bluuebunny/crossref_metadata_2025_split huggingface dataset:
Electro-Hydraulic Servo Actuation for Well Completions
Authors: Lerner Daniel M. , Orban Andre E. 
Published: September 2022

Objectives/Scope
Well Completions are challenged with the demands of managing increased multiple production zones.
This paper addresses a solution to these issues:
Reduce the number of hydraulic control lines.
Provide independent production zone flow control.
Support a multiplicity of hydraulic actuated devices.

Methods, Procedures, Process
These Well Completion challenges are addressed using networked Electro-hydraulic Servo Actuators (EHSA). The EHSA is a small diameter, closed loop, hydrostatically balanced electro-hydraulic actuation system. EHSA has a feature set to support intelligent and autonomous multizone Well Completions. Each EHSA servo provides controlled operation of a device at a remote endpoint downhole.
Bidirectional flow is obtained directly from the rotation of the pump and motor, eliminating the use of check, relief, and solenoid valving. Measured flow and pressure provide incremental precision positioning.
Multiple hydraulic control lines are eliminated.

Results, Observations, Conclusions
Years of extensive testing programs validated reliable and consistent operations verified in hydrostatic autoclave stress test equipment. EHSA tests demonstrate years of operation, estimated to meet or exceed 20 years of operation.
The system operates with electrical wires providing direct command/response capability and power. A single TEC line can support a multiple EHSA network.
Alternately, pressure pulse commands can be transmitted from the surface to control each battery powered EHSA. Autonomous control in response to sensor inputs allows for adjustment of the well control devices, for instance in response to well pressure changes. A real-time clock provides for a predetermined schedule of operations, possibly combined with
command/response, autonomous control, and sensor measurements.
Self-balancing eliminates hydraulic lock by uniquely adding or disposing of fluid imbalance with the hydraulic reservoir. The positive displacement operation is calibratable and proven highly repeatable.
Remedial override is inherent in the EHSA because there are no valves.

Novel/Additive Information
The EHSA is a multiple-use hydraulic engine with intelligent control features for various types of completion devices either single-use or permanent installation.
Digital Tool Allows Simultaneous Operation and Facilities Optimization in Limited-Budget Projects
Authors: Gonzalez Muro Luis , Calderon Ruiz Diego , Fun Sang Robinson Byron , Florez Florez Fabian 
Published: September 2022

Abstract
This paper presents an example of how small oil fields can approach digital transformation aiming higher digital maturity and becoming a "smart asset". The asset targeted to integrate the well performance and the available capacity of the existing processing facilities, and with that allocate resources to actionable optimization opportunities. The optimization is driven by allocating the facilities volume (in oil) to those wells with higher oil output.
The methodology uses the classic well by well production optimization approach (find the highest incremental oil with the lowest investment), the novelty is to rank the wells based on the main bottlenecks of the processing facilities. In this way the ranking of the wells is dictated by the overall production system analysis from the pore to the export pipeline.
Once a constraint is identified a baseline is set and a target status is defined. The gap between current and target states is overcame by robust data structure that enables business and artificial intelligence workflows for well and facility smart analytics.
The enhanced workflow allows surface facilities surveillance in a relative high frequency, this in combination with the well monitoring improve optimization decision dramatically.
As a result, this strategy has allowed the asset to reduce 900 man-hours a year, reduce operative production losses by 40%, lessen artificial lift failure events rate by 40%, increase production in the order of 5% (in a 9K BOPD asset), bringing the project to outstanding production levels. Furthermore, this solution has indirectly helped to reduce CO2 emissions in at least 20 Tons per year, reducing the carbon footprint in a sensitive environmental area in the amazon forest.
Understanding and Preventing Incomplete Shunted Open Hole Packs in Trinidad's Colibri Field
Authors: Tibbles Raymond , Wassouf Phil , Govinathan Kesavan , Campbell Patrick , Daniel Vijay , LaPointe Michael , Rattananon Pichate , Zhang Ying 
Published: September 2022

Abstract
Three out of four shunted gravel packs in Colibri suffered from severe losses near the end of the gravel pack and failed to achieve a final screenout even though as much as 50% excess gravel was placed. This study uses reservoir, completion, and bottom hole gauge data to understand why the final screenout was not achieved and how to ensure complete packing/final screen-outs in the future. The evaluation started with building representative models for each well in a gravel pack simulator to predict the pressures and packing mechanisms downhole. The data used in the models included the relevant completion and reservoir data. The model was then used in conjunction with the treatment records (surface pumping data and bottom hole gauge data) to evaluate the packing extent and sequence for different parts of the openhole. This evaluation pinpointed the time and location where losses occurred as well as the extent of openhole packing in each section. Various theories were formulated to describe the observations and one theory was selected as the most likely. The evaluations showed a consistent packing behavior across all the wells in which the screens were initially covered without the aid of shunts from toe to heel with much less gravel than required to fill the annulus void. After this initial packing stage, shunt packing began, and additional packing in all of the sections occurred. During this part of the packing process, losses began which resulted in all of the final slurry exiting the open hole into the reservoir. Based on the analysis, the most likely cause of the strange packing behavior was the combination of low screen inflow area, relatively low gravel permeability, higher fines content in the natural gravel sand and high gravel carrier fluid viscosity, which resulted in a high pressure drop across the pack/screen interface. The one well which achieved a final screenout had a lower pumping rate, resulting in lower pressure drop.
Experience of the Development and Implementation of Cognitive Technologies for the Serbian Upstream Oil Industry
Authors: Naugolnov Mikhail , Micic Ponjiger Tanja , Zalevskii Nikolai 
Published: September 2022

AbstractThe work is devoted to the experience of creation and implemention of digital solutions in the Petroleum Industry of Serbia (Serbian: NIS). The paper detaily examines digital projects which applied data science, machine learning/deep learning in seismic, petrophysics, geology, reservoir engineering and production technology. These projects aimed to solve current challenges of brown fields at a late stage of operation, as well as in working with sand-bearing well stock, control of scale and efficient development of fractured reservoirs.
Bioremediation Study on Formation Damage Caused by Hydraulic Fracturing: A Microfluidic Approach
Authors: Liu Songyuan , Sie Chao-yu , Malekahmadi Fatee , Lu Bo , Li Yifan , Fan Cara , Zhang Xinyue , Serediak Owen , Fortin Jelayne , Abedini Ali 
Published: September 2022

Abstract
Hydraulic fracturing has been applied to unconventional reservoirs with low permeability to achieve higher productivity and economic potential. However, polyacrylamide-based friction reducer and guar gum, two of the most common components in fracturing fluid could cause formation damage by penetrating into the matrix and blocking the flow path. To regain the conductivity of the damaged area, a bioremediation method was developed and validated by a microfluidic approach. Modified nutrients were used to stimulate the indigenous bacteria that could consume or break the polymer residues.
Indigenous bacteria were extracted from oil field produced water collected with customized anaerobic sampling kits which have been sterilized. Feasibility studies were conducted to investigate the indigenous bacteria activity with and without nutrient supply. Fracturing fluid, field water, and a modified nutrient recipe which contained 300 ppm of inorganic salts were loaded into anaerobic sample vials in a 140°F - 150°F incubator. Microfluidic tests were performed in 150°F oven with microfluidic chips designed and fabricated based on the topology of matrix networks. Fracturing fluids were injected into a chip saturated with field water to simulate formation damage. Remediation fluid consisting produced water, injection water and nutrient was injected into the chip. After two weeks soaking, 2% KCl brine was then injected into the chip at 200 nl/min until a stable pressure drop was achieved. Microscopic pictures were taken before and after soaking to demonstrate the polymer damage and the remediation of microfluidic chips.
The indigenous bacteria were successfully stimulated with and without the existence of the friction reducer based on the results of feasibility tests. Microfluidic tests showed there is a significant difference in precipitations between the case with and without nutrient supply, which indicates that the bioremediation method could regain conductivity of the damaged formation.
This work is novel research on bioremediation application in unconventional reservoirs with only indigenous bacteria involved. The customized sampling technology and laboratory approach could prevent contamination of other microbes and oxygen, which could improve the quality of the research. Microfluidic chip is a great simulation of porous media and a proof of concept between scientific hypothesis and field application which requires small sample size and provides good reproducibility. In field applications, only an extremely low amount of nutrient is required in this process which provide great economic potential. Additionally, the injected nutrients will be fully consumed by the bacteria which makes this technology is an Environmental, Social and Governance (ESG) approach in energy industry.
Unlocking Solutions in Oil Field Production: Innovative & Advanced Autonomous Flow Control Device application.
Authors: Martinez Santiago Maryvi , Ortiz Jhon , Bethapudi Bhanu , Noordin Firdaus , Trisnadi Dicky , Mohammed Tawheed , Al Obeidi Mazna , Permana Krisna , Soufi Abdulrahaman 
Published: September 2022

Abstract
As a result of Reservoir Monitoring Plan, a Non-uniform Saturation has been identified in the Southern part of the reservoir. High gas saturation, coming from gas injection in underlying units, was observed within the first 10 to 30 Ft. TVD of top-most section of the reservoir. Therefore, in order to mitigate the potential problems that this gas production can generate on the well production performance which could shorten the well productive life, a flow control strategy was implemented in the lower completion designs of six new drilled wells.
Following the best practices as per ADNOC Standard Operating Procedure and after performing an opportunities screening, inflow control device ‘ICD’ was found as the technology to be used on these cases. A steady state modelling was performed for identifying the most suitable ICD design for the new wells drilled during 2021-2022. In order to consider the changes on the reservoir fluid conditions over time along the wellbore, a sensitivity analysis was conducted during the steady state modelling. Likewise, the final ICD design took into account that production profile should be adhered to reservoir management guidelines.
The result of wellbore simulations provided insights about the optimum solution for the well completion. This called for both adequate well positioning along the reservoir section and the utilization of ICD technologies as a means for GOR control, making feasible a more efficient practice for well and reservoir management.
A successful trial of installing the first Autonomous or self-regulating ICDs have been completed and deployed as an innovation in the field to optimize and balance downhole influx profile, which will allow to minimize the impact of the gas breakthrough GBT while maintaining wells productivity.
Overdesigned ICDs was avoided since they not just increase the cost of well completion, but also will impact the well performance negatively. Most of wells with segmented completion with Autonomous Inflow control Device AICD pertaining to PAD drilling project, will be commissioning in Q2 2023. One out of the six wells is currently flowing and an evaluation program and results will be further discussed in this publication.
Extensive Laboratory Test to Validate Material Selection for CO2 Injector in Depleted Carbonate Field - A Case Study of Carbon Capture and Storage Development Project in Offshore Malaysia
Authors: Abu Bakar Mohd Azuan , Riyanto Latief , W Mohamad W Amni , Moh Wahi M Wahidullah , A Halim Rahimah , Kamitani Hiroki , Amaya Hisashi 
Published: September 2022

Abstract
As part of decarbonization initiatives, the K1 field CCS project plans to capture the CO2 produced from the nearby gas field development and store it in the depleted carbonate reservoir. One of the challenges in CCS project is to choose the optimum material for the well design. This paper presents the case study of CO2 injection well material selection of K1 field CCS project development.
The injection fluid contains more than 90-98% CO2 and about 500-711 ppm of H2S. This condition and presence of free water might create high risk environment for Stress Corrosion Cracking (SCC) and Sulfide Stress Cracking (SSC). Materials were initially screened based on Oil Company Tubular Good (OCTG) charts. Further qualification was deemed required through fit for purpose tests which represent the most likely and worst-case conditions. Test matrix has been developed based on NACE TM 0177 and NACE TM 0136 guidelines.
Initial material selection using the OCTG chart suggested 25 Cr as a suitable material. No verification through the lab test is required for this material. As an alternative material, 22 Cr and enhanced 13 Cr were considered, subject to further verification on Sulfide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC). The test matrix had been developed to simulate two scenarios where the injected gas mixes with condensed water during injection and flowback of formation water. For enhanced 13 Cr material, SSC test is performed at 24°C and 34°C. The temperature of 24°C is chosen as the temperature of highest susceptibility of SSC expected to occur for martensitic material. For temperature of 34°C, it is performed to investigate the effect of supercritical CO2 fluid phase on the corrosion and cracking if any. For 22 Cr which is duplex material, the test is performed at temperature of 90°C, which is the temperature of the highest SSC susceptibility of duplex material expected to occur. The corrosion and cracking test result show that the material suitable for more than 90% CO2 with about 711 ppm of H2S in condensed water condition and flowback fluid condition is 22 Cr and above grade.
As part of material selection process, extensive lab tests to qualify tubing material has been performed by both OCTG manufacturer and independent lab. The result enables further optimization on well cost while giving assurance on K1 CCS injector well's integrity
Neutral-We Proppant Improves Post Treatment Cleanup and Enhances Productivity
Authors: Kortam Mostafa , Sobhi Ihab , Khalil Mahmoud , Yahia Omar , Spurr Naima 
Published: September 2022

Abstract
A well, with very low bottomhole pressure, required frequent workover operations due to pump failures from sand production. A gravel pack was designed to minimize the production sand issues. However, to sustain low pore pressure (less than 0.1 psi/ft) without affecting well productivity, lower drawdown was needed during an acceptable sand control completion. This presented a challenge due to massive completion brine losses and increased risk of formation damage. These challenges could create impairment in well productivity. Usually, a rig utilizing coiled tubing is used to handle the flowback and unload the well.
To increase the amounts of flowback fluid, and minimize formation damage, the completion of this well used a neutral wet proppant. The proppant, which had surfaces that are neither oil nor water wet, was used in this gravel pack to improve the flowback fluids recovery. The expected benefits of this proppant were to (1) eliminate capillary pressure within the proppant pack and (2) alter the interaction between aqueous/organic (hydrocarbons) and the proppant surfaces. This would be accomplished by decreasing the intra-molecular interactions between the fluids and the proppant surfaces thus resulting in improved flow compared to native surfaces.
Lightweight ceramic (LWC), neutral-wettability proppant was used to improve clean-up and enhance fluid flowback recovery. Extensive laboratory testing on the proppant was performed ahead of the job, including properties and compatibility with stimulation fluid. This proppant had both hydro- and oleophobic properties. The hydrophobic properties improve the flow of the aqueous fluids, while the oleophobic properties improve the flow of the hydrocarbon phase. The proppant was pumped similarly to any other conventional proppant and no changes in the procedures were needed. After completion of the job, the well was shut-in and the flowback un-loading was performed a week later. This completion relied on using ESP to perform the cleanup and producing the well concurrently to reduce the operation time and cost spent during well unloading.
After completion, 100% of all pumped brine was recovered leading to an enhanced production rate with no impairment or coiled tubing lifting post treatment required. The cleanup was carried out after one week from the treatment date. The well cleanup, in comparison with wells that used conventional proppant, was much faster and saved $50,000. The calculated productivity index is 3.2 compared with 2.8 bpd/psi before the treatment representing 15 % gain. No sand production was observed during production performance nor seen in the wellbore during pump replacement after two years of continuous production period. The average run life prior to this treatment was 3 months, thus impacting not only the well productivity but also the run well life.
Innovative, Cost Effective and Zero Flaring Solution to Clean-Up and Start-Up New Wells in High H2S Field in Kazakhstan. The Vital Step Forward Towards Net Zero Carbon Footprint
Authors: Tankiyev Timur , Kartamyssov Aidyn , Zhumabayev Bolat , Izbassov Arman , Bissakayev Beibit , Hosatte Pierre , Burkitov Ulan , McGachy David , Privitera Salvatore , Itoua Rolle , Kydatov Mikhail , Kurmanbayev Altay , Akbayev Beibit , Osokin Ivan , Kaipov Yermek , Valdivia Paulo G. , Zhandin Alexander 
Published: September 2022

Abstract
Flaring has received significant attention over the past few decades and has become a major concern for many operators today. One of the contributors to hydrocarbon flaring is well clean-up operations, where traditionally oil and gas are disposed by flaring at the wellsite.
This paper will share in details how integrating various technologies allowed to come up with a cost effective, zero flaring solution for well clean-up operations, that substantially reduced overall field carbon footprint.
A common alternative to flaring is to store the crude in tanks and/or pump crude into production line, if available. However, the associated gas is typically flared off, as using gas compressors to inject gas into production line is extremely cost intensive and operationally complex.
As an alternative, fit for purpose multiphase pumps, specifically designed to handle clean-up operations and combined with a high pressure surface well testing package proved to be a successful, innovative and cost effective solution to bring new wells to production without gas flaring. The pumps, installed at the inlet of a high-pressure separator, boost the pressure such that both oil and gas can flow directly into the production line, while water and spent acid from well stimulation treatment are separated out onsite into water tanks.
The method does not require any hydrocarbon flaring, thereby drastically reducing emissions for well clean up and start up operations. The solution enabled a reduction of an average of 24 Kilo-Tonnes of CO2 equivalent of emmissions per well clean up, when compared to 100% flaring, resulting in a very significant and measurable positive environmental impact.
The pumps proved to be reliable and fit for purpose, by toleranting high gas-volume-fraction (GVF) conditions and unstable flow, which is vital for clean-up operations. In addition, the setup proved to be an efficient pressure-boosting package, to gain additional production, by overcoming the high backpressure from the production lines network. The package was introduced in the giant Karachaganak oil and gas condensate field in Western Kazakhstan in high H2S environment, and was used in 13 wells over a two-years period, resulting in significant net production gains for the operator.
Pilot Program for Digitally Validating Well Barrier Integrity During Inflow Testing
Authors: MacDonald Cody , Cully Rick , Franklin Mark , Flenoy Donald 
Published: September 2022

Abstract
Inflow (negative) tests are critical for verifying the integrity of well barrier elements (WBEs) that prevent unwanted flow of formation fluids into the well. Historically, inflow tests have been validated and documented using subjective and inconsistent techniques, including analog circular chart recorders and hand-written notes. The consequences of misinterpretation of test results can lead to catastrophic well control events. This paper presents the results of a major oil & gas operator's pilot program to standardize the use of closed system testing and a digital analysis application as a global solution to improve the safety and efficiency of inflow tests.
The pilot program was deployed on multiple drillships in the U.S. Gulf of Mexico. Each test involved displacement of drilling mud with lower density test fluid followed by a series of bleed down steps to incrementally reduce the hydrostatic pressure above the WBE until it was less than the formation pressure from below. The displacement and bleed-down steps induced complex thermal effects on the fluids in the wellbore, complicating pressure analysis and leak detection. The digital analysis application used research-based algorithms capable of differentiating between thermal effects on the fluids and a leak. The application provided an objective and transparent pass-fail determination for each test.
The software was installed at the rig sites, coupled to surface pressure data acquisition equipment, and configured to evaluate tests per BSEE-accepted criteria. Test progress and results were transmitted to a cloud-based service, enabling teams to collaborate and view critical tests in real-time. Test records were archived automatically, and digital records were preserved in comprehensive and standardized reports, ensuring knowledge transfer throughout the well's lifecycle. The test results were 100% in agreement with the operator's own pass/fail analysis results, which was one of the key success factors of the pilot. Notably, the time savings were significant. Historical inflow tests ranged between 4-12 hours for this operator, while the average total time for the pilot using digital inflow analysis was less than one hour.
The pilot program proved that using a closed system method and the digital application's inflow analysis algorithm provided direct information about the thermal effects of fluid displacement and bleed-down phases resulting in more accurate and efficient inflow tests that improve safety and well integrity assurance.