Cost-Effective Field Applications Utilizing Coiled-Tubing Inflatable Packer System in South Mexico

2010 ◽  
Author(s):  
Francisco Cazares-Robles ◽  
Juan Jose De La Fuente Rodriguez ◽  
Angel Moreno ◽  
Mario Noguez Lugo ◽  
Guadalupe Tellez ◽  
...  
Keyword(s):  
Cost Effective ◽  
Effective Field ◽  
Coiled Tubing

Asphaltene Mitigation in Giant Carbonate Abu Dhabi Fields: A Techno-Economic Comparison Between Continuous Injection and Formation Squeeze

2021 ◽  
Author(s):  
Mark Grutters ◽  
Sameer Punnapala ◽  
Dalia Salem Abdallah ◽  
Zaharia Cristea ◽  
Hossam El Din Mohamed El Nagger ◽  
...  
Keyword(s):  
Cost Effective ◽  
Threshold Value ◽  
Field Trials ◽  
Mitigation Strategy ◽  
Operating Conditions ◽  
Mitigation Strategies ◽  
Production Cycle ◽  
Asphaltene Precipitation ◽  
Coiled Tubing ◽  
Continuous Injection

Abstract Asphaltene deposition is a serious and re-occurring flow assurance problem in several of the ADNOC onshore oilfields. Fluids are intrinsically unstable with respect to asphaltene precipitation, and operating conditions are such that severe deposition occurs in the wellbore. Wells in ADNOC are generally not equipped with downhole chemical injection lines for continuous inhibition, and protection of the wells require frequent shut-in and intervention by wireline and coiled tubing to inspect and clean up. Since some of the mature fields are under EOR recovery strategies, like miscible hydrocarbon WAG and CO2 flood, which exacerbates the asphaltene precipitation and deposition problems, a more robust mitigation strategy is required. In this paper the results of two different mitigation strategies will be discussed; continuous injection of asphaltene inhibitor via a capillary line in the tubular and asphaltene inhibitor formation squeeze. Three asphaltene inhibitors from different suppliers were pre-qualified and selected for field trial. Each inhibitor was selected for a formation squeeze in both one horizontal and one vertical well, and one of the inhibitors was applied via thru-tubing capillary string. The field trials showed that continuous injection in remote wells with no real-time surveillance options (e.g. gauges, flow meters) is technically challenging. The continuous injection trial via the capillary string was stopped due to technical challenges. From the six formation squeezes four were confirmed to be effective. Three out of fours squeezes significantly extended the production cycle, from approximately 1.4 to 6 times the normal uninhibited flow period. The most successful squeezes were in the vertical wells. The results of the trial were used to model the economic benefit of formation squeeze, compared to a ‘do-nothing’ approach where the wells are subject to shut-in and cleanup once the production rates drop below a threshold value. The model clearly indicates that the squeezes applied in ADNOC Onshore are only cost-effective if it extends the normal flow period by approximately three times. However, a net gain can be achieved already if the formation squeeze extends the flow cycle by 15 to 20%, due to reduction of shut-in days required for intervention. Therefore, the results in this paper illustrate that an asphaltene inhibitor formation squeeze can be an attractive mitigation strategy, both technically and economically.

Increasing Operational Efficiency in Extended Reach, Offshore Wells – A Case Story from Middle East

2016 ◽  
Author(s):  
Anthony MacLeod
Keyword(s):  
System Integration ◽  
Cost Effective ◽  
Lessons Learned ◽  
Operating Efficiency ◽  
Coiled Tubing ◽  
Electric Line ◽  
Release Device ◽  
Integration Test ◽  
Closed Position ◽  
Shifting Profile

ABSTRACT Objective A case story from ME will be presented covering an extreme extended reach, offshore well. Any increase to operating efficiency can save time and increase production. In this case story two SSD's were opened in a single run on e-line, an outstanding achievement due to the ID restrictions and extended reach of the well. The paper will discuss the planning, the operation, the achievements and the lessons learned. Methods, Procedures, Process This well was recently worked over, retrieval and new installation of upper and lower completion. Due to the well going on total losses during the workover, a closed system was deployed to enable the operator to set the hydraulic packers. The packer is utilized for isolation between two zones, with each zone having two SSD's in which one SSD per zone was required to be opened to allow access to the formation. From day one of planning the primary solution for this intervention was an electric over hydraulic toolstring made up of five tools, a 218 electric release device, 218 CCL for correlation, a 218 tractor for conveyance, a 218 stroker for the mechanical manipulation and a 218 key to address the shifting profile in the SSD (toolstring). A slimhole toolstring was required due to the packer ID of 2.81" The operator was using the service provider for other interventions on this workover campaign and decided to challenge them with opening two SSD's in one run while not shifting the adjacent SSD's. The challenging underlying economics of the industry today has created a powerful driver for operators to find more efficient, cost effective and safer intervention methodologies. The operation covered in this case provided just such improvements to the client: by utilizing electric line intervention tools the operator negated the requirement for a large footprint coiled tubing intervention. Results, Observations, Conclusions A System Integration Test (SIT) was completed onshore prior to mobilization, where multiple shifts were successfully executed on a 90° deviated pipe using a single set of shifting key pads. Test results were then repeated offshore, completing two interventions in a single run. The SSD's were successfully opened at ~12,000 ft MDRT and ~8,000 ft MDRT, respectively while leaving the two adjacent SSD's in the closed position. Results, client objective was 100% achieved using only electric line, enabling the client to move forward with similar well designs having the confidence that a safe, reliable electric line solution is locally available. Additional results include reduced HSE risks as the e-line approach eliminated the use of a heavier CTU. Further contributing to the HSE benefits on this operation, only 6 persons were needed on site and no heavy lifts were required. The paper will also cover some lessons learned as debris in the profile and tubing caused some challenges. Novel/Additive Information This operation shows how the industry is constantly trying to improve on existing methods in order to be more efficient, safe and cost effective.

Evaluation of Two Field Screening Test Kits for the Detection of PCBs in Soil by Immunoassay

1994 ◽  
Vol 77 (6) ◽  
pp. 1664-1671 ◽  
Author(s):  
Larry C Waters ◽  
Rob R Smith ◽  
Joe H Stewart ◽  
Roger A Jenkins ◽  
Richard W Counts
Keyword(s):  
False Negative ◽  
Cost Effective ◽  
Effective Field ◽  
Screening Methods ◽  
Laboratory Methods ◽  
Rigorous Evaluation ◽  
Field Screening ◽  
Hazardous Waste Sites ◽  
The Cost ◽  
Antigen Antibody

Abstract Effective field screening methods could minimize the time and reduce the cost of characterizing and remediating hazardous waste sites. Rigorous evaluation of novel field screening methods is required before they can be considered as replacements for, or adjuncts to, currently used laboratory methods. Alternatives to standard laboratory analytical methods should be rapid, analyte-specific, cost-effective, accurate, and sensitive in the range at which the analyte is regulated. In this study, 2 immunoassay- based field test kits for polychlorinated biphenyls (PCBs) in soil were evaluated with reference to those criteria. PCBs were analyzed in both spiked and field soil samples. Based on laboratory performance, we estimate that 20 to 40 samples can be analyzed in the field per day. Sensitivity of the assay is in the 1 ppm range. Because the assay is based on the specificity of the antigen/antibody reaction, interferences are practically negligible. The method is accurate; the false-negative and false-positive results that were observed can be explained by differences in the immunoreactivities of the Aroclors present in the test samples and the Aroclors used as standards in the assay. The savings in time and expense to analyze PCBs in soil with the immunoassay-based test kits over conventional laboratory methods should be substantial.

scholarly journals Development of a Push-Type Liquid Fertilizer and Pesticide Sprayer

2021 ◽  
Author(s):  
Fadeyibi, A., ◽  
Akpenpuun, T. D. ◽  
Issah, A. M.
Keyword(s):  
Crop Production ◽  
High Efficiency ◽  
Production Systems ◽  
Insect Pest ◽  
Field Capacity ◽  
Cost Effective ◽  
Effective Field ◽  
Rotating Shaft ◽  
Liquid Fertilizer ◽  
Materials Used

Low yield, insect, pest and weeds competing with crops are challenges in crop production systems in Nigeria. This research was carried out to design and developed a push-type wheel operated liquid fertilizer/ pesticide sprayer. The materials used for fabrication were selected based on the design assumptions, calculations and sourced locally. The sprayer was mechanically operated through the rotating shaft of the cartwheels using a slider-cranks mechanism. An accumulator was provided to create the required pressure of continuous spraying action. The sprayer possesses two tanks of 16 L each, a wheel, a coup-able stand, eight nozzles and an adjustable height depending on the crop height. The sprayer can cover 4.8 hectares per day, effective field capacity of 1.13 ha/h, theoretical field capacity of 1.24 ha/h. and field efficiency of 91%. The developed sprayer consumes less time, cost effective, high efficiency and the users will just have to pull the cart and the whole mechanism will be operated with ease.

Thermal Benefits With Subsea Heat Bank

2002 ◽  
Author(s):  
Kristin Falk ◽  
Rune Killie ◽  
Svein Ha˚heim ◽  
Per Damsleth
Keyword(s):  
Oil And Gas ◽  
Hydrate Formation ◽  
Cost Effective ◽  
Effective Field ◽  
Production Equipment ◽  
Cfd Simulations ◽  
Field Development ◽  
Gas Hydrate Formation ◽  
Computational Fluid Dynamics Cfd ◽  
Cfd Analyses

Subsea production of oil and gas involves structures on the seabed such as manifolds and X-mas trees that require thermal insulation of piping and valves to avoid gas hydrate formation. The insulation is expensive and time consuming to apply yet may still leave areas with inadequate protection. These “cold spots” accelerate the cooling during a production shutdown. A Heat-Bank concept is developed as an alternative to conventional insulation. The entire subsea structure is covered with an insulated shell. During shutdowns the heated fluid inside the cover keeps the production equipment warm over a prolonged period before hydrates start to form. Computational Fluid Dynamics (CFD) simulations are used to quantify the heat loss effects of natural convection and leakage through openings in the cover. The CFD analyses demonstrate the relative performance of the concept compared to the traditional method of insulating individual piping components. Application of the Heat-Bank concept opens new possibilities for environmentally friendly and cost-effective field development, especially for deep water.

scholarly journals Simple, affordable, and sustainable borehole observatories for complex monitoring objectives

2015 ◽  
Vol 4 (1) ◽  
pp. 99-109 ◽  
Author(s):  
A. Kopf ◽  
T. Freudenthal ◽  
V. Ratmeyer ◽  
M. Bergenthal ◽  
M. Lange ◽  
...  
Keyword(s):  
Pore Pressure ◽  
Data Transfer ◽  
Effective Means ◽  
Drill Pipe ◽  
Cost Effective ◽  
Drill String ◽  
Data Sets ◽  
Coiled Tubing ◽  
Complex Monitoring ◽  
Acoustic Modem

Abstract. Seafloor drill rigs are remotely operated systems that provide a cost-effective means to recover sedimentary records of the upper sub-seafloor deposits. Recent increases in their payload included downhole logging tools or autoclave coring systems. Here we report on another milestone in using seafloor rigs: the development and installation of shallow borehole observatories. Three different systems have been developed for the MARUM-MeBo (Meeresboden-Bohrgerät) seafloor drill, which is operated by MARUM, University of Bremen, Germany. A simple design, the MeBoPLUG, separates the inner borehole from the overlying ocean by using o-ring seals at the conical threads of the drill pipe. The systems are self-contained and include data loggers, batteries, thermistors and a differential pressure sensor. A second design, the so-called MeBoCORK (Circulation Obviation Retrofit Kit), is more sophisticated and also hosts an acoustic modem for data transfer and, if desired, fluid sampling capability using osmotic pumps. In these MeBoCORKs, two systems have to be distinguished: the CORK-A (A stands for autonomous) can be installed by the MeBo alone and monitors pressure and temperature inside and above the borehole (the latter for reference); the CORK-B (B stands for bottom) has a higher payload and can additionally be equipped with geochemical, biological or other physical components. Owing to its larger size, it is installed by a remotely operated underwater vehicle (ROV) and utilises a hot-stab connection in the upper portion of the drill string. Either design relies on a hot-stab connection from beneath in which coiled tubing with a conical drop weight is lowered to couple to the formation. These tubes are fluid-saturated and either serve to transmit pore pressure signals or collect porewater in the osmo-sampler. The third design, the MeBoPUPPI (Pop-Up Pore Pressure Instrument), is similar to the MeBoCORK-A and monitors pore pressure and temperature in a self-contained manner. Instead of transferring data on command using an acoustic modem, the MeBoPUPPI contains a pop-up telemetry with iridium link. After a predefined period, the data unit with satellite link is released, ascends to the sea surface, and remains there for up to 2 weeks while sending the long-term data sets to shore. In summer 2012, two MeBoPLUGs, one MeBoCORK-A and one MeBoCORK-B were installed with MeBo on RV Sonne, Germany, in the Nankai Trough area, Japan. We have successfully downloaded data from the CORKs, attesting that coupling to the formation worked, and pressure records were elevated relative to the seafloor reference. In the near future, we will further deploy the first two MeBoPUPPIs. Recovery of all monitoring systems by a ROV is planned for 2016.

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