bluuebunny/crossref_metadata_2025_split huggingface dataset:
Challenges & Mitigations in a Matured Gas Field in the Sultanate of Oman
Authors: Yahyaai Faisal , Lawati Basayir , Abri Sara , Salmi Maryam , Razvi Mohamed , Mahruqi Salha , Winchester Arlene , Maartje Koning 
Published: March 2022

Abstract
The SN-Deep field is located in the central area of the Sultanate of Oman, 20 km west of the Qarn Alam (QA) station and is operated by the Gas Directorate. The field consists of three deep sandstone reservoirs with rich and lean gas fluids. 50% of GIIP has been produced resulting in significant pressure depletion. This paper will:
Illustrate the WRFM approaches used to manage some of the late life of the field challenges such as sand production, water breakthrough, and scale formation, which were not predicted during the fields’ development phase. Enhanced field production recovery through new technologies to unlock additional reserves.
Extensive well, reservoir, and field management (WRFM) interventions have reduced the field's production decline and sustained the production performance through the following:
Water producing wells – analytical techniques are used to predict water production and forecast which wells are expected to reach critical rates. Resources are therefore allocated yearly for wells expected to show significant water production, limiting well down time. In addition, velocity strings with water shut-off are deployed to minimize deferment and cost. During interventions, wells with additional behind casing reserves volumes are also produced. Foam assisted lift (FAL) and permanent installation has been used as secondary means to reduce additional hydrostatic heads for wells with high water production. A trial with FAL on some wells showed sustainable gas rate with high WGR after foam injection. Scaling and salting – to prevent declining production potentials, proactive fresh water bull heading is used to treat symptomatic wells. The technique and the frequent well interventions were able to reduce the deferment and the need for other expensive resources. Solids production – sand production in the field is managed via implementing an integrated sand management strategy that covered all aspects related to required investigation, arresting, and control monitoring.
Hydraulic Fracturing Challenges and Solutions for the Development of a Low Permeability Oil Reservoir – Case History from Offshore West Africa
Authors: Tassone Gianluca , Giammancheri Michele , Banoori Saadoun , Parziale Sabino , Mittiga Vincenzo , Ilyasov Robert , Dupouy Nicolas , Reilly Brett 
Published: March 2022

Abstract
The operator in West Africa embarked upon the "N" field offshore development in 2016 with 13 multi-stage horizontal wells being fracture-stimulated in Phase-I, with further wells being planned in next development phases. Due to the complex nature of the reservoir, which is a multilayered sandstone characterized by high heterogeneity and low permeability, wellbore connections are often located in structurally altered areas with high presence of faults. The unpredictable local re-orientation of the stresses has resulted in complications for the fracturing operations with multiple fractures being induced. This paper presents the challenges and solutions implemented for delivering more consistent fracturing execution and well productivity improvements.
The horizontal wells in the "N" field were hydraulically fractured using the "plug-and-perf" method with up to four fractured intervals. The quality of the near-wellbore connection and the observations of complex near-wellbore fracture geometries have hindered far-field proppant distribution and limited maximum proppant concentration inside the fracture. When fracturing this tight formation, controlling the opening of the pressure-dependent multiple fractures was identified as a critical issue. An engineering breakdown process and adapted frac strategy was implemented to minimize the multiple fractures generated at the formation.
For the early hydraulic fracture treatments performed, conservative treatment designs were applied in order to avoid premature screenout with the consequence of increasing operative time. Implemented solutions have shown to improve the near-wellbore connections and increase well productivity. The successful outcomes are attributed to the implementation of improved perforating strategies, the optimization of fracturing fluid performance, an engineered fracturing breakdown process, and the development of a frac decision tree for improved decision making. The hydraulic frac strategy has been tailored well-by-well depending on the reservoir conditions (e.g. faults, permeability thickness, contacts), and on the operational conditions interpreted from the diagnostic injection tests (e.g. near wellbore tortuosity, net pressure). The holistic implementation of these new concepts for hydraulic fracturing and field development have delivered positive production results beyond initial expectations.
For the horizontal wells intersecting the deep low permeability "D" reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques and unique solutions applied for each fracturing stage.
A Self-Adaptive Artificial Neural Network Technique to Estimate Static Young's Modulus Based on Well Logs
Authors: Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin , Ali Abdulwahab , Moussa Tamer 
Published: March 2022

Abstract
Static Young's modulus (Estatic) is an essential parameter needed to develop the earth geomechanical model, Young's modulus (E) considerably varies with the change in the lithology. Recently, artificial intelligence (AI) techniques were used to estimate Estatic for carbonate formation. In this study, artificial neural network (ANN) was used to estimate Estatic for sandstone formation.
In this study, the ANN design parameters were optimized using the self-adaptive differential evolution (SaDE) optimization algorithm. The ANN model was trained to predict Estatic from conventional well log data such as bulk density, compressional time, and shear time. 409 data points from Well-A were used to train the ANN model which was then tested using 183 unseen data from the same well and validated on 11 data points from a different well (Well-B).
The developed SaDE-ANN model estimated Estatic for the training data set with a very low average absolute percentage error (AAPE) of 0.46%, very high correlation coefficient (R) of 0.999 and coefficient of determination (R2) of 0.9978. And the Estatic values of testing data set were estimated with AAPE, R, and R2 of 1.46%, 0.998, and 0.9951, respectively. These results confirmed the high accuracy of the developed Estatic model.
The Dynamic Performance Evaluation of the New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Injection Fluids
Authors: Moradi Mojtaba , Todman Steven 
Published: March 2022

Abstract
Several techniques have been applied to improve fluid conformance of injection wells to increase water flooding performance and eventually field oil recovery. Normal outflow control devices (OCDs) are effective solutions for this problem in reservoirs with static properties, however, they fail in reservoirs with complex/dynamic properties including growing fractures. There, the continuously increasing contrast in the injectivity of a section with the fractures compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone thus creating short-circuit to the nearby producer wells.
A new autonomous outflow control device (AOCD) has been developed recently to choke the injection fluid into the propagating fractures crossing the well autonomously after reaching a designed flowrate thus maintaining a balanced/prescribed injection distribution. This work focuses on modelling design workflow to find the optimum completion design and demonstrates its added value through an extensive dynamic reservoir simulation study. Like other OCDs, this device should be installed in several zones in the injection well. The device is a bi-stable flow control device with two operating conditions, one, devices operate as normal passive OCDs initially, and two, if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This allows the denied fluid to that specific zone to be distributed among the neighbouring zones. This performance enables the operators to minimise the impacts of thief zones on the injected fluid conformance and to react to a dynamic change in reservoirs properties specifically the growth of fractures. This also reduces the injection cost and improving the reliability of the injection well systems.
A sector reservoir-model coupled with a Geomechanics model via commercial reservoir simulation software was established to study the impacts of temperature and flowrate of injection fluids on the performance of injection wells completed with various completions. The simulation study showed less imposed pressure and much more efficient fluid conformance and fracture growth was delivered with the new device compared to various other completions. The results showed how the new device may change the sequence of thermal fractures initiation and the extends of their growth. This autonomously reactive control on the injection fluid conformance resulted in an increased sweep and ultimate oil recovery (up to 20%) while reducing the total volume of injected fluid (by 30%), so significantly increased field NPV. This study illustrates how efficiently the new injection valve chokes/restricts water into dynamic thief zones in a reservoir. This new device is autonomous and reacts to the rate of fluid passing through and eliminates the cost of alternative techniques including running PLT and following intervention actions.
Polymer Stability at Harsh Temperature and Salinity Conditions
Authors: Skauge Tormod , Ormehaug Per Arne , Alsumaiti Ali , Masalmeh Shehadeh , Skauge Arne 
Published: March 2022

Abstract
Polymer flooding has a large potential for unlocking EOR reserves in carbonate reservoirs in the Middle East. ADNOC has developed an EOR roadmap to realize some of these reserves. A milestone on this roadmap is to identify and verify polymers that have good performance at high temperature and high salinity conditions.
The reservoir conditions include temperatures in the range of 100 – 130 ºC and formation brines of more than 200 000 ppm TDS with high concentrations of divalent ions in carbonate rock. These conditions have been beyond the limitations of synthetic polymers and most biopolymers. Here we report thermal stability measurements performed at anaerobic conditions for a number of synthetic polymers at high temperature, high salinity (HTHS) conditions. A custom thermal stability chamber and flooding rig was designed and produced where storage and measurements were performed without contact with oxygen or iron.
A series of synthetic polymers with different ratios of the monomers amide, acrylate, ATBS and NVP were tested for temperature stability for up to 2 years at 120 ºC. Shear viscosity was measured frequently from the start while the time between tests was increased after trends in viscosity versus temperature was established. The viscosity was determined by measuring the differential pressure over a long coiled tubing. Three different brines ranging from ~200 to ~180 000 mg/L TDS were used as solvents. The results show that polymers with a low degree of ATBS and/or NVP have poor stability at the combined conditions of high temperature and high salinity and degrade within a short time. Polymers with a high degree of ATBS showed good stability at HTHS conditions. For these polymers high salinity improved stability, probably by stabilizing polymer conformation.
In this paper, we report thermal stability at HTHS conditions for a number of polymers using a custom designed thermal stability chamber and flooding rig for storage and viscosity measurement. The design gives significant improvement over other methods where samples are either removed and exposed to air during measurement or opened to inert atmosphere during measurement. Polymers stable at HTHS conditions were identified, expanding the boundaries for polymer EOR applications to carbonate reservoirs with temperatures up to 120 ºC and high salinity formation water.
Post-Frac Clean Up and Testing Optimization
Authors: Al Shidhani Ruqia , Al Shueili Ahmed , Shehab Ragab , Masood Nabeel 
Published: March 2022

Abstract
The Oil and Gas industry currently faces the dual challenge of meeting the global energy demand with minimal carbon footprint. The Barik formation is a tight to low-end conventional reservoir in Khazzan/Ghazeer Field (Block 61) in the central of the Sultanate of Oman. The field requires hydraulic fracturing to economically produce the wells, in which chemicals and proppant are pumped into the formation. Each well requires a period of clean up after pumping the frac and before connecting it to the facility in order to get rid of all the undesirable material from entering the processing facility. During this clean up and testing period, all produced gas and condensate are flared in the atmosphere.
This paper presents an optimization project which was implemented in Khazzan and Ghazeer fields in Block 61 to optimize the post frac clean up and testing period in order to reduce hydrocarbon flaring and CO2 emissions as well as reducing the testing cost, without compromising the overall well clean up and testing objectives.
The optimization project was originally started in 2015 where the clean-up and testing period was reduced gradually by optimizing the well bean up schedule (choke management and duration for each choke).
Addressing Challenges for Consistent Improvement of Cement Bonds in South Oman Fields
Authors: Meza Gluber , Satti Samiullah , Al-Sabti Hashem 
Published: March 2022

Abstract
Short liner cementing is very common in Oman southern oil fields. Among the challenges one can find no mechanical separation between the fluids, cement and pre-flush volumes are relatively small leading or increasing the chances of contamination and requiring remedial cementing jobs with uncertain success.
As a result, poor cement bond log across the liner section were observed in more than 80% of all the cementing jobs.
An engineering approach was proposed for this scenario. First increase rheologies of the fluids using physics instead of chemistry to diminish the fluid contamination inside of the casing and create a better sweeping effect outside of the casing. Selecting the adequate solid size ratios of the weighting agent to reduce the possible loss circulation problems generated by higher friction pressure. Increasing the generation and ultimate compressive strength of the cement system and finally providing expansion properties to the set cement.
This paper presents the field CBL/USIT logs results and a case study showing the application and effectiveness of the technique proposed comparing with the previous approach in different wells.
Addressing the Challenges of Hydraulic Fracturing Vertical Wells in Differential Depleted Tight Gas Accumulations in Oman
Authors: Al Bahri Khalfan , Chaves Juan , Al Hinai Adnan Saif , Al Sulaimani Ahmed Abdullah , Nunez Alvaro Javier 
Published: March 2022

Abstract
Hydraulic fracturing has been a key technology enabler for the development of tight gas formations in Oman. This tight gas accumulation has been developed with the supported of vertical wells, fractured at different depth covering up to 10 different hydrocarbons units. 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. It was anticipated that depletion of the higher mobility units will impact and change the contribution dynamics of the commingle production. However, this is only one dimension of the challenges to be considered as part of the hydraulic fracture strategy during the field development.
This paper will be focus key operational challenges and the 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 wellbore stability evaluation and mini-fracture operations. It will be presented how variations on pressure and stress profiles, as the field developed, will impact the perforation and fracture strategies as well as pressure operating envelop to assure well integrity.
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 increase of pressure confinement potentially affects the in-situ elastic properties as depletion is experienced on specific gas units, inducing alterations on stress profiles that impact fracture propagation and final conductivity distribution. 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. Key operations covering plug milling, post fracture clean out and well lifting will be also discussed.
Finally, it will presented key observation that can be implemented as part of methodologies used for fracture deployment on differential depletion formation, this leading to optimum field development while maximize investment.
Cheaper and More Effective Stimulation of Horizontal Polymer Injectors in South Sultanate of Oman
Authors: Harrasi Ameera , Urdaneta Gerardo , Al-Jumah Ali , Nasif Mohammed , Qassabi Hajir 
Published: March 2022

Abstract
The multidisciplinary Authors summarize the lessons learned from stimulating a long horizontal Polymer Injection well with a Hoisting Unit; the main objective was to reduce the associated cost as compared to a Coiled Conventional Tubing (CCT) Unit, but achieving the same or even improved results. The details procedures for conducting this type of job is summarized in this paper.
The well was completed with a smart completion, creating four distinguished zones, Earlier, bullheading approach was carried out, but later on when the smart completion failed, it was necessary to stimulate with a CCT to cover all the different zones in the long well section. This has caused a sharp increase in the price of the job. Hence, a trial has been carried out utilizing a Hoist, with improved acid recipe that is cheaper and better in performance as compared to earlier. The detailed procedure for conducting this type of job is summarized in this paper
The tables show the injectivity test result in three stages, in the Hoist and the CCT approach the result shows a good improvement after main treatment and a success of the trial with Hoist as compared to CCT. This has proven to be economically viable and unlocked huge cost savings for all future stimulation jobs. A 50% reduction in the total cost is observed. This work has concluded a successful methodology in the utilization of a hoist in performing multi-stage stimulation in long horizontal wells. Very encouraging results have been observed and the suggested method is highly recommended, further trials will continue to be done with other wells
The authors believe the learnings from these trials are of great benefit and will add to the state of knowledge of the industry relating to stimulating long horizontal wells
Field Tests with a Multi Chamber Flotation Technology: Advanced Water Treatment in EOR Polymer Operation
Authors: Grillneder Roland , Marx Markus , Jamek Karl , Rodriguez Wiston 
Published: March 2022

Abstract
Cost-effective treatment of produced water is crucial for the implementation of EOR technologies. A multi-chamber flotation unit was tested under real-field conditions for a polymer flood of the Matzen field, Austria. The operating conditions, performance, and potential for cost-effective separation were successfully assessed with HPAM polymers for a concentration up to 800 ppm.
In order to evaluate the performance of the flotation technology, a comprehensive test matrix for a widespread operating envelope was defined. Characteristics of the feed water were varied by selecting specific production wells from the Torton reservoir. Consequently, a wide range of retention times, oil-in-water contents, oil droplet size distributions, and EOR polymer concentrations were tested. The unit was operated with and without the application of a water clarifier. Performance was evaluated by measuring inlet and outlet water quality parameters via laboratory analyses and an in-line monitoring device. The impact of EOR polymer on the treatment efficiency clearly indicated a turning-point of treatment efficiency dependent on polymer concentration. Produced water conditions of polymer flooding operations are considered harsh due to the impact on oil droplet coalescing behavior and impacted viscosity. The influence of oil droplet size and shearing of polymer versus the impact of retention time on effectiveness was assessed. On-site core-flood tests were performed to evaluate the injection behavior of treated water with different HPAM polymer concentrations and in combination with and without a water clarifier.
Geochemical Investigation of Water Composition Effect on Formation Damage and Related Oil Recovery in Carbonates
Authors: Khurshid Ilyas , Al-Shalabi Emad W. , Alameri Waleed 
Published: March 2022

Abstract
Several benefits of low salinity/engineered water injection (LSWI/EWI) have been reported in the literature including its ability to increase oil recovery at low cost and with least environmental impact. However, the related reservoir-engineering problems to these techniques such as formation damage and fluid mobility control are still uncertain and have not been thoroughly investigated. This study investigates the effect of water composition on formation damage and the related oil recovery from a geochemical prospective.
The study presents coupling of the IPhreeqc geochemical engine with Matlab to simultaneously solve the oil-water multiphase flow and the related geochemical reactions. Using this coupling technique, the geochemical capabilities of Phreeqc were successfully incorporated in a multiphase flow simulator. The latter enabled modeling of reactive transport and formation damage in subsurface multiphase reservoir. The results showed that the temperature, sulfate concentration, and dilution of injection water have a pronounced effect on formation dissolution and precipitation during LSWI/EWI. Also, anhydrite scale is the main controlling solid specie for formation damage. In addition, high temperature water injection should be avoided in carbonate reservoirs due to the likelihood of anhydrite precipitation and formation damage. This precipitation occurs because of the low-solubility of anhydrite at high temperature. Moreover, water dilution could decrease the scale formation while sulfate spiking might increase scale precipitation. Hence, sulfate concentration should be optimized as a wettability alteration agent to enhance oil recovery while avoid formation damage. Furthermore, as a sequence of anhydrite precipitation by sulfate spiking, oil production is expected to decrease by around 23% in the selected case study. The dissolution and precipitation mechanisms during LSWI are very case-dependent and subject of pore distribution, crude oil/brine/rock compositions, and thermodynamic conditions. Hence, the findings of this study cannot be generalized.