bluuebunny/crossref_metadata_2025_split huggingface dataset:
Completion Standardization Utilizing Conformable Sand Screen Technology in Multilayered Ultrafine Sand Reservoir
Authors: Simancas Ricardo Gomez , de Sa Carlos , Timoteo Yuri , Gomez-Nava Sandra , Weirich John B. , Forsyth Robert E. , Garza Ramon R. , Gomes Guenji Jose , Gandomkar Arjang 
Published: February 2022

Abstract
The development activities of CABGOC Block 0 pose various challenges to completion design. Multiple types of reservoirs are encountered, while it is also critical ensuring field development remains economic. Completion standardization has been an important tool to maximize operational efficiency and reduce costs of installation. Nonetheless, given the variety of reservoir types found in the area of operation, few completion types are required to solve most of the cases. Despite of having successfully implemented completion standards in several types of reservoirs, there was a gap on the type of completion to efficiently drain multilayered fine particle reservoirs with sanding tendencies. These field characteristics make standard completion techniques difficult to deploy, therefore a novel conformable sand screen solution was selected for a field trial.
This paper describes the plan, preparation, execution, and the results of the conformable sand screen deployment in CABGOC's N'Singa field. Furthermore, it demonstrates how effective the conformable sand control technology can be established for a multi zone open hole type of reservoir. Integral zonal isolation and flow control of various zones provided flexibility in production management for a four well campaign. The Shape Memory Polymer (SMP) conformable sand screen technology was key to produce sand free from the fine particle sands in this marginal field in Cabinda Province offshore Angola.
Unlike the conventional sand control technique, the conformable sand management system selected for this field trial leverages a unique SMP material that expands downhole in the presence of an activation fluid and conforms to the borehole wall. Compatibility and expansion tests were conducted in the planning stage to validate screen conformance with selected completion fluids. Tests were also used to define deployment procedures and optimal fluids management practices for the completion operation.
Installation was successful on all four wells as per plan. All equipment and fluids were managed and operated efficiently with flawless execution. The wells were brought to production and the results confirmed the effectiveness of the technology in terms of sand retention, and completion efficiency during production. The project was concluded with significant reduction in rig time, personnel requirement, fluid management, and pumping operations. This allowed for selective production of reservoir that would not have been possible with standard techniques. Additionally, the obtained results facilitated the decision to implement conformable sand screens as standard completion design for other fields in the reservoir with similar challenges as those observed in N'Singa.
Innovative Water Based Mud Design to Improve Formation Damage Results on Mariner Field
Authors: Houston Kirsty Ann , Fleming Niall , Bonkat Julya Jennifer , Kaarigstad Havard , Barclay Jonathan , Watson Russell , Viste Patrick 
Published: February 2022

Abstract
The Mariner Field consists of two shallow heavy oil reservoir sections: the deeper Maureen Formation and the shallower Heimdal Reservoir. Produced water is re-injected through stand-alone screens providing pressure maintenance for the aquifer support and producer well life longevity. The challenge is to design a drill-in fluid for the injectors to allow matrix injection across the sand face. This improves the longevity of the lower completion screens by reducing hot spot completion damage created by the injection fluid (Yildiz, 2004). It also improves the pressure support for the producing wells.
Equinor is committed to using sustainable, environmentally sound drilling fluid options. Therefore, the preference was to utilize a water-based drilling fluid with the application of a breaker after the lower completion was in place. A significant formation damage study was performed using various designs of water-based fluids. Each formulation utilized a biopolymer to provide viscosity and rheological support. The sands were unconsolidated and sand packs had to be created to mimic the reservoir characteristics of the Maureen reservoir. This potentially impacted the formation damage interpretation.
From the formation damage study, biopolymer was highlighted as a limiting damage mechanism. This prompted both Equinor and Schlumberger to look at alternative ways to provide rheological support without using biopolymers. A mono-valent biopolymer free reservoir drill-in fluid was designed specifically for this challenging high Darcy reservoir to mitigate the formation damage seen from coreflooding. This paper will detail the design, testing, diagnostic analysis of the formation damage mechanism and the new biopolymer free fluid. Together they showed a step change improvement in the formation damage testing. In addition, the paper will also detail the deployment of the new fluid on Mariner. Furthermore, it will describe how the laboratory design translated into large scale plant mixing with deployment at the rig site.
A Comprehensive Review of Sand Retention Test Methods and Data Analysis with a Focus of Application
Authors: Linden Tanner , Fischer Christine 
Published: February 2022

Abstract
Sand Control completions in long horizontal laterals often present challenging conditions because of a wide range of formation particle sizes and inflow rates which must be contained with a single completion. To aid in the screen selection process, laboratory testing of possible sand control media has proven to be a reliable method to improve the success of the completion.
Soft sand completions are generally characterized into two classes of wellbore environments. A rapid wellbore collapse onto the screen or a gradual mechanical failure of the surrounding formation. Depending upon the type of wellbore environment encountered, one sand control test may provide a closer simulation to the failure phenomenon in the wellbore than another.
This paper reviews three primary types of sand retention tests that include Constant Drawdown (pre-pack), Constant Rate, and Cyclical Brine. There are several variations on each test method, particularly the constant rate test method.
The primary objective of any sand retention test method is to determine the amount and size of solids production through the sand control media with a specific particle size distribution. However, the various test methods provide additional performance data to aid in selecting a sand control system for a given environment. The Constant Drawdown method simulates a wellbore that is in conformance with the sand control media. This method provides retained screen permeability, as well as the formation and system permeabilities at multiple stress levels. Similarly, the Cyclical Brine method simulates a rapid wellbore collapse with an emphasis on injection well shut ins. This test provides system permeability data in both the injection and production flow directions. Lastly, the Constant Rate methods simulate a gradual or erosional failure of the wellbore on the sand control media. In these tests, a fluidized slurry contacts the sand control media in the open annulus, providing increasing pressure data with time.
Using the sand retention data from these test methods a master curve is generated, which can predict how the screen will perform with various particle size distributions. A detailed analysis of particle size data down a lateral and interpretation with the Master Curves has been completed and provides a prediction of the performance of the sand retention media across the range of formation particle size distributions.
By comparing the various evaluation methods through a reproducible sand retention study, we can optimize laboratory evaluation methods for a variety of wellbore environments. This provides the industry a comprehensive guide for matching wellbore specifications to the ideal laboratory sand retention evaluation method, optimizing the sand control selection to the well.
Water Injector Acid Stimulation: An Offshore Case Study
Authors: Bolingbroke Hannah F , Yao Calvin C 
Published: February 2022

Abstract
Waterflooding presents many unique challenges, especially in the offshore environment. Cost, slot availability, and uncertainty about return on investment limit the number of water injection wells and the use of ideal flooding patterns. Furthermore, water injectivity commonly declines with time due to formation damage. Well stimulation is a routine solution to remove such damage and recover injectivity. This case study focuses on our experience with a mud-acid stimulation of a water injector in the Gulf of Mexico (GOM).
When the injectivity index of an offshore water injection well had decreased over time by a factor of 4, a mud-acid stimulation was performed, and significant injectivity was recovered. The well logs show multiple high-permeability layers, which can cause issues with waterflood conformance. A non-flowback operation, also known as bullheading, was decided upon to push insoluble fines into those high-permeability layers to improve waterflood conformance. Forgoing a post-stimulation flowback also decreased the cost of the job, reduced the risk of personnel exposure to acid, and was more favorable from an environmental viewpoint.
Water injectivity was monitored with traditional diagnostic Hall plots. The efficacy of the stimulation job was evaluated through Hall plots, calculated injectivity index, and skin. Pressure transient analysis (PTA) was used to determine kh products, reservoir pressures, and skin factors before and after the mud-acid stimulation.
This paper presents the successful, bullhead-style acid stimulation of a water injector supporting two oil producers in the deepwater GOM.
Understanding Fluid Exchange as Screens are Run in Hole – Mitigation of Formation and Completion Damage Risks
Authors: Byrne Michael , Djayapertapa Lesmana , Watson Ken , Fleming Niall , Taugbøl Knut 
Published: February 2022

Abstract
To reduce the risk of screen plugging with drilling fluid solids, wellbore fluids are typically displaced to low or no solids systems before sand screen lower completions are run in to wells. Displacing the entire wellbore volume to low solids fluids can add significant cost particularly in high pressure wells. An option can be to displace the open hole section of the well only with the low solids fluid and run the lower completion through the original drilling fluid. A refinement of this process is to fill the upper hole section with the low solids fluid in order to pre-saturate the screens assembly. The movement or exchange of the two fluids as the screens are run in to the wellbore has been a significant uncertainty, until now!
This work was conducted to investigate the potential for fluids to exchange as sand screen completions are run in to wells in the Field 1 Satellite and Field 2 developments. The hypothesis that fluids in the wellbore would displace fluids inside the screen assembly as the screens are run in to the well was tested. Computational Fluid Dynamics (CFD) modelling was used to simulate the movement of the lower completion in to the well and determine the rate and quantity of fluid exchange.
The simulations demonstrated that when stand alone screen (SAS) completions are run in to wellbores, fluids will exchange from outside to inside the screens. This process happens at all tripping speeds examined and in all parts of the cased and open hole wellbore. The fluid exchange continues throughout the running in process, including in the open hole lower completion. There is no value in filling the top hole section with low solids completion fluid unless fluid exchange during running in can be controlled. When a one-way inflow control device (ICD) check valve is fitted to each screen joint allowing fluid to flow in to the tubing but not back out to the annulus then fluid exchange is significantly limited.
Careful consideration should be given to the exchange of fluids as lower completion assemblies are run in to wells. If it is considered undesirable that the fluid in the well should enter the lower completion string as it is run in to the well then appropriate valves or flow reduction should be considered. Eliminating the requirement to fill the top hole section with low solids fluid can lead to significant cost reduction in well where expensive fluids, such as Cs formate, are required to meet the low or no solids specifications. Understanding fluid exchange in wells as screens are run in can significantly reduce the risk of formation/completion damage. The work illustrates the value in a novel application of CFD to determine the optimum well construction process.
Novel Sealing Technology Increased Wellbore Integrity While Optimizing Well Schematic in La Caverna Bandurria Sur Unconventional Field
Authors: Emanuel Lopez Gaston , Vidal Gonzalo , Claus Hedegaard Allan , Maldonado Reinaldo 
Published: February 2022

Abstract
The Bandurria Field in Argentina is known for its narrow operational window due to the difference in pressure gradients while drilling through the Quintuco and Vaca Muerta formations. This scenario usually requires managed pressure drilling (MPD) and a robust well design, including four casing sections, which significantly increases the well construction cost. The operator's objective was to design an efficient and cost-effective well aligned to the current economic market conditions.
Using a break-even price target of 43 USD/bbl, high-end technologies resulting in high operational costs are not cost effective and unacceptable. Therefore, the operator selected a new technology and operational method focused on the drilling fluids to increase the pressure-gradient operative window.
An ultra-resistant and flexible technology was used in the open hole section in real-time while drilling. The technology is designed with the drilling fluid system so that new rock drilled would be sealed quickly. Minimizing the interaction between the drilling fluid and the formation would preserve the original formation conditions. Using this technology, it was possible to perform a flawless operation, increasing the operative window and minimizing wellbore instability while drilling through the Quintuco and Vaca Muerta formations which are characterized by interbedded carbonates/shale layers under high-pressure conditions.
The offset wells on the same pad presented severe operations issues, including stuck pipe, lost circulation, and sidetracks, even with the use of MPD. The technique implemented, known as Wellbore Stabilization Technology (WSST), enabled the operator to perform a dynamic formation integrity test (DFIT) while drilling through the transition zone to evaluate the magnitude of the operative window increase and compare those results to the offset wells on the same pad. As measured in the field, the WST allowed an increase of 2-3 lb/gal beyond the fracture gradient window.
The WST was later applied in six additional wells in the same area, where the drilling efficiency significantly improved compared to historical wells. Further, the operator reduced the volume of oil-based drilling fluid (OBM) used per well, minimizing drilling fluid costs and optimizing the drilling operations.
A thorough laboratory analysis was performed to evaluate this novel technology's effectiveness against several high-end technologies. This innovative adoption to the drilling fluid design resulted in a significant cost reduction to drill the Bandurria Sur Field. In addition to presenting field results, including the increase in the fracture gradient window as compared to offset wells, this paper describes the prevention of lost circulation, resulting in a nearly 50% decrease in wellbore instability.
Industry First: Shunt Tubes Open Hole Gravel Pack Completion Through 9-5/8" Milled Casing Window in ACG Field, Azerbaijan
Authors: Susilo Raden Yoliandri , Yahyayeva Narmina , Saavedra Luis , Loboguerrero Santiago , Akhundova Gumru , Rasul-zade Ali , Whaley Kevin 
Published: February 2022

Abstract
Azeri-Chirag-Gunashli (ACG) is a giant field located in the Azerbaijan sector of the Caspian Sea. The major reservoir zones are multi layers sandstone formations with oil column up-to 1000m, and weakly consolidated where Open Hole Gravel Pack (OHGP) completions have become the standard design for production wells. Development began in 1997 and to date more than 130 high rate OHGPs have been installed.
Once existing wells has been uneconomically to be produced, a Sidetrack or Up-Hole Recompletion (UHRC) will be performed. The standard 9-5/8" sidetrack technique will be done by drilling new section, installing and cemented a 7-5/8" liner, then drilling 6.5"x8" hole in pay zone followed by running 4" Shunted Screen and gravel packing. Previously C&P technique has been used for UHRC option but it was producing at limited drawdown and quickly sand up when water break through. Cased Hole Gravel Pack (CHGP) technique has been trialed as UHRC option in the past 2 years but has limitation of the number zone & length can be perforated which resulted in leaving some zones unperforated behind casing.
A new concept of UHRC has been designed and successfully tested. This concept consists of sidetracking into the overburden, drilling to TD and removing 7-5/8" liner section. Shunted screen then deployed into open hole through a cased milled window followed by gravel pack operation. While standalone screens have been deployed through cased milled windows before, deploying shunted screens through a cased milled window followed by an OHGP is an industry 1st. This technique delivers the well 20 days earlier compare to standard Sidetrack OHGP well due to removal 7-5/8" production liner section. This technique is also give advantage over stacked CHGP option because can provide higher k*h access, can handle high levels of differential depletion within the completed interval and has the potential to unlock up lot more well candidates to allow and deplete the reserves from overlying reservoirs.
This paper will also describe window and well design to deliver successful Shunt Tubes OHGP installation with this technique.
Managing to Reproduce Original Carbonate Core Condition: Is Core Initialized Realistically on Three-Dimensional Geometry?
Authors: Yonebayashi Hideharu , Uetani Takaaki , Kaido Hiromi 
Published: February 2022

Abstract
In this study, we established initial water saturation (Swi) using three techniques: (1) the dynamic displacement technique, (2) the porous plate technique, and (3) the vacuum saturation technique. A unique heterogeneous carbonate reservoir rock sample (1.5-inch diameter and 3-inches long) was used repeatedly to compare the techniques without an uncertainty of different cores. After establishing Swi by each initialization technique, the cross sections were scanned using a micro-CT scanner. The image data was processed to estimate the cross sectional fluid distribution in XY-direction. Furthermore, each areal average Swi was calculated to investigate Swi distribution in Z-direction (direction of injection). Based on the comparison of interpreted fluid distribution, pros/cons of each technique was discussed.
Smart Drill-In Fluid and Breaker Design for a Limestone Reservoir for Persian Gulf Offshore Wells
Authors: Pietrangeli Gianna , Barry Michael , Alvarez Daniel , Hayden Laurie , Addagalla Ajay 
Published: February 2022

Abstract
Offshore reservoirs in the Southwest Persian Gulf are commonly oil-wet limestone with an average permeability of 10 md. High production of hydrogen sulfide and carbon dioxide is often encountered in the oil producer wells. The tight reservoirs are commonly drilled with water-based reservoir drill-in fluid (DIF) with high concentrations of lubricants.
DIFs based on sodium chloride or calcium chloride brines with corresponding optimal breakers to remove the filter cakes were formulated and evaluated to optimize production in newly drilled wells.
Fluid displacement by return permeability (RP) testing was used to evaluate the fluid/limestone rock interaction. This paper discusses the compatibility of a sodium chloride-based and a calcium chloride-based DIF with limestone formation and the necessity of introducing an optimal breaker to maximize the opportunity to achieve high production rates.
RP tests are widely used to determine the potential damage caused by the DIF and production enhancement after removing the DIF filter cake with a breaker. Desired results for RP tests performed with the brine-based DIF in limestone cores were a minimum of 75% regain permeability to oil production. The cores used for the RP tests were from an analogue limestone outcrop from a Mississippian formation with permeability between 9-16 md and 14-18% porosity.
DIF properties were determined following API RP-13I recommended practices. Emulsion tendency for the fluids was determined by using emulsion tendency testing with a high-speed mixer to mimic shear at the pore throat.
A 10.0 lb/gal sodium chloride water-based DIF with a high content of ester-based lubricant was designed for drilling a limestone formation. A high pH close to 10 was necessary to control H2S and CO2 corrosion.
The return permeability of the 10.0 lb/gal fluid was 44% using LVT-200 oil as an analogue for the native hydrocarbon permeating fluid. The low return permeability was likely caused by emulsion blockages generated by the saponification of the ester-based lubricant used in the sodium chloride-based DIF.
Emulsion tendency was observed between the DIF filtrate and permeating fluid in a fluid/fluid compatibility evaluation. Therefore, a breaker system was formulated and customized to enhance RP from 44% to a minimum of 75%.
In contrast, a 11.0 lb/gal calcium chloride-based DIF with pH of 9.0 and same ester-based lubricant content was evaluated using a comparable limestone analogue core and demonstrated a high return permeability (&gt;80%). Filtrate of the calcium chloride-based DIF did not form emulsions during fluid displacement in the RP test.
Compatibility evaluation (return permeability) between drill-in fluids and reservoir rock is essential for oil producer wells in order to determine and avoid potential problems caused by interactions between them.