bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unlocking Drag Reducing Agent Systems Potential Using Data Analysis
Authors: Al-Aiderous Abdullah Younis 
Published: October 2022

Abstract
The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques to operate a Drag Reducing Agent system optimally, minimizing Drag Reducing Agent Losses and unlocking Drag Reducing Agent system's potential to increase facility throughput through pipelines. Drag Reducing Systems have recently received widespread industry adoption in various applications such as debottlenecking pipelines constraints, increase facility throughput and elimination of costly CAPEX. These proven data analysis techniques were used to tackle major and chronic issues associated with Drag Reducing Agents systems operation that led to excessive Drag Reducing Agent losses, Drag Reducing Agent system solidification and reduction in facility throughput and production. Drag Reducing Agent loss and solidification associated with system storage, handling and improper operations is the most important operating problem in the Drag Reducing Agent system and it represents a concern to the operation personnel. There are various types of Drag Reducing Agents classified by the type of carrier, each individual agent has its unique handling requirements and most optimum pipeline service usage.
In this paper, comprehensive data analysis of the potential root causes that aggravate undesired drag reducing agent losses, solidification and reduced throughput will be discussed along with solutions to minimize the expected impact. For example, operating the Drag Reducing Agent system at high temperature will increase the agent losses by solidification. In addition, improper agent circulation at the storage facility results in a reduction in agent efficiency as a result of carrier disengagement. This paper will focus on a detailed case study in one of the running Drag Reducing Agent systems at a gas-oil separation plant.
Enhanced Approach for Asphaltene Risks Study to Unlock Hundred Millions Barrels Stranded Oil
Authors: Kaouche Salim , Agrawal Pawan , Keshtta Osama , Bigno Yann , Elhassan Mohamed , Al Ameri Shaikh Rakkad , Al Ghailani Abdullah , Saidoun Mohamed 
Published: October 2022

Abstract
Severe Asphaltene deposition is encountered in some wells drilled in newly developed reservoirs of one of Abu Dhabi's giant offshore assets (Field AD), and for the first time, full well plugging with Asphaltene is experienced in the field. While successful curative clean up treatments are regularly made, the relatively high intervention frequency (once every month per well) has impeded the full-scale development of these reservoirs. This study shows how understanding the mechanism of Asphaltene stability/instability in field conditions can unlock the production of under-developed reservoirs (with hundred millions barrels of OIP) by anticipating and considering preventive measures during the design of new wells to limit Asphaltene deposition. In order to prevent the occurrence of Asphaltene deposition from reservoir formation to surface level, a Flow Assurance study was launched by the operating company with close support from the international partner. The objective was to determine the Asphaltene Deposition Phase Envelope (ADE) of the reservoir fluid by measuring onset pressures with Visual (High Pressure ‘HP’ Microscope) and Near Infrared Solid Detection System (SDS) as a function of 2 main variables: Different temperatures to investigate Asphaltene risks over the oil production pathway (at reservoir formation, and from wellbore to surface facilities) & Different Gas compositions to investigate the effect of rich Gas-Cap gas and injected lean gas on the Asphaltene stability. Also, the segregation of the nature of Asphaltenes within the reservoir has been investigated by using the experimental approach named ‘ASCI (Asphaltene Solubility Class Index) experiment’ introduced by the international partner (SPE-164184) to rank Asphaltenes’ solubility with atmospheric dead oil samples taken in different locations.
In addition to that, 2 more experiments were performed: Organic – Inorganic test on solid sample to determine the composition and the nature of the solid deposit (whether it is Asphaltene or other type of depositions) & SARA analysis on atmospheric samples.
This paper presents the improved work-flow based on the collaboration of the local operator and the international partner, introduces the use of ASCI (Asphaltene Solubility Class Index) experiment and discusses the results of the study and its way-forward.
Challenging Traditional Practices in Conventional Reservoirs: Overflushing, Water Conformance and Pillar Fracturing Combination, S Field, Ecuador
Authors: Izurieta Alvaro Javier , Padilla Wilson Leonardo , Mayorga Christopher Jonathan 
Published: October 2022

Abstract
We discuss the application of overflushing along with pillar fracturing in a mature oilfield in Ecuador, where an effective high conductivity (high proppant concentration) fracture is required to enhance productivity because of low reservoir pressure and high permeability. Hydraulic fracturing is a proven technology used in the Oriente Basin with three challenges that remain constant (1) maximize conductivity and (2) reduce proppant flowback risk in the production stage and (3) reduce well intervention time.
To address these challenges a combination of overflushed pillar fracturing, and tip screen out (TSO) are proposed. We show the reservoir analysis, laboratory tests and hydraulic fracture modeling performed to support the implementation of overflushing. Reservoir analysis includes a methodology used to execute an optimized fracture design, and laboratory tests include core flow tests that define non-damaging fluids to be used during workover and fracturing operations, and relative permeability modifiers (RPM) for water conformance. Relevant results are also presented using three key performance indicators (KPI) to evaluate the effectiveness of resin-based pillar fracturing with overflushing viz., (1) pressure buildup data (2) fluid production and (3) productivity index increase post fracturing. Three case studies are presented for fracturing candidates with special conditions, that show that this technique can be extended beyond the traditional job.
Pillar fracturing (fracture and refracturing jobs) combined with overflushing in conventional reservoirs is documented for the first time, with effective stimulation results. This study applies overflushing, a practice developed for completion efficiency in unconventional reservoirs, and combines it with already proven practices in mature conventional reservoirs (pillar fracturing, customized fluids, 3D fracture design, and water conformance while fracturing) with a positive effect on production enhancement and proppant flowback risk reduction. Pressure buildup tests confirm no adverse effect of overflushing since negative skin or bilinear flow is observed, along with an increase in fluid production and productivity index in the studied wells.
Steamflooding Sandstones by Converting Horizontal Producers to Horizontal Injectors with Different Flux Rates
Authors: Al Aamri Rawa'a Mubarak , Al Bulushi Hussain Ali , Al Ajmi Zainab Mohammed , Al Shukri Yahya Mohammed , Al Mazrooe Ibrahim Khalfan , Bait Khalifa Hamid Sanjoor 
Published: October 2022

Abstract
Located in southern Oman, the Mukhaizna heavy oil field has been under steamflood since 2007, but a shallower reservoir was later discovered in a flank area with no steam injectors nearby to extend thermal support to the new zone. The big challenge with cold production in this zone was the steep decline rate, which reached up to 50% per year. Multiple Horizontal Producers (HPs) are at pump-off condition (POC) and are working on a timer mode because there is insufficient inflow to keep the pump running 24 hours a day. The objective of this project was to steamflood this shallow sandstone reservoir to enhance its performance and productivity.
A trial "with two pilots" was carried out in which the middle well of three HPs was converted to a Horizontal Injector (HI) to monitor steam injectivity, the response in the outer two producers, and the improvement in their productivity indices. The selection criteria were based on sand property similarities, channel continuity deduced from the seismic and geological interpretation, cross-sections, reservoir pressure, and production data that showed interference. The spacing between the HI and HP wells was considerable at 250 m, but the injected steam quality (SQ) for the First Phase was hovering around 99%, which is considered excellent.
There were two phases in the trial, each lasting 6 months. The HP to HI conversions were done in December 2020 in two locations at different flux rates "which had negligible effects". Water cut increased significantly in both locations without any clear heat signals. The breakthrough was confirmed by taking salinity samples from the outer HPs. Some interesting observations and learnings have been extracted from the trial, which opened the door for new ideas to be examined.
Case Study of First Successful Aqueous Based In-Situ Formation Consolidation Treatment in the Gialo Field, Libya
Authors: Ghonim Ahmed ElSayed , Khalifa Mohamed , Palanivel Maharaja , Fuser Colby , Shengarou Hamza , Aljwili Aimen , Elusta Shaaban , Abouzenen Fathi , Etabib Abdulaati , Etajri Mosaab Mohamed 
Published: October 2022

Abstract
Sand production is a major challenge for many oil and gas industry operators, especially with unconsolidated reservoirs with weak bonding between the sand grains that enter the wellbore. This can eventually lead to damage to production lines and erosion effects to other surface equipment along with well productivity when drawdown exceeds the critical drawdown pressure. Although several techniques are used globally to combat sand production, most are uneconomical when considering the risk versus reward and the overall effectiveness in controlling sand production.
An aqueous-based resin consolidation technique was evaluated for application in this case after the mechanical properties of the formation and sanding behavior in the field were estimated to be in the acceptable range for this technique to be applied successfully. An injection test followed by the aqueous-based consolidation treatment was bullheaded into the sand-producing zone resulting in minimal rig up and equipment required to operate. Post-treatment, a curing period allowed the resin to consolidate the coated sand grains.
Compared to conventional resin, which requires large volumes to coat the near-wellbore region, this treatment used only a small volume of active resin. This effectively coated and cured in the near-wellbore region, providing excellent consolidation strength allowing the well to produce without any sand particles under the same drawdown applied to offset wells in the field.
A case study is presented in this paper illustrating an effective, cost-efficient, and proven sand control solution for the high potential reservoirs of Libya. This solution can help develop fields that previously suffered from impaired well productivity and required expensive formation sand handling and disposal. Such a solution restored oil production without any considerable effects on the relative permeability of the formation to hydrocarbon or water while maintaining sand consolidation without any further sand production problems.
Successful Delivery of a Breakthrough Implementation of Novel Well Testing Operation Philosophy: Open Sea Extended Well Testing Operation with Temporary Tanker for Crude Evacuation and Storage for Field S Appraisal Project in Malaysia
Authors: Hamid S. Abd , Abdullah S. , Chan W. , Mokhtar Z. 
Published: October 2022

Abstract
Reservoir connectivity and productivity uncertainty can be reduced through the application of an extended well testing (EWT). In the open sea condition, this approach project incurs huge monetary commitment and to reduce this, recovery from produced hydrocarbon is necessary. Conventional open sea well testing is unable to recover the hydrocarbon as no storage facility is made ready. This paper presents the success story of a first application of open sea EWT operation in Malaysia in which it has proved the novel concept of an open sea EWT with the inclusion of Temporary Storage Tanker (TST) to complement the crude storage need, ability to recover and markets the production volume significantly improved the economic value. In addition, this novel method eliminates the practice of hazardous crude flaring activity, damaging emission from flaring was eliminated as well as significantly reduce the HSSE risk exposure.
Novel Machine Learning and Data Analytics Approach for History Matching Giant Mature Multilayered Oil Field
Authors: Suwito Edy , Sianturi Julfree Anto Dongan , Irawan Andi , Panjaitan Pahala Richard , Saeed Yawar , Priyanto Agus Dwi , Elfeel Mohamed Ahmed 
Published: October 2022

Abstract
This paper discusses an integrated reservoir study utilizing structured and novel machine learning and data analytics approach for history matching a giant mature multilayered oil field in Mahakam Delta of Indonesia. The unique reservoir modeling challenges and novelty of the data science methods will be presented, along with preliminary results and lessons learnt.
One of the most important elements in reservoir characterization and history matching process is integration between static and dynamic modeling. With numerous layers as study perimeter, a large number of uncertain parameters is unavoidable, from dynamic uncertainties such as hydrocarbon contacts and communication between regions to static properties like porosity, water saturation, etc. These in turn will create hundreds of possible scenarios during History Matching. Using python scripting embedded in the reservoir simulator and the agile reservoir modeling (ARM) approach, these uncertainties can be handled quickly, and each ensemble can be analyzed easily with Data Analytics and Machine Learning based proxy approaches.
The case study presented here is a giant mature oilfield with more than 50 zones and 100 contact regions. With more than 45 years of production and injection history, the conventional reservoir modeling where each zone is modeled individually and independently, assuming no communication between the regions, has been deemed as taking too much time and effort. The integrated approach bypasses this challenge by allowing simultaneous reservoir modeling as well as quick sensitivity analysis and history matching quality checking. Uncertainties were managed early on; for instance, the porosity model was generated through available algorithms and hydrocarbon contacts with Latin-hypercube sampling method. Preliminary results showed that overall time required to perform the modeling has been reduced significantly, while also establishing communication between the regions. Analytical aquifer modeling and communication between the regions were observed as the most sensitive parameters especially when matching the pressure behavior. Moreover, embedded python script and Data Analytics Dashboard have made it possible to perform fast and systematic analysis, thus more effort and time can be allocated to plan the way forward. The Machine Learning results will be further finalized at the next gate review, considering the project was initially proposed into several gates.
Static modeling using Machine Learning, coupled with dynamic modeling workflow and data analytics, has created a complete loop of reservoir study and characterization. All of these are conducted in a structured cloud-based platform, ensuring time-efficient process and repeatability while at the same time enabling hybrid approach by combining conventional method and advanced data driven approach
Deep Reservoir Conformance Control for the Wara Formation of the Greater Burgan Field: Lab Evaluation, Numerical Simulation and Field Implementation Design
Authors: Al-Murayri Mohammed Taha , Hayat Laila , Al-Qattan Abrar , Al-Kharji Anfal , Bouillot Jerome , Omonte German , Salehi Nazanin , Zaitoun Alain 
Published: October 2022

AbstractImproving water-flood efficiency in heterogeneous reservoirs with high permeability contrast is of high strategic importance to maximize oil gains, debottleneck production facilities and alleviate water-handling constraints. This paper presents key lab, simulation and field design insights to implement Deep Reservoir Conformance Control (DRCC) in the Wara formation of the Greater Burgan Field. Prior technical assessment and high-resolution streamline modelling are covered in other technical publications.Full-field high-resolution streamline reservoir simulations have been used to identify 23 candidate injectors for DRCC. The wells having one layer taking more than 50% of the total water injected were considered as good candidates for DRCC to mitigate water channeling challenges and increase sweep efficiency accordingly.Mechanical water shut-off options were considered, but it was confirmed that near-wellbore solutions do not adequately address deep reservoir conformance issues and can compromise water accessibility to unswept oil zones. Furthermore, mechanical water shut-off options require recompletion and can be expensive and difficult to deploy.To overcome these drawbacks, DRCC has been evaluated in an integrated laboratory and simulation study to design a field implementation plan. The recommended DRCC approach involves injecting a microgel followed by a gel. The microgel enables deep treatment while the gel strengthen Permeability Reduction near the well.Laboratory evaluation qualified a microgel having a size of around 2 µm and a gel combining water-soluble polymer with an organic crosslinker. Gelation time was 2 days and full gel consistency was obtained after two weeks, under the form of a strong and slightly deformable gel (E-F on Sydansk scale). Permeability reduction post gelation was as high as 10,000 times.Reservoir simulations were executed to validate this approach, size-up the treatment and forecast performance. A pattern involving an injector and a producer well was selected. Laboratory coreflood data were used as input for the simulations. The combination of microgel followed by gel with a total volume of around 6000 bbl, pumped in two days, induces a gain in oil production of around 20 to 50% in 10 years. Simulation shows improvement of both vertical and areal sweep efficiency. Moreover, the gain appears very early after chemical injection.The combination of microgel and gel gives an efficient in-depth conformance system that can increase waterflood efficiency in formations such as Wara. This innovative approach has high potential in multi-layer high-permeability heterogeneous sandstone reservoirs.
EOR Signature in Carbonate Reservoirs from Extended Low-Salinity Waterflooding in Oman
Authors: Al Busafi Badar Salim , Al Rawahi Nuzha 
Published: October 2022

Abstract
Low-salinity Enhanced Oil Recovery (EOR) signatures have been well proven by numerous lab and field trial studies (Zhang et al., 2007; Austad et al., 2008; Yousef et al., 2013; Al-Busafi et al., 2014). The evidence is very strong in clastic formations, even extending to full-field application evidence (Seccombe et al., 2010). However, low-salinity EOR in carbonate reservoirs is relatively underexplored and is still being studied in laboratory waterflooding tests and single-well trials. This is attributed to the lack of a single agreed physical model for the way low-salinity brine interacts with oil and carbonate rock surfaces under various subsurface conditions. Unlike sandstones, the reactive nature of carbonate rocks and the larger number of variables affecting the interactions have made the theory more complicated than clastic cases. For this reason, there are still some doubts about whether low-salinity EOR in carbonate rocks works or not. The conflicting arguments have made the oil industry very cautious of field applications in carbonates compared with sandstone reservoirs.
This work presents field evidence of waterflooding performance from long periods of low-salinity waterflooding in carbonate reservoirs in Oman. The fields were subjected to low-salinity water injection that was fifty times less saline than formation water. Two approaches were adopted to assess the benefit of low-salinity water injection. In the first example, history matching of long-term low-salinity water injection was used to infer the shape of the relative permeability curves. Those curves were compared to the lab-derived versions and to those from analogous fields that were subjected to formation water injection. The other approach compared data for extended periods of water injection from two patterns from the same field: one pattern was injected with low-salinity water (~4,000 ppm) and the other pattern was injected with produced formation water (~150,000 ppm). Plots of recovery factor versus pore volumes of brine injected were compared to observe differences in performance.
History matching results showed that the relative permeability curve had to be shifted from an oil-wet system to a water-wet system to achieve a good match. The resulting history-match curve was very different from the lab-measured relative permeability curve, which indicated an oil-wet system in this carbonate reservoir. The lab-derived curve was measured using a steady-state experiment with formation water. Furthermore, comparing the waterflood performance of the two areas with different salinities injected showed a clear distinction between their respective performance, with an 8-10% recovery factor difference after 0.3-0.4 pore volumes injected. Such observations support the argument that low-salinity waterflooding in carbonates has a long-term value that might not be easily observed from coreflooding tests in the laboratory or short field trials.