummaryInjection water chemistry plays a major role in governing oil recovery from carbonate formations due to its strong effect on wettability. Various studies have shown that surface charge manipulation caused by tailored water chemistry is the main driver behind modifying carbonate reservoir wettability towards a water-wet state. Therefore, understanding the electrokinetics of brine/calcite and brine/crude oil interfaces is important for optimizing injection water compositions for different enhanced oil recovery (EOR) methods in carbonates.
In this work, the physicochemical interactions of various EOR-based water solutions in carbonates are studied using a Surface Complexation Modeling (SCM) approach. First, the brine recipes of NaCl, Na2SO4 SmartWater, and high-salinity water are analyzed as a baseline for zeta-potential comparisons. Different EOR additives, such as surfactants, and dissolved CO2 are added to these brine recipes. The SCM results are compared with experimental zeta-potential measurements for calcite suspensions and crude-oil emulsions in various brine chemistries.
The SCM results for EOR-solutions reasonably capture the experimental zeta-potential trends for both brine/calcite and crude oil/brine interfaces. In surfactant solutions, the anionic surfactants shift the zeta-potential values of brine/calcite and crude oil/brine interfaces toward more negative values for all considered brine recipes with the impact being more pronounced for SmartWater and high-salinity water. For the amphoteric surfactant, which includes both anionic and cationic hydrophilic ends, the surfactant effect is found to be in the opposite direction, where the surface charge has been altered toward a positive direction. For carbonated water, where CO2 is dissolved at high pressure, the magnitude of the zeta-potentials is found to be positive at the two interfaces due to the high activity of H+ surface reactions in both calcite and crude-oil surfaces.
The novelty of this work is that it successfully validates the SCM results with experimental zeta potential data. Such validated models can be used to determine the physicochemical interaction of different EOR-based solutions in carbonates. These modeling results provide new insights on optimal SmartWater compositions that synergize with various EOR methods to yield enhanced wettability alteration and further improvement in oil recovery in carbonate reservoirs.
-
-
-
Determination of in-Situ Remaining Oil Saturation Before ASP Flooding for Giant Sandstone Reservoir in North Kuwait
Authors B. Baroon, I. Abu Shiekah, C. Chao and M. AL-AjmiSummaryAn Alkaline Surfactant Polymer (ASP) pilot is planned for a giant sandstone reservoir in North Kuwait. The reservoir has good oil recovery, thanks to its favorable geological characteristics, light oil and strong aquifer support. However, the reservoir is exposed to very harsh salinity and temperature conditions that contribute to additional complexity of the envisioned development concept and the costs of the identified and field-tested optimum chemical ASP formulation. Therefore, the determination of remaining and residual oil saturations to water flooding are vital to assess the economic feasibility of ASP field development.
The pilot designed 7 wells have been drilled in mature area of the reservoir and detailed open hole logs surveys were collected in addition to acquiring cores from 3 of the pilot wells in the target zone. Saturation logs show consistently uniform low oil saturation signaling the target zone remaining oil saturation is very close to true residual oil saturation. One of the pilot wells was successfully cored with water based-mud Liquid Trapper technology to reduce the range of uncertainties from quantifying remaining oil saturation.
The Liquid Trapper fluids collected during the coring process were analyzed and only very slight traces of oil were detected. Full diameter cores, horizontal plugs, and vertical plugs in the least invaded parts in the middle of the core covering ∼100 ft interval were cut and prepared for Dean-Stark extraction to estimate oil and water saturation. The results from the analysis confirm low oil saturation range observed from the open hole logs, from a Single Well Chemical Tracer Test (SWCTT) in a nearby well and centrifuge SCAL experiments. However, water saturation estimates from the collected cores were subject to higher uncertainties that are attributed to inevitable artefacts from drilling, coring and core handling operations in addition to new insights on inherited limitations of data analysis from Dean-Stark extraction. The paper will address best practices on integrating data from different sources as well as capturing and highlighting lessons learned.
-
-
-
FDP Optimization with Techno-Economic Viable Infills and Their Impact in Water/Miscible WAG Injection in Heterogeneous Reservoir
More LessSummaryAn extensive study was conducted to optimize the field development plan (FDP) with infill wells in water and miscible water-alternating-gas (WAG) displacement processes for high and moderately heterogeneous areas of stratified carbonate reservoir. This reservoir is complex heterogeneities with numerous fractures, high perm steaks, multiple sub-layers with variable permeability and intrabed communication with other reservoirs. Within this reservoir, the wells have dual completion through short/ long strings. It is observed that injected water /gas is flowing through high permeability layers and leaving a lot of oil in un-swept area. Therefore, in order to sustain target oil production and improve recovery, this reservoir is currently undergoing re-development with different innovations including maximum reservoir contact (MRC) wells with line drive injection pattern drilled from different artificial islands, gas lift, infill wells, different tubing size strings, different types of well completions (limited entry liner –LEL, pre perforated liner- PPL, inflow control devices- ICD and inflow control valve- ICV) and appropriate EOR technology.
This article presents analytical models and a step by step work flow to optimized FDP for optimum tubing size, well spacing, vertical well placement, well length to reduce the gap between toe to heel of two wells, techno-economic viable number of infill wells and their location (vertical and areal) for maximizing the recovery and maintain the longer plateau at target production rate.
An FDP is formulated with optimum tubing size, well spacing, well length, vertical well location and techno-economic viable infills in water / miscible WAG flooding for a highly heterogeneous complex stratified reservoir.
-
-
-
One Approach to Waterflood Conformance Control in Carbonate Reservoirs
Authors A. Andrianov, J. Hou, E. Li, E. Liu and L. YangSummaryThe low sweep efficiency of ongoing water flooding in many mature oilfields is attributed to huge permeability contrast or existing high-permeability streaks. Using polymer-based conformance control treatment can be the only viable option to improve oil recovery in many water flooding projects. There are many chemical agents that are developed and used for sandstone formations. However, for the carbonate reservoirs, often characterized by low permeability, fractures, high salinity and temperature, only a limited number of IOR field trials is reported.
The polymeric nanospheres is conformance control agent improving oil recovery through redistribution of water flows deep in a reservoir. The nanospheres are expanding in size after injection into the formation, and swelling period is well controlled. Different classes of nanospheres were developed for various reservoir conditions. Nanospheres are less impacted by geological conditions when compared to other chemical agents and can be used in reservoirs with very high temperatures (upto ∼130°C) and high salinities (upto ∼300,000 mg/l).
There is a long history of application of this agent in sandstone formations that will be briefly reviewed in the paper. Nanospheres have been effective in the reservoirs with permeability as low as 0.1 mD.
Recently, the extensive experimental study was conducted to analyze primarily: a) interaction of carbonate rock and nanospheres (through zeta potential), and b) effect of nanospheres on oil displacement in carbonate cores.
The paper presents evaluation results showing that water quality composition has a great influence on the electrical properties of carbonate rock and nanospheres. In two extreme cases of evaluation (de-ionized water and highest-salinity brine), nanospheres have a uniform charge with rock surface, and there is mutual repulsion that means reduced adsorption on the rock. The positive impact on oil production has been also demonstrated.
Field trial and injectivity tests are essential to de-risk polymer-based IOR technologies.
After the laboratory evaluation the field trial in carbonate reservoir has begun. The nanospheres solution have been injected in two wells. The pilot design included different concentrations and injection rates that were selected after careful review of geological features and ongoing water injection results. The positive impact on watercut and oil rate in producing wells has been reported and confirmed. Furthermore, no loss in injectivity has been observed. This work and field trial can enable the water flooding improvement in carbonate reservoirs through novel IOR method. Besides, nanospheres injection prior to conventional polymer flooding can significantly improve the performance of latter.
-
-
-
Cold Waterflooding vs. Steam Injection Applicability for Heavy Oil Reservoirs as a Secondary Stage Recovery Method
More LessSummaryPrimary production can be exploited to produce oils with viscosities up to 10,000 cp or even more and usually this stage is followed by water flooding. Since the water temperature is always lower than the temperature of the reservoir, a cooling process starts at this stage and this may continue many years before starting a thermal EOR technique to produce the residual oil which may exceed 50% of OOIP. Injecting a cold fluid may bring many changes into the reservoir, one of which is reservoir temperature change which is the main theme of this paper.
During our simulation of the cooling of the geothermal reservoirs, it has been observed that the natural thermal gradient will not be able to compensate for the decrease in temperature during a long period of injection of cold water. The same behavior has been observed in the case of water injection in oil reservoirs. This phenomenon has been reported since the fifties of the last century in some oilfields in the USA and confirmed by real data measurements at the bottom hole of some wells. This study illustrates numerically how the temperature will drop down on a long time scale. On the other hand, when a steam injection is planned for the next phase of production, a huge amount of energy will be needed to restore the temperature of the reservoir.
To illustrate the above-mentioned theory and observations, a model of a geothermal reservoir is solved to show the cooling process in 3D using a commercial finite element software package. SPE4 Benchmark model is used to compare the ultimate recovery by cold water injection scenario and steam injection counterpart. The temperature change of the reservoir in both cases is shown and compared.
The results show that starting steam injection as a secondary stage in heavy oil reservoirs can save time and gain more profits, especially at the high oil prices phase. Furthermore, the compensation for installing and operating a steam injection facility can pay for itself in a short period of time.
-
-
-
Novel Approach to Model and Visualize the Transport of Polymer Molecules in Porous Media Using Microfluidics
Authors H. Hoteit, A. Sugar, S. Habuchi, M. Serag, U. Buttner and M. FahsSummaryPolymers have been successfully deployed in the Oil&Gas Industry for various field applications, including waterflood mobility control, flow divergence, and well conformance control. Polymers are among the most widely used chemical EOR methods. Polymer intermolecular interaction and resulting permeability alterations are not fully understood. In this study, we present a novel approach for dynamic visualization of polymer molecular interaction and transport behavior using porous media replication in a microfluidic device, including fluorescent tagging of polymers and single-molecule microscopy. We then use pore-scale simulations to reproduce the experimental observations.
The microfluidic chip, conceptually referred to as “Reservoir-on-a-Chip”, serves as a two-dimensional proxy, which facilitates assessing the flow mechanisms occurring at pore-scale. A microfluidic model was developed to observe polymer flow behavior and transport mechanisms through porous media. The designed microfluidic chip honors the pore-size distribution of oil-bearing conventional reservoir rocks, with pore-throats ranging from 2 to 10 μm. We built the micromodel out of polydimethylsiloxane (PDMS) through soft-lithography.
The traditional use of tracers to track polymers has a limitation because of the tendency of polymer molecules to segregate. Polymer induced pore-clogging, alongside with the reverse mechanism, namely pore-unclogging, have been dynamically captured, for the first time. On the basis of the experimental observation, pore-scale simulations were performed to model the phenomenon. We investigated the flow of the polymer molecules and agglomerates residing in the polymer solution and the clogging-unclogging mechanisms. The simulations emphasize consistent flow conductance increase with time, in the flow channels that underwent unclogging. Both experimental and simulation results bring evidence of polymer retention and attainable flow conductance restoration to the initial pre-polymer flooding values.
We show the first direct dynamic observations of a tagged polymer molecules at dynamic conditions. The conducted single-phase flow experiments enabled direct observation of polymer molecules’ flow behavior within the hosting phase. Additionally, the retention mechanisms manifested during flow and their impact on apparent permeability are analyzed.
The study presents a novel approach for labeling and visualizing polymer molecules and their flow behavior in porous media. We successfully used advanced microscopy techniques, to present dynamic visualization of polymer pore-clogging and unclogging mechanisms, for the first time. Using microfluidic techniques and single-molecule microscopy, we provide new insights at the molecular level, and flow behavior at the pore-scale, which helps to optimize polymer selection for field implementation.
-
-
-
Carbon footprint forecasting of IOR activities via an intelligent NARX framework for promoting greener reservoir management
Authors K. Katterbauer, A. Marsala, A. Sofi and A. YousifSummaryIntroduction:
Sustainability is increasingly considered a key strategic driver across all industries including oil and gas, and its upstream sector. We continuously thrive to maximize hydrocarbon production while minimizing the associated carbon footprint. In water flooding oilfield operations, the primary driver of carbon emissions is actually water – usage, production, and disposal. The required energy to transport and process the water is considerable, and it is therefore the major carbon emitter. Forecasting carbon emissions from oilfield operations challenges our ability to optimize field development plans in light of carbon footprint besides profit or recovery.
Method:
In this work, we present an innovative approach for forecasting the carbon footprint of a reservoir in terms of the associated development and production activities. We use an advanced nonlinear autoregressive neural network approach integrated with time-lapse electromagnetic data to forecast the carbon emissions from the reservoir in real-time under uncertainty. Within this artificial intelligence (AI) framework, we also incorporate the ability to study the adoption of a circular carbon approach. For this scenario, the AI framework allocate the reinjection of produced greenhouse gases while adjusting water injection levels and forecasts the impact of such circular development plan.
Results:
We tested the framework on a synthetic reservoir encompassing a complex fracture system and well setup. The carbon emissions were forecasted in real-time based on the previous production levels and the defined injection levels. The forecasted carbon emissions were then integrated into an optimization technique in order to adjust injection levels to minimize water cut and overall carbon emissions, while optimizing production levels. Results were promising and highlighted the potential significant reductions in carbon emissions for the studied synthetic reservoir. Moreover, the deployment of deep electromagnetic surveys was found particularly beneficial as a deep formation evaluation method for tracking the injected waterfront inside the reservoir and optimizing the sweep efficiency. Accordingly, such integrated AI approach has a twofold benefit: maximizing the hydrocarbon productivity, while minimizing the water consumption and associated carbon emissions.
Future Outlook:
Such framework represents a paradigm shift in reservoir management and improved oil recovery operations under uncertainty. It proposes an innovative technique to reduce the carbon footprint and attain at real-time an efficient circular injection development plan.
-
-
-
Smartwater Flooding in Carbonates: The Role of Iodides Ions in Wettability Alteration
Authors A. Gmira, D. Cha, A. Alghiryafi and A. AlyousefSummaryWater injection have been a successful procedure for recovering incremental crude oil from carbonate reservoirs. This recovery method contributes in altering carbonate formations wettability from oil-wet to more water-wet, leading to higher oil mobility and additional hydrocarbon recovery. Recently, the concept of tuning the injected water composition, either by altering the salinity or the ionic composition have gained a significant momentum in the oil industry, encouraged by laboratory and field tests results. Both strategies can make a multiscale adjustment at the fluid-fluid and fluid-rock interfaces, in favor of oil recovery enhancement. However, salinity tuning and ionic composition tailoring have their own challenges and limitations.
In this study, we are investigating the approach of a practical concept in enhanced oil recovery with the addition of Iodide ions in a very small concentration without further treatment. Iodide ions are added to high and low ionic strength brines with different concentrations (500 ppm, 1000 ppm, 2000 ppm and 5000 ppm) to formulate an optimum injected water composition. Contact angle and interfacial tension measurements with selected crude oil are utilized to screen the effect of iodide ions concentration and to study the effect on carbonate rock wettability and crude oil-brine interface. Zeta potential and advanced Sum Frequency Generation (SFG) spectroscopy are utilized to investigate the electric charge variations and to capture the chemical structure changes at the interface.
The initial results show a limited effect of iodide ions on crude oil-brine interfacial values while they alter significantly the rock wettability to stronger water-wet. Zeta potential and SFG measurement brings new insights on understanding the chemical structures at the crude oil-brine interface and how the presence of iodide ions is affecting the interface organization and the structure of organic and inorganic components.
The proposed study is tackling the tailored water injection for EOR purposes from another angle: adding specific ions instead of adjusting the ions levels and ionic strengths. The novelty of this investigation is to bring together routine wettability alteration analysis (contact angle, interfacial tension and zeta potential) and Sum Frequency Generation technique to understand the effect of iodide ions at the fluid-fluid and fluid-rock interface and the potential in-situ changes at low scale. Such understanding is crucial to optimize the injected water chemistry at lower costs.
-
-
-
Toward Smarter Oilfield Chemicals for EOR/IOR
Authors N. AlJabri, A. Gizzatov and H. ShateebSummaryThe advances in nanotechnology are receiving much attention to transform the oilfield chemicals into smarter, greener and sustainable chemicals. This work describes the synthesis of novel nanofluid via encapsulating superparamagnetic iron oxide nanoparticles (SPIONs) in nanosurfactant (NS), using an inexpensive, scalable, and straightforward method. This nanofluid (NF) is designed to enhance or improve the oil recovery at lower concentrations at reduced cost and, comparing to the conventional chemical flooding. Superparamagnetic iron oxide nanoparticles (SPIONs, 5 and 10 nm in toluene, (5 mg/mL) were obtained from commercial supplier. Different amount of SPIONs was encapsulated into NSs to establish maximum encapsulation concentration. For that, first, 5 and 10 nm SPIONs in toluene were mixed in different ratios with as received Petronate HL/L (61 wt% active) and further formulated into the high-salinity and high-temperature stable NFs. Stability of the formulations in the presence of high salinity was verified through incubation at 100 °C for an extended period. Equilibrated interfacial tension (IFT) measurements were performed using spinning drop tensiometer. The SPIONs encapsulated nanofluid exhibited remarkable colloidal stability at 100 °C and high-salinity of 56,000 ppm of total dissolved solids for over a year. We conducted an equilibrated IFT measurement between different types of crude oil and SPIONs encapsulated nanofluid with corresponding control measurements. Significant reduction in IFT (0.001-0.005 mN/m) was observed for the nanofluid with the encapsulated 5 nm SPIONs when compared to the first generation of NS (0.02 mN/m). The cryo transmission electron microscopy (cryo-TEM) images confirmed the SPIONs encapsulation within the nanosurfactant vesicles. The lower IFT owes to the great synergy between SPIONs and the NS to reduce the IFT by more than two orders of magnitude comparing to NS alone. This work demonstrates the synthesis of economic, efficient and environmentally friendly nanofluid to allow further improve oil mobilization beyond the waterflooding. A novel SPIONs encapsulated nanofluid was synthesized using an inexpensive, scalable, and simple synthesis method. The new nanofluids exhibited colloidal stability under reservoir conditions for a year. The synergy between NS and SPIONs resulted in lower IFT values compared to the use of SPIONs and NS alone. These findings open the horizon to encapsulate a wide range of nanoparticles to generate a library of multifunctional nanofluids to support several upstream applications.
-
-
-
Low Carbon Foot-Print Reservoir Stimulation Technologies for Improved Oil Recovery
Authors A. Alghamdi, A. Al-Qasim, S. Ayirala and A. YousefSummaryGlobal efforts have been exerted since the 1960s to explore the best technologies for effective enhanced oil recovery (EOR), including thermal, chemical, and gas flooding methods. Yet the adoption and field implementation of these conventional methods is limited. The limitation arises from the fact that those technologies are expensive and mandate substantial modifications in both injection and producing facilities.
In this work, we discuss unconventional improved oil recovery (UIOR) methods that can be implemented in existing waterflooding projects. These technologies include ultrasonic treatment, reservoir electric stimulation, pressure pulse injection, seismic stimulation, and plasma pulse. The main objective is to review the proven best practices and draw examples from ongoing projects. It is also to look at the new horizon for the best feasible solution and provide the most practical option for deploying UIOR technologies in the field.
The ultrasonic treatment targets mainly near-wellbore regions to increase well production rates and decrease water cut. The electric stimulation technology can cover a radius of up to 2–3 km to reduce oil viscosity and remove the clogs in the pore throats to improve oil recovery. The technology is tested in USA and Canada and showed oil recovery enhancements from sandstone reservoirs by applying electric current on pairs of largely spaced wells. The pressure pulse assisted power waves promote greater depth of penetration for the injected fluid to mobilize the stranded oil. The technology has been successfully applied in different patterns of a waterflooding project in eastern Alberta to enhance oil production. The seismic stimulation relies on harnessing low frequency elastic waves either from injection or abandoned wells for increasing oil recovery within a radius of up to 1.4 miles. It has been observed to significantly increase oil production in different formations including carbonates, sandstones, dolomite, and shales. The Plasma Pulse technology uses a high energy plasma source to reduce oil viscosity, and the associated acoustic waves also help in reducing surface tension and increasing oil mobility. This technology is tested widely in Europe and USA to show positive results.
Each of the identified UIOR technologies would result in a lower greenhouse emission and almost no consumption of chemicals. These methods should be selectively screened by taking into consideration the respective technology limitations and uncertainties associated with different reservoir fluids and formation types. The synergy between such technologies could also mitigate some of the individual limitations and enlarge their applicability envelope for eco-friendly and cost-effective improved oil recovery applications.
-
-
-
Analysis of the Temperature Impact on the Calcite Surface Reactivity in Modified Salinity Water Applications
Authors M. Bonto, A.A. Eftekhari and H. NickSummaryThe success of modified salinity waterflooding (MSW) in carbonate reservoirs is dictated by the interactions between the injected brine and the rock. To describe these interactions, different surface complexation models (SCM) have been proposed. These SCMs usually rely on experimental data at room temperature to obtain the equilibrium constants of the surface reactions. However, these conditions diverge from the actual reservoir temperature, e.g. greater than 70oC in the North Sea. Thus, the existing models cannot describe the surface reactivity at real field conditions unless the temperature dependency of the equilibrium constants is included. The conventional approach to account for the impact of temperature on the surface reactivity is to include an extrapolated temperature effect observed for solution complexation. However, this non-validated assumption may lead to misinterpretation of experimental data.
We address this issue by first identifying methods that give information on the affinity of ions for the calcite surface at different temperatures. We found that calorimetry, streaming potential, and molecular simulations are potential ways that enable capturing the temperature effect on the surface reactivity. Whereas molecular simulations studies provide directly enthalpy data for each defined interaction, calorimetry and streaming potential require geochemical modelling to interpret and break down the observed temperature effect for individual surface reactions. Thus, we perform the modelling of published data from calorimetry and streaming potential experiments by implementing in Phreeqc a Charge Distribution MultiSite Complexation (CD-MUSIC) model, which includes reactions between the calcite and ions relevant for MSW applications; this model is thoroughly validated with experimental data at room temperature. Next, we infer the enthalpy of the reactions by assuming that the equilibrium constants follow a temperature dependence according to van’t Hoff equation. Given the synergy between the interactions, we note that modelling different type of experimental data results in distinct enthalpy values. After a detailed analysis of the experimental methods/simulations, we establish a unique set of enthalpies for the defined reactions. These enthalpies are further verified against flooding experiments in the work of Hosseinzadeh et al. (EAGE IOR 2021) by coupling the reaction module to the single-phase flow equations. The resulting thermodynamic model that accounts for the temperature effect is not only a useful tool for interpreting the laboratory experiments but can also reduce the uncertainty of implementation of MSW projects at the field scale. The study is not only relevant to MSW IOR but also to other non-isothermal reactive transport processes in carbonate formation.
-
-
-
Integrated Study and Application of Polymer Injection in Arctic Environment
Authors T. Pepe, M. Martin, P. Galeazzi, F. Masserano, M. De Simoni, M. Bartosek, S. Furlani, H. Giraud and V. SalviSummaryThis work presents the interpretation of a polymer injectivity test performed in a heavy-oil field (50–200 cP), located in a challenging arctic environment, during the first half of 2019 to assess the feasibility of the polymer injection process. Following the positive results achieved with the injectivity test, a polymer interwell pilot test started in the last months of 2019, but it was suspended in April 2020 due to Covid restrictions. Thanks to the acquired data during the pilot test, polymer model was tuned into a dedicated sector of the reservoir model, including one injector and two producers.
Using internal company EOR-screening tools, polymer flooding was identified as the most suitable technology for the asset. An integrated study of 3D-modeling and in-house laboratory activities was performed to assess polymer injection potentialities and select the best chemical product for the asset. 3D dynamic analyses confirm the benefits of polymer injection with a significant oil production gain.
Four representative horizontal wells were selected for the injectivity test in order to confirm the injection effectiveness. The selection of injectors was based on an extensive analyses of wells status and performance. The test strategy consisted of 2-weeks polymer injection per well, at constant injection rate and increasing polymer concentration steps. A detailed real-time surveillance plan was realized to monitor injector pressures and polymer solution properties.
The injectivity test was concluded successfully: target viscosity, defined during the laboratory and modeling analyses, was achieved with a limited impact on injectivity. Pressure increase and stabilization during polymer injection confirmed the feasibility of the technique for the reservoir. Well test and temperature profile acquired before and after polymer injection were interpreted.
Once assessed the feasibility of polymer injectivity, a 1-year inter-well pilot started in November 2019. Injection took place up to March 2020 and was suspended due to Covid restrictions. The re-start is planned for mid-2021. During the test several injection and production data were gathered, analyzed and interpreted. In addition to that, starting from the full reservoir model, a detailed sector model was set up in order to match pressures and water cut and forecast the performances of polymer injection.
-
-
-
Using Surfactant at Ultra-Low Concentration to Unlock Polymer Field Projects
Authors A. Klimenko, V. Molinier, N. Passade-Boupat and M. BourrelSummaryPolymer injection is now a conventional technique for improving mobility control and volumetric sweep efficiency in the field. However, capital and operating expenses are sometimes borderline to ensure profitability, putting the project in jeopardy. An alternative to mitigate this risk would be to significantly improve the oil recovery potential for a low enough marginal cost.
The addition of surfactant is tempting as Surfactant-Polymer injection has proven at the laboratory scale to be very effective to enhance oil recovery, but, with traditional formulation guidelines, the high cost of chemicals and the difficulties in preparing the SP solution are a major obstacle to the project. From this perspective, the objective of this study is to try to adapt the concept of optimal surfactant formulation, without necessarily trying to achieve ultra-low interfacial tensions, to improve the overall efficiency of polymer injection, and thus unlock the potential of polymer projects.
To this end, physicochemical phase behavior of conventional surfactants/crude oil/water systems has been studied to find the optimal formulation conditions at high surfactants concentration. This ultra-low tension formulation was then diluted by more than one order of magnitude compared to “traditional” surfactant designs and was successfully tested in core floods at different injected volumes in order to optimize the design and minimize the cost.
Contrary to expectations, it was found that the optimal formulation used at ultra-low concentrations can sufficiently modify the flow propagation to significantly improve polymer flood. The volume of surfactant injected was optimized to be “good enough” just to upgrade polymer flood without seeking complete desaturation. As so, the limited CAPEX and OPEX that would be required for putting in place this strategy would be game changers on a whole polymer project.
Based on our knowledge, it is the first time that the surfactant formulation of ultra-low concentration shows such promising results. The concentration level is of the same order of magnitude as that of other oil field chemical additives (tens to hundreds ppm), which makes it easy to handle but can considerably extend the application limits of polymer injection.
-
-
-
Zeta Potential of the Crude Oil-Brine Interface and Implications for Controlled Salinity Waterflooding
Authors H. Collini and M. JacksonSummaryIt is commonly observed that improved oil recovery (IOR) by controlled salinity waterflooding (CSW) coincides with a change to a more water-wet state. An important parameter controlling the wetting state is the zeta potential of the mineral-brine and oil-brine interfaces, which controls the electrostatic forces acting between. Evidence suggests successful CSW is observed when the injection brine composition is modified so as to increase the electrostatic repulsion acting between the interfaces, leading to detachment of oil from the mineral surfaces and IOR on the core- to field-scale.
Measurements of zeta potential at the mineral-brine interface have been reported using the streaming potential method (SPM) at representative reservoir conditions of temperature, salinity and wetting state. It is generally accepted that the mineral-brine zeta potential becomes more negative with a reduction in the injection brine salinity and/or specific ions. However, comparable zeta potential data for the oil-brine interface are scarce. Most report negative values at pH>6, increasing in magnitude with increasing brine dilution, however, these are typically made using commercially available electrophoretic methods which operate far from reservoir conditions, using suspensions of crude-oil droplets in dilute (<0.1M), single-salt species brines and ambient conditions.
Here we report novel and systematic SPM measurements of zeta potential of the oil-brine interface in brines of high ionic strength and containing multivalent ions. A strongly oil-wetting, hydrophobic porous substrate was prepared and coated with the crude-oil of interest. The SPM was used to measure the zeta potential of these substrates when saturated with brines of interest to CSW. We find the zeta potential is negative in simple NaCl brines (up to 2 Mol/L) with the magnitude increasing with decreasing brine salinity, consistent with previous literature. The concentration dependence of a given oil depends on properties such as the acid number and base number. Increasing the concentration of specific ions such as Ca2+ causes the zeta potential to become more positive and for some oils can invert the polarity. The sensitivity of the crude-oil to potential determining ions such as Ca2+ varies significantly dependent on the oil properties.
Integrating these measurements with CSW corefloods, we find diluting the injection brine yields IOR only when the zeta potential of the oil-brine interface is negative. In samples where the oil-brine zeta potential is positive, no IOR was observed, consistent with the hypothesis that IOR is caused by an increase in the repulsive electrostatic force between the mineral-brine and oil-brine interfaces.
-
-
-
Estimating two-phase reactive flow model parameters from single- and two-phase modified-salinity core flooding data
Authors H.M. Ciriaco, H.M. Nick and A.A. EftekhariSummaryDue to the complexity of underlying physics of the modified salinity water flooding, mechanistic models are often utilized to better understand and predict its behaviour in the field scale. The mechanistic models are a combination of several submodels of different nature, each with several adjustable parameters. Adjusting these parameters by fitting the model to a limited number of recovery factors obtained from core flooding experiments is not a viable solution, often estimating highly uncertain values for the model parameters. We address this challenge by providing a framework for fitting a mechanistic two-phase reactive-transport model to a combination of low-cost single- and two-phase flow experimental data.
The effectiveness of modified-salinity water flooding is often tested in (qualitative) spontaneous and (quantitative) forced imbibition tests in the lab. Several mechanisms that are suggested for explaining the observed improved oil recovery cannot be distinguished in those traditional imbibition tests. Mechanistic models with adjustable physically-meaningful parameters exist for these mechanisms, e.g. carbonate dissolution, surface charge (and force) alteration, fines migration, water weakening, etc. However, obtaining these adjustable parameters by fitting “a mechanistic model that incorporates all these mechanisms” is not a good strategy. Our mechanistic models are a combination of chemical equilibrium and kinetics models that describe the chemical reactions between the ionic species in the aqueous phase (electrolyte model with known parameters), chalk and oil surface complexation reactions (CD-MUSIC, diffuse layer models with unknown parameters), and an empirical parameter linking the surface reactions to the relative permeability and capillary pressure model parameters. When fitting the model to the core flooding data, the optimization algorithms are more sensitive to the relative permeability parameters. Moreover, the number of parameters are often too many and can result in a largely underdetermined system of equations, for which the optimization algorithm is very sensitive to the initial estimates.
Our novel numerical framework optimizes the model parameters by simultaneously fitting the parameters to a set of core flooding, spontaneous imbibition, and single-phase chromatographic tests (i.e. injecting MSW to a core saturate with formation water and measuring effluent ionic concentrations with time). We obtain the initial estimates of the surface complexation model parameters by fitting the model to the zeta potential measurements performed on powdered carbonate suspensions. We finally demonstrate the capabilities of our framework by optimizing model parameters for a set of inhouse experiments performed on chalk cores from the North Sea reservoirs.
-
-
-
Laboratory Study to Investigate Cyclic Hysteresis in Miscible and Immiscible WAG Experiments in Carbonate Reservoir
Authors S. Masalmeh, A. Al-Mesmari, A. Farzaneh and M. SohrabiSummaryIn this paper, we present the results of a detailed experimental study aimed at understanding three-phase hysteresis in miscible and immiscible WAG injection processes. It has been reported in literature that the two-phase hysteresis models will generally not be able to describe relative permeability obtained in three-phase core floods. The main shortcoming of two-phase hysteresis models is that after imbibition cycle, the relative permeability is reversible. In three-phase flow, a cycle dependent hysteresis was reported which could significantly impact the gas mobility in the different cycles and improves sweep efficiency.
In this study, a number of immiscible and miscible gas and WAG injection experiments were performed using limestone reservoir core samples from a carbonate reservoir. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir conditions. Methane (C1) was used as the immiscible injectant and CO2 was used as the miscible injectant.
The main conclusions of this study are: 1- Cyclic hysteresis in gas relative permeability was observed when comparing the first and second gas cycle, however, no further hysteresis was observed in the subsequent cycles, 2- The gas mobility at similar gas saturation for experiments starting with gas is better than that for experiments starting with water, 3- Gas and water relative permeability end points are not dependent on their own saturation alone as assumed in three-phase relative permeability models, significant variation in the relative permeability end points was measured at almost the same saturation, and 4- The water mobility of the experiments starting with water cycle is better than the water mobility of the experiments starting with gas cycle at the same water saturation. This shows the presence of gas before the first water cycle reduces the water mobility.
-
-
-
Rheology, Stability, and Adsorption of an Amphoteric Foaming Agent for CO2 Mobility Control Applications under Reservoir Conditions
Authors Z. AlYousef, A. Gizzatov, M. Almajid and A. AlabdulwahabSummaryFoam injection is one of the most promising techniques to overcome gas mobility challenges during gas injection processes. Foam reduces gas mobility by increasing the gas apparent viscosity and reducing its relative permeability and, consequently, improving the gas sweep efficiency. The stabilization of foam at reservoir conditions, together with reducing surfactant adsorption on the rock minerals are the major challenges facing this technique. The objective of this study is to extensively evaluate the effectiveness of a potential surfactant on generating stable foams using sc-CO2 at high temperature and salinity conditions.
In this study, bulk and dynamic foam tests were conducted to evaluate the effectiveness of an amphoteric surfactant, Amphosol LB, on stabilizing foams at harsh reservoir conditions (more than 2000 psi, 100 oC and 57,000 ppm of brine salinity). For bulk foam tests, the stability of surfactant solutions as well as the foam rheological properties using foam rheometer apparatus were analyzed and quantified. For dynamic foam tests, the CO2 mobility reduction factor as a result of foam generation using the surfactant was measured using two different systems: microfluidic device (chip with physical rock network) and coreflooding apparatus (actual rock samples). Also, the adsorption of the surfactant on carbonate rock minerals was quantified using the coreflooding apparatus.
The experimental results demonstrated that the surfactant solution is chemically stable and able to generate foams at different reservoir conditions. The Amphosol LB surfactant solution produced foam with relatively high apparent viscosity when compared to those used for foam applications. The results also demonstrated that the foam viscosity increased as the foam quality decreased. For retention test, the results revealed that 86.56% of the injected surfactant solution was recovered. The amount of surfactant adsorbed by rock is about 0.257 mg/g rock. In the microfluidic chip and actual rock sample, the results also demonstrated that Amphosol LB surfactant solution showed higher resistance to gas flow and, accordingly, higher mobility reduction factor of sc-CO2 at 70% foam quality when compared to the other tested foam qualities. High apparent viscosity, small adsorption to the rock, and an acceptable CO2 mobility reduction factor are indicative of strong and more stable foam for reservoir applications.
-
-
-
Microfluidic Device for Fast Pre-Screening of EOR Chemicals at Close to Reservoir Conditions
Authors A. Gizzatov, W. Wang, S. Chang, G. Thomas, A. Mashat and A. Abdel-FattahSummaryMicrofluidic devices allow manipulations with the flow of fluids at sub-millimeter scales. The advantages of this technology include a significantly reduced volume of fluids required for certain physical and chemical characterizations; reproducible and enhanced mixing of flowing phases; better control over the heat exchange; access to imaging of the pore-scale flow phenomena; reduced cost of characterization methods when compared to some conventionally used methods and devices; and more. This work reports on an innovative approach to study the recovery of crude oil from microfluidic devices. This approach was designed to closely mimic the environment within pores of carbonate rocks.
Commonly used techniques to study the recovery of crude from saturated core plug samples are coreflooding and imbibition experiments using an Amott cell. Coreflooding is labor intensive, does not provide pore-scale imaging, takes close to a week or longer to operate, uses liters of solvents, and is also cost intensive. Imbibition experiments also do not provide a visual understanding of the oil recovery process at the pore scale. To address some of these challenges, transparent microfluidic devices made of glass that are capable of operating at close to reservoir conditions were developed to improve and complement conventionally used devices. These devices contain patterned channels representing carbonate pore networks. The interior surface of the channels are fully coated by growing a thin layer of calcite nanocrystals, which closely represent a carbonate reservoir’s rock chemistry. The surface is then treated by crude oil aging to generate appropriate wettability resembling the natural reservoir carbonates. The fabricated device was used to study the recovery of oil from porous networks and to successfully prescreen candidate surfactants for enhanced oil recovery (EOR) applications.
The microfluidic devices developed here allowed us to effectively differentiate between three in-house developed surfactant formulations. Data obtained by image analysis of the oil recovery process from within the porous microfluidic channels using various surfactants provided quantitative oil recovery for each chemical and served as a useful benchmark to differentiate the best candidate formulations. Results also were used to compare efficiency of surfactants based on interfacial tension and potential effects related to wettability alteration. The high-temperature microfluidics platform allows us to rapidly prescreen a large number of formulations for applications in EOR, visualize mobilization of the oil from porous structure at close to carbonate reservoir conditions, and allow cost savings by facilitating processes in developing best EOR formulations.
-
-
-
Investigation on the Effect of Micro-structure Difference between Hydrophobic Associated Polymer and Salt-resistant Polymer on Enhance Oil Recovery
More LessSummaryHydrophobic association polymers and salt-resistant polymers are functional polymers with stronger viscosifying properties than common polymers such as hydrolyzed polyacrylamide (HPAM). And both of them can furtherly expand sweep volume to improve oil recovery efficiency. However, the current researches on the two types of polymers are mainly focused on the EOR effect, and there is no in-depth investigation on the differences in their microstructure. In this paper, hydrophobic association polymer HSP and salt-resistant polymer SRP were selected to evaluate, and the differences in microstructure, hydrodynamic characteristic size, migration capacity and enhanced oil recovery were compared. The results show that the HSP has a complex spatial network structure, while the SRP has a rigid coarse-straight chain structure. The HSP has stronger spatial aggregation structure corresponding to larger hydrodynamic characteristic size. Compared with HPAM, both HSP and SRP have higher adsorption retardation rate, causing the resistance coefficient and residual resistance coefficient are larger. The higher flow resistance of spatial network leads to better EOR effect of HSP. Compared with the SRP, the EOR of HSP flooding can be increased by 2.98%.
-
-
-
A Deep Investigation of EOR/EGR and Stimulation Enhancement Methods in Unconventional Reservoirs
Authors C. Temizel, C. Canbaz, H. Aydin and Z. WijayaSummaryProduction from Unconventional structures is being expected to be the future trend of oil and gas industry. Although the primary recovery values range between 5 to 8%, liquid-rich shale structures has great amount of hydrocarbon in place and it can be produced by EOR applications such as cyclic gas injection that can boost the production up to 1.7 times. This reference study gives a deep review of EOR mechanisms and the stimulation techniques for unconventionals.
A comprehensive investigation about the historical development of the concept, the technologies utilized as well as transferred from other industries, adaptness and impetus of the methods in both conventional and unconventional structures is described with the escalating efficacies that these methods ensured for different reservoir structures. The concepts are exemplified with existing worldwide field case studies and applications by implying the advantages, challenges and drawbacks belong to each story. All parameters are discussed and summarized that lead to conclusions on the criteria of application of enhanced technologies.
The concept of EOR and Stimulation is a proven area of application which demonstrated itself with its great number of worldwide applications in conventional structures. Key factor of success for an EOR application is to evaluate each case individually to take the suitable actions of technical and economic concerns. This study underlines the theory, key parameters, methodology, challenges and advantages of a successful EOR application for the wells that include intelligent or standard completions in unconventional structures. It aims to serve as a unique reference study which combines of all the aspects of the employed techniques and their usability in specific cases.
There are dozens of publications which includes certain examples of Enhanced Oil and Gas technologies, but a detailed study that includes all the aspects of EOR methods suitable to apply in unconventional reservoirs is missing. This study aims to be a reference study by giving all the details from design to result of a successful EOR application in unconventional reservoirs.
-
-
-
Huff’n Puff EOR Optimization by using Different Cyclic Gases in Unconventional Shales
Authors C. Temizel, C. Canbaz, H. Aydin, V. Kudrashou, J. Wu, F. Haeri, Y. Unal and N. NurlybayevSummaryIncreasing global trend of unconventional production impelled the oil and gas companies to adapt the EOR mothods to unconventionals to increase the recovery. In this study, a deep review of cyclic gas (Natural Gas, CO2, N2) injection processes and the methodology to apply in unconventional shale reservoirs is described by investigating all the geological, petrophysical, production and reservoir engineering aspects. The significance of each uncertainty and control variable throughout the process is outlined.
A full-physics commercial simulator is used to identify the significance of control variables, and also the level of uncertainty which are directly affecting the production and recovery functions. The challenges encountered during implementation of cyclic gas injection processes are outlined in order to provide a comprehensiveand practical implementation perspective rather than only theoretical or a simulation work. Besides, the theory, advantages, drawbacks, benefits are given in details. Results of real cases are being compared and matched with the simulation results.
The study indicates the incremental advantages of appliying huff`n puff process in unconventional shale reservoirs by comparing the primary production performance with the performances of cyclic injection cases that uses various gases. Key factors that directly affect the reservoir, completion and operational attitudes are circumstantially given to technically handle a successful project in a feasible way. In the model, the objective function is built by considering the economic parameters to help NPV maximization in a realistic perspective. S-curves and tornado charts is used to visualize the results and illustrate the significance of parameters and ranges of the developed probabilistic economic model. The effect of huff`n puff method and how a successful cyclic injection gives better recovery and feasibility results is clearly shown.
Petroleum literature includes several studies related to cyclic gas injection. However, these works are either only focus on the simulation/theoretical parts or only includes a case study that focuses reservoir/production analysis. This comprehensive study closes the gap aims to be a reference by including a deep look into details of the theory and combines it with real field cases and solutions by clearly describing the candidate selection, modeling, physical parameters/key factors, economics, and success stories.
-
-
-
Evaluation of First-Ever Foam Assisted Conformance Control for a Middle Eastern Carbonate Reservoir Offshore Qatar
Authors M. Taha, A. Kumar, P. Patil, M. Pal and Q.P. NguyenSummaryGas injection has been evaluated and implemented in a middle-eastern oil field as water alternating gas or WAG. It has been seen that WAG is economically viable and a robust EOR method for areas of the field which are homogenous and do not pose conformance issues. However, the application of WAG in heterogeneous parts of the field has not been widely attempted due to issues like an early gas breakthrough and unfavorable sweep efficiency that are typically associated with WAG in heterogeneous reservoirs. Hence it was decided to design a foam assisted WAG system that can provide the required conformance control to mitigate those issues and expand the use of WAG to the entirety of the field.
There are numerous references in literature to ‘aqueous foam’ as an attractive option to reduce the conformance issue of injected gases like hydrocarbon gas or carbon dioxide. There have been many field implementations of foam assisted WAG in CO2 flooded reservoirs in the United States. There is one example of foam-assisted hydrocarbon gas injection in the Snorre field. However, Foam as an EOR or IOR method remains untested and unproven in middle eastern reservoirs. In this study, we have carried out a comprehensive experimental program to design an effective foam system, that evaluates foam performance under specifically field conditions.
A complete laboratory program has been carried out to screen the best foaming surfactant formulation that resulted in selection of Alkyl Polyglucoside surfactant. The criteria’s used in selection of surfactant involves having low adsorption on rock, good aqueous stability at reservoir conditions, and strong foam stability in presence of oil. The surfactant screening also involved foamability tests in porous media under oil-wet and water-wet conditions. The selected surfactant showed good foam strength under both oil-wet and water-wet conditions. The impact of mobile oil was also observed by co-injecting oil during the linear core flood experiments which clearly showed that good foam strength can be achieved in lower flow fraction of mobile oil with foam. Additionally, it was shown that altering wettability using another non-ionic surfactant along with APG resulted in a higher foam strength. The evaluation of surfactant formulation for boosting of foam strength using Lauryl Betaine surfactant was also performed. All the experimental results generated in this detailed evaluation of foam in the lab will be used in a foam modeling during next phase of the project to design a field injection strategy.
-
-
-
Successful Wettability Alteration Pilot in Offshore Reservoir: Pilot Planning, Execution, Monitoring and Interpretation
Authors M. Pal, P. Saxena, N. Rohilla, A. Katiyar, P. Rozowski and T. KnightSummarySurfactant injection as an EOR method is considered for a giant middle-eastern carbonate oilfield in offshore setting. The field is characterized by thin oil column, low permeability, and large lateral variations in fluid properties. Even after an extensive water-flood program, there are substantial amounts of oil left behind in the reservoir due to the mixed-wet to oil-wet nature of the Reservoir. An extensive surfactant-based wettability alteration EOR screening process was conducted to select the best surfactant for improving the oil recovery. After successful short surfactant injection trials, a long-term surfactant injection pilot was planned and executed. The pilot was supported by a comprehensive monitoring program. The pilot was conducted in an offshore environment involving very long horizontal well, which is unique in the industry and is first of its kind. A robust and comprehensive monitoring program is key to successfully evaluate the pilot performance and qualify the incremental oil production from the trial. A detailed monitoring program was prepared in advance before the pilot start-up, which involved internal and external parties. Monitoring plan consisted of high frequency monitoring of delivered surfactant quality, constant monitoring of surfactant injection concentration and injection rates. Plan involves high-frequency collection and monitoring of production samples with the aim of highlighting any changes compared to the base line measurement. External labs were also involved for precision monitoring of any surfactant breakthrough for pro-actively mitigating effects of any upset due to pre-mature surfactant breakthrough. For monitoring a dashboard has been created for identifying correlation between various processes. The pilot monitoring is still on-going and will continue for another 6 months. The comprehensive monitoring program has contributed to the successful conclusions from the pilot. The data gathered during the monitoring program will enable scale up of trial to other wells, qualification of incremental oil production, and to improve efficiency of the future implementation of surfactant injection on a greater number of wells.
The paper presents the results planning of trial form lab to field, implementation of monitoring plan and results of the monitoring plan, which support the trial conclusions. The pilot and the monitoring program are unique in themselves as the scale of operations and number of stakeholders involved are large. The pilot demonstrates that it’s possible to implement an EOR project in a highly complex offshore carbonate field. The pilot was conducted in an offshore environment involving very long horizontal well and is first of its kind.
-
-
-
Hybrid Nanoparticle-Surfactant Stabilized Foams for CO2 Mobility Control at Elevated Salinities
Authors A. Soyke, B. Benali, T. Føyen and Z.P. AlcornSummaryA major problem during CO2 enhanced oil recovery (EOR) and CO2 storage is reservoir heterogeneity and the high mobility of CO2 relative to reservoir fluids. Surfactant-stabilized CO2 foams are a viable method for mitigating the impacts of reservoir heterogeneity and reducing CO2 mobility. However, surfactant-stabilized foams can breakdown at harsh reservoir conditions with elevated temperatures, salinities and pH. The addition of silica nanoparticles to the surfactant-stabilized CO2 foam has gained attention for increasing the foam strength and stability at harsh conditions. Therefore, this work includes nanoparticles in the surfactant-based CO2 foam to evaluate their ability to increase foam stability at harsh conditions. The primary objective was to systematically determine the effect of salinity on hybrid nanoparticle-surfactant, surfactant-, and nanoparticle-based foam generation and stability. We implement a multi-scale approach that spans from pore- to core-scale to investigate foam generation and stability with low and high salinity brines at reservoir conditions.
At the pore- and core-scale, unsteady-state CO2 injections were performed in porous media pre-saturated with the hybrid-, surfactant-, or nanoparticle-based foaming solution at low and high salinity. High-pressure silicon wafer micromodels enabled direct pore-level visualization of fluid dynamics and foam morphology with different the foaming solutions. Bubble density and size (foam texture) were compared and the results were used to corroborate core-scale measurements. Pore-scale results showed an increase in the number of bubbles by 20 to 27% for the hybrid solution, compared to the surfactant solution, indicating stronger foam. At the core-scale the hybrid foaming solution generated a weak foam of 5 cP whereas the surfactant-based solution generated a foam of nearly 20 cP. Increasing the salinity from 3.5 to 15 wt.% NaCl increased the number of bubbles by more than a 100% at pore-scale for both the surfactant and hybrid solutions. At the core-scale, apparent viscosity increased from 5 to 18 cP using surfactant solution. The generation of CO2 foam with and without nanoparticles delayed gas breakthrough by approximately 65% and improved water displacement which is advantageous for combined CO2 EOR and CO2 storage operations.
-
-
-
Adsorption/Retention of HPAM Polymer in Polymer Flooding Process: Effect of Molecular Weight, Concentration and Wettability
More LessSummaryOne of the major issues of polymer flooding in EOR is the loss of polymer material during injection due to retention/adsorption and even the formation damage because of other mechanical phenomena. So, operating companies usually look for minimizing this polymer loss.
To understand the retention of polymers in reservoir rocks, we carried out several core flood experimental studies by investigating the influence of rock nature and permeability (high and intermediate permeability considering Bentheimer and Berea sandstones), polymer molecular weight (low and high), and concentration of polymer solutions (from dilute to semi-dilute).
Under monophasic conditions and high permeability, we show that the polymer retention if corrected for inaccessible pore volume (IPV) depends on polymer concentration regime: retention increases rapidly with polymer concentration (Cp), in the dilute regime and increases then very weakly in the semi-dilute regime. Moreover, the use of low polymer weight results in a high material loss, and in case of high molecular weight and low permeability, plugging is evidenced.
Besides, diphasic tertiary experiments were performed under water-wet and intermediate wet conditions. The first set of experiments was performed on the native water-wet Bentehimer porous medium. The second set of experiments was performed by altering first the wettability of the same porous media, by submitting them to ageing in presence of crude oil.
Our results mainly show that the polymer retention decreases when the oil is present in the porous system due to additional inaccessible pore volume as the added volume is now occupied by residual oil. However, the retention is even smaller in intermediate wet porous media because the pore surface is partially filled by oil. A phenomenological explanation is proposed that supports such observed behaviors.
-
-
-
Polymer Screening to Enhance Oil Recovery at High Salinity/High Temperature Conditions; Rheology and Static Adsorption Studies
Authors M.S. Mousapour, M. Simjoo and M. ChahardowliSummaryThis paper aims to investigate the polymer screening for a clayey sandstone reservoir with a temperature of 80ºC having a high salinity formation brine. Ordinary HPAM does not tolerate this condition, and thus we considered three modified HPAM based polymers in our study, i.e., Polymer-A, polymer-B and polymer-C. Polymer solutions are prepared in a brine that was considered representative for see water. The rheology of the solutions was measured by a Paar rheometer. Moreover, the static adsorption tests for polymer solutions prepared in the makeup water were performed using reservoir rock sample through the bleach method. According to the rheology results, the viscosity of the solutions was a function of the polymer molecular weight (i.e. B>A>C). In addition, the viscosity of 2000 ppm polymer solutions at different temperatures ranging from subsea to reservoir condition (4º to 80ºC) was measured. At a shear rate of 10 1/s, the viscosity reduction due to the increase in temperature from 4º to 80º C was 35% for polymer C, while it was 48% for polymer B. Polymer C has the lowest molecular weight, and exhibited the lowest adsorption on the reservoir rock, e.g. 51% lower than polymer B (the highest adsorption value).
Results shows that the studied polymers could be considered proper candidates for core flooding studies, among the studied polymers, polymer-C can be considered the most proper one. However, it is necessary to investigate its long-term stability.
The results of this paper provide useful insight for other polymer flooding studies at HS/HT conditions.
-
-
-
Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in Sultanate of Oman
Authors R. Al-Jabri, R. Farajzadeh, A. Alkindi, R. Al-Mjeni, D. Rousseau, S. Renard, V. Miralles and E. DelamaideSummaryHeavy oil reservoirs remain challenging for surfactant-based EOR, particularly in selecting fine-tuned chemical formulations which exhibit high performances and are cost-effective. This paper reports a core-scale laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ∼500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage.
The coreflood tests performed involved various rock mineralogies and structures: Bentheimer sandstone as model analogues ; artificial sand and clays granular packs with representative mineralogical composition ; native reservoir rock plugs, to validate the injection strategy in fully representative conditions.
Under injection of “infinite” slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil.
These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.
-
-
-
Experimental Investigation on the Formation, Stability and Emulsification Mechanism of Polymeric Surfactants Emulsion in Porous Media
More LessSummaryPolymeric surfactants display brilliant capabilities in expanding sweep volume and improving oil displacement efficiency as compared with that of traditional displacing agents attributing to the co-existence of hydrophilic and hydrophobic groups in molecular chains. The displacement effect of emulsification and the difficulty of demulsification are the key factors affecting the application of polymeric surfactants. In order to study the formation, stability, and oil displacement ability of the polymeric surfactants emulsion in porous media, we took the newly synthesized anti high temperature and high salt polymeric surfactants as the research object to study the influence of different concentrations, different oil-polymer ratios, and different migration distances on the stability of polymeric surfactants emulsion. The generative mechanism of emulsified oil droplets with the polymeric surfactants and its relationship with EOR were then elucidated by comparing core flooding experiments with different injection rates, different saturated oil types, and different polymeric surfactants concentrations. The results showed that the main reasons for the formation of polymeric surfactant emulsions are a certain shearing action, the snapping action of hydrophobic microdomains on residual oil droplets and assisted effect of colloidal asphaltene. The longer the migration distance of polymeric surfactants in porous media, the larger the size of the emulsion and the weaker the stability. Contrary to the migration distance, the higher the ratio of oil to water and the concentration, the easier it is to produce the emulsion, and the smaller the particle size of the emulsion, the better the stability. The combination of dimensionless pressure gradient and capillary number as the characterization parameters of polymeric surfactants emulsion can effectively determine whether emulsification can occur during the polymeric surfactants displacement process. The results of this paper can provide some theoretical guidance for formulating the production plan of polymeric surfactants in offshore oil fields.
-
-
-
Successful Wettability Alteration Pilot in an Offshore Reservoir: Laboratory Analysis to Support Planning, Implementation and Interpretation
Authors N. Rohilla, A. Katiyar, P. Saxena, M. Pal, P. Rozowski and A. GentilucciSummaryWettability Alteration from oil-wet to water-wet condition is a very promising EOR technique for producing significant incremental oil recovery from oil-wet carbonate reservoirs. A thorough lab program led to the development of the wettability altering surfactant formulation for a giant offshore carbonate reservoir. The field implementation was done in a systematic step wise manner to mitigate the risk in implementing such a technology field wide. A long term surfactant injection pilot was then conducted to evaluate efficacy of developed solution at field scale. Post surfactant injection, a rigorous Monitoring and Surveillance program was put in place to carefully monitor production data and quantify incremental oil gains.
Surfactant injection was done in a continuous mode at 4,000 ppm active concentration in sea water for 7 months followed by sea water injection. Surfactant injection didn’t result in any injectivity loss or formation of any viscous emulsions in the reservoir. An injector where surfactant was injected (Injector-01) gained 8% yearly injectivity as a result of the surfactant injection. Incremental oil response was observed for both producer wells for the pattern. There was no surfactant breakthrough observed from produced water analysis till now.
-
-
-
Approximating Irreversible Asphaltene Adsorption to Screen IOR Candidates
Authors S. Hassan, S. Kamireddy, M. Yutkin, C. Radke and T. PatzekSummaryAfter drainage of brine-filled rock pores with an asphaltenic crude oil, the wettability state of a sandstone or limestone subjected to a high capillary pressure eventually changes from strongly water-wet to mixed-wet. A partial reversal of this mostly irreversible change of reservoir rock wettability is the condition necessary to increasing field-scale recovery of asphaltenic crudes.
In this work, we propose asphaltene molecule proxies that possess many asphaltene properties and satisfy reservoir adsorption conditions. We quantify the irreversible adsorption of these analogs with carboxylic, amino, or sulfate groups onto the silica using a quartz crystal microbalance with dissipation (QCM-D). We explore conditions for desorption of the irreversibly adsorbed analogs.
We use aqueous-soluble functionalized dextran polymers of variable chain length as asphaltene analogs. Adsorption was studied in brines with varying salts and pH. QCM-D results reveal that positively charged ammonia-functionalized poly-dextrans adsorb on silica irreversibly regardless of chain length and brine composition. However, sufficiently long chains and the presence of calcium ions are required for negatively charged sulfate- and carboxylate-modified poly-dextrans to adsorb irreversibly onto silica surface. Such a phenomenon is explained by calcium ion bridging of two negatively charged moieties. Experiment duration is found to be important for irreversible adsorption as well.
After the polymers have irreversibly adsorbed to silica, we attempt to desorb them by changing the brine composition. Desorption tests included combinations of 10, 100 and 300 mM of NaCl, KCl and CsCl. Preliminary results suggest that dextran polymers adsorbed via the bridging mechanism (i.e., sulfate- and carboxylate-modified) desorb using salt solutions with monovalent cations of potassium and cesium in obedience to the Hofmeister series. A similar result, but to a lesser extent, applies to ammonia-functionalized poly-dextrans yielding far less desorption.
In summary, positively charged amines adsorb irreversibly on the negatively charged silica surface. However, three factors are important to achieve irreversible adsorption of carboxylates and sulfates: a sufficient chain length, presence of calcium ions, and time. For monovalent cations, desorption efficiency seems to follow the Hofmeister series but to different extents depending on the adsorption mechanism.
-
-
-
Detailed Surfactant Model Construction Elucidates Benefits of Cross-Flow in Fluvial Heterogenous Surfactant-Polymer Pilot in Grimbeek
Authors V.S. Scordo Paes De Lima, G.F. Villarroel, V. Lara, F. Schein, A. Therisod, P. Guillen, V. Serrano, A. Ruiz, A. Lucero and J. JuriSummaryAfter an 18%STOOIP incremental oil polymer pilot we have developed the surfactant-polymer(SP) formulation to recover the residual oil. The SP formulation has a viscosity more than 1.5 times greater than oil viscosity. The Grimbeek reservoir is a heterogeneous multilayer fluvial system with many surfaces of contact between high permeability and low permeability.
Increasing oil recovery because of induced flow from low permeability to high permeability driven by a high viscosity slug has been around for more than 30 years. This phenomenon occurs when there is higher pressure drop across a viscous slug.
Does the cross-flow mechanism (Sorbie2019) that increased the polymer flow recovery benefit the surfactant-polymer flooding? How is this mechanism affected by factors such, removal of residual oil, surfactant concentration, slug size, salinity changed, retention and injection strategy? To answer these questions, we construct a detailed surfactant model in a compositional simulator that captures the multiscale nature of the multiple surfaces of contact created by the fluvial depositional environment. This realistic representation of the subsurface poses challenges to the numerical methods in the compositional simulator.
Through modelling the fluvial geometry in a compositional simulator, our simulation reveals that the viscosity overdesigned of the surfactant-polymer formulation favours accessing to more residual oil. Starting from a black oil model, the work was divided into four main tasks. First, converting the BlackOil PVT Model to a compositional model, followed by creating trajectories and perforations in an unstructured grid that brings complexities to the typical well-tracking task to place wells in corner point grids. Third, the compilation of the historical production of oil and gas as well as the water injected and polymer. We automate the input deck using visual basic and Python scripts that now are useful for any source file. Based on them, we can propose the most suitable injection strategy.
This result indicates that when the geological setting is heterogeneous is better to increase formulation viscosity (it depends on the formulation, but this usually means to increase surfactant concentration) and avoid the typical EOR workflow of formulation optimization to reduces surfactant concentration.
Our simulation elucidates the efficacy of increasing the formulation concentration to reduce the slug size. And It improves our understanding of the interplay between viscosity and capillary forces. Also, we developed different scripts that allow us to easily obtain the dataset for our compositional simulator.
-
-
-
Development of a Thermogel for the Treatment of Fractured Reservoir
Authors L. Hernando, N. Martin, A. Zaitoun, E. Read and O. BraunSummaryMany fields worldwide suffer of excessive water production and poor sweep efficiency because of conformance problems due to the existence of reservoir heterogeneities and preferential pathways for water flow. When heterogeneity contrasts are high, a permeability barrier has to be placed in water thief zones. In this paper, a new Conformance technology using thermo-associative polymers (TAPs) is presented. TAPs are polymers containing temperature-sensitive chemical moieties, called “LCST moieties” (“LCST” for “Lower Critical Solubility Temperature”). These moieties are totally hydrophilic at low temperatures and becomes hydrophobic above a threshold temperature. They can thus interact with each other, forming a three-dimensional network through hydrophobic associations. This process is thermo-reversible. By adjusting the amount of LCST moieties and the molecular weight of the polymer, strong viscosity contrasts may be obtained between low and high temperature (up to several decades). This strategy was used to develop a new family of conformance products called “thermogel” where a transition from a low viscous solution to a strong gel may be obtained upon heating. The paper presents the work performed to develop a Thermogel for a North Sea fractured chalk application. Since chalk matrix has a very low permeability (K∼1.5mD), strategy of production is to fracture and acid stimulate the formation along the well with water injection support. In this specific field case, one isolated fracture connects injection well to production well inducing a short cut between the wells. The aim of the pilot is to inject a Thermogel treatment to reduce water intake from the fracture. The paper describes the development of the product through laboratory experiments. The evaluation of the properties of different thermogels in bulk rheology and in coreflooding experiments are discussed in view of the pilot application. The main results can be listed as follows:
- – The new thermogel has a threshold temperature of around 40°C, that enables gelation far from the injection well, deep in the reservoir.
- – Coreflooding experiments in carbonate pack that mimic fracture permeability (K∼250D) have been performed. A minimum Thermogel concentration of 60 000ppm is necessary to form a gel with high blocking efficiency.
- – Injectivity in coreflooding experiments depends on Thermogel chemistry and on elasticity properties.
- – Strong face plugging when Thermogels are injected in pure matrix conditions (K=2mD) ensures that the product cannot propagate inside the matrix and will flow in fracture only.
From those laboratory results, two products have been qualified for further field applications.
-
-
-
Model for the Diffusion of N-alkane Confined in Nanopores: Effect of the Fluid/Pore-Wall Interaction
More LessSummaryAs one of the most important parameters describing the dynamic behavior of fluid, diffusion coefficient can be used to evaluate the mobility and viscosity. Under nanoconfinement, the diffusion behavior is quite different from that in bulk space because of the strengthened fluid/pore-wall interaction. In this work, the ‘extra energy barrier’ induced by fluid/wall interaction is emphasized, and the main factors affecting the diffusion behavior, including pore size, temperature, and pore geometry, are discussed. We find that the ‘extra energy barrier’ is significant at the first molecule layer and decreases rapidly within two layers, and when the distance from the wall is greater than 2.5 nm, the ‘extra energy barrier’ can be ignored. However, the temperature almost has no effect on the ‘extra energy barrier’. In addition, the diffusivity of shorter chain n-alkanes is higher than that of the longer ones due to the weaker fluid/wall interaction.
Besides, geometry of nanopores also has a great impact on the apparent diffusion, and it is easier for n-alkane molecules to transport in a slit nanopore than in a circular nanopore because of the curvature effect of the later ones. N-alkane molecules seem to stick to the wall when pore size reduces to 0.5 nm in a slit and 5nm in a circular pore. And when the size of slit and circular pore exceeds 500 nm and 5000 nm, respectively, the existence of the ‘extra energy barrier’ can be ignored and the apparent diffusion is quite similar to that of the macropores.
-
-
-
Pore Scale Observations of Wetting Alteration During Low Salinity Water Flooding Using X-Ray Micro-CT
Authors E. Andrews, A. Muggeridge, A. Jones and S. KrevorSummaryThis paper describes the first pore scale in-situ observations of wetting alteration on clays during tertiary low salinity flooding. Observations in the laboratory over a range of scales show that reducing the salinity of injected water can alter the wetting state of a rock, making it more water-wet. However, there remains a poor understanding of how this alteration impacts the distribution of fluids over the pore and pore network scale and how it leads to additional oil recovery. In this work, X-ray micro-CT scanning is used to image an unsteady state experiment of tertiary low salinity water flooding in a Berea sandstone core with an altered wettability due to exposure to crude oil. Oil was trapped heterogeneously, at a saturation of 0.62, after flooding with high salinity brine. Subsequent flooding with low salinity brine led to an oil production of three percentage points. To understand the mechanisms for this additional recovery, we characterise the wetting state of the sample using imagery of fluid-solid fractional wetting and fluid pore occupancy analysis. Pore occupancy analysis shows that there is a redistribution of oil from large pores to small pores during low salinity flooding. We observe a decrease in the solid surface area covered by the oil after low salinity flooding, consistent with a change to a less oil-wetting state. Pore by pore analysis of the mineral surface area covered by the oil shows that the wetting alteration during low salinity flooding is more significant on clays which likely control the behaviour. Whilst there was only three percentage points of additional recovery during low salinity flooding, the wetting alteration led to the redistribution of 22% of oil within the rock. The success of low salinity water flooding depends on a wetting alteration and oil mobilisation as well as a pore structure which can facilitate the production of the mobilised oil.
-
-
-
Monitoring subsurface temperature from radar scans using machine learning with applications to EOR using thermal injection
Authors K. Van den Doel, G. Stove and M. RobinsonSummaryTechnological advances and depletion of easily extracted oil reserves have led to the development of enhanced oil recovery (EOR) methods that allow significantly more oil to be extracted from a reservoir. An increasingly commonly used technique uses thermal injection, which requires a good knowledge of the subsurface thermal conditions.
Temperature observation wells (TOW) are used to measure subsurface temperature profiles, an expensive and invasive process.
We present a noninvasive method for the remote monitoring of subsurface temperature using low frequency radar pulses. Radar surveys were performed at 40 locations near TOWs in an oilfield and returns were correlated, after signal processing to extract the modulation, with measured down hole temperatures by machine learning techniques. The TOW temperature logs were fed to an autoencoder/decoder network, compressing the data to 3–5 neural activations. A feedforward neural network was then trained on the outputs of the autoencoder to predict the activations from the radar data and finally converted into actual temperature logs using the decoder.
The results were evaluated by excluding one of the 40 data sets from training and use the remaining data sets to predict the excluded site, resulting in 40 blind tests. We believe results are encouraging, though not yet fully reliable and we discuss further avenues for improvements.
-
-
-
A Predictive Approach for Condensate Blockage Risk Evaluation with Limited Data Availability
More LessSummaryCondensate blockage is a major risk in gas-condensate field development. In the investigated field, the initial reservoir pressure is close to the dew point, leading to condensate dropout and banking from the very beginning. The uncertainty in condensate blockage in the absence of reliable SCAL measurements is considered one of the main challenges. In this work, two approaches were presented to approximate gas-condensate relative permeabilities including high-velocity flow effects. Furthermore, condensate blockage mitigation methods are evaluated.
The first investigated method is that of Whitson, based on the relation krg=f(krg/kro) in which PVT data and analog coreflood experimental data were used to generate relative permeabilities, also including a model for the capillary number effect. In the second method, a digital rocks SCAL analysis, based on Lattice Boltzmann two-phase flow simulation on a microscale 3D scan of remnants of sidewall core plugs, was used to simulate the relative permeabilities at low to high capillary numbers. For implementation of the curves in the dynamic simulation, the model by Henderson was used.
The estimated relative permeability curves for different rock types were used directly in reservoir simulation to evaluate the risk of condensate blockage. In both methods, the effects of high velocity and non-Darcy flow were considered. The simulation results show that the designed gas plateau production rate cannot be maintained even for a few months. However, in an artificial single-phase gas flow case in which the presence of condensate is not influencing the gas flow, the gas plateau production could be sustained up to four years. As a result, the field needs to be produced three to four years longer to reach the same recovery factor, and thus significantly less return on investment is expected.
Comparing both generated relative permeability curves, it is remarkable that the immiscible relative permeability curves (at lower capillary numbers) do not differ significantly from each other, despite the fact that neither of them is based on conventional SCAL experiments. Furthermore, a gas cycling scenario, well placement optimization, and a near wellbore treatment with wettability altering surfactants were analyzed in numerical simulations with promising preliminary results to mitigate condensate banking. The risk of condensate blockage for a real case scenario in the absence of reliable SCAL measurements, by adapting and comparing two approaches to approximate relative permeability curves including high-velocity flow effects, was evaluated and numerically analyzed in the present work.
-
-
-
Analysis of Density, Viscosity and CO2 Solubility in the Water-Oil-CO2 System for CO2-WAG Simulation
Authors L. Bastos, M.O. Rios, G.M.N. Costa and S.A.B. Vieira de MeloSummaryCO2 injection has been considered as an advantageous method for improved oil recovery (IOR) in terms of increasing the oil recovery factor as well as for carbon storage due to environmental issues. Water alternating CO2 injection (CO2-WAG) has recently been evaluated to improve the sweep efficiency and promote CO2 mobility control, but further studies are needed for a better understanding. In this study, a comparative evaluation of different methods was done to calculate the density, viscosity and solubility of CO2 in aqueous and oily phases, for CO2-water, CO2-oil and CO2-water-oil systems. In addition, the behavior of these properties was analyzed through CO2-WAG simulations. The results indicated high accuracy of the semi-empirical correlation proposed to calculate CO2 solubility in water, with an average deviation of 4.17%. For the aqueous phase density, an average deviation of 0.25% was obtained. The effects of swelling and extraction of light components on the oil properties along the flow due to the presence of CO2 in the system were also observed. The analysis of CO2-water-oil system, relating to the CO2-WAG injection, shows that the CO2 solubility is much higher in the oil phase than in the aqueous phase. However, according to preliminary results, the CO2 solubility in water also affects the oil recovery factor (around 5%) during CO2-WAG simulation.
-
-
-
New Correlations to Calculate the CO2-Oil Interfacial Tension Including the Asphaltene Precipitation Effect
Authors I.E. Lins, P.H.A. Dantas, G.M.N. Costa and S.A.B. Vieira de MeloSummaryCOi-based Enhanced Oil Recovery (CO2 EOR) methods have been widely applied and studied in the recent years due to their capability to increase the reservoir recovery factor, as well as an alternative for carbon capture and storage. For instance, CO2 EOR projects have been extensively employed in the Brazilian Pre-Salt reservoirs to take advantage of the high CO2 content in the associated gas. However, CO2-oil interfacial tension (IFT) strongly affects the performance of CO2 EOR processes because the major mechanisms of CO2 injection depend on oil swelling and viscosity, which govern the capillary number and the oil displacement in the porous media. Thus, an accurate modeling of the CO2-oil IFT is required to reach reliable numerical reservoir simulations of CO2 EOR methods. For this reason, this work used CO2-oil IFT and oil characterization data from the literature over pressures up to 55.15 MPa and temperatures from 40 to 70°C – typical conditions of Pre-Salt reservoirs – to develop empirical equations for the CO2-oil IFT prediction. First, new equations to calculate IFT as a function of pressure and CO2 solubility in oil, for dead oils. Afterwards, a sensitivity analysis was performed to evaluate the factors that most affect IFT for live and dead oils, such as pressure, temperature, and oil molecular weight and density. Subsequently, correlations for IFT prediction as a function of the three most relevant factors were proposed. The new equations were validated with additional experimental data from the literature. They are able to predict the CO2-oil IFT under Pre-Salt conditions with high accuracy, providing an absolute average deviation of 6.28% for dead oils and 8.34% for live oils, which are much more accurate than the Parachor model – usually chosen in the numerical reservoir simulators –, which yields 23.38% and 49.69%, respectively. Emphasis should be given to the applicability of the new proposed correlations to calculate IFT in numerical reservoir simulation, once they require low computational efforts, contrasting the overcomplexity of other recently developed equations, which are unfeasible for simulations purpose. Finally, an unprecedented procedure was proposed to examine the effect of the precipitated asphaltenes on the CO2-oil IFT, relating it to the Asphaltene Onset Pressure (AOP) curve. The results are presented with Figures and Tables and properly discussed.
-
-
-
Upscaling Miscible CO2 EOR Processes: Characterisation of Physical Instabilities
Authors P. Ogbeiwi and K. StephenSummaryObjectives/Scope:
An approach for upscaling of miscible displacements is presented which adequately represents physical instabilities such as viscous and heterogeneity induced fingering on coarser grids using pseudoisation techniques is presented. The approach has been applied to compositional numerical simulations of two-dimensional and three-dimensional reservoir models with a focus on CO2 injection.
Methods:
The approach is based on the pseudoisation of relative permeability and the application of transport coefficients to upscale viscous and heterogeneity induced fingering in a multi-contact miscible CO2 injection in a black oil- water system. Fine-gridded compositional simulations of 2D cross-sectional and 3D reservoir models were performed for calibration purposes. The cases considered included a homogeneous 2D model and heterogeneous 2D and 3D models.
The effects of transmissibility schemes on the performance of the fine-grid 3D miscible displacement process was quantified by considering the minimisation of grid orientation errors by each scheme. The permeability and porosity distribution of the 3D model were extracted from a quarter five-spot of the SPE 10th comparative project. Pseudo-relative permeability curves were computed using various pseudoisation techniques and these were applied in combination with transport coefficients which account for small-scale variations in phase composition and behaviour to upscale the fine-grid simulations to coarser scales. Results and Conclusions:
We upscale the fine grid compositional 2D and 3D reservoir models to coarser grid compositional flows. In the fine-grid homogeneous and heterogeneous 2D models, four fingering regimes were observed which we link to very-early time, early time, intermediate time, and late time regimes. These regimes occur both near and far away from the injection well. Our results show that fingering behaviour is adequately captured and represented in the upscaled coarse grids.
In the 3D model, a nine-point transmissibility weighting was required to adequately reduce grid orientation effects and was thus employed in the upscaling procedure of the 3D models. The robustness of the upscaled models was assessed by comparing the total volume of fluid produced versus pore volume of fluid injected, and the saturation profiles and history of the upscaled models with those of the fine-grid simulation. The accuracy of the results of the pseudoisation procedures was assessed by applying statistical analysis to compare them to the results of the fine-grid simulations. The results show that the coarse models provide accurate predictions of the miscible displacement process and that the fingering regimes are adequately captured in the coarse models.
-
-
-
Specificities of surfactant-polymer flooding modeling and its role in the technology implementation at the Tatneft plays
Authors L. Minikhairov, A. Lutfullin and A. GaifullinSummaryPJSC Tatneft has significant experience in the mature oil fields development and the application of various “local” low-volume technologies for increasing oil recovery, flow deviation and conformance control. Currently, in the context of residual recoverable reserves decrease, one of the main tasks of the company is to test and replicate technologies aimed at increasing the ultimate oil recovery factor. One of the optimal technologies that can solve the current problem is surfactant-polymer flooding technology, which is chosen due to high levels of formation water salinity, which greatly restricts the use of alkaline compositions and decrease the effectiveness of polymer flooding. A distinctive feature of this technology from those currently available in the company is the injection volumes (more than 10% of the pore volume) and a significant increase in the final oil recovery factor of the oil field. Considering the capital intensity and the importance of the project for the organization of surfactant-polymer flooding, PJSC Tatneft pay great attention to high-quality preparatory work, including laboratory filtration studies, the results of which were then used during the reservoir modeling of the process to form the most reliable feasibility study of the technology. This paper will highlight the features of the preparatory work, the applicability of their results in reservoir modeling, the assessment of various options for implementing the technology, the results of forecast scenarios and the role of the obtained calculations in the feasibility study of the technology implementation. To assess the correctness of setting the properties of the surfactant-polymer composition in the reservoir model, a core model was built, which was used to simulate laboratory filtration studies. There were built more than 150 forecast scenarios for the surfactant-polymer composition injection, differing in the size of the injected pore volume, surfactant and polymer concentrations, as well as the sequence of surfactant and polymer injection.
-
-
-
Advanced Surfactant-Polymer EOR Pilot in Algyő Field, Hungary; Experiences and Lessons Learned
Authors S. Puskás, T. Ördög, M. Törő, G. Kálmán, R. Nagy, L. Bartha, Á. Vágó, J. Dudás, I. Dékány, R. Tabajdi, I. Lakatos and G. SzentesSummaryExtensive R&D activity provided reliable basis for testing a reservoir-specific surfactant-polymer mixture as EOR flooding pilot performed in the largest multi-layered (stacked) hydrocarbon occurrence at the Algyö field. The target formation was a sandstone reservoir with 70 mD permeability on average bearing low viscosity oil (0.64 cP at 98 °C and 190 bar).
The injected SP solution contained a specific surfactant blend developed by MOL and his Hungarian university partners, and a mobility controlling agent was a commercial copolymer of acrylamide and ATBS. For the preparation of the SP solution, after additional filtration, formation water was used at the site. During the pilot period, altogether 1/3 pore volume of SP solution was injected into the reservoir.
The surfactant/polymer solution was injected into two injection wells starting from April 2016 and was intended to finish in 2019, after 45 months of continuous injection period. The injection was started with 100 m3/day/well flow rate of chemical mixture, containing 15,000 ppm surfactant and 1,000 ppm polymer driven into the reservoir using injection well head pressure of 0 bar. Most important parameters and effects of the pilot were continuously recorded and evaluating the reservoir response as a function of the injected volume including both injection and production wells (seven oil wells were operating around the two injection wells). It should be noted that due to the high heterogeneity of the reservoir, a fine tuning of the injection plan supported the technology through the whole frame of the pilot. The successful upscaling of the surfactant manufacturing and the easily available raw materials provided a problem-free supply of surfactant with standard quality. Various laboratory measurements were performed to control the polymer and surfactant concentration as well as the rheological and interfacial properties of injected SP solution. In addition one of the main advantage of the EOR method was that the produced emulsion could be easily broken into bulk fluids.
This paper summarizes the workflow and results of the pilot performed in the past four years. The results of this pilot provided reliable information and adequate basis to start a new project of similar field-scale chemical EOR technology for other blocks, hoping that it will further increase the recovery factor in the Algyö-2 reservoir and yielding substantial incremental oil production in matured, depleted fields in the coming years.
-
-
-
Role of Water Chemistry on the Adsorption Behavior of a Saponin-based Biosurfactant on the Sandstone Surface
Authors J. Amanabadi, M. Simjoo and M.S. MousapourSummaryBiosurfactants have been received more attention in oil recovery due to their low-cost and environmental friendly characteristics. In this study, we investigated adsorption behavior of a saponin-based biosurfactant named SUTBS which was extracted from the leaves of one of the Iranian plants growing in the southern part of the country. To this end, adsorption analysis of the SUTBS solution was performed on a clayey sandstone surface in the presence of different seawater solutions under high temperature that represents reservoir conditions. Role of water chemistry on the surfactant adsorption was addressed by changing the composition of seawater (SW) through tuning ionic strength and also manipulation of divalent ions. Adsorption analysis was then performed by contacting surfactant solution with the rock powder at 80 °C while tracking surfactant concentration using UV-spectrophotometer. Results showed that surfactant adsorption in the presence of SW brine increases with surfactant concentration up to 1500 ppm and beyond that it levels off to a plateau value that represents a Langmuir-type isotherm. In order to explore the effect of ionic strength, surfactant solutions were prepared by SW brine and its different dilution (0.5SW and 0.1SW). As to results, a lower surfactant adsorption was observed for diluted brines such that at surfactant concentration of 1500 ppm surfactant adsorption in the presence of 0.1SW was almost half of the SW brine. To check the role of aqueous ions on the adsorption behavior, a brine solution without any divalent ions was synthesized while keeping ionic strength equal to the SW brine only by adjusting NaCl concentration. It was found that removing divalent ions from brine solution caused a reduction in the surfactant adsorption level by 35%. Finally, to get further insights into the role of divalent ions (Mg2+, Ca2+ and SO42-), three SW brines were prepared such that in each solution only one of the divalent ions became present and the two other ones were excluded. Ionic strength of all these solutions was kept constant by adjusting NaCl concentration. As to results, adsorption level in the presence of sulphate-rich brine decreased as compared to the native SW brine. However, a higher adsorption level was observed for the case of divalent cation-rich brines. These observations could be discussed in terms of physicochemical interactions among aqueous ions/surfactant molecules/rock minerals. Findings from this study shed light on the importance of water chemistry to design an appropriate surfactant flooding.
-
-
-
Initiation of a surfactant-polymer flooding project at PJSC Tatneft: from laboratory studies to test injection.
Authors M. Toro, M. Khisametdinov, D. Nuriev, A. Lutfullin, A. Daminov, A. Gaifullin, S. Puskas and T. OrdogSummaryPJSC Tatneft develop oil fields in the Republic of Tatarstan, mainly belonging to the category of mature, which leads to the systematic application of various enhanced oil recovery technologies for stimulating the formation, using gel, emulsion and other chemical compositions. Despite the high water cut, at a number of Tatneft plays there are favorable and and potential economic profitable conditions for the implementation of large chemical flooding projects, for example, using surfactant-polymer flooding technology. The choice of surfactant-polymer composition is generally due to high level of formation water salinity, which severely limits the use of alkaline compositions and reduces the effectiveness of polymer flooding. The initiation of the surfactant-polymer flooding project was conducted through several main stages: the development of primary criteria for the optimal areas selection for the technology application, the primary areas selection and a detailed description of their geological and physical conditions, laboratory studies on the selection of composition components that provide the highest level of oil displacement efficiency, in conditions close to reservoir, performing a test injection of the composition at a potential site of application, analyzing the results and adjusting the chemical composition and obtaining initial data for conducting reservoir modeling of pilot project. Laboratory studies were conducted according to accepted programs for studying the compatibility of chemical agents with injected and formation waters, studying the properties of surfactants, for example, interfacial tension and adsorption, the rheological behavior of polymer solutions depending on the concentration and shear rate, studying the properties of surfactant-polymer compositions and conducting filtration studies. All laboratory filtration studies were conducted using oil from the test injection site on the cores of 50 cm length. The data obtained during laboratory studies were used to conduct reservoir modeling of the pilot surfactant-polymer flooding and to form a feasibility study for testing and replicating the technology.
-
-
-
Upscaling Simulations of 3D Displacement Processes that Include Change of Wettability using Analytically Derived Relative Permeability
Authors H. Al-Ibadi, K.D. Stephen and E. MackaySummaryWe introduce an upscaling method that can be used to improve the accuracy of forecasts of EOR processes that involve changes to fluid mobility either by modifying wettability and interfacial tension as in surfactant flooding, alkaline flooding and low salinity water flooding, or by increasing the injectant viscosity as in polymer flooding. The suggested upscaling method is designed to solve the two numerical artefacts associated with discretization of these processes which include well know dispersion effects as well as more recently reported pulses. Simulations involving changes to wettability or interfacial tension usually require two sets of input relative permeability curves. In this newly derived upscaling method, we show how to develop a single set of pseudorelative permeability curves for coarse scale models to represent fine scale behaviour. The shape of the derived properties is based on the analytical solution of the fractional flow theory of chemical flooding. Using this analysis, we are able to build a pseudo relative permeability that honours the correct velocity of the formation and chemical waterfronts with an appropriate oil banking interval. It also ensures the sharpness of the shock fronts. We derived a single set of relative permeability curves, avoiding numerically based pulses. We built pseudo-relative permeability curves that includes the impact of effective concentration range and physical dispersion induced by geological heterogeneity.
The numerical results of the upscaled models were compared against the fine scale models. We analysed the flow behaviour in 1D homogenous models and 2D models of communicating and non-communicating layers. We also analysed flow in 2D and 3D models of correlated random permeability. Our method is shown to work for all of these cases. However, for unfavourable displacement in strongly heterogenous models of correlated random permeability, some tuning was required due to significant fingering effects. Secondary and tertiary flooding were considered in the analysis.
This novel upscaling method was able to control the artefacts of numerical pulses and dispersion. It also simplified the complex modelling of these processes, improving the upscaling step and decoupling the representation of solutes. We reduced the requirement for relative permeability curves to one set, and removed the need to simulate solutes such as polymers and salinity. This means that simplified fast simulations of oil displacement can be run.
-
-
-
Analytical and Numerical Analysis of EOR process in Stratified Reservoirs
Authors H. Al-Ibadi, K. Stephen and E. MackaySummaryWe develop analytical tools to predict the flow behaviour and solute transport during advanced EOR processes in stratified models as an extension to simpler waterflood models based on fractional flow theory. We also derive an extended set of dimensionless numbers that are particularly designed to quantify the flow behaviour in EOR processes. These analyses are essential for upscaling and improve the accuracy of predictions. We consider EOR flow conditions in which layered models are affected by retardation and dispersion of flow and include variations in wettability and relative permeability as well as other petrophysical properties. We developed our analysis using the principles of the fractional flow theory, applied to EOR processes. A revised model corrects for the effects of numerical and physical dispersion. By grouping and rearranging the derived formulae, we obtain dimensionless numbers and scaling groups to evaluate the effect of various scenarios of properties contrast between layers. We investigated the impact of various parameters on the recovery factor and the water cut from the production data. The scaling groups can be utilized to identify properties of the model that should be changed so we can reproduce flow behaviour from small scale (e.g. core scale) to larger scale (e.g. reservoir scale). The new analytical model was validated against numerical solution of low salinity waterflooding with varying degrees of heterogeneity and mobility ratio, where a very good match was obtained.
These analytical tools enable us to obtain ultra-fast predictions complex flow during EOR processes without a need to run a numerical simulator and with better accuracy. The approach can potentially be applied in streamline simulators and used as flow diagnostics to improve analysis of EOR methods where retardation and dispersion occur.
-
-
-
An Experimental Study of Steam-Solvent Coinjection for Bitumen Recovery Using a Large-Scale Physical Model
Authors K. Sheng, R. Okuno, M. Imran, P. Nakutnyy and K. NakagawaSummaryThis paper presents a detailed investigation into compositional flow in solvent-assisted steam-assisted gravity drainage (SA-SAGD) with multicomponent hydrocarbon solvent “condensate”, which is readily available near thermal operation sites. Designing SA-SAGD with condensate requires understanding the complex interplay between phase behavior and fluid flow that affects bitumen production and solvent recovery.
This research consisted of three stages. First, an SA-SAGD experiment was performed using a cylindrical physical model with an inner diameter of 0.45 m and a length of 1.2 m. Steam and synthetic condensate (2.7 mol%) were coinjected at 3500 kPa. Second, the experimental data were history-matched by using a numerical model, and the resulting model was analyzed for the detailed analysis of solvent flow behavior. Third, observations of compositional details in the SA-SAGD experiment were further investigated with a simulation case study using stochastic realizations of a 3-D heterogeneous reservoir. We present a novel way of analyzing how much of the injected solvent was used for in-situ bitumen dilution beyond the edge of an SA-SAGD chamber, which is referred to as “utilization factor” in this paper. Solvent utilization factor is related to, but different from solvent recovery factor because different components have different volatilities in the coinjected condensate.
SA-SAGD experimental results showed that the produced condensate was heavier than the injected. Material balance analysis showed that the in-situ condensate composition for bitumen dilution was similar to the injected condensate composition, but the volatile components (C1 and C4) had lower recovery factors. The simulation case study for an upscaled 3-D heterogeneous reservoir confirmed that a large fraction of the volatile solvents in the condensate was used for in-situ bitumen dilution. The solvent recovery factor that has been used as an economic indicator for SA-SAGD does not represent how much of the injected solvent is used for in-situ bitumen dilution.
-
-
-
Generalized Analytical Solutions for Shale Gas Production in Compressible Porous Media Including a New Scaling Time
More LessSummaryShale gas has been established as a key energy source over the last decades. Tight permeability, non-Darcy flow mechanisms, adsorption and compressibility make shale gas formations more challenging to model than conventional reservoirs. The aim of this work is to present analytical solutions overcoming those challenges.
We model shale gas production from a 1D porous medium, where a well or fracture with constant pressure is assumed at one side and a noflow boundary at the other (e.g. due to symmetric geometry between multiple fractures). The system is depleted accordingly. Gas is stored as mobile phase in the pores and adsorbed phase on the matrix surface as modeled by a Langmuir isotherm. The gas and rock are both compressible; when pressure is reduced, gas expands (according to a real gas equation of state), while porosity is reduced. The porosity reduction reduces intrinsic permeability. Non-Darcy flow, which is important for shale gas flow in tight porous media, is accounted for via apparent permeability depending on the Knudsen number.
The partial differential equation describing this system can be formulated as a nonlinear diffusion equation in terms of the conserved property of mass per bulk volume of free and adsorbed gas. The well pressure boundary condition corresponds to a fixed value of as boundary condition. Similarly a uniform initial pressure corresponds to a uniform initial . This system is comparable to the form described by McWhorter and Sunada (1990) for spontaneous imbibition where they derived universal analytical solutions regardless of the shape of the diffusion coefficient which could depend arbitrarily as function of the conserved property, in their case fluid saturation. Analytical solutions are thus obtained that can give spatial profiles, at given times, of pressure, adsorption, porosity and apparent permeability, in addition to time profiles of gas recovery. In accordance with the analytical solution, it is shown that gas recovery follows a square root of time profile at early times before the no-flow boundary is encountered. Late time behavior and validation is investigated using numerical solutions. We further adapt the work by Schmid and Geiger (2012) who suggested a time scale for the analytical solution during spontaneous imbibition. Adapted to our case, a similar scaled time results in the same depleted fraction of recoverable mass under the given pressure conditions and scaling different cases results in full overlap of recovery profiles at early time, typically to obtainable recoveries of 35–50%.
The late time behavior profiles deviate as individual cases may leave the square root profile at different recovery values and with different trends vs time.
The role of system length, adsorption isotherm, rock compressibility, porosity-permeability relations and non-Darcy effects are examined to see how they contribute to increase or reduce production rate and time scale, affect profile shapes and the amount produced when the no-flow boundary is met.
To our knowledge, no analytical solution yet exists for shale gas production which is able to account for either nonlinear adsorption, non-Darcy flow, compressible porous media or permeability reduction.
Keywords: shale gas production; compressible low permeable porous media; non-Darcy flow; generalized time scale; analytical solutions.
-
-
-
Theoretical Comparison of Two Setups for Capillary Pressure Measurement by Centrifuge
Authors J. Abbasi and P.Ø. AndersenSummaryCapillary pressure is routinely measured using a centrifuge setup where capillary forces retain a heavy, wetting phase (e.g. water) and keep a light, non-wetting phase from entering. By increasing the rotational speed of the centrifuge, the density difference of the phases forces the heavy fluid out, while the light fluid can enter. In this work, we consider and compare the behaviour of two centrifuge setups: In the first setup the core face closest to the rotation axis is open to non-wetting phase, while the core face farthest from the rotation axis is open to wetting phase; labelled Two-Ends-Open, TEO. At increased rotation, this setup generates strictly co-current flow of both phases from the inner towards the outer radius. In the second setup, only the outer radius surface is open and is exposed to the light non-wetting phase; labelled One-End-Open, OEO. All other core faces are closed. At increased rotational speed the wetting phase is forced out the open face and non-wetting phase must flow in opposite direction through the same phase. This setup induces strictly counter-current flow. The two systems are formulated mathematically and solved by implicit pressure and explicit saturation (IMPES) numerical discretization. The standard co-current setup is validated by comparison with commercial software. Experimental data from the literature are used to parameterize the models.
It is mathematically, and with examples, demonstrated that the same equilibrium is obtained in both systems with the same rotational speed. This equilibrium, as represented by saturation and capillary pressure distributions, is only dependent on the rotational speed, capillary pressure curve, fluid densities and system geometry, not the relative permeabilities or fluid viscosities. The difference in flow regimes and transient data can be used to obtain better estimates of the relative permeabilities, which previously would need independent measurements using time consuming core flooding tests. It is observed that the counter-current setup has longer corresponding equilibration time scales than the co-current setup under otherwise identical conditions. For saturation function measurement it is still quick relative to comparable techniques.
By performing these tests in parallel, a significant difference in flow regimes and thus different dependence on saturation intervals makes it possible to better match relative permeabilities in addition to the capillary pressure. Greater intervals of the functions can be determined with greater accuracy. Measurement of flow regime dependent relative permeabilities can be captured by an expansion of the model.
-
-
-
Pushing Oil Recovery Technical Limits For Liquids-Rich Shales
Authors M.R. Fassihi and A. KovscekSummaryEven with the great advancements in hydraulic fracturing and shale well completions, the current recovery factor for liquid-rich shale is about 5% whereas that for gas-rich shale is about 25%. This indicates that the full potential of unconventional resources has not yet been realized. The large initial production rate followed by a rapid decline makes the unconventional industry heavily dependent on continuous drilling and completion. With the areas available for further drilling shrinking, there is a need to revive and sustain production in existing shale wells. Hence, this paper discusses the fundamentals of EOR application in unconventional reservoirs. Through a review of existing field tests, and the knowledge base of EOR mechanisms in shale, guidelines are provided for successful EOR application in liquid-rich shales. Shale resource characterization is fundamental to any future application of EOR. Thus, advancement in this area is emphasized including core-scale studies, discrete fracture network modeling, and simulation with coupled flow and geomechanics. Results from application of chemical blends, gas injection huff-n-puff, and new hybrid methods are discussed. It is shown that EOR as a drive process is very inefficient in shale and requires the presence of a natural/complex fracture system. It is indicated that gas injection Huff-n-Puff could increase the primary recovery by an additional 50%. On the other hand, chemical blends could provide up to 20% increased recovery due to wettability alteration. Hybrid methods combining chemical blends with the hydraulic fluids and gas injection Huff-n-Puff do provide additional uplift in oil recovery. Through a review of the field results, this paper provides new screening criteria for application of EOR to liquids-rich shale
-
-
-
Potential of Foam Enhanced Oil Recovery Process for a Strongly Oil-Wet and Heterogeneous Carbonate Reservoir
Authors L. Ding, S. Jouenne, O. Gharbi, M. Pal, H. Bertin, M.A. Rahman, C. Romero and D. GuerillotSummaryThe feasibility of foam enhanced oil recovery (EOR) for a heterogeneous carbonate reservoir in the Middle East with medium temperature (55°C) and high formation salinity (above 16% TDS) is presented here.
The promising surfactant formulations were firstly evaluated based on solubility tests and bulk foam tests. Afterwards, a series of core flooding experiments both in the absence and in the presence of crude oil were performed on Estaillades Limestone, a heterogeneous carbonate presenting reasonable similarities with the actual formation. In these foam tests, the influence of foam quality, injection velocity and surfactant concentration on foam strength and incremental oil recovery were investigated. Then, the lab results were reproduced by numerical simulation using a commercial reservoir simulator, where the model parameters were obtained after history matching. Finally, a synthetic 2D heterogeneous model was established to investigate how foam can assist in improving oil recovery for a stratified heterogeneous reservoir.
An Alkyl Poly-Glycoside (APG) surfactant was firstly selected based on its prominent foamability and foam stability from bulk foam tests. The optimal foam quality is found to be around 70% from foam quality scan tests in the absence of crude oil. Moreover, foam still can be generated under strongly oil-wet conditions, and it is observed that the presence of oil and surfactant concentration have negligible effects on the optimal foam quality. However, the foam strength in high quality scheme is largely dependent on the surfactant concentrations. More than 20% OOIP of the water flooded residual oil was recovered after co-injecting 5.0 total pore volume (TPV) of nitrogen and 0.5 wt.% APG surfactant (in synthetic seawater brine) at 70% foam quality (4 ft./d). The numerical simulation results indicate that the permeability effect on foam strength and foam stability need to be considered in order to accurately model the foam behavior in heterogeneous reservoirs.
In this presentation, the foam dry-out, shear thinning, surfactant concentration, permeability and oil saturation effects on foam transport in a heterogeneous carbonate were systematically investigated. The results of this study demonstrated the feasibility of foam EOR for a strongly oil-wet and heterogeneous carbonate reservoir with medium temperature and high formation salinity.
-
-
-
Keynote: Comparing Benefits of CO2 storage and CO@EOR from a Climate Mitigation Perspective
Authors P. Ringrose, B. Nazarian and A.M. ZadehSummaryOver the coming decades our society has a significant challenge in achieving globally significant reductions in greenhouse gas emissions. Numerous studies show that large-scale geologic disposal of CO2 from industrial emissions will be essential to achieve this objective. There are currently 21 large-scale CCS facilities in operation. Of these large-scale CCS projects, five use geologic storage in saline formations (Sleipner, Snehvit, Quest, IBDP & Gorgon) and together inject nearly 6 million tonnes CO2 per annum (Mtpa). The remaining large-scale projects mainly use CO2EOR as the storage vehicle. Enhanced oil recovery using carbon dioxide (CO2EOR) can have a dual purpose: (a) To recover additional oil, thereby supplying energy and additional revenues; and (b) to mitigate climate change by reducing anthropogenic CO2 emissions.
Historically, CO2EOR projects have tended to maximize oil production as a function of the CO2 injected. There are various options proposed to enhance the climate mitigation effect of CO2EOR projects by maximizing the ratio of the CO2 injected to the oil produced, or by transiting projects from CO2EOR in the initial stages to pure storage projects in the later stages. However, to achieve net zero-emissions, CO2EOR projects need to include a significant fraction of non-EOR CO2 storage. CO2EOR projects also play an important role in building the infrastructure needed for large-scale carbon capture, utilisation, and storage. We illustrate these potential pathways using examples of large CCUS/CCS projects, both from offshore Norway and onshore Canada.
-