bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Synergistic Surfactant Mixtures for Improving Oil Production in Carbonate Reservoirs
Authors: Xu Limin , Han Ming , Cao Dongqing , Fuseni Alhasan 
Published: March 2022

Abstract
The paper presents the development of new surfactant formulations composed of various low-cost and low-performance surfactants to make them high performance products for high temperature and high salinity carbonate reservoirs. The objective of this study is to optimize the surfactant chemistry by mixing different kinds of surfactants (ionic, nonionic, and amphoteric), which results in significant synergistic effects in interfacial properties to improve oil production at the given harsh conditions.
The optimal mixing surfactant ratios were determined according to the brine-surfactant compatibility, microemulsion phase behavior, and the interfacial tension (IFT) between oil and surfactant solutions in high salinity brine and at 90˚C. Comprehensive performance of the surfactants was evaluated, including adsorption of the surfactants onto the carbonate rocks and the long-term stability at 95˚C. The coreflooding displacement experiments were performed using carbonate core plugs at 95˚C to evaluate the potential of the optimal mixing surfactants in improving oil production.
Three formulations composed of two types of low-cost surfactants were developed in this study. The mixing surfactants were chosen based on moderate electrostatic interaction among the surfactants. It appeared the synergistic effect between the mixing surfactants was enhanced with increasing temperature. Although the IFT of the individual surfactants with crude oil was in the range of 100mN/m, a significant IFT reduction in the magnitude of 10−2 - 10−3 mN/m was observed by mixing the surfactants. A salinity scan showed that the IFT values maintained a value of 10−2 mN/m in a wide salinity range, which demonstrated the robustness of the surfactants mixtures. In microemulsion phase behavior studies, these mixed surfactant solutions in the presence of crude oil exhibited Winsor Type III emulsions. The static adsorptions of the mixed surfactants were lower than the individual surfactant adsorption. All this indicated the feasibility of these formulations for their applications in the harsh reservoir conditions. The results of coreflooding displacement tests demonstrated significant oil production improvement beyond water flooding.
This work provides an efficient way to get surfactant formulations by mixing low-performance and low cost surfactants to obtain high performance in improving oil production under the harsh conditions.
Experimental Assessment of the Viability of High Temperature Steam Foam Applications
Authors: Jones Sian , Bos Robert , Lastovka Vaclav , Farajzadeh Rouhi , Riyami Mohammed 
Published: March 2022

Abstract
The efficiency of oil processes depends on the product of volumetric sweep and microscopic sweep. In oil recovery by steam injection the microscopic sweep is generally good; however, obtaining a good volumetric sweep can be challenging. This is caused by low density and viscosity of the injected steam combined with the reservoir heterogeneity, in particular existence of thief zone. Consequently, the steam utilization factor measured by steam-to-oil ratio (SOR, kg steam/bbl of oil) for many steam-flooding projects becomes poor. All these issues can be addressed by a successful application of steam foam technology.
In steam foam applications, steam (plus a non-condensing gas) is injected simulateneously with a surfactant solution. Under the favorable injection conditions a foam is formed inside the reservoir leading to significant reduction of steam mobility and can eventually improve sweep efficiency.
In the literature many successful steam foam pilots have been reported. However, most of these applications are at relatively shallow reservoirs with low pressures and thus low temperatures. In our paper we investigate if steam foam can also be effectively used for applications at high steam temperatures, significantly exceeding 200°C.
To test the viability of steam foam technology at high temperatures, we have tested the stability of multiple surfactants at reservoir conditions. For those surfactants that showed good stability, core flood tests have been carried out to test the ability to form foam and to assess the resulting foam strength. Steam foam tests have also been carried out at temperature up to 240°C.
Well Performance Analysis in Shale/Tight Gas Reservoirs: Case Study Review
Authors: Haghshenas Alireza , Hamedpour Mohammad 
Published: March 2022

Abstract
In recent years, the shale and tight reservoirs have emerged as one of the top resource plays for securing the world energy demand. Because of extremely low permeability nature of tight reservoirs, the advanced drilling and completion techniques are required to adjust economic production from these reservoirs. The current industrial practice is to drill long horizontal wells with multi-stage hydraulic fractures. The goal of multi-fractured horizontal well is to create a larger contacted area between the well and tight rock and in turn, make it easier for the fluid to flow toward the producing well. However, as development proceeds, the analysis of the data and accurate forecasting of the well performance is still facing challenges. In fact, as more data become available, it is becoming more clear that the conventional reservoir engineering may no longer be accurately valid to analyse the production data of shale reservoirs.
As a traditional evaluation process, the early-time production rate (IP) is used as a proxy for ranking the well performance and estimating the ultimate recovery (EUR) and, therefore, forecasting the economic viability of individual wells. However, as it is shown in this paper that the IP analyse is not the most accurate measurement and sometimes can be indeed a misleading parameter in shale/tight wells evaluation. Alternatively, more advanced reservoir engineering tools and parameters are required to interpret the performance of the well and forecast the production of shale reservoirs.
This study uses production data analysis to estimate the productivity trend of shale wells in the reservoir of interest. Our dataset is limited to a restricted geographic area with presumably consistent geological properties such as porosity, water saturation, pressure, and temperature. With limited variation in reservoir properties, the flow trend of the well becomes a good metric for completion efficiency.
The production data from a few typical shale gas wells are provided and the well performance is evaluated using rate transient analysis tools. The long-term production forecast of the wells is then estimated using empirical models. The results of this study would help operators/investors to better understand the challenges they may face with as well as possible opportunities in shale reservoirs. This study would also help operators to decide about the best completion approach to achieve optimal production within a shale region.
Water Injectivity Decline in an Omani Oil Field: Possible Causes and Mitigation
Authors: Al-Shabibi Ibtisam , Naser Jamil , Al-Maamari Rashid S. , Karimi Mahvash , Al-Salmi Ahmed , Al-Qassabi Hajir 
Published: March 2022

Abstract
Treated oilfield produced water is injected into reservoirs to increase the depleted reservoir pressure and enhance oil recovery. The main challenges in this process are injectivity decline and high tubing head pressure (THP) which is most often caused by the deterioration in the reservoir permeability.
This investigation focuses on identifying root causes behind injectivity decline in a sandstone reservoir in Oman. Acid stimulation has been applied to improve the reservoir permeability, but it turned out to be non-feasible due to frequency of such interventions and high associated costs. Several factors, such as injection water quality and reservoir mineralogy, can adversely affect the reservoir permeability and cause injectivity decline. Various approaches to tackle this problem have been adopted in this study including; water analysis, scale modeling, formation damage simulation and core flooding experiments.
The scale modeling results showed compatibility between formation and injection water where the scaling potential for both barium sulphate (BaSO4) and calcium carbonate (CaCO3) scales were unlikely to form at reservoir conditions. Injection water analysis showed that, in some cases total suspended solids and oil content exceeded the recommended limit, which might contribute to reservoir permeability decline. XRD analysis of the reservoir core samples revealed that fines and expansive clays are the main components. The core flooding experiments demonstrated that reservoir pore throats get plugged due to two main factors; the suspended solid particles present in the injected water and swelling clays present in reservoir core samples. The formation damage simulator showed that fines migration and clay swelling are the two main possible formation damage mechanisms. To enhance the water injectivity process, the use of a clay swelling inhibitor along with a filtration system to remove suspended particles in the injected water are recommended for the reservoir studied.
Nimr Polymer Project: the Results of Multi-Well Trial in the Medium-Heavy Oil Reservoir with Strong Bottom Aquifer
Authors: Mjeni Rifaat , Gharbi Mohammed , Lawati Sakeena , Dickson Sara-Jane , Ismaili Abdul Rahman , Hashmi Mohammed , Amri Ibrahim , Belushi Khalid , Farajzadeh Rouhi , Glasbergen Gerard , Karpan Volodimir , Anand Adi , De Kruijf Sander , Lomans Bart , Wever Diego 
Published: March 2022

Abstract
Efficient production of heavy oil from the reservoirs with strong bottom aquifer has proven to be a challenge. While providing enough energy to produce the field under the primary depletion, the strong bottom aquifer in combination with unfavorable oil/water mobility contrast leads to rapid development of water coning thereby limiting oil recovery. Drilling of long horizontal producing wells in the upper part of the oil column maximizes the distance from the aquifer and allows relatively high production rates. This slows down the water cone development and increases primary recovery. Even with further optimization of the primary production, the recovery factor remains relatively low and consequently application of Enhanced Oil Recovery (EOR) techniques is required to increase the recovery.
Сrude oil from Nimr-E field is medium-heavy with the viscosity of 250-700cP under reservoir conditions. The field has been developed with mostly horizontal producing wells with relatively short inter-well distance. Due to strong bottom aquifer the reservoir pressure is maintained at the initial level despite the production under primary depletion. To increase the recovery factor polymer flooding was selected with expectation to increase the recovery by 5-10%. A field trial was conducted to understand the influence of polymer injection on oil recovery and address major uncertainties identified as key enablers for the full-field project. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives.
The paper presents field data of polymer injection trial in Nimr field and focuses on the performance results and principal operational challenges. The injection of polymer resulted in the incremental oil production that was assessed using field data and simulations. A significant increase of initial oil production and clear watercut reversal due to polymer injection was observed and incremental recovery reached approximately 7% of the initial oil in place. Injectivity issues encountered in the pilot wells were mitigated by the techniques and chemicals developed to solve the issues. The results prove the subsurface and operational success of polymer field trial that leads the way to a commercial development.
Velocity Strings in Sultanate of Oman Gas Fields; A Case Study
Authors: Janusz Norbert 
Published: March 2022

Abstract
Petroleum Development Oman operates large amount of gas wells in Sultanate of Oman. Due to the liquid loading occurring in these ageing assets, PDO has already installed 110+ Velocity String completions in the various gas fields across the concession area. In the 2015–2019 period, 39 wells in the Saih Rawl field were retrofitted with Velocity Strings. This paper presents the integrated and standardized approach to Velocity String candidate selection and compares the production performance post-installation against the forecast.
Evaluation of Organic Acids Implementation in Stimulating Tight Gas Reservoirs: A Case Study on Sarah Sandstone Formation
Authors: Elsheikh Ellewa Ahmed , Moawad Taha , Alnetaifi Ali , AlQuraishi Abdulrahman , Almutawea Yusuf 
Published: March 2022

Abstract
Sandstone formations are yet stimulated with mud acid when matrix acidizing is most competent. In terms of high-pressure high-temperature (HP-HT) conditions, the corrosive impact of hydrochloric (HCl) acid prompted the need to explore other alternatives to mud acid. This study examines the efficiency of organic acids in stimulating Sarah sandstone, a tight gas formation of potential.
Two Berea cores were first exploited to investigate the optimum and most efficient injected acid volume. The mineralogy of Sarah formation was identified using X-ray diffraction (XRD) aided by Scanning Electron Microscopy (SEM). Formation mineralogy led to the selection of acetic-HF and oxalic-HF as proper acids for stimulation experiments. Bentonite water-base mud was used to alter the permeability of three fresh Sarah sandstone core samples. The organic-HF acids were used to stimulate two core samples, while mud acid was tested in the third core for comparison. Energy-dispersive X-ray spectrometer (EDX) and SEM were utilized to study the impact of acids on porous media.
Experiments conducted in Berea core samples led to the execution of five pore volumes (PV) of preflush and one PV of main treatment as the optimum volume during the acidizing trials. XRD and SEM identified pore-filling clay minerals causing the low permeability of Sarah formation. Furthermore, the water-base mud injected decreased the permeability further by 80%. Oxalic-HF and acetic-HF mixtures recovered the initial permeability of core samples by 46% and 35% respectively. SEM-EDX results showed how organic acids have partially unblocked the pathways of the structural pores leading to permeability enhancement.
This research not only recommends the use of oxalic-HF acid for acidizing Sarah sandstone formation but also spotlights the ability of organic acids employment as preflush in hydraulic fracturing operations.
On the Importance of Reservoir Rock Mineralogy on Design and Performance of Surfactant-Based EOR Processes
Authors: Guillon Valentin , Delamaide Eric , Rousseau David , Morvan Mikel 
Published: March 2022

Abstract
Chemical EOR processes based on surfactants are highly constrained by chemicals losses due to retention in porous media. Surfactant adsorption is usually considered as the main retention mechanism. It can lead to a decrease in process efficiency and to an increase in costs. Among the factors impacting surfactant adsorption – namely reservoir rock mineralogy, brine composition and chemicals types — mineralogy is known to be prominent with an impact that is hard to predict and should be dealt with. This paper presents a comprehensive review on the importance of reservoir rock mineralogy on laboratory design and performance evaluation of surfactant-based EOR processes, using several field cases as illustrations.
First, the main effects of the various factors quoted above on surfactant adsorption will be presented. Then a summary of the mitigation strategies that can be applied on field, based on either brines treatments, chemical selection or specific injections processes, will be presented.
Four representative cases studies of Surfactant-Polymer process design and evaluation at the lab scale on different mineralogies and conditions will be discussed. Each of them exhibits specific hurdles and requires solutions to mitigate mineralogy impact on designed process. Oil recovery corefloods on reservoir rock were conducted with surfactant in effluent and oil production measurements. Mineralogy analysis were also conducted using XRD, SEM and NMR experiments.
The first case focuses on a low clay – low temperature sandstone, an apparently simple case which nonetheless shows a very high and unexpected surfactant adsorption due to a very particular clay repartition. The second case focuses on a high clay — high temperature sandstone: this expectedly difficult case was mitigated by the use of adsorption inhibitors, leading to a good oil recovery and a low adsorption. The third case focuses on an unconsolidated – low clay sandstone containing heavy oil which shows a pronounced sensitivity to fine mobilization by surfactant-polymer process. The selected solution was an adapted brine treatment. The last case focuses on a high temperature carbonate which classically shows high adsorptions. A combined process using brine treatment and adsorption inhibitor resulted in particularly low surfactant adsorption of 60 μg/g.
Mineralogy is shown to be a key factor that controls surfactant adsorption in chemical EOR processes. Using representative mineralogy in the lab feasibility studies is therefore mandatory to design relevant Surfactant-Polymer processes. This review demonstrates that efficient strategies can be developed to mitigate the impact of mineralogy on SP chemical EOR processes in a wide range of challenging conditions.
Chemical Enhanced Oil Recovery and the Dilemma of More and Cleaner Energy
Authors: Farajzadeh Rouhi , Eftekhari Ali Akbar , Kahrobaei Siavash , Mjeni Rifaat , Boersma Diederik , Bruining Hans 
Published: March 2022

Abstract
We develop a method based on concept of exergy-return on exergy-investment (ERoEI) to determine the energy efficiency and CO2 footprint of polymer and surfactant enhanced oil recovery (EOR). This integrated approach considers main surface and subsurface elements of the chemical EOR methods. The main energy investment in oil recovery by water injection is mainly related to circulation of water with respect to exergy of the oil produced. At large water cuts of &gt;90%, more than 70% of the total invested energy is spent on pumping the fluids. Consequently, production of barrels of oil is associated with large amounts of CO2 emission for mature oil fields with large water cuts. Our analysis shows that injection of polymer increases the energy efficiency of the oil recovery system. Because of additional oil (exergy gain) and less water circulation (exergy investment), the project-time averaged energy invested (and consequently CO2 emitted) to produce one barrel of oil from polymer flooding is less than that of the water flooding at large water cuts. We conclude that polymer injection into reservoirs with high water cut can be a solution for two major challenges of the transition period: (1) meet the global energy demand via an increase in oil recovery and (2) reduce the CO2 footprint of oil production (more and cleaner oil). For surfactant-polymer EOR, the extent of improvement in energy efficiency depends on the incremental gain and the simplicity of the formulations.
Drilling Optimization in the Low-Resistive, Thin-Layer Reservoirs of Northern Oman
Authors: Awadalla Muhannad , Vasquez Bautista Ramiro Oswaldo , El Hawy Ahmed , Beche Amina , Elkarim Ahmed , Al Ghaithi Ghaida , Al Maktomi Assad , Sanchez Gonzalez Vanessa Carolina , Al Rashdi Hussain , Al Nummani Hafidh , Al-Khalil Hashemi , Omairi Shatha 
Published: March 2022

Abstract
Ultralow-resistivity reservoirs, common in Oman, are frequently encountered when drilling wells at the flank of an infill field with nearby oil/water contacts (OWC) in a reservoir sweet spot window of 1 to 2- m true stratigraphycal thickness (TST). An integrated solution developed to better position the wells in this type of reservoir has resulted in successful cases on net-to-gross (NTG), which exceeded expectations in terms of wells production and well deliveries.
Integrating resistivity propagation curves response with directional resistivity curves (distance- to- boundary curves) response allows for optimizing well placement and assists in determining the best approach of well objective during drilling. Once drilling the lateral section began, a careful evaluation of the distance-to-boundary service tool inversion and directional measurements were performed in addition to conventional resistivity curves evaluation. This procedure ensured accurate placement of the well; thereby, avoiding water contact.
Drilling optimization in long lateral sections has been carried out by optimizing bottom hole assembly (BHA) design, bit selection, and drilling parameters, taking geo-mechanics and geological uncertainty factors into consideration.
Hard Rock Horizontal Drilling—Using Mechanical Specific Energy, Downhole Vibrations Analysis, and Well Design to Optimize Performance
Authors: Heidari Varnamkhasti Mohammad Reza , Al Hinaai Qasim , Patil Ravindra , Al Lawati Ali Baqir , Al Ghasani Rashid , Vasquez Bautista Ramiro Oswaldo 
Published: March 2022

Abstract
This paper presents a deep horizontal drilling campaign with the goal of eliminating several inefficiencies restricting the drilling performance, including downhole drilling bit or tool failures. The operator and the service company identified the inefficiencies by using engineering methods to overcome the challenges. Since 2013, the operator had been drilling horizontal wells with 600 to 1000 m of lateral targeting deep gas sandstone multilayer reservoirs with 15 to 35 kpsi unconfined compressive strength. The focus in the campaign will be from the kickoff point in the 8 3/8-in. section to the total depth (TD) of the well. Well-1 performance was greatly affected by the issues related to the wellbore instability in the build section, which dictated a change in the well program from the original fat to slim design. Later, other challenges and drilling inefficiencies resulted from this change, causing Well-6 design to be switched back to the original fat design to improve wellbore stability by having proper mud weight and other mud properties, bit and drive systems selection, as well as the drilling practices. Mechanical specific energy (MSE) is an industry recognized optimization tool to evaluate the drilling efficiency (Teale 1965) but it does not identify the sources of the inefficiencies (Chen 2019). The MSE, in addition to the downhole high-resolution drilling dynamics data, have been used to identify not only the drilling dysfunctions but also to help find the sources. This method supports the decisions for a change in the well design, bit, or the drilling practices, which in turn reduces the total number of runs and the downhole tool failures or damages.
The improvements in drilling the horizontal wells since the campaign began are significant; i.e., Well-1 was drilled in approximately 165 days in 2014 while Well-6 was drilled in 49 days in 2017, which was 39 days ahead of the well plan with the majority improvements occurring in the last section. Well-6 is considered to be the most efficient Barik formation horizontal well drilled in Oman to date.