bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractOne 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

Abstract
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

Abstract
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.