First use of a Newly Developed High-Density Brine in an Oil-Based Screen Running Fluid in a Multilateral Extended Reach Well: Fluid Qualification, Formation Damage Testing, and Field Application, Offshore Norway

2020 ◽  
Author(s):  
B. Salmelid ◽  
M. H. Strand ◽  
D. Clinch ◽  
C. Davis ◽  
E. Jeurissen
Keyword(s):  
Field Application ◽  
High Density ◽  
Formation Damage ◽  
Extended Reach Well

Preventing Formation Damage Caused by High-Density Completion-Fluid/Crude-Oil Emulsions

1998 ◽  
Vol 50 (11) ◽  
pp. 60-61
Author(s):  
_ JPT staff
Keyword(s):  
Crude Oil ◽  
High Density ◽  
Formation Damage ◽  
Oil Emulsions

Case Study: Field Application of a Novel High-Density Fluid-Loss Pill

2003 ◽  
Author(s):  
D. Messler ◽  
J. Richey ◽  
J. Powell ◽  
D. Miller ◽  
J. Guidry
Keyword(s):  
Field Application ◽  
High Density ◽  
Fluid Loss

Formation Damage Tests of High-Density Brine Completion Fluids

1986 ◽  
Author(s):  
L.N. Morgenthaler
Keyword(s):  
High Density ◽  
Formation Damage ◽  
Completion Fluids

scholarly journals High-Density Livestock Operations, Crop Field Application of Manure, and Risk of Community-Associated Methicillin-ResistantStaphylococcus aureusInfection in Pennsylvania

2013 ◽  
Vol 173 (21) ◽  
pp. 1980 ◽  
Author(s):  
Joan A. Casey ◽  
Frank C. Curriero ◽  
Sara E. Cosgrove ◽  
Keeve E. Nachman ◽  
Brian S. Schwartz
Keyword(s):  
Field Application ◽  
High Density ◽  
Crop Field

Investigation and Field Application of Ultra-High Density Fracturing Technology in Unconventional Reservoirs

2021 ◽  
Author(s):  
Fanhui Zeng ◽  
Yu Zhang ◽  
Jianchun Guo ◽  
Su Diao ◽  
Wenxi Ren ◽  
...  
Keyword(s):  
Field Application ◽  
High Density ◽  
Unconventional Reservoirs

Multiscale Formation Damage Mechanisms and Control Technology for Deep Tight Clastic Gas Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-16
Author(s):  
Yijun Wang ◽  
Yili Kang ◽  
Lijun You ◽  
Chengyuan Xu ◽  
Xiaopeng Yan ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Damage Control ◽  
Production Capacity ◽  
Damage Mechanism ◽  
Field Application ◽  
Formation Damage ◽  
Fluid Loss ◽  
Drilling Process ◽  
Gas Reservoirs ◽  
Filtration Loss

Summary Severe formation damage often occurs during the drilling process, which significantly impedes the timely discovery, accurate evaluation, and efficient development of deep tight clastic gas reservoirs. The addition of formation protection additives into drilling fluid after diagnosing the damage mechanism is the most popular technique for formation damage control (FDC). However, the implementation of traditional FDC measures does not consider the multiscale damage characteristics of the reservoir. The present study aims at filling this gap by providing a complete and systematic damage control methodology based on multiscale FDC theory. First, the characteristics of multiscale seepage channels were described through petrology, petrophysics, and well-history data. Subsequently, based on laboratory formation damage evaluation experiments, the formation damage mechanism of each seepage scale was determined. Finally, based on the multiscale formation damage mechanism, a systematic multiscale FDC technology was proposed. Through the use of optimized drilling fluid based on multiscale FDC theory, high-permeability recovery ratio (PRR), high-pressure bearing capacity of plugging zone, and low cumulative filtration loss were observed by laboratory validation experiments. Shorter drilling cycle, less drill-in-fluid loss, lower skin factor, and higher production rates were obtained by using the optimized FDC drilling fluid in field application. This multiscale FDC theory shows excellent results in minimizing formation damage, maintaining original production capacity, and effectively developing gas reservoirs with multiscale pore structure characteristics.

A Practical Approach To Prevent Formation Damage by High-Density Brines During the Completion Process

1991 ◽  
Author(s):  
S.K. Baijal ◽  
L.R. Houchin ◽  
K.L. Bridges
Keyword(s):  
High Density ◽  
Practical Approach ◽  
Formation Damage ◽  
Completion Process

Formation Damage Tests of High-Density Brine Completion Fluids

1986 ◽  
Vol 1 (06) ◽  
pp. 432-436 ◽  
Author(s):  
L.N. Morgenthaler
Keyword(s):  
High Density ◽  
Formation Damage ◽  
Completion Fluids

Experimental Study of the Factors Influencing Filtrate Loss of the High-Density Brine Drilling Fluid

2011 ◽  
Vol 361-363 ◽  
pp. 461-464
Author(s):  
Ming Zhang ◽  
Tian Tai Li ◽  
Xi Feng Zhang
Keyword(s):  
Laboratory Experiments ◽  
Oil And Gas ◽  
Drilling Fluid ◽  
Field Application ◽  
High Density ◽  
Fluid Loss ◽  
Affecting Factors ◽  
Oil And Gas Fields ◽  
Filtrate Loss ◽  
Gas Fields

High density brine drilling fluid has been widely applied in the high pressure and complex oil and gas fields. Effectively controlling high density brine drilling fluid loss is an important factor for reducing the reservoir damage and keeping well stability. Base on general drilling fluid formulations，the affecting factors of filtrate loss of high density brine drilling fluid were analysed through mass laboratory experiments. The results show that the main fctor was the content of caustic soda and bentonite, secondly the density and the shape of adding product. The combination of adding product is one of effective method to control the filtration property of high density brine drilling fluid. The results will provide reliable foundation for successful field application.

A Game Changer in Scale-Squeeze Technology

2021 ◽  
Vol 73 (02) ◽  
pp. 40-43
Author(s):  
Paula Guraieb ◽  
Ross Tomson ◽  
Victoria Brooks ◽  
Ji-young Lee ◽  
Jay Weatherman
Keyword(s):  
Field Trials ◽  
Field Application ◽  
Third Party ◽  
Reservoir Rock ◽  
Formation Damage ◽  
Scale Inhibitor ◽  
No Formation ◽  
Intact Core ◽  
Large Improvement

Background Field trials using a new scale-inhibitor technology that improves treatment lifetime of scale squeezes have been successfully performed in the Gulf of Mexico. Tomson Technologies, in partnership with Shell, developed proprietary nanoparticle carriers that enhance scale-inhibitor adsorption to the reservoir and control the return rate for extended periods of time. This technology results in less chemical bleed off in the initial flowback and increases the chemical retained in the reservoir, allowing for more effective squeeze treatments. Both nanoparticle-enabled phosphonate and polymer inhibitors have now been developed and successfully squeezed in the field. Phosphonate inhibitors are widely used for squeeze treatment due to their desirable adsorption and release properties in carbonate and sandstone reservoirs. Minor changes have been made to the chemistry, but overall, the fundamentals have remained unchanged for decades. Polymeric scale inhibitors have also been developed for cases in which phosphonates are not applicable. The nano-enhanced technology provides a large improvement of treatment lifetime of 2 to 4 times (200-400%) when compared to incumbents, making this technology advancement attractive even in cases where current squeezes are considered successful. The well selected for this case study is an offshore formation with a predominantly sandstone mineralogy (approximately 80% quartz) with 25-30% porosity and bottomhole temperature of 183°F (83°C). Technology From the Lab to Field A sandpack sample from the trial well was used in the laboratory to deter-mine the adsorption and desorption properties of the nano-enabled inhibitor in realistic rock conditions. Multiple conditioning steps were used before product was injected in a sequence that mimicked field squeeze treatments. Mass-balance results from the sandpack experiment show adsorption of approximately 8 mg of polymer retained per gram of crushed reservoir rock used in the experiment. A typical rule of thumb for phosphonate-scale inhibitors (only as a comparison since this is a polymeric scale inhibitor) is 1-2 mg of inhibitor retained per gram of rock. Therefore, this is considered a large improvement on adsorption. There are challenges associated with measuring polymers in brine as residuals; however, multiple methods, both in-house and external, were com-pared to ensure accuracy. The results using the nano-enhanced scale inhibitor show concentrations higher than 1 mg/L of active polymer for over 7,000 pore volume of return in the sandpack experiment. Complete intact core experiments were also conducted with reservoir fluids and showed no formation damage during the injection of the product with regained oil permeability of 96%. Oil permeability was in the 150-200 mD range for the intact core experiments. Third-party coreflood testing was performed with nitrified and foamed stages to ensure compatibility with the nano-enabled chemistry. No formation damage was observed with the nitrification of the stages containing the nano-enabled chemistry. Field Application Case Study After extensive lab validation of the product and supporting corefloods to de-risk the technology, Well A was selected by Shell to be the first well treated with the new nano-enabled extended-lifetime inhibitor.

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