IOR+ 2023

40% to 50% STOIIPs remain in the subsurface after polymer flood, characterized by highly scattered remaining oil distribution. Currently, most discussed measures regarding post-polymer flood Chemical Enhanced Oil Recovery (CEOR) are in lab study or by reservoir simulation. However, some more advanced efforts have been made to produce the remaining oil after the primary polymer flood.

Based on 11 established pilot or field-wide test projects, this paper presents key results of post-polymer flood (i.e., Quaternary) recovery through CEORs. These cases of Quaternary Recovery involve various CEOR methods, including polymer flood, Surfactant Polymer (SP) flood, new agent type of polymeric surfactant flood, Alkaline Surfactant Polymer (ASP) flood and heterogeneous phase combination SP plus Pre-formed Particle Gel (SP + PPG) flood. The above quaternary CEORs have been implemented on three main types of sandstone reservoirs, e. g., medium viscosity reservoir (Type I); high permeability, viscous reservoir (Type II); and high permeability, high salinity, unconsolidated reservoir (Type III).

A variety of CEORs, such as high concentration polymer flood, polymeric surfactant flood and ASP flood applied to Type I reservoir achieved incremental recovery from 8% to 10.1% and ultimate recovery of 60%–70%. High concentration, large bank-size polymer solution flood implemented in Type II reservoir obtained incremental recovery from 7.9% to 10.3%. SP or SP + PPG flood conducted in Type III reservoir resulted in incremental recovery from 7.6% to 9.7%. During Quaternary Recovery process, primary CEOR well patterns were modified with the injection-to-production distance being reduced from 250 m to 125–175 m, to maximize sweeping the fractional flow remaining oil.

Compared with primary CEOR, high concentration, high MW polymer and large slug size were adopted in Quaternary CEORs. However, incremental recovery is similar or less than that of the primary polymer flood and maximum water-cut drops are typically 6% to 10% compared with 10% to 20% of the primary polymer flood, indicating a larger agent utilization per barrel oil incremental. Technically, the above Quaternary Recovery technologies are successful. The success of their field-wide applications, however, depend on specific economic conditions. For Type I reservoir, ASP flood achieved the highest incremental recovery, while polymetric surfactant flood proved to be more feasible economically. High concentration polymer flood works for Type II reservoir but need to promote its economic feasibility by optimizing agent and improving reservoir management. SP + PPG flood is the most promising technology for Type III reservoir Quaternary Recovery.

Low Salinity Modified Water (LSMW) injection is considered as promising advanced water based Enhanced Oil Recovery (EOR) technique. Understanding the mechanism of modified water injection and its impact is complex due to several chemical liquid-solid interactions. This work presents an experimental study to better investigate the effects of Low Salinity Modified Water injection on oil recovery by in situ monitoring of fluid displacement relying on 3D X-Ray CT imaging.

In this paper, we report the results of sets of advanced core-flooding experiments carried out on outcrop and reservoir sandstone plugs to study the effect of formation water, Low Salinity water (LSW) and modified water composition (MW) on oil recovery. A set of experiments are conducted, where different brine solutions with different salt compositions are injected in tertiary mode, by following the displacements with an advanced X-Ray CT (Computed Tomography) scanner. In our experiments, we measured dynamically pressure variation, oil recovery, pH and conductivity. Additionally interfacial tension (IFT) was measured for some of the collected fluid during outcrop core experiment. On outcrop core an additional experiment in absence of oil was carried out, to highlight the dynamical behaviour of salinity front and displacement. All the core-flooding tests were conducted in tertiary mode by reducing the salinity and modifying the ionic composition of injected water. The oil recovery is obtained through quantification of CT scans acquired during the dynamic flooding.

The results of core-flooding experiments showed the differential effects of Low Salinity Modified Water on increasing the pH and wettability alteration toward more water wet, reducing residual oil saturation. With the aid of advanced core-flooding setup integrated with industrial X-Ray tomography, we were able to deeper monitor the complex dynamics displacements leading to advanced observation of the effects of local sample inhomogeneity on oil recovery.

By optimizing the water salinity and composition, LSMW injection as advanced water based EOR technique, can be implemented to enhance oil recovery in favorable conditions.

Polymer flooding is one of the most mature enhanced oil recovery (EOR) techniques, where the injection water viscosity is increased through addition of a high molecular weight polymer. This results in a lower viscosity contrast between the displacing water phase and the displaced oil phase leading to a more efficient oil displacement. In field operations, one of the most critical parameters for successful polymer flooding is the polymer adsorption. During transport the polymer will irreversibly adsorb onto the reservoir, with the extent of adsorption depending on various factors, such as the polymer chemistry, reservoir mineralogy, brine composition, temperature etc. For a given application, there will be an upper limit of adsorption above which the polymer concentration will be significantly depleted, leading to either a diminished EOR performance or a requirement to increase the polymer concentration.

Polymer flooding has predominately used hydrolysed polyacrylamide (HPAM) to viscosify the injection water. In this work, it is demonstrated that there is a large kinetic component to the adsorption of HPAM on silica sand. While an adsorption of ∼24 µg/g was measured after 24 hours, this increased continuously over 14 days to a plateau of ∼110 µg/g. This behaviour is shown to be present at a range of concentrations under both aerobic and anaerobic conditions. To the authors knowledge, the kinetic adsorption of HPAM and its impact both on lab experiments and field polymer flooding has not been very extensively discussed in the literature.

From our experimental measurements of HPAM kinetic (and equilibrium) adsorption, a series of both core and field scale numerical simulations are carried out to demonstrate the potential impact of this relatively slow polymer kinetics at each length and time scale. At the core scale, we demonstrate that flooding at quite normal experimental rates may lead to significant underestimates of the true level of equilibrium polymer adsorption. In the reservoir, where residence time is much greater than 14 days, the polymer adsorption can reach kinetic equilibrium resulting in significantly retarded propagation of the polymer front, and hence the oil bank, and a requirement to overdose lower concentration polymer floods.

The ability to accurately plan polymer flooding projects is essential to fully optimise recovery performance as efficiently as possible, minimise the environmental footprint and reliably predict polymer breakthrough for production chemistry requirements. Thus, a complete understanding of the polymer adsorption and adsorption kinetics is critical for continued development of polymer EOR.

The workflow used to select and study polymer candidates for polymer flooding has remained relatively unchanged since the first projects were performed in the 1960s. Starting with viscosity curves and filtration test, the polymer candidates are then injected into cores representative of the reservoir from which parameters are extracted for history matching and simulation purposes. Interestingly, all studies follow the same book without questioning the validity of the approaches used or the representativity of the polymer solution studied.

First, what is being qualified is not a polymer but a polymer batch with characteristics that might differ from the next one or from a different manufacturer. Secondly, the polymer solution in the laboratory is pristine and exempt of any minor degradation which will occur in the flow lines and impact the molecular weight distribution as well as resistance factor. Thirdly, almost all corefloods are performed at a fixed injection rate supposedly representative of the velocity in the reservoir. The issue here is that at reservoir conditions, it would be logical to consider fixed pressure drop or drawdown and not fixed rate which resembles an extrusion process likely to happen only in the near wellbore area. Lastly, many corefloods are underused, without mentioning the fact that trying to history match the results instead of checking if the equations can predict the latter reveals a lot about the inadequacy of the approach used to understand polymer flow.

In this paper, we will revisit the existing workflow for polymer evaluation and propose changes to reflect on the wealth of knowledge available and the need to better analyze the field candidates before starting laboratory evaluation.

Before selecting samples and designing a testing protocol, we will show that starting with field appraisal (well selection, completion, spacing, etc.) can accelerate laboratory testing and avoid studying phenomena which might not occur in real conditions such as shear-thickening. Next, we will discuss the laboratory tests required and emphasize the need to assess the differences between polymer batches and solutions prepared in the laboratory vs. field. Finally, at the light of typical core flood results, we will revisit the ideas to screen polymers and discuss how the history matching process has prevented engineers to correctly model polymer injection and eventually predict injectivity.

Study Goal and Objectives: A life cycle analysis (LCA) was conducted of greenhouse gas (GHG) emissions associated with CO2 enhanced oil recovery (EOR) where the CO2 is captured from a coal-fired power plant. The objectives were to i) build upon previous LCAs and integrate new information to provide improved ranges for CO2 storage in the reservoir and CO2 recycle;

ii) build a system model representing a cradle-to-grave system boundary; and iii) compare the results to the GHG emission factor for conventional crude oil production.

Methods: The cradle-to-grave system boundaries included emissions associated with upstream, gate-to-gate, and downstream segments. The upstream segment included coal mining, processing, and transport from the mine to the power plant; coal-fired power plant with CO2 capture; and pipeline transport of the captured CO2 from the power plant to the CO2 EOR field. Gate-to-gate emissions for the CO2 EOR field operations used a model developed by the U.S. Department of Energy National Energy Technology Laboratory (NETL); however, we incorporated new information on CO2 EOR performance. Lastly, downstream segments used the baseline NETL petroleum-based transportation fuel model to account for the GHG emissions associated with crude oil transport from the field to the refinery, refining of the crude oil, fuel transport and distribution from the refinery to point-of-sale, and combustion of the refined petroleum fuel.

Results and Major Conclusions: The base case modeling results estimated a net life cycle emission factor for incremental oil produced via CO2 EOR that was approximately 10%–15% lower than conventional oil. The modeling results were most sensitive to the CO2 capture rate, grid mix emission factor assumed for electricity displacement, and net CO2 utilization factor of the CO2 EOR field operations. Optimization scenarios using higher net CO2 utilization factors suggested that lower emission factors for incremental oil produced via CO2 EOR were achievable, with emission reductions of up to 40% lower than conventional oil. The study results showed that CO2 EOR where the CO2 is sourced from a coal-fired power plant provides one potential means for addressing the energy demand–climate change conundrum, by simultaneously producing electricity and oil to meet growing energy demand and reducing GHG emissions to abate global warming.

Recent improvements in reservoir petrophysics have brought about the need for generating more realistic and detailed reservoir models. In this study, forecasting models of wettability distributions are yielded for improved oil recovery (IOR) programs, Notably for vast crude oil quantities of Middle East unconventional tight carbonate reservoirs. Emphasis on pore-level wettability distribution models will be significant towards future IOR potential recoveries development and management programs. Wettability contact angle initial state is captured between residing fluids at tight pores and complex grain particle surfaces. The fluid/ rock boundary will be well described, per se, and morphological geometrical contact angles measurement will no longer be random or follow stochastic approach. However, novel conceptual, low cost, and improved workflow models are enhanced with pore-level morphological big lab-generated data.

In this study, fresh unconventional Kuwaiti carbonate rock samples are studied. Matrix-Wettability-Distribution model is introduced by constructing statistical model based on measured big data contact angle. All measured wettability contact angles yields are from available pore/ grain wall boundaries for each available pore space attached to a grain surface. A complete 2D image analysis of pore area, pore counts, pore distribution as well as contact angle is required to determine this wettability distribution model. Petrophysical parameters such as porosity, permeability, pore volume, pore size distribution, grain volume, and grain diameter are all captured and measured digitally. Further, validated data are accurately generated. Previously, wettability contact angle always portraits as angles measured on smooth surface assumptions, and its usual limited quantification contact angle is vaguely established. In this study, however, quantifying wettability contact angles follows morphological approach that has greater information confidence.

This study includes real reservoir core sample collected from a carbonate Kuwaiti reservoir. Also, images are captured, and then processed for dashboard wettability distributions. In addition, Mathematical A.I. models are created based on high quality data.

The overall Objective for this study is to create a complete dashboard IOR recovery model through 2D image capturing deterministic approach. This dashboard model is a robust technique where image analyses are applied on an unconventional tight carbonate Kuwaiti reservoir. An accurate data driven model will physically describe wettability trends in the tightest unconventional pores available in reservoir rock sample.

Non-thermal methods for improving viscous oil production tends to be less energy intensive than the commonly used thermal techniques. Polymer flooding can achieve more favorable mobility ratio, which helps significantly reduce water production and usage. Carbonated water flooding utilizes CO2 for improving oil recovery. Evaluating their beneficial effects on reducing carbon footprint as well as production enhancement is crucial in the current energy transition environment. In this study, we conducted oil displacement experiments to demonstrate the potential of polymer flooding and carbonated water flooding in oil production enhancement. Field scale simulations were performed on a synthetic reservoir model, and the results were then used as inputs for estimating the carbon emissions in different production processes. Coreflooding results showed that polymer flooding remarkably accelerated and increased viscous oil production. Injecting a 20-cp polymer solution for a 560-cp viscous oil achieved close to 22% incremental oil recovery, with significant water cut reduction. Carbonated water flooding for viscous oil production was more favorable than the conventional waterflooding. A carbonated water flooding applied after conventional waterflooding obtained more than 15% incremental oil. Based on the simulation results, polymer flooding process can reduce carbon intensity by 65% to 77% in terms of per barrel of oil production. A noteworthy reduction in water cut and much less requirement of injection water are mainly attributed to the CO2 emission reduction. Injecting carbonated water for viscous oil production also revealed the similar trends in oil production enhancement and carbon emission reduction. More importantly, significant amount of CO2 can be stored in the reservoir formation during the carbonated water injection process. Results of this study demonstrates that both polymer flooding and carbonated water flooding are viable carbon efficient solutions for viscous oil production.

More than 70% of the global reserve were in heavy oil reservoirs. The huge energy intensity and CO2 emission makes current thermal production of heavy oil less attractive in the era of carbon neutrality. The comparison of polymer flooding and steam flooding showed that while steam injection can achieve much higher recovery than polymer flooding, polymer flooding has wider application scenarios, lower operating costs and less capital input. Various studies have shown that polymer flooding can get an additional oil recovery of up to 20% original oil in place (OOIP). Commercial application of polymer flooding in Pelican Lake (Canada), Shengli and Bohai has shown the benefit of increasing oil production and reducing water injection and production, which in turn reduced the CO2 emission significantly. The low carbon emission nature of polymer flooding was recently verified by various studies. However, the mechanisms of polymer flooding were less understood for heavy oil reservoirs due to various reasons. First, the polymer flooding mechanism regarding viscoelasticity effect in lab and reservoir was still in development. The classic capillary number theory was noticed great drawback because of invalid assumptions ( Guo et al, 2021 ,Transport in Porous Media). Some mechanisms were misunderstood. Second, the high mobility contrast between heavy oil and water and/or polymers makes the effective sweep at different places difficult. The problem of many EOR ideas such as chemical viscosity reducers and even hot steam was how to contact viscous oil in reservoirs. Finally, the reservoir complexity makes polymer flooding more difficult to get desired benefit at least due to the crossflow between layers. Some good laboratory tests can give to erroneous results in actual oilfields due to the scale differences (pore scale, core scale and reservoir scale) which were one of the most challenging parts in upscaling. Various polymer flooding field tests were reviewed and one polymer flooding application Gucheng in China was discussed. Gucheng polymer flooding has shown the limited contribution of high concentration high molecular weight viscoelastic polymer on oil recovery. By contrast, the low viscosity polymer solution worked very well in heavy oil reservoirs (Canada, USA). One important finding was the mild viscosity can get balance between productivity and mobility control. Polymer flooding in heavy oil reservoirs was different from in conventional reservoirs. As long as water flooding works, polymer flooding works better in heavy oil reservoirs.

CO2 enhanced oil recovery (EOR) was very promising technology in new era of carbon neutrality. A brief review on CO2 EOR in the USA and China has shown that CO2 EOR has both pros and cons. The frustrating fact was that even CO2 EOR has been economically and technically successful for decades, the oil production from CO2 EOR only represents less than 5% of total oil in the USA in 2020, although there are 140 commercial field projects. It is more frustrating to say that CO2 flooding has very limited field tests in other countries. 66 CO2 EOR field projects were conducted in China. Even so, the oil production from CO2 EOR in China was insignificant because the projects were not cost-competitive. The main cause was the high cost of CO2 flooding and low CO2 oil recovery. Theoretically, miscible CO2 flooding can get an oil recovery of more than 90%. However, even with the help of water alternating CO2 (WAG), the actual average of CO2 EOR projects (most were miscible) were only 17% OOIP. This was mainly due to the low viscosity of CO2 which significantly affects the reservoir sweep efficiency. Several ways, such as using CO2 viscosity thickeners to improve the mobility ratio, and foaming flooding, were used to improve sweep efficiency. The EOR performance can still be improved. Based on the improved understanding of polymer flooding mechanisms, a novel polymer alternating CO2(PAG) was proposed. The novelty lied in the fact that polymer flooding was not widely used in low permeability reservoirs where CO2 flooding was mainly applied. Recent studies indicated that polymer flooding can be injected into low permeability formations. We thus used numerical simulation to see the oil recovery performance of PAG with low viscosity polymer. By building conceptual model, we find that PAG can improve oil recovery due to enlarged sweep efficiency. PAG works better than WAG. However, recovery of PAG did not outweigh that of polymer flooding or polymer injection followed by water injection. The simple simulation indicated the importance of viscosity of displacing phase in CO2 flooding or CO2 alternating gas injection.

Polyacrylamides are used in polymer flooding to improve the water/oil mobility ratio by increasing the viscosity of the injected fluid. The performance of the polymer within the reservoir is affected by temperature and salinity, and harsher conditions typically lead to lower viscosity yield and long-term stability, at high temperatures eventually even to polymer precipitation within the reservoir. Moreover, even if the reservoir conditions are moderate enough to maintain good viscosity yield and solubility, the presence of polymer in the produced water can lead to precipitation and deposit formation in the surface facilities. This can occur if the temperature in the water treatment units exceeds the cloud point of the polymer, i.e. the temperature where back-produced polymer becomes non-soluble in the produced fluid.

In this study we have generated systematic information on the effect that temperature and brine composition have on EOR polyacrylamide performance. The investigated parameters include viscosity yield, long-term stability and cloud point. Various types of polyacrylamides were studied (both HPAM and sulfonated). The performance of each polymer type was shown as a set of visual contour maps, allowing fast comparison between products.

The viscosity yield maps show that HPAM type polymers provide highest viscosity when temperature, salinity and hardness is low. Furthermore, it is shown that when temperature and/or brine harshness increases, the optimal level of polymer charge decreases. Sulfonation is shown to improve viscosity yield at harsh conditions.

Long term stability mapping was done by dissolving aged and non-aged polymers into various brines, and comparing their corresponding viscosity yields. Cloud point maps were generated for both aged and non-aged polymers. The long term stability and cloud point maps have similar shape as viscosity yield maps: prolonged stability and highest cloud points are obtained in conditions where salinity and hardness are low. High cloud point predicts lower risk for deposits in the surface treatment facility. It is shown that cloud point can be improved by adding sulfonation or adjusting the degree of hydrolysis.

This study collects information from hundreds of measurements into systematic maps. Using this systematic data we can accurately predict performance of typical EOR polymers under any specific conditions of interest (within the range of this study), and present the results visually, to accelerate optimal polyacrylamide selection.