bluuebunny/crossref_metadata_2025_split huggingface dataset:
Will Hydraulic Fracturing Enhance the Production Recovery in a Complex Comingled Water Flood Field?
Authors: Kindi Muktar , Hamm Carmen , Kindi Said , Al Toqi Shaymaa , Breiki Majdi , Saadi Zuwayda , Harthy Abdullah , Jahwari Mohsin , Gheilani Hamdan , Al Farsi Shaymaa , Suchta Bogdan , Persac Stephen 
Published: March 2022

Abstract
This paper discusses the outcome of a hydraulic fracturing concept in a complex commingled water flood field with dense infill well spacing. The objective was to prove this concept of fracturing in a graywater flood field to improve oil production and increase the recovery factor.
A mature oil field in the central Sultanate of Oman is facing production decline. The flank part of the field is not meeting the expected production even with water flooding. The main challenge is how to communicate between the injector wells and the producer wells. The 5-spot patterns are not showing effectiveness in the flank area. The heterogeneous reservoir complexity and tightness are the main factors for that. The water zones are very close to or imbedded in between the reservoirs.
A careful candidate selection exercise was conducted from the field's 140+ wells. Factors assessed included spacing between producers and injectors, multiple commingled reservoirs, proximity to the Oil Water Contact (OWC), and petrophysical parameters.
A successful fracturing trial in one of the wells, located in the southern part of the field and five kms away from nearest oil producer, was followed with a selection of fracture candidates inside the main field. The method of selection was to gather all well data and select criteria to narrow the list to those wells with a higher success probability to help prove a new concept of fracturing in the middle of water injectors and oil producers by controlling fracture length propagation and height containments. A candidate was selected and the fracturing design was manipulated with different scenarios to overcome challenging oil water contact and control fracture propagation to avoid nearby producers and water injectors. The fracture was design selected and the operation successfully implemented, which resulted in a contained fracture confirmed by the low water cut, salinity results, and the radioactive tracer. One lesson learned from the first fractured well was that the pump design should be optimized to sustain a new production profile after the fracture treatment. Triple production resulted from the initial production stage and a fracturing proposal was prepared to follow the success of the operation.
Deployment Strategies for Effective Hydraulic Fracturing Vertical, Highly Deviated and Horizontal Wells Across Challenging Differential Depleted Tight Gas Formations in Oman
Authors: Chavez Florez Jua Carlos , Fathy Abdelazim Mohamed , Bahri Khalfan , Al-Yaqoubi Mazin , Abri Ahmed , Hinai Adnan 
Published: March 2022

Abstract
Oman tight gas accumulation has been initially developed with fractured vertical wells targeting up to 10 different hydrocarbon units, as well as with dedicated highly deviated to horizontal wells targeting the most tighter zones. The intrinsic geomechanical, petrophysical and lithological heterogeneities of this tight units impact not only the fracture conductivity distribution but the drainage efficiency of the fractured zones, this is observed as mobility variations across this unit impact their contributions once all become commingle, with the areas of higher mobility dominating the total gas well production, this for all wells architectures.
This paper will discuss fundamental formation characterization requirements to assess in-situ stress dynamic variations during the life of the field; incorporating formation pressure points as integral part of the drilling program and in-situ stress measurements supported by comprehensive mini-fracture data evaluation. The use of radioactive tracers in combination with production logging were implemented to assess containment and fracture prediction, providing this an essential tool to determine fracture propagation behavior, deployment strategy and final conductivity distribution. It will be described the logging requirements as well as the lab characterization needed to determine key elastic properties to assess the hydraulic requirements for fracturing individual units or combination of them.
It will be discussed how variations on pore pressure and stress profiles, as the field developed, will impact perforation and fracture strategies for vertical, highly deviated and horizontal wells. It will be presented how increase of pressure confinement affects the in-situ elastic properties as depletion is experienced on specific gas units, inducing alterations on stress and net pressure profiles that impact fracture propagation and final conductivity distribution, this becomes of particular importance on highly deviated and horizontal wells where vertical connectivity with all hydrocarbon units is fundamental to maximize recovery.
Finally, it will discuss the methodology used for fracture deployment considering the differential depletion expected during the field development and its impact on completion integrity and fracture implementation strategies. We will share the identified best practice that will lead to optimum fracture development while maximize investment.
Enhanced Oil Recovery in Naturally Fractured Reservoirs: State of the Art and Future Perspectives
Authors: Delamaide Eric , Batôt Guillaume , Alshaqsi Abdulaziz , Alkindy Abdullah , Al-Mejni Rifaat 
Published: March 2022

Abstract
In Naturally Fractured Reservoirs (NFRs), production rate quickly drops once the oil in the fractures is produced. Indeed, high connectivity of the fracture network soon requires the application of IOR/EOR methods to unlock production from the low permeability matrix blocks which bear the major part of the oil in most carbonate-NFRs. This paper is intended as a thorough review of the EOR field tests in such reservoirs and discussion of the physical mechanisms at stakes.
To the best of our knowledge there has never been any review dedicated to EOR methods specifically applied to NFRs. After a description of the main mechanisms involved in these processes this paper proposes to revisit the EOR field tests performed in carbonate-NFRs based on the following technologies: Gas injection, thermal- and solvent-assisted production, and finally chemical EOR, the latter being seen as a way to improve the kinetic of oil recovery from the matrix: foam, surfactant-polymer, low-salinity and hybrid processes, including a discussion of the remaining challenges to successfully apply these more recent technologies in the field.
Beyond the fact that NFRs are quite interesting because of their complexity, they account for a large part of the world's oil proven reserves, approximatively 20%. Even though this value should be taken with caution, as it depends on the NFRs definitions and their characterizations, there are clearly significant amounts of oil trapped inside these reservoirs. For that reason, they are of great interest, both in terms of understanding and economical consideration for oil companies willing to get the most out of their fractured fields. Even when based on sound static and dynamic characterizations, production optimization of NFRs remains challenging: classical flooding mainly produces the oil contained in the fractures during the early stages of the field development. The high connectivity of the different levels of the fracture network along with the low permeability of the oil-bearing matrix blocks, combined with the often oil-wet nature of carbonate formations, are the three main factors at plays preventing the production of the remaining oil from the matrix blocks. Design of dedicated EOR solutions are needed and learning from past experiences through the review and analyze of the past field trials is of great value to that purpose.
This review and discussion will allow engineers to get an extended and up to date understanding of the features and drawbacks of the main EOR methods which could be applied to NFRs, and also provide some guidance in the selection or design of the best suited EOR solution to a specific naturally fracture carbonate field.
Foam for High Temperature and Ultra-High Salinity Conditions: Its Displacement Efficiency Under Different Permeability Heterogeneity
Authors: Yuan Chengdong , Pu Wanfen , Varfolomeev Mikhail A. , Hui Jian , Zhao Shuai , Zheng Xiaojie , Timofeeva Anastasia A. 
Published: March 2022

Abstract
Foam flooding is one of promising enhanced oil recovery (EOR) methods for waterflooded reservoirs due to its good mobility control capability. However, its application in high-temperature and high-salinity reservoir has always been a challenge. This work presents salt-tolerant foam that can be used at about 100 °C under the salinity of more than 200000 mg/L (Ca2+ + Mg2+ &gt;10000 mg/L). Its displacement efficiency was evaluated at different permeability heterogeneity conditions.
The surfactant (foaming agent) solution was prepared using reservoir formation water (total salinity 204672 mg/L, Ca2+ + Mg2+ 11480 mg/L) obtained from a reservoir in Tarim Basin, China. The displacement efficiency of foam was investigated in different permeability conditions (35.47, 72.72, 165.75, 265.28, 410.73, 600.38, and 950.11 mD) using single-core flooding experiment and in different permeability heterogeneity (permeability max-min ratio of 3.34, 6.62, 9.22, and 11.98) using parallel-core flooding experiments (one high-permeability core and one low-permeability core). For all flooding experiments, nitrogen foam was used by co-injection of nitrogen and surfactant solution.
For all permeability conditions in single-core flooding experiments, after water flooding with a 98% water cut, the injection of foam could increase the injection pressure. Foam injection together with its subsequent water flooding could yeild an additional oil recovery of 11.73, 12.35, 12.8, 13.04, 15.45, 16.04, and 17.51% under the permeability of 35.47, 72.72, 165.75, 265.28, 410.73, 600.38, and 950.11 mD, respectively. Obviously, the yielded additional oil recovery increased with permeability. Under the permeability max-min ratio of 3.34, 6.62, and 9.22, an addtition oil recovery can be yielded from both high- and low-permeability cores, but the additional oil recovery from low-permeability core was higher. This implies that the injection of foam can not only improve displacement efficiency after water flooding, but also can effectively increase flow resistance in high-permeability core, and thus improving oil recovery in low-permeability core. However, when the permeability max-min ratio was increased to 11.98, the oil in low-permeability core cannot be mobilized even after foam injection, which means that foam injection can effectively work only in a certain permeability heterogeneity condition. When permeability heterogeneity is strong, enhanced foam should be considered to increase the strength of foam using polymer (only for low temperature), gel or nanoparticles, etc.
The obtained results show that the developed foam formulation has a great potential for improving displacement efficiency and sweep efficiency in water-flooded heterogenous reservoirs with very high temperature and ultra-high salinity.
Autonomous Gas Shut-Off in Gas Oil Gravity Drainage Reservoir, Sultanate of Oman
Authors: Al Shibli Abdullah , Al Maamari Hilal , Griborio Csimiro , Adeponle Simeon , AL Wahaibi Hamed , AL Zuhaimi Khalid , Al Saadi Hamoud , Bdair Mohammad 
Published: March 2022

Abstract
FH is one of the largest oil producing assets in the Sultanate of Oman. With more than 30 years of production, the current recovery mechanism from the naturally fractured carbonates is relying 80% on the gas oil gravity drainage (GOGD) process whereby produced formation gas is re-injected into the reservoir for pressure maintenance. Optimizing the GOGD process and hence maximizing oil production is the main objective in FH WRFM strategy. Controlling the formation gas production from subsurface and surface gas capacity handling are the main challenges to unlock reservoir oil potential.
Down hole gas shut-off technology has been proposed in 2018 to control high GOR (+1000) producers and minimize formation gas production for more efficient GOGD process. The technology provides a mean for blocking formation gas through autonomous valve compartments installed within a production liner in the open hole section of the horizontal wells. The independent compartments are positioned against the open fractures and the inflow from the fractures to the open hole is controlled autonomously based on the fracture GOR. The valves in each compartment is designed to close against low viscosity fluid (gas) and allow high viscosity (liquids) to flow into the liner.
Screening process has identified up to 80 candidates for the technology with a potential gain of up to 6% of the total field production. Formation GOR, well uptime and lateral fracture interference are the top criteria for candidate selection. The full field deployment started in July 2018 after a six months trial period with a target to complete the full scope by 2022.
90% reduction in formation gas has been observed in the wells where gas shut-off technology have been installed. A sustainable oil gain up to 50% has been realized after the gas reduction from the first 14 candidates. In addition to that, a significant improvement in the well uptime from 40% to 80% has also been recognized due to low producing GOR after the technology deployment. The technology has also enabled the re-instatement of long term closed-in wells due to high producing GOR.
The originality of the technology lies on the ability of the downhole inflow control valves to react to the gas autonomously and successfully shut off the gas contribution and the same time allow oil to flow.
Hazardous Events Prevention and Management Through an Integrated Machine Learning and Big Data Analytics Framework
Authors: Cadei Luca , Rossi Gianmarco , Lancia Lorenzo , Loffreno Danilo , Corneo Andrea , Milana Diletta , Montini Marco , Purlalli Elisabetta , Fier Piero , Carducci Francesco , Nizzolo Riccardo 
Published: March 2022

Abstract
This paper reports the development and tests of an advance methodologies to predict Upstream plant risky events, such as flaring, applying an integrated framework. The core idea is to exploit Machine Learning and big data analytics techniques to tackle and manage both major upsets that would lead to significant inefficiency and loss. The tool is developed for complex upstream production system, where upset could be caused by a huge amount of heterogeneous factors, exploiting data driven monitoring systems to identify the weak signals of the upcoming events.
The framework proposed is mainly composed by a strong pipeline divided in 3 modules operating before (predictive phase), during and after the event. The former aims to reduce the probability of an event, the second works on the severity and the third one has a dual function: reporting upsets and feedback gathering system to be used to further improve the analytics implemented. The Predictive component alerts operators when it recognizes a dangerous pattern among the parameters considered. The other two components can support this one and can be exploited to detect early signs of deviations from the proper operating envelope, while predictive performances are not satisfying. Moreover, during an event occurrence, operators can promptly identify the causes of the upset through the entire production system. This allows a faster reaction and consequently a significant reduction in magnitude. The solution proposed provides 2 complementary methodologies:
an agnostic anomaly detection system, helping to map plant functional unit anomalous behavior, as a dynamic operating envelope, and identifying the most affected ones;
A real time root-cause analysis, as a vertical solution, obtained learning from the monitoring of the different specific functional unit;
The tool is also able to provide an automatic event register using information provided by the root-cause system, including operator feedbacks that will improve the performances of each module of the framework.
The entire pipeline developed has been applied on-line, working with real time data coming from an operating oilfield, with special focus on blowdown and flaring system. The robust architecture generated is able to overcome some main issues related to the complexity of Upstream production assets such as lack of data, quick dynamic of physical phenomena analysed and randomness of upsets. The first test demonstrates that the tool accuracy allows to identify and suggest actions on 35% of the most dangerous flaring events occurring. Moreover, the effectiveness increase significantly proving a real time root-cause analysis considering both strong and weak signals that cause dangerous overpressures through the treatment plant.
ESP Performance Enhancement and Premature Failure Reduction Through Esp Equipment Reliability Project in a West Kuwait Field - Case Study From Kuwait
Authors: Hassan Mohmaed , Nour Ahmed , Abdul-Aziz Wejdan , Al-Yaqout Thanyan , Al-Azmi Ali , Al-Hashash Budoor , Al-Methen Badriya , Abu-Eida Abdullah , Munoz Jorge , Al-Suwailem Lulwa 
Published: March 2022

Abstract
Most of wells in the major oil fields of West Kuwait Asset are producing with Electrical Submersible Pump (ESP). During 2012- 2013, the ESP premature failures reached high percentages of up to 30% of ESP population with high deferred oil.
In order to enhance the ESP performance and reduce the number of premature failed ESP, FD (WK) has initiated ESP Equipment Reliability Project in 2014. The main objective was to define a proper workflow that will be capable to identify the root cause of ESP premature failures, find the way forward and mitigation actions to overcome the issue.
All ESP business partners from KOC and service providers were involved in the project. Series of technical workshops following the API and KOC standards were conducted by the team members to analyze the ESP performance and premature failures where the team was able to define analytical workflow in the early review sessions to conduct the required work.
The workflow takes in consideration the reservoir parameters and conditions, ESP performance with all tags and signatures, ESP systems from the overhead electrical line or generator, surface equipment down to ESP down hole equipment specifications, installation and pull-out procedures, and ESP operating conditions. Also attending the tear down of the failed wells to ensure the vendors procedures and the reported findings. In-addition, well models were utilized to find the deviation between the design and actual parameters and surface network model was utilized to define the impact of the pipeline issues on the ESP performance.
Based on this study, the root cause of the ESP premature failures were found to be mainly due to; Power Quality, Sour condition, External sand source, Down hole emulsion, and some Equipment quality / specifications that were not designed to handle the down hole conditions of UG wells.
A mitigation plan and list of recommended actions were concluded and implemented with a measure of the outcome and results in addition to some modifications that were applied within time.
The project shows excellent results with time where the premature failures reduced from 30% in year 2012- 2013 to 12% in year 2018. Also the ESP showed enhanced performance over time. Extra room for improvement can be chieved by enhancing the power quality of the overhead lines and generators.
Applying the mentioned workflow with the proper project structure form will help ESP stakeholders to identify the root cause and not the failure reason, Hence reduce premature failures. This will lead to reduce deferred oil, reduce cost per barrel, and avoid equipment compensation fees.
Innovative Perforating Strategy Saves Completion Cost and Improves Production in Tight Gas Sandstone Reservoir
Authors: Almulhim Abdulrahman , Tarihoran Anton , Hamid Saad , Zaouali Zouhir 
Published: March 2022

Abstract
Tight Gas reservoirs require fracturing as part of the reservoir exploitation strategy. The quality of perforations play an important role in establishing effective contact with the reservoir prior to fracturing. Several perforating technologies have been used and evaluated to optimize operations and saving completion costs. This practice has provided a wealth of data to analyze the most efficient strategy for tight gas reservoirs. An optimized perforating method has been implemented recently in fields that traditionally required hydraulic fracturing to bypass drilling damage and produce commercially.
Combining deep penetration charges with an instantaneous underbalance is the key ingredient for this method. The method results in achieving maximum reservoir contact, away from washouts, breakouts and damaged zone; thereby, delivering clean perforation tunnels and higher entrance hole diameter. In cases, where the productivity is limited by extremely low permeability and hydraulic fracturing becomes inevitable, the benefits extend to the fracturing operation in terms of lowering the breakdown and treatment pressures, improved treatment rates, effective proppant placement and minimizing the likelihood of pre-mature screen out. The paper outlines the detailed workflow including candidate recognition, treatment design, execution and evaluation leading to significant savings in operating expenditure. The paper also provides a comprehensive comparison with other perforating practices and evaluate their effectiveness.
The results obtained through deployment of this method on several wells are extremely encouraging. The wells were able to produce naturally, exceeding production expectations. As a result, significant time and cost savings were realized by eliminating subsequent production operations and well intervention work. The pressure transient analysis showed low skin pointing towards insignificant near wellbore damage.
This innovative method improves the way perforations are performed. Encouraged by this success, additional candidates are being evaluated with similar approach with an objective to optimize completion costs and improving initial production.