bluuebunny/crossref_metadata_2025 huggingface dataset:
How Polymer Flooding Reduces CO2 Emissions and Energy Consumption - An Exergy Return on Exergy Investment Case Study
Authors: Skauge Tormod , Skauge Arne , Lugo Nancy , Johnson Geoffrey
Published: April 2024

A major part of the energy transition transformation is reduction of carbon footprint in the current oil and gas operations. The energy consumption in the whole chain of operations needs to be evaluated.

The energy efficiency of water flooding is compared to polymer flooding for extraction of heavy oil from an oil field in the UK sector of the North Sea is evaluated using Life Cycle Assessment (LCA) with the concept of Exergy-Return-on-Exergy-Investment (ERoEI). The LCA allows for separation of the process into material and work streams, assessing the impact of each separately. By applying the exergy concept, i.e. the amount of useful energy invested or returned, a comparison of different process steps and different extraction strategies can be achieved.

The Oil field, characterized by an oil viscosity of approximately 80 cP, poses challenges for water flooding operations. Early water breakthrough in producers and high water cuts are anticipated outcomes. While thermal EOR methods could potentially address sweep efficiency concerns, they come at a considerable energy and CO2 cost. Building upon recent advancements in the understanding of polymer flooding for heavy oil extraction, a low-dosage polymer flood was implemented, yielding highly positive results. By utilizing the established water channels in the field, cross-flow of oil into the channels generates a rapid increase in oil production by polymer. In this paper we present the results of an expansion of the current polymer flood to new sections of the field. When comparing like for like development infrastructure and UR recovery times scales, polymer flood leads to a strong acceleration of the oil production which results in a significant increase in Net-Present-Value (NPV). Furthermore, there is an increase of 2.4 times the exergy return on exergy investment and a reduction of 35 % in CO2 emissions.

Extraction of heavy oil has for a long time been dominated by energy intensive and/or inefficient methods. Our study demonstrates that the implementation of low-dosage polymer flooding not only significantly enhances recovery rates, accelerating production by decades, but also accomplishes this with reduced energy cost. The CO2 intensity (kg CO2/bbl oil) is quantified and providing a useful optimization factor for the polymer flood design.
Associative Polymer Propagation, Pressure Response, and Recovery
Authors: Mai K. L. , Watts N. A. , Herman G. C.
Published: April 2024

Hydrophobically modified polyacrylamides, commonly referred to as associative polymers (aP), present a promising alternative to conventional hydrolyzed polyacrylamides (HPAM) used in enhanced oil recovery (EOR). The bulk rheological properties of associative polymers have been studied in the literature and are believed to be well understood. However, debate continues over the underlying mechanisms that govern the observed behaviors of aP in porous media testing. In this study, a mechanistic single-phase coreflood test was conducted to investigate aP behaviors in porous media at shear rates representative of deep-reservoir flow. Additionally, a series of two-phase coreflood tests were performed to study potential application advantages of aP over HPAM. The resulting observations support a hypothesis that high resistance factors (RF) generated by aP are caused by formation in the porous media of an associative network which modifies permeability. This study also provides support for proposals from literature that the formation of the permeability-modifying associative network is dependent upon specific surface characteristics in which the hydrophobic groups of aP adsorbed on the pore surface can functionally anchor an associative network in the pore space. Building upon these concepts and study of previous observations, we propose a mechanism that certain processes can affect these associative anchor points to allow for the mobilization and removal of the retained associative network out of the porous media. This observed behavior may function by either removing these anchor points or by masking their attraction to the non-adsorbed associative polymer. In addition to these studies of flow mechanisms, the two-phase testing demonstrated superior RF generation and incremental oil recovery when utilizing aP compared to HPAM of similar molecular weight, showing potential for aP to improve incremental recovery with reduced concentration versus conventional HPAM.
Does Interfacial Viscoelasticity Increase Oil Recovery at Very High Temperature and Salinity in Carbonates?
Authors: Chávez-Miyauchi Tomás Eduardo , Kar Taniya , Ayirala Subhash , Yousef Ali , Firoozabadi Abbas
Published: April 2024

Flooding with low salinity water (LSW) may increase oil recovery. Despite the general belief that the mechanism of LSW is governed by wettability alteration, crude oil-water interfacial viscoelasticity appears to be a more dominant oil recovery process. Our recent work using 15 crude oils from different parts of the world show that there is a strong correlation between the elasticity of the oil-brine interface and oil recovery. The elasticity of the crude oil – water interface may be tuned by a very small amount of a polymeric surfactant.

In this work, we present a systematic study in four different crude oils (A, B, C, D) with different viscoelastic interfaces in different crude oil-brines. We have measured interfacial elasticity of crude-low salinity water (LSW), crude-high salinity water (HSW), and crude-high salinity water with 100 ppm polymeric surfactant (HSW-PS). The polymeric surfactant may increase the interfacial elasticity of the interface significantly. Two of the crude oils (A and C) show an increase in interface elasticity with 100 ppm PS in HSW. In the second crude oil (B), there is not much change in interface elasticity observed with HSW, LSW, and HSW-PS. With the fourth crude oil (D) we observe LSW and HSW-PS increase interface elasticity. We have conducted nine different coreflooding experiments. Six are at 50 °C, one at 90 C, and other two at 100 °C. Extra recoveries vary in the range of 8% to 20% for systems with high elasticity promoted by the addition of 100 ppm polymeric surfactant in HSW. In crude A, we observe the largest extra recovery with HSW-PS at 50°C; it is 20% higher in comparison to LSW. At 100°C, extra recovery with HSW-PS is 10%. At both temperatures, pressure drop is lower with HSW-PS than with LSW. The implication is higher injectivity besides mobilizing incremental residual oil from carbonate cores.
Measurements and Modeling of Polyacrylamide Polymer Viscosities for Chemical EOR Applications
Authors: Jang Sung Hyun , Nurmi Leena , Mattis Nytara , Bava Luciana , Rosati Louis
Published: April 2024

High molecular weight Polyacrylamide polymer brine viscosities were measured and modeled in a wide range of conditions to improve fundamental understanding and field application of chemical enhanced oil recovery (EOR) processes. More than 300 steady shear rate sweep viscosity curves were generated using a copolymer of acrylamide-polyacrylate and two sulfonated tert-polyacrylamide polymers. The generated viscosity curves were fitted to the Carreau-Yasuda (C-Y) viscosity model with fixed Huggins coefficient of 0.2. Intrinsic viscosity was determined using Martin's equation for the given polymer and brine. The obtained intrinsic viscosity was correlated to the brine composition using the 22 data points for each polymer, so this correlation for intrinsic viscosity is a function of material and brine composition. The zero-shear viscosity, shear thinning index, and time constant parameters of the C-Y model were then correlated to intrinsic viscosity, polymer concentration, and temperature for all three polymers simultaneously, which enabled a unified model approach. Polymer solution viscosities were modeled by plugging three individual correlations for zero shear viscosity, time constant, and shear thinning exponent into C-Y model. The modeling results were compared and discussed with those of the Abdullah et al. model (Abdullah et al., 2023) and the Jouenne and Lavache model (Jouenne and Levache, 2020). Of particular importance is the range and composition of the synthetic brines which are representative of the real brine chemistry variable space in chemical EOR research and field applications. The synthetic brine compositions were derived from 119 brines of polymer flooding field projects worldwide, so the work is aimed at practical field applications by excluding unrealistic brine compositions from the design-of-experiment stage. The proposed viscosity model demonstrated significantly improved prediction performances and/or workflow compared to the existing models.
Critical Thresholds for Deep CO2 Foam Generation: Effects of Injected Quality, Surfactant Concentration and Permeability
Authors: Wei B. , Yang M. , Tang J. , Wang Y. , Lu J. , Rossen W. R.
Published: April 2024

Long-distance propagation of foam is one key to deep gas mobility control for enhanced oil recovery and CO2 sequestration. It depends on two processes: convection of bubbles and foam generation at the displacement front. Prior studies with N2 foam show the existence of a critical threshold for foam generation in terms of a minimum pressure gradient (∇pgenmin) or minimum total interstitial velocity (vt,genmin), beyond which strong-foam generation is triggered. The same mechanism controls foam propagation. There are few data for ∇pgenmin or vt,genmin for CO2 foam.

We extend previous studies to quantify ∇pgenmin and vt,genmin for CO2 foam generation, and relate ∇pgenmin and vt,genmin with factors including injected quality (gas volume fraction in the fluids injected) - fg, surfactant concentration - Cs, and permeability - K. In each experiment, steady pressure gradient, ∇p, is measured at fixed injection rate and quality, with total interstitial velocity, vt, increasing-then-decreasing in a series of steps. The trigger for strong-foam generation features an abrupt jump in ∇p upon an increase in vt.

In most cases, the data for ∇p as a function of vt identify three regimes: coarse foam with low ∇p, an abrupt jump in ∇p, and strong foam with high ∇p. The abrupt jump in ∇p upon foam generation demonstrates the existence of ∇pgenmin and vt,genmin for CO2 foam. We further show how ∇pgenmin and vt,genmin scale with fg, Cs and K. Conditions that stabilize lamellae reduce the values of the thresholds: both ∇pgenmin and vt,genmin increase with fg and decrease with increasing Cs or K. Specifically, ∇pgenmin scales with fg as (fg)2 and vt,genmin scales as (fg)4, and both ∇pgenmin and vt,genmin scale with Cs as (Cs)−0.4. The effect of K on the thresholds for foam generation is greater than the effects of fg and Cs. Our data in artificial consolidated cores show that ∇pgenmin scales with K as K−2 for CO2 foam, in comparison to K−1 for N2 foam in unconsolidated sand/bead packs. More data are needed to verify the confidence of these correlations.

It is encouraging that ∇pgenmin in the cores with K = 270 mD or greater is less than 0.17 bar/m (~ 0.75 psi/ft), 2 to 3 orders of magnitude less than for N2 foam. Such low ∇pgenmin can be easily attainable throughout a formation. This suggests that: limited ∇p deep in formations is much less of a restriction for long-distance propagation of CO2 foam than for N2 foam. Foam propagation could still be challenging in low-K reservoirs (∇pgenmin ~ 10 bar/m for K = 27 mD). Nevertheless, formation heterogeneity and alternating slug injection of gas and liquid help foam generation and may well reduce the values of ∇pgenmin. More research is needed to predict long-distance propagation of foam under those conditions.
An Experimental Investigation of Polymer Enhanced CO2 Foam Flooding: Foam Stabilization and CO2 Mobility Control
Authors: Lliguizaca-Davila Jorge Rodrigo , Sanz Jorge Segundo Mendoza , Brattekås Bergit , Alcorn Zachary Paul
Published: April 2024

Carbon dioxide (CO2) foam mobility control in CO2 storage and enhanced oil recovery can improve the storage potential and oil production by reducing CO2 mobility and increasing reservoir sweep efficiency. A coreflooding study of CO2 foam strength and stability during the co-injection of CO2 and a nonionic surfactant (CO2 foam) solution with and without hydrolyzed polyacrylamide (HPAM) polymers was conducted, including one experiment adding chromium cross-linker solution to the surfactant-polymer solution, to assess gelation effects to assess the effects on improving CO2 mobility reduction. Foam strength, stability, and propagation at unsteady-state flow were compared between the surfactant-based CO2 foam and the polymer-enhanced foam (PEF) solution at 70% foam quality in sandstone cores at scales of 9 cm and 83 cm in length, and rates of 2 ft/day and 4 ft/day. In addition, pure CO2 was injected after foam to identify dynamic changes in foam stability and determine CO2 flow reduction efficiency of the solutions after their placement. Furthermore, the experiment with the 83 cm core added a stage of injection with a chromium cross-linker solution to the surfactant-polymer solution to assess the propagation and strength of the PEF gelled. Apparent viscosity quantified foam strength during co-injections of CO2 foam and CO2 PEF. Adding HPAM polymers significantly increased the foam's apparent viscosity, efficiently creating a stronger foam. PEF propagated at a higher differential pressure compared to CO2 foam, but differential pressure did not increase substantially during the injection of several pore volumes. While the effect of foam injections without polymer was fully reversible during pure CO2 injections, polymer-enhanced foams could significantly reduce the flow of CO2 after placement. The PEF floods high DP showed that the polymer has the ability to block flow channels. The chromium cross-linker with the polymer solution showed that gelation occurred during injection, after which gel entirely blocked the core so CO2 could not enter. Higher rates showed the shearthining behavior of foams and a higher impact on reducing flow mobility during and after the PEF placement. Foam with added polymers may be promising for CO2 mobility reduction during and after placement. Foam has been acknowledged to reduce carbon dioxide (CO2) mobility during its injection in a porous media from pore scale to field scale. Therefore, enhancing in-situ CO2 foam propagation into sedimentary reservoirs is essential to maximize CO2 storage and EOR, and it may be achieved by adding polymers in the liquid lamellae.
Evaluation of a Wettability Modifier on Improving Oil Recovery in Fractured Reservoirs
Authors: Siddique A. K. , Uzun O. , Alghunaim E. S. , Zerpa L. E. , Kazemi H.
Published: April 2024

Enhanced Oil Recovery (EOR) methods using injection of cost-effective, water-soluble chemical additives (e.g., surfactants and mutual solvents) have great potential for increasing oil recovery from low-permeability fractured reservoirs. In a previous paper (Alghunaim et al., 2021), we presented experimental results pertaining to the efficacy of using a 1% solution of 3-pentanone (a mutual solvent) and separately a 1% non-ionic surfactant solution injected in four unfractured Permian Basin carbonate cores saturated with a low-salinity brine. The experiments indicated that we produced substantial amounts of oil from the four non-fractured Permian Basin San-Andres cores with permeability ranging from 2.67 mD to 17 mD, and porosity from 7.4% to 12.14%. In the experimental study pertaining to this paper, we used a fractured and an unfractured sandstone core to demonstrate oil recovery potential of 3-pentanone. The main factors that affect oil recovery from fractured reservoirs are preferential flow through fractures that provide large surface areas, matrix rock heterogeneity, and rock wettability.

The wettability modifying agents reduce both the interfacial tension between oil and water and the water-oil contact angle to enhance oil recovery. The laboratory assessment included measurements of interfacial tension, rock wettability alteration, and incremental oil recovery beyond waterflood. To quantify the efficacy of 3-pentanone, coreflooding experiments included injecting this mutual solvent both in an unfractured core and a fractured core in a Colton sandstone from Central Utah. The effects of changing concentration of 3-pentanone and duration of soaking period before injecting water were also investigated. The results showed that the oil recoveries from the unfractured core and fractured core at the end of the flooding tests were 59.85% and 64.28%, respectively with the incremental oil recovery of 7% and 22%, respectively. The incremental oil recovery from 3-Pentanone can be explained by the combination of various mechanisms that includes a slight reduction in interfacial tension, alteration of rock wettability from water-wet to strongly water-wet (contact angle reduced from 38° to 18°) and ketone partitioning into the oil phase with a reduction in oil viscosity and increased oil mobility. The increase in enhanced oil recovery by ketone solution in the fractured core is probably due to the increase in mass transfer surface area between the fracture and the rock matrix. The 3-pentanone solution provides an operationally simple, environmentally friendly, and cost-effective EOR method in low-permeability formations.
Insights Into Oil Bank Propagation in Reservoirs Under Bottom Aquifer Drive During Polymer Flooding
Authors: Al Ghafri Al Yaqathan , Karpan Volodimir , Al Sulaimani Hanaa , Al Ramli Najib , van Batenburg Diederik
Published: April 2024

The current work aims to understand and characterise the parameters governing the development of the oil bank and its propagation in viscous oil reservoirs under bottom aquifer drive during polymer flooding. The interest in the scope originated from two recent polymer trials which culminated in different results in terms of the oil bank breakthrough time. A two-dimensional numerical model, homogeneous and anisotropic medium under the influence of gravity, is deployed. The model, subjected to an infinite Carter-Tracy type bottom aquifer uses trial's data. Various parameters were studied and compared, including remaining oil saturation, injector-producer distance, voidage replacement ratio, and polymer viscosity. The polymer trials, namely E6 and E157 gave breakthrough time within a few months and a few years respectively. Based on our study, it was concluded that the primary factor for delaying the oil gain in E157 was the remaining oil saturation. The findings address how the initial remaining oil saturation, if overlooked, could significantly delay the oil gain. Nevertheless, the injector-producer distance is another factor that could also contribute to such a delay. The work outcome should be taken as a learning when developing mature oil reservoirs with similar engineering and geological settings.
Synergistic Effects of Binary Surfactant Systems for Enhanced Oil Recovery in Carbonates
Authors: Bello Ayomikun , Rodionov Alexander , Ivanova Anastasia , Cheremisin Alexey
Published: April 2024

This study investigates the use of binary surfactant systems for enhancing oil recovery (EOR) in carbonate formations, which have complex surface charges and harsh conditions (high temperature, high salinity) that limit the effectiveness of single surfactants. Binary surfactants form mixed micelles with lower interfacial tension (IFT) and higher solubilization capacity than single surfactants, thus improving their performance and synergism. We measured the critical micelle concentrations (CMCs) of various binary surfactant ratios and applied Rubingh's Regular Solution Theory (RST) to analyze their behavior and interactions. We found that the binary surfactants had lower CMCs than their individual components, which means less surfactant is needed to achieve optimal surface activity, reducing costs and environmental impact. The nonionic surfactant concentration was a key factor for synergism. We also conducted static adsorption and spontaneous imbibition tests to examine the effects of binary surfactants on oil recovery. We observed that the nonionic surfactant reduced the adsorption of the anionic and cationic surfactants by 53% and 28%, respectively, and increased the recovery factor to nearly 60%. Our results demonstrate the potential of binary surfactant systems for EOR in carbonate formations, as well as for CO2 sequestration and filtration optimization.
Polymer Flooding: The Good, the Bad, and the Ugly - Lessons Learned from Field Practices
Authors: Chang Harry L. , Guo Zhidong , Zhang Jieyuan
Published: April 2024

It has been over 40 years since the publication of an early paper titled 'Polymer Flooding, Yesterday, Today, and Tomorrow' in the Journal of Petroleum Technology (Chang, 1978). Significant progress has been achieved since then, with successful commercial-scale applications in China (Daqing, Shengli, Xinjiang, Henan, and Bohai Bay offshore), Canada (Pelican Lake and Brintnell), India (Mangala), Oman (Marmul), the UK North Sea (Captain), and the USA (Yates, Vacuum, and Milne Point) since then. However, global polymer flooding (PF) production remains below expectations by the industry, particularly in the US (NPC, 1976 and 1984). The objective of this paper is to share our analyses and lessons learned to encourage more commercial-scale applications of PF worldwide.

This paper reviews basic concepts, screening criteria, and mechanisms of polymer flooding and analyzes historical PF field activities from the early 1960s through 2023. It then presents reasons for the lower-than-forecast productions. Conventional wisdom holds that low crude oil prices are the roadblock to the commercialization of all chemical flooding. However, our analysis suggests that this is not the case, and there are other reasons for the lower-than-forecast results.

Based on the progress made over the decades, we divide PF into three stages: the exploration stage from 1960 through 1980, the development stage from 1981 through 2000, and the commercialization stage from 2001 through 2023, including nine major commercial-scale polymer flooding projects worldwide. We analyzed key factors that impacted PF technology over the years, including the critical amount of polymer used, the impact of reservoir heterogeneity on-field performance, the issue of ineffective polymer recycling, the reversal of injection profile, injectivity and productivity problems, and difficulties in treating produced fluids.

After these analyses, we propose a set of design criteria, including reservoir evaluation, polymer selection and slug design, laboratory and simulation studies, pre-commercial field tests, and surveillance/monitoring programs to ensure commercial success. We suggest areas for improvement in future operations, such as enhanced PF combined with other technologies. Future applications of polymer flooding in high-temperature and high-salinity, heavy oil, and carbonate reservoirs are also discussed.
Can Low Salinity Wastewater Act as Smartwater for Improved Oil Recovery in Carbonates?
Authors: Hoecherl M. , Saleh S. H. , Ayirala S. , Yousef A.
Published: April 2024

This study comprises an experimental evaluation of different brine compositions for waterflooding applications in carbonate reservoirs. In particular, the low-salinity wastewater obtained from a gas plant is benchmarked against the conventional high-salinity injection water and SmartWater (diluted high-salinity injection water). Such a study is essential to promote wastewater reuse in waterflooding projects and achieve improved oil recovery.

The detailed characterization of interfacial properties, as well as static oil recovery tests, were conducted using high-salinity injection water, SmartWater, and wastewater. To understand electrostatic interactions between interfaces, the zeta-potentials of oil/brine emulsions and calcite nanoparticle/brine suspensions were measured at 25°C and 70°C. Furthermore, oil-brine interfacial tension (IFT) and contact angle measurements were carried out at reservoir conditions (70°C and 2200 psi). The contact angles of captive oil bubbles were examined on both aged reservoir rock and crystalline calcite. Incremental hydrocarbon recovery was studied through two multi-stage Amott cell experiments at 70°C.

The zeta-potential results indicate a generally negative effective charge at both the oil/brine and the calcite/brine interfaces. Additionally, an electric double layer (EDL) collapse with increasing salinity and temperature is observed for both interfaces. The reduction in zeta-potential magnitude is accompanied by a decrease in electrostatic repulsion between the two interfaces, promoting oil-wet behavior. This observation is confirmed by the contact angle results, which display a wettability transition from a water-wet state for wastewater and SmartWater to an oil-wet state for high-salinity injection water. The normalized incremental recovery from spontaneous imbibition also showed this wettability trend, with both wastewater and SmartWater resulting in an almost similar 50% normalized oil recovery increment after high salinity water imbibition. These results clearly demonstrate the ability of low-salinity wastewater to act as SmartWater in carbonates.

This work has demonstrated, for the first time, the potential of wastewater as a "SmartWater" for improved oil recovery in carbonates. Consistent trends were obtained from zeta potentials, contact angles, and spontaneous imbibition results to confirm the wettability alteration capability of wastewater to achieve a higher oil recovery. These findings would eventually promote wastewater recycling/reuse and environmental sustainability in waterflooding projects.
A Data-Driven Approach to Optimize WAG Injection in a Large Carbonate Field
Authors: Davudov D. , Agarwal A. , Varma A. , Venkatraman A. , Osei K.
Published: April 2024

Water-alternating-gas (WAG) injection is an enhanced oil recovery (EOR) technique used to overcome problems related with gas injection, including gravity override, viscous fingering, and channeling. However, the success of WAG injection is influenced by reservoir characteristics, the injector-producer connections, and the injected gas water ratio (GWR). This study proposes a hybrid model that combines the Capacitance Resistance Model (CRM), machine learning model (ML) and oil model to assess and optimize WAG injectors in a carbonate field.

Interwell connectivity between injection and production wells is obtained by combining a physics-based reduced order model (CRM) and a machine learning model (ML). The hybrid combination of CRM and ML increases confidence in results, eliminating shortcomings associated with CRM models used alone. Next, the results obtained from injection connectivity are combined with reduced order Power Law oil model to evaluate the impact of injection rate increase on oil production. Finally, injectors are optimized and ranked based on their potential to contribute to oil production.

The proposed workflow is applied to a large, complex carbonate field with more than 93 production wells and 47 injection wells. The hybrid combination of CRM and ML used to obtain interwell connectivity compares wells with each other, resulting in higher confidence in the results. Using an ML, results obtained from multiple signals are aggregated to further identify and verify the injector-producer pair connectivity. The further combination of CRM with an oil model helps evaluate additional oil recovery based on the changing gas-water ratio (GWR). A combination of CRM optimization and the ML connectivity results help rank and prioritize 47 injectors quickly and accurately. Five injectors are selected for field testing and results show significant improvement in oil production after implementation of suggested injection schedules.

Hybrid models that combine CRM and ML to obtain connectivity address the shortcomings of the individual models. The identification of efficient injectors for WAG injection by the novel use of hybrid models accelerates decision-making. The approach presented can be extended to similar WAG injection fields with many injectors and producers to help optimize the injection strategy. This new approach helps with current digitization strategies in oil companies to accelerate decision making, especially in mature reservoirs where history matching is not available.
Polymer Developments in Petroleum Development Oman PDO: Learnings from Past Applications and Advances for Future
Authors: Al-Sulaimani H. , Karpan V. , Nabhani H. , Yaarubi Z. , Ghafri Y. , Rawahi Z.
Published: April 2024

A significant part of PDO oil resides in the fields located in the South of Oman. These oil fields have good reservoir rock properties, moderate reservoir temperatures, brine salinities, and medium to high oil viscosities with low GOR. Most fields are mature and were waterflooded for decades; however, growing production water cuts make such oil recovery increasingly expensive and GHG emission intensive.

Polymer flooding is an optimal and mature technology to address these challenges. PDO has embarked on trialing the technology as early as the 1980s in the Marmul oil field, where today, several field applications (from the field trials to commercial scales) are implemented. With the start of a commercial-scale project in Marmul in 2010, polymer flooding has proven to be cost-competitive throughout the long period with varying oil prices even compared to conventional waterflood. The injection of a polymer solution intensifies the oil recovery, reducing the production water cut, thereby decreasing the intensity of greenhouse gas (GHG) emissions.

There are several advances in PDO regarding polymer developments in other oil fields, where efforts are being made to implement external competitive solutions and improve the project schedules. This approach eliminates the need for field trials and uses available data to forecast the polymer flood performance in different fields and reservoirs. Additionally, the project schedules are improved by utilizing the Operational Lease contracting concept whereby the polymer facilities are leased from and operated by an experienced contractor. This approach can significantly accelerate the project's start-up since the facilities are standardized and, in some cases, are readily available for lease.

This paper summarizes the learnings from previous polymer projects over the past decade and the forward outlook on the ongoing PDO efforts to expedite the polymer projects in the funnel. In addition, the efforts to improve the cost competitiveness by the recently adopted Category Management approach for polymer projects from both contracting and standardizations are discussed.
Enhancing Advanced Completion Design Through Permeability Evaluation in Heterogeneous Carbonate Reservoirs Using Integrated Multiple Logging While Drilling Measurements
Authors: Taher A. , Fouda M. , Alradhi H.
Published: April 2024

Lateral changes in petrophysical parameters and diagenetic effects introduce uncertainty in porosity-permeability transforms in complex carbonate reservoirs. This results in discrepancies between actual downhole production and permeability profiles in horizontal wells. Designing sophisticated completions requires high confidence in predicted permeability to achieve lateral flow equalization and maximum oil recovery. This paper presents a model, to improve lower completion design and permeability prediction, by integrating multiple technologies such as nuclear magnetic resonance (NMR), formation tester while drilling (FTWD), and imaging. Analyzing deep and ultra-deep resistivity inversions can also be used to evaluate permeability variations away from the wellbore which can affect the production profile.

NMR can be used to estimate lateral permeability since the Timur-Coates model, usually used for carbonate reservoirs, honors both pore size and porosity variations. Mobility calculations obtained while drilling using formation tests are used to calibrate the Timur-Coates permeability equation. Fracture analysis based on high-resolution images can also be utilized to derive permeability. Integrating multiple sensors and after logging several wells, a reservoir-specific permeability model is developed based on unique field-specific parameters. The calibrated permeability model is then imported into completion design simulation software to design inflow control devices (ICDs). Hence, a higher confidence of lateral inflow equalization, water breakthrough delay and oil recovery maximization are achieved.

The main objective of ICD is to maximize recovery by equalizing the inflow of different permeability compartments along the horizontal wellbore. Hence, permeability is a main controlling factor behind ICD design. Porosity-permeability transforms can overestimate or underestimate the permeability, especially in heterogenous carbonates. Integrating multiple LWD measurements provides improved understanding of lateral permeability changes enabling timely ICD design decisions to be taken. One of the main benefits of the customized calibrated permeability is a better prediction of simulated productivity index (PI), primarily affected by permeability profile input into completion design software and most influential in ICD design. While NMR, FTWD and imaging are sensitive to permeability variations near the wellbore, indications of formation characteristics in the far field can be indicated by analyzing deep and ultra-deep resistivity inversions. Integrating both measurements in the completions design can allow for better flow equalization and delay in the predicted water breakthrough. This paper presents an integrated workflow for enhanced permeability evaluation for a heterogeneous complex carbonate reservoir.
Breaking Barriers: Forging a Strategic Path for CCS Through Innovative Management of Other Contaminants Beyond CO2
Authors: Zamri W. Wan Mohd , Yasin M. Muhammad , Hashim W. Wan , Sani A. Md
Published: April 2024

Planning for CCS (Carbon Capture and Storage) development involves end-to-end evaluation from source to storage. When CCS is brought up as a topic, the conversation tends to center on managing CO2 (Carbon Dioxide). However, emission sources consist not only CO2, but also other contaminants and impurities such as H2S (Hydrogen Sulfide), SOx (Sulphur Oxide) and NOx (Nitrogen Oxide) and H2O (water). The origin of the emission determines the type of impurities present. For example. SOx and NOx only appears from post combustion sources but not from Acid Gas sources (recovered from the AGRU (Acid Gas Recovery Unit)), and H2S often present from Acid Gas source. These impurities are required to be manage in meeting the requirements of both subsurface (e.g. injectivity) and surface (e.g. technology limitation); in which will add to the process complexity, full cycle cost, HSSE (health, safety, security, environmental) risk, operational complexity, etc. Due to this fact, proper trade-off analysis needs to be conducted to generate the best end-to-end development scheme, whilst considering the suitable technologies to manage these impurities and their associated waste/by-product management. This development scheme should not only consider the type of emissions that it will initially handle but should also considers the future emission sources that plans to tie-in to it. Consideration should also be on the sequestration sites’ requirements since future sites may impose a different set of requirements (e.g. different acceptance of impurity concentration). It is then crucial to conduct project framing, concept identification, concept selection and storage site identification during the initial stage of the project. This paper shares a case study on the development of a CCS hub whilst discusses the approach taken to develop its end-to-end configuration and the consideration of available treatment technologies to manage its impurities thus meeting the transportation and sequestration requirements.
Selection of Surfactants for Cyclic Injection into a Low-Permeability Reservoir of an Oil Field for Enhanced Oil Recovery
Authors: Osipov A. , Groman A. , Bondar M. , Kosikhin A. , Varfolomeev M. , Nazarychev S. , Badretdinov E.N. , Bykov A. , Malakhov A. , Morozov M. , Seleznev V.
Published: April 2024

In low-permeability reservoirs, more than half of the pore channels do not participate in filtration and the oil is blocked due to the small pore size. If the reservoir is water wet, this oil can be recovered by initiating capillary water impregnation by injecting water into the production well, but the efficiency of increasing the oil recovery factor may not increase significantly or may be reduced due to a decrease in oil phase permeability. In case of oil wet reservoir, it is necessary to apply surfactants optionally. It is known that surfactants are perspective methods for mobilization of residual oil in cEOR by means of decreasing surface tension at the water/oil phase boundary and by changing wettability of reservoir rock from oil wet to water wet.

Anionic surfactants are the most widely used type of surfactants in cEOR because most of the cEOR work has been conducted in sandstone reservoirs. The relationship between anionic surfactants and sandstone is related to adsorption and surface charge. Anionic surfactants are negatively charged same as the surface of sandstone, this helps to reduce adsorption on the rock. The adsorption of anionic surfactants on the sandstone surface can alter its physicochemical properties such as surface tension and wettability.

Anionic and non-ionogenic surfactants on a laboratory scale under conditions of high temperature and high salinity have been investigated. The selection of a suitable surfactant is a difficult task, and surfactants must be evaluated using a combination of screening methods. International studies show that most surfactant flooding has been conducted in low-temperature and low-salinity sandstone reservoirs. However, high-temperature and highly mineralized reservoirs are still challenging reservoirs for surfactant flooding.
Recent Developments of Cyclic Solvent Injection Process to Improve Oil Recovery from Unconsolidated Heavy Oil Reservoirs
Authors: Perez Daniel Cartagena , Shokri Alireza Rangriz , Chalaturnyk Rick
Published: April 2024

One of the practical limitations of cold heavy oil production method in unconsolidated reservoirs is sand production that leads to very low recovery factor (5-15%). To target the remaining 85-95% heavy oil resources, several enhanced oil recovery (EOR) techniques such as cyclic solvent injection (CSI) have been proposed. Due to its potential success in Canada and elsewhere, this paper reviews the technical and efficiency requirements of CSI EOR in heavy oil reservoirs.

To have an improved understanding of the conditions that result in a successful CSI process, we reviewed the dominant driving mechanisms of CSI at reservoir conditions such as fluid displacement, pressure gradients, non-equilibrium gas dissolution/exsolution, potential formation collapse, and deformation issues; the interest is on the application of CO2 as a solvent. Limitations of current thermal and non-thermal EOR methods were briefly compared against the CSI in thin oil reservoirs. To complete the assessment, several case studies and lessons learned from CSI applications were included based on the latest laboratory experiments, numerical studies, in addition to the CSI pilot/field tests.

Specific to thin heavy oil reservoirs with sand production (e.g. CHOPS), incremental oil recovery requires to re-energize the depleted reservoirs in a cyclic manner, aiming to provide more drive energy by economical gaseous solvents (e.g. CO2). It was realized that other EOR techniques such as waterflooding, gas flooding, and steam injection can face major issues with flow and heat efficiencies, including fingering and significant heat/solvent losses; this makes CSI a feasible EOR alternative. Regarding the solvent use, laboratory experiences have not been conclusive about what solvent stream could result in an improved oil recovery; however, most of the solvents should be designed to either reduce heavy oil viscosity, or strengthen the nucleation and stability of the injected solvent bubbles in the heavy oil reservoir (i.e. foamy oil behavior). To this end, successful field scale CO2 EOR applications have been reported in several oil reservoirs. Although progress has been made, but numerical modelling still faces challenges to properly model the main CSI driving mechanisms, including fluid-solvent interactions and deformation of subsurface reservoirs. Moreover, field implementation indicates that highly productive wells during primary production from unconsolidated reservoirs might also outperform during a follow up CSI process.

This work addresses the recent improvements in application of CSI EOR to develop heavy oil reservoirs, especially for thin and poorly consolidated sandstones. The findings of this paper, including the limitations and requirements of different recovery techniques, enable more effective design of field scale CO2 EOR operation in depleted heavy oil reservoirs.
Towards Freshwater Conservation: Seawater Based Dry Friction Reducer for Slickwater Fracturing
Authors: Qi Z. Y. , Huang T. P. , Kalgaonkar R. , Sahu Q.
Published: April 2024

Hydraulic fracturing with slickwater has been widely used in development of unconventional reservoirs. One of the key components in slickwater formulation is friction reducer (FR). Regular slickwater fracturing operation requires huge amount of low-salinity water, which poses great challenges in areas with freshwater shortage. This study aims to develop slickwater formulation using high performance dry friction reducer (DFR) that can be fast dissolved in seawater to reduce freshwater usage.

The DFR products were evaluated in several key aspects, including hydration time, viscosity, friction reduction, and flow-back performance. Hydration time of the DFRs in synthetic brine was measured by viscosity monitoring. The viscosity was measured using rheometer at 160°F. Friction reduction of DFR samples was characterized by industry standard friction flow loop system. Formation damage evaluation was conducted by measuring permeability of core plug before and after slickwater injection at 270°F.

The DFRs are cost effective and easy for logistic handling under harsh environmental conditions comparing to liquid and emulsified FRs. To ensure the successful use of DFR with seawater, the evaluation on polymer hydration time was conducted. Viscosity measurements were used to quantitatively compare the hydration time for different DFR samples. An optimum DFR candidate was able to totally dissolve in seawater in 1 minutes, and similar hydration performance in brines with salinity range from 58,000 ppm to 315,000 ppm. The friction reduction can reach 74% in 2 minutes, at low concentration around 2 pounds per thousand gallons (pptg). The relatively high viscosity of slickwater solution ensures the proppant carrying during hydraulic fracturing. A slickwater formulation containing several components was also developed using seawater. Because of the high salinity, the compatibility of different components was investigated, the formulation was able to reach high retained permeability ratio over 85%, The excellent performance of the slickwater makes it promising for field trial.

The seawater suitable DFR based slickwater was developed to perform properly under unique environmental conditions. The excellent performance of DFR based chemicals makes this slickwater fracturing technology available for field operations and assist the conservation of freshwater.
Experimental Investigation of Early Leak Detection in Offshore Multiphase Flow Pipelines Using Non-Invasive Electrical Resistance Tomography
Authors: Khan M. S. , Barooah A. , Ferroudji H. , Rahman M. A. , Hassan I. , Hasan R. , Sleiti A. K. , Gomari S. R. , Hamilton M. , Marashdeh Q.
Published: April 2024

Prompt and reliable detection of pipeline leaks is vital for human safety, the economy, the environment, and corporate reputation. The objective of the current analysis is to investigate the effectiveness of non-invasive Electric Resistance Tomography (ERT) in detecting and locating leaks in offshore oil and gas pipelines under various multiphase flow scenarios and compare it with real-time visualization data. A flow loop apparatus with a diameter of 0.0508 m and a length of 6.9 m is used for conducting experiments. Water is employed as a representative Newtonian fluid, while air is utilized to simulate the gas phase in different scenarios. The experiments were conducted on different flow rates of liquid (150-383.50 kg/min) and gas (10-50 g/min). The three distinct leak sizes (3, 2,5 and 1.8 mm) are introduced together to replicate offshore leak scenarios in this study. For the same gas input scenario (10 g/min), increasing the liquid mass flow rate from 150 to 383.50 kg/min reduces the system's gas phase composition in ERT from 4.16% to 1.44% which is about 65.3% less, highlighting the influence of liquid flow rate. Furthermore, the ERT measurement revealed that when increasing the gas phase quantities (10 to 50 g/min) under constant liquid conditions (173.5 and 244.8 kg/min), more gas pockets were identified in ERT observations, resulting in higher gas phase compositions. Moreover, in the case of leak conditions, it provides relatively fewer quantities of air voids in the pipeline when compared to no leak cases, indicating the applicability of ERT in leak scenarios. The correlation between liquid flow rate and gas phase composition indicates the potential for optimizing pipeline operations by adjusting flow rates to minimize gas phase presence. The applicability of ERT in detecting leaks, especially in offshore scenarios, is promising for water (Newtonian fluid), however, further experimentation is needed to assess its performance for non-Newtonian fluids, multiple leak sizes and leak locations which are often encountered in real-world pipelines.