bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of Factors Controlling Low Salinity Water Flooding in Carbonates: An X-Ray Photoelectron Spectroscopy Insight
Authors: Souayeh M. , Al-Maamari R. S. , Kyaw H. H. 
Published: April 2024

Abstract
Low salinity water (LSW) flooding, as a wettability modifying agent, is observed as one of the viable technologies for improving oil recovery in carbonates, owing to its low cost, low carbon footprint and effectivity. However, the optimum salinity (i.e. dilution factor) and wettability state to trigger the low salinity effect remain subjects of conflicting views. Thus, the main objective of this study was to investigate the factors controlling the low salinity effect (LSE) quantitatively and qualitatively.
Series of interfacial tension (IFT) measurements, contact angle (CA) analysis on calcite surfaces, and, spontaneous imbibition tests in Indiana limestone outcrops were carried out at 75°C. The experiments were performed using synthetic formation water (FW) having high salinity (196 g/L), which was diluted by various factors: 2 times (97.9 g/L), 4 times (49 g/L), 10 times (19.6 g/L), 20 times (9.8 g/L) and 100 times (1.96 g/L), and crude oil sample obtained from the targeted carbonate reservoir. Furthermore, surface composition of calcite surfaces before and after wettability modification were analyzed using X-ray photoelectron spectroscopy (XPS).
The measured IFT between formation water and crude oil was equal to 9 mN/m and it reduced to ∼6 mN/m upon decreasing the salinity. Such IFT reduction could contribute to the recovery mechanism. CA results showed that the wettability of the calcite surfaces was altered from an initial oil-wet state towards an intermediate-wet state, upon reducing the salinity from 196 to 19.6 g/L. Further reduction of salinity resulted in no wettability alteration and the calcite surfaces remained oil-wet. It was found that the positive effect of increasing rock dissolution, by decreasing salinity, in reducing oil-wetness is opposed with the negative role of sulfate in shifting the wettability towards oil-wet due to the resultant increase of the pH of LSW solution. The oil recoveries by spontaneous imbibition were in perfect agreement with CA results, as maximum oil recovery (∼50 %) was obtained for the LSW system (19.6 g/L) that shifted the wettability from oil-wet towards intermediate-wet. From XPS analysis, it was observed that the atomic percentage of C−C/C−H peaks reduced after treatment with LSW suggesting the calcite was slightly dissociated during treatment. In addition, calcium dissociation was more dominant than carbon after treating with 1.96 g/L, while for the case of 19.6 g/L, carbon dissociation was more dominant.
The findings of this study provide a deeper understanding of the factors influencing the LSE in carbonates by coupling the change in surface composition with wettability alteration. It is interesting to state that although none of the LSW solutions used in this study could alter the surface wettability towards a water-wet state, some of the intermediate-wet systems were able to efficiently increase oil recovery by spontaneous imbibition.
EOR of Sour Oil Field Through CO2 Miscible Gas Injection: De-Bottlenecking Challenges for Surface Facilities
Authors: Al Lawati M. R. , Dhahli A. 
Published: April 2024

Abstract
The cluster of fields under the scope of the study are located in South of Oman. Most of the fields are located within a salt basin. The fields were discovered in different periods and all are under production. The study was focused on the largest two fields in the area that are currently under Miscible Gas Injection (MGI) as means of Enhanced Oil Recovery (EOR). Both of the fields have been under MGI for over 10 years, with sour gas produced from the two fields, among other fields, is re-injected into the reservoir. A small fraction of the produced sour gas is treated and exported as sales gas to a nearby pipelines. The sales gas is mostly used for power generation.
The re-injected gas used for MGI consists of a significant gas bubbles that is currently used for EOR purposes. If the current EOR scheme continues, the gas bubble cannot be commercialized until most of the oil reserves are produced.
The objective of the study was to assess the feasibility of Carbon Dioxide (CO2) utilization for EOR of the oil fields through additional oil miscibility by replacing sour natural gas injection with acid gas injection (i.e. CO2 injection). The study also intended to quantify the amount of natural gas that can be displaced with CO2 injection, and the overall economics of the project.
New Insight into the Synergism Between Engineered Water and Nonionic Surfactants for Improving Spontaneous Imbibition in Oil-Wet Carbonates
Authors: Souayeh M. , Al-Maamari R. S. , Aoudia M. 
Published: April 2024

Abstract
Altering the wettability of rock matrix to water-wet has been recognized as an effective approach to enhance oil recovery from fractured carbonate reservoirs. This can be achieved using various techniques, including but not limited to, water salinity/composition modification (engineered water) and surfactants injection. This study features an experimental evaluation of engineered-water-surfactant (EWS) performance in wettability alteration of oil-wet carbonate having high salinity formation water (196 g/L) and moderate temperature (75 °C), representative of an actual Omani carbonate reservoir.
Two commercially available polyethoxylated nonionic surfactants were used in this study. The surfactants were mixed to obtain an average ethylene oxide (EO) units equals to 12 (C13EO12). The surfactant solutions were prepared at concentration of 0.3 wt. % using diluted formation water (100 fold) and spiked with either 50 or 100 mmole/L of Mg2+ and Ca2+. The crude oil was acquired from the targeted reservoir. The experimental workflow included the following measurements: cloud point, interfacial tension (IFT) against crude oil, contact angle (CA) on calcite surfaces, and, spontaneous imbibition in Indiana limestone outcrops.
Results revealed that increasing the concentration of either Mg2+ or Ca2+ had a minor effect on the cloud point temperature (≤2 °C), despite the increase in salinity. On the other hand, increasing divalent ions concentrations further reduced the IFT by 1 order of magnitude and reduced the IFT equilibrium time. However, the minimum IFT value obtained was 0.06 mN/m, which still falls within the range of Winsor Type-I. From CA measurements it was found that low salinity nonionic surfactant was able to alter the wettability from oil-wet to weak water-wet state. Spiking the surfactant solution with 50 mmole/L of divalent ions proved to be more effective than 100 mmole/L as the latter concentration showed a negligible impact on the CA. A strong water-wet state (27°) was achieved after treatment with surfactant solution spiked with 50 mmole/L of Mg2+. Unexpectedly, the system that yielded strong water-wet state resulted in the lowest oil recovery by spontaneous imbibition (37 %). While, the remaining EWS systems were able to substantially improve oil recovery (69 - 74 %) compared with the reference low salinity surfactant system (51 %). One interesting finding; the additional oil recovery is inversely related to the difference between the cloud point of the EWS system and the testing temperature.
The findings of this study clearly indicate that strong water-wet state does not always result in high oil recovery from carbonates. The role of divalent ions in boosting the solubility along with the interfacial activity of nonionic surfactants is promising; it provides a new insight and a new approach for EWS implementation to obtain optimum synergism that leads to higher oil recovery.
Utilizing a Design of Experiment Approach in Reservoir Simulation for Pattern Balancing and Optimizing a Polymer Flood
Authors: Grover K , Saadi J Al , Farsi M Al , Shetty S , Villar J , Doroudi A 
Published: April 2024

Abstract
Improving the efficiency of polymer flood or enhancing the incremental barrel of oil per pound of polymer injected is one of the most important factors for a successful polymer project. In almost all the active polymer floods, total polymer injection and liquid processing capacity is limited with the original design. Utilizing polymer to its fullest extent is therefore imperative for effective reservoir management in a polymer flood.
A full-field polymer flood is made up of several patterns, and consequently polymer flood efficiency depends on pattern efficiency. The scope for optimizing patterns include identifying priority for Optimizing injection/production rates.Optimizing polymer concentration.
The key reservoir-level factors that affect a polymer flood are geology, voidage replacement, and in situ polymer viscosity and should be given due consideration in reservoir management. The paper outlines a novel way based on a straightforward simulation model for optimizing polymer flood.
Base case reservoir simulation model is used to represent the fulfilled polymer flood, capturing geology and polymer rheology and overall flow behavior. Then, a design of experiment is created with individual pattern's injection rate and concentration as primary variables. The objective function is defined to maximize sweep efficiency, oil recovery and polymer flood efficiency for short term interval. More than 1000 experiments were created and run to identify sensitivity of individual patterns. Further using Sobol and Morris analysis, relative ranking of patterns is done for all patterns with reference to individual and global objective function. To further ascertain impact on ultimate recovery, cases with identified pattern changes have been ran till end of field life and compared with the base case.
Experimental Evaluation of Treated Produced Water for Improved Oil Recovery in Carbonates
Authors: Hoecherl M. , Alshammari S. , Saleh S. H. , Ayirala S. C. , Yousef A. 
Published: April 2024

Abstract
This study comprises an experimental investigation and comparison of different brine compositions for waterflooding applications in carbonate reservoirs. In particular, a novel zero liquid discharge (ZLD) brine, which is obtained from produced water treatment and features no significant salinity, is benchmarked against conventional high salinity injection water. Such a study is essential to promote produced water reuse in waterflooding projects and achieve improved oil recovery.
A detailed characterization of interfacial properties as well as static and dynamic oil recovery tests were conducted using high salinity injection and treated produced water. To understand electrostatic interactions between interfaces, 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 aged reservoir rock and crystalline calcite. Incremental hydrocarbon recovery was studied through a multi-stage Amott cell experiment and a high-pressure, high-temperature (HPHT) core flood 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 ZLD treated produced water to an oil-wet state for high-salinity injection water. The incremental recovery from spontaneous imbibition also showed this wettability trend. ZLD water resulted in an oil recovery increment equal to the recovery by high salinity water imbibition. Finally, the core flood revealed the full potential of ZLD treated water, yielding an incremental oil recovery of 4-5% after high salinity water injection in a carbonate core.
This work has demonstrated, for the first time, the potential of treated produced water for improved oil recovery in carbonates. Consistent trends were obtained from zeta potentials, contact angles, spontaneous imbibition, and core floods to confirm the wettability alteration capability of treated produced water to achieve incremental oil recovery. These findings would eventually promote produced water recycling/reuse and environmental sustainability in waterflooding projects.
Azimuthal Geosteering: New Opportunities Revealed by Advances in Ultra-Deep Resistivity Technologies
Authors: Elkhamry A. , Fouda M. , Al-Zawad A. , Al-Maimani A. 
Published: April 2024

Abstract
Ultra-deep electromagnetic (EM) technology has been used for over a decade for well placement operations. As the measurement primarily responds to resistivity variations around the wellbore, it has been used to map lithological boundaries and fluids enabling geosteering the well path in real time to the desired formations. Traditionally a multi-layer 1D geological model is constructed by inversion algorithms utilizing five measurement components of the EM signal. Recent advances in tool designs and computational capabilities enabled the utilization of the full nine EM measurement components to construct a full 3D model around the wellbore, hence enabling new opportunities in reservoir visualization, well placement decisions and fluid mapping in real time. This paper presents some real-life opportunities of azimuthal geosteering revealed by the ultra-deep resistivity 3D inversion.
Advancements in logging-while-drilling (LWD) tool designs including tilted EM transmitter and receiver antennas enabled the acquisition of all nine components of the EM field around an EM tool. Advanced algorithms and real-time transmission systems have been introduced allowing the visualization of the 3D resistivity volume around the wellbore in real time, providing insight into formation and fluid changes in all directions. Well placement decisions can now target optimal zones as defined by their resistivity in any direction around the wellbore and not only in the vertical plane as defined by 1D inversions. New operational workflows including intensive pre-well planning and collision avoidance monitoring have also been enhanced, accounting for any additional risks that could result from real-time azimuthal well path adjustments.
Ultra-deep resistivity 3D inversion was successfully used on several geosteering wells crossing multiple formations. Advanced computational methods were utilized in real time, which enabled several real time decisions to be made. The visualization of the resistivity volume around the wellbore revealed variations in all directions around the wellbore, uncovering more complex structures of the subsurface geology. New opportunities were enabled to include "turning" instructions into well placement decisions to maximize reservoir contact and improve petrophysical properties of the drilled interval. In addition, enhanced operational workflows ensured drilling and well collision risks were avoided.
This paper presents an integrated approach to utilize a newly developed 3D ultra-deep resistivity inversion technique to adjust well paths in all directions placing wells in the best reservoir properties.
Applying Particle Swarm Optimisation Technique to Calculate Rod Torque Limits for Wells and Preventing Impending PCP Rod Failures
Authors: Rodrigues J. 
Published: April 2024

Abstract
Most of the producing oil wells require some form of artificial lift for pumping production fluids to the surface (Bates, Cosad et al. 2004). The Progressing cavity pump (PCP) is considered as one of the most robust types of artificial lift method. About 10 to 15 percent of almost one million wells worldwide produce oil with the help of PCPs. PCPs are very efficient and can handle a range of viscosities, gas-liquid ratios, and solids production. Over the years, one of the most pressing concern of operators using PCPs in their Oil-fields have been, high workover costs and subsequent failures. If the operators do not take care of the PCP installation and take care of the PCP whilst start up, then the PCP efficiency gradually declines over time and the PCP fails at some point of time. This can be attributed to High Torque, Pump Deterioration, Parting of the Rods and other such failures. Due to the failure the financial costs are substantial accompanied by lost production, workover rig costs, replacement costs and intervention costs. To reduce failures operators are investing in real-time surveillance systems to monitor PCP performance using downhole measurements and raise alarms in case of abnormal events such as tripping's or failures. This is done by monitoring various parameters and then action is taken based on the operator's ability to discern the impending failure based on some signature trends. However, more often than usual at this stage it is already too late to do anything that could save the pump or the whole PCP system. Thus, it is important to move from a reactive to a proactive approach. This paper offers such an approach. Specifically, a analytical solution is proposed to proactively calculate and suggest a Torque value within which the PCP should work to deliver the required deliverability from the reservoir. statistical techniques for dimensionality. This analytical solution combines engineering principles with mathematical models to detect a suitable torque long before the PCP crosses this value in an actual well startup scenario. Supervisory control and data acquisition (SCADA) systems and data historians bring about an increased value by optimizing the work procedure or Workflow. Particle swarm optimization (PSO) is one such technique that can be used in conjunction with the workflow to monitor an important parameter such as Rod torque to enable the production engineer to calculate the most suitable hydraulic torque limit for the oil and gas well where a PCP (Progressive cavity pump) is installed. Thus, if a situation arises where the Torque limit is not calculated correctly, this implementation of this analytical solution which is implemented in Python programming language can prevent the wrong Torque value from being calculated and result in saving the PCP pump.
Innovative Near-Online Flow Assurance Tool for Pipeline Historical Performance Analysis
Authors: Natta A. , Tiozzo A. , Montini M. , Hester K. C. , Di Lullo A. G. 
Published: April 2024

Abstract
This paper introduces an innovative in-house developed near-online flow assurance simulation concept for continuous monitoring of pipeline performance, such as deposition of solids. The tool can be retrofitted to the analysis of brown fields without specific requirements for the installation of customized instrumentation hardware. In addition to detailing the tool, a field application case is discussed to provide insight on the pipeline historical performance.
The tool is based on a dynamic multiphase flow simulator and relies on the presence of a Digital Oil Field (DOF) system. The field data are acquired by the tool directly from the remote DOF database and used as input to automatically generate, run, and post-process various simulations representing stable production conditions of the field. The tool can perform periodical runs and the results obtained populate a historical database of the pipeline performance for further analyses.
The near-online flow assurance tool has been applied to investigate the potential wax deposition in two subsea multiphase pipelines. Starting from the second year after the field start-up, due to the reservoir depletion, the temperature at riser base had fallen below the wax appearance temperature (WAT). Laboratory analyses confirmed the potential for wax deposition under current and past operating conditions and the use of wax inhibitor at the wellhead was recommended. However, there was uncertainty regarding the inhibitor effectiveness since pigging activities have been conducted unfrequently and on a discontinuous basis. Therefore, it became essential to monitor the pressure drop trend of the pipelines over time as a non-invasive wax detection technique.
The analysis has been conducted over a seven-year period since the first start-up of the field. Given that the discrepancy of simulation data from field data turned out to be within the simulation's uncertainty range and it does not change throughout the whole timespan of the analysis, the tool has proven the effectiveness of the injected wax inhibitor.
A traditional flow assurance analysis workflow would have required large time-consuming manual input for the case-study presented, since a substantial number of field data has been processed. This renders the traditional approach impractical. The near-online tool has proven to be capable and robust for different flow assurance applications by reducing the time effort and the error probability linked to manual input. In future, other pipeline studies will benefit from the definition of the presented workflow.
Improved Water Management Through the Usage of Sulfonated Polymers
Authors: Al-Murayri M. T. , Kamal D. , de Kruijf A. , Imqam A. , Andrianov A. , Liu E. , Al-Rawahi S. 
Published: April 2024

Abstract
Oil and gas production uses large volumes of water for injection during polymer flooding and hydraulic fracturing operations. The same operations generate large volumes of wastewater, of which produced formation water and flowback water make up the dominant volumes. The availability of fresh water is a growing challenge in many regions of the world and major oil companies take these challenges seriously and recognize their need to preserve fresh water. They report operations in water-scarce areas in their annual sustainability reports and they strive to reduce and ideally eliminate freshwater intake for their operations by increasing recycling capacity. Reusing high salinity water for hydraulic fracturing and polymer flooding applications is a challenge as high salinity water negatively impacts the economics and success rate of these treatments as the apparent viscosity of standard HPAM is affected by the high salinity. Desalination of these high salinity water sources can be executed by thermal desalination techniques which are not cost effective at these large water volumes. Altering the HPAM polymer by adding ATBS or AMPS monomer instead will enhance the viscosity and stability of the polymer solutions at high salinity. These sulfonated polymers showed excellent performance in using saline water in hydraulic fracturing operations, where friction reduction during injection and proppant carrying capacity are the main requirements. When using the right fraction of ATBS/AMPS monomers in the polymer, high salinity (even combined with high temperature) reservoirs can be flooded with sulfonated polymer solutions to obtain increased recovery as indicated by a field case.