bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Use of Coiled Tubing Catenary System to Intervene a Well with Restricted Flowback Facilities
Authors: Tapia W. R. , Marsaleh Z. , Srisa-ard S. 
Published: February 2017

Abstract
After an operator confirmed wellbore integrity failure in a well located on a small platform, a coiled tubing (CT) catenary intervention was urgently required. However, the production facilities of the platform were not authorized to operate, which represented an impediment to receive returns from the wellbore. This paper documents the analysis and implementation of nonconventional flowback methods and the actions taken to perform the intervention using a state-of-the-art fly-by-wire CT catenary package in a setup that had never used before in this field.
After a shut-in period, the subject well faced integrity issues that could end in an uncontrolled situation. To remediate this situation, milling and plug-setting runs were designed using a catenary system with a fly-by-wire CT unit set for first time completely on the vessel and leaving only the injector head on the platform. To address the flowback limitation, technical and economical assessments were performed on three options: using slope barges to receive fluids in storage tanks, setting conventional flowback equipment on board the catenary vessel, or using the gas injection pipeline available on the platform.
After analyzing each alternative, the options to use slope barges and flowback equipment on the vessel were discarded after confirming that they represented an additional risk and generated higher costs for their implementation. The use of the gas injection pipeline involved the modification of many resources on land and at the offshore facilities, and a detailed plan was needed to utilize the lines in a different way from their initial design. Additionally, weather conditions played a major role during the job execution. Consequently, a special focus was placed on elaborating contingency plans to address emergencies during the operation taking into account that the method implied handling hydrocarbons at surface under uncommon situations. The coordination and collaboration in the operation enabled the operator to achieve the expected results, recovering the wellbore integrity in a cost-effective way, while also eliminating the exposure of additional vessels or sophisticated equipment on location.
The paper presents the large amount of information that was amassed during the implementation of the solution, which could be used by other locations facing similar conditions where conventional production facilities cannot be used during well interventions. The document also includes contingency plans for every stage of the project, safety measurements, lessons learned, and details of the modifications done to the gas injection system and the CT equipment.
Coiled Tubing Advancements Enable Multistage Stimulation and Production Profiling in an Exploration Well in Eastern Siberia
Authors: Burdin K. , Yudin A. , Ronzhin K. , Demkovich M. , Kreknin S. , Pushnikov K. , Borovinskiy Yu. , Zykov. A. 
Published: February 2017

Abstract
The geology of Eastern Siberia formations is unique. In particular, producing formations of the Chayandinskoye field have extremely low temperatures 46 -55° F (8 to 13°C). The field is currently in the exploration stage. Geological properties of the formations vary significantly, and it is necessary to define appropriate methods of well construction and completion prior to switching to a field development stage. One of the prospective options is to implement hydraulic fracturing in low-permeability areas of the Chayandinskoye. A multistage stimulation campaign was executed to test the efficiency of hydraulic fracturing in subhorizontal multilayer well. Coiled tubing was involved in operating controllable frac ports, well kick-off and inflow profile recording using proprietary technologies. The project is one of the first gas fracturing campaigns in Eastern Siberia.
The well completion configuration combined 6-5/8- and 4-1/2-in. liners, equipped with three frac ports that allow multiple opening and closing. This completion makes possible to get separate or combined inflow from producing layers. The coiled tubing fleet made several runs for frac port manipulation, wellbore cleanout of debris and residual proppant, and well kickoff until production achieved the natural flow regime.
Gas wells of Chayandinskoye field have a potential to form gas hydrates at formation conditions. Therefore, special inhibitors at high concentrations were introduced in stimulation fluid and during wellbore cleanout and kickoff. Coiled tubing minimized the hydrate issues from production start up until stable gas flow was reached. A wireline bottomhole assembly for inflow profiling and downhole pressure and temperature recording was used to obtain precise measurements of multiphase flow in the sub-horizontal wellbore. The tool was run via coiled tubing, and fiber optic telemetry transferred data from the bottomhole in real time.
The remote location of the field and limited operational timeframe due to winter road conditions generated additional difficulties in equipment logistics. As a result, the planning and preparation phases were crucial for project execution. Results have shown that fracturing as a method of field development is effective, but requires a complex preparatory stage in the laboratory and further optimization to local logistics and geological conditions. Coiled tubing services are an integral part of the completion process. By combining fiber optics telemetry and multiphase flow scanning, engineers could identify underperforming frac ports and propose prompt remedies. The technologies used in the well also enabled production testing in the exploration well in various regimes – separately from each formation, and combined. Results from the complex exploration workflow will be used to make decisions on overall field development.
Sand Consolidation Case History and Lessons Learned from Peninsular Malaysia
Authors: Othman Anis Izzuddin , Zaki Shazana Bt. , Naharindra Adhi , Riyanto Latief , Yahia Zaidil B. , Govinathan Kesavan , Kristanto Tutus , Yeo Kim Teng 
Published: February 2017

Abstract
Field A, an oil field located in Peninsular Malaysia, was completed in 2007 with an initial production of 6,000 BOPD and managed to reach a peak production of 15,000 BOPD the same year, with a water cut of 15%. Toward the end of 2014, a decrease in production was observed with an increase in water cut to 85%. Coupled with high water cut, some of the wells experienced sand production issues. Most of the wells were completed with either standalone screens or without any sand control methods. After a few years in production, the sand-producing wells were shut-in to help prevent damage to surface facilities.
Two idle oil wells, Wells 1 and 2, were identified and efforts were made to reactivate them. High costs can be associated with remedial mechanical sand control to work over a well, so a chemical consolidation treatment using solvent-based resin was identified as a less expensive solution for remedial sand control for these wells.
Chemical sand consolidation using solvent-based epoxy resin was tested in a laboratory using produced sand samples from the selected wells and showed good results. The chemical consolidation treatments for Wells 1 and 2 were designed based on these results. Before treatment was performed for either well, Well 2 was replaced with Well 3 because of a gas supply shortage, which affected total field production. In October and November 2015, Wells 1 and 3 were intervened and chemical sand consolidation was executed on both wells. After the treatment, Wells 1 and 3 were brought back on production. Sand production for Well 1 was below the threshold limit of 15 pounds per thousand barrels (pptb). However, the performance of Well 3 did not meet expectations.
This paper describes the process of treatment design and execution for the chemical sand consolidation of Wells 1 and 3 and explains the workflow used during the design stage. Coiled tubing isolation technique and bullhead treatment technique are discussed together with lessons learned from Wells 1 and 3 in terms of designing chemical sand consolidation treatments for future applications.
Cost and Value of a Dissolvable Frac Plug
Authors: Walton Zachary , Porter Jesse , Fripp Michael , Vargus Greg 
Published: February 2017

Abstract
Although all plug-and-perf systems require frac plugs to isolate zones in the wellbore, there are alternative approaches to hydraulic fracturing using the plug-and-perf method. The availability of dissolvable frac plugs enables operators to weigh the cost and risk of using non-dissolvable frac plugs against the cost and risk of dissolvable frac plugs. This paper analyzes the cost and value of these varying fracturing approaches for applications in North America in traditional and extended reach wellbores.
Frac plugs must be removed from the wellbore before production begins. Non-dissolving frac plugs are removed by milling; this step increases the cost of the overall completion and can sometimes lead to production delays. Risks associated with the milling operation include becoming stuck in the wellbore, damage from the milling debris, and the requirement for larger amounts of water. Consequently, the cost of milling is an added cost to non-dissolvable fracture products. Dissolvable solutions, however, have a larger upfront cost because dissolvable materials are more expensive than non-dissolving materials.
There is a trade-off between the larger upfront costs of dissolvable fracturing technology and the milling costs and risks of non-dissolvable fracturing technology. This trade-off depends on the number of stages, wellbore fluids, formation parameters, operational costs, cost of delayed production, and the operator's willingness to accept risk. The trade-offs also vary between operators and regional geographies. The costs of non-dissolving frac plugs are acquired from historical data and include tools, milling, materials, and the time delay to production, as well as the weighted risk of potential formation damage and lost time incidents. The costs of dissolvable fracture plugs are estimated from the experience in the use of this dissolvable technology. These dissolvable costs are modeled for a typical wellbore in North America for both full wellbore and extended reach laterals. The result is an estimate of the trade-off between cost and risk for non-dissolving and dissolvable fracture technology.
A dissolvable frac plug adds both cost and value to fracturing operations in the unconventional market. A key advantage for dissolvable frac plugs is the ability to fracture longer extended reach wellbores. This paper enables the operator to balance the tool cost with the value of eliminating operational mill-out steps, overall cost of the completion, risk associated with the completion, and the time necessary to begin production.
Electric Submersible Pump Changeouts with the use of HWO Units: An Evolutionary Path of Efficiency
Authors: Chacon Alejandro , Pedraza Carlos , Berthe Vanessa Hernandez , Marcano Aurelio Jose 
Published: February 2017

Abstract
Within the oil industry worldwide, artificial lift (AL) has become necessary to achieve desired reservoir production and maintain commercial output levels. According to Spears and Associates, in 2005, about $50,000 was spent per every new well drilled, by the end of 2016 it is expected that this figure is above $300,000. Bear in mind that this is a figure to bring things into perspective, as part of that investment is in replacing equipment in older wells, however, it does tell an important story in terms of showcasing the evident growth of the service. In an ever-evolving industry, where the ultimate goal is reducing the costs per BOE lifted, being efficient is paramount to the overall success of an operation.
According to industry statistics (Spears 2016 Artificial Lift Market Analysis), wells fitted with electrical submersible pump (ESP) systems represent approximately 56% of the global AL market revenue-wise; representing the most common lifting method, followed by rod lifting, progressive cavity pumps (PCP), and gas lift in fourth place. Just as with any complex piece of equipment, these pumps must often be pulled out for maintenance or replacement, and retrieval is not a trivial task. Workover rigs are the usual workhorse for such operations; however, other equipment, such as hydraulic workover (HWO) units, can be used to perform the same task in a more efficient manner. The evaluation approach was based on analysis from operational times throughout the past year, comparing both the evolutionary improvement of the HWO interventions as well as the operations performed with a conventional workover unit.
HWO units offer several advantages compared to workover rigs when performing retrieval and deployment of ESPs. The most important are smaller footprint and shorter rigup times. Additionally, if a well exhibits wellhead pressure (WHP), only an HWO unit can be used to perform the work. For these reasons, in land operations in western Venezuela, HWO units have proven to be the method of choice for artificial lift equipment replacement operations. Because these wells produce from 1,000 to 3,000 BOPD, they are of paramount importance to Venezuela's production stream. This paper explains the necessary steps and procedures to complete such operations; additionally presented are study results showing decreased intervention time from 15 to 11 days, which is a significant increase in efficiency. Conversely, this study showed that it takes approximately 20 days to complete the same intervention using a conventional workover unit.
Lastly described is the evolutionary path of efficiency developed by the operations team to improve intervention results, which are based on key performance indicators and other qualitative data, providing solid evidence of improvement.
Big Bore Balanced Sand Cleanout in HP/HT Gas Well: An Amalgamation of an Innovative Fluid System and Engineering
Authors: Khandelwal Nakul , Chandak Raj , Makkar Archit , Pathak Himanshu 
Published: February 2017

Abstract
Coiled tubing (CT) is widely used during sand cleanout applications for its multiple benefits, such as speed, cost effectiveness, minimum reaction time, efficient operations, the ability to perform live intervention cleanouts, etc. However, these benefits are difficult to achieve in complex, offshore, high-pressure/high-temperature (HP/HT), or big bore wells because of various operational constraints, such as weight, dimensions, wellbore trajectory, and completion design, resulting in increased expenditures and operation time for workover activities.
This paper describes how these constraints were eliminated using a synergy of an innovative fluid system and engineering to perform a challenging, balanced sand cleanout treatment using 1.75-in. 5800 m long CT in ~500 m of a 7-in. 35-lbf casing section executed in a 5300-m deep HP/HT well.
The deep HP/HT well had a minimum restriction of 2.56-in. in the upper completion limits, requiring large-diameter CT strings and a bottomhole assembly (BHA). Feasibility studies for use of a 1.75-in. CT vs. 2-in. CT string were performed, resulting in the selection of the 1.75-in. string. Another challenge was executing sand cleanout in a balanced condition, resulting in the selection of a saturated 13.1-lbm/gal potassium-formate (K-formate) brine. The combination of all three major constraints, a) 500-m long 7-in. section, b) use of 1.75-in. CT string, and c) use of saturated brine, made the cleanout design challenging, as sand cleanout with CT requires circulation rates, net particle rise velocity, friction pressures, viscosity, and fluid properties within the design envelope. However, the inversely proportional nature of such treatments means tuning of one property would decrease the operational feasibility of other properties.
Based on results of several tests, a customized fluid recipe was designed containing a gelling agent that can become hydrated in saturated brine and remain stable at high temperatures. A compatible friction reducing agent was used to help reduce pumping friction to attain the desired annular fluid rate and velocity. A field test was performed with the designed fluid at surface with a CT string that was to be used for operations, confirming the effectiveness of the fluid recipe.
Using downhole turbulence created by the tool, along with the custom-designed recipe in combination with wiper trips, the necessary design parameters were achieved for the cleanout operation, resulting in a) effective sand cleanout with ~98% efficiency, b) reduced operating hours, c) cost savings on workover operations, d) safer operation by keeping the well in a balanced condition, and e) a contingency action in place for screenout during fracturing treatments.
The procedure described in this paper, along with lesson learned, can be applied in similar applications to help optimize results and overcome related challenges.
Wireline-Deployed Perforating: Maximizing Efficiency without Killing the Well
Authors: Aboelnaga Sharif , Martin Andy , Ugalde Angel , Contreras Javier Mercado 
Published: February 2017

Abstract
In the current oil and gas environment, the status quo for completing and perforating wells is being challenged by increased well complexities and extreme cost pressure. In pursuit of increased productivity, improved operational efficiency, and reduced costs, operators and service companies must look at novel approaches to how they complete and perforate wells.
Several innovative approaches have been implemented to optimize perforating operations and enable operators to complete wells in a more efficient, cost-effective, and productive manner. Detailed job planning and preparation identified candidate wells with intervals that typically would not be accessible or cost-effective via wireline perforating. Through the introduction of wireline perforating tractors, addressable selective switches, release devices and high-strength cables, the ability to access these wells by wireline and convey ultralong perforating gun strings has pushed the operating envelope. Utilizing job simulation and planning software, optimum perforating configurations can be designed to maximize gun length while ensuring the assembly can reach the target depth, perforate, and either drop the guns intentionally or withstand the perforating shock and return to surface safely with the spent guns.
In the last several years, ultralong perforating operations deployed on wireline have become more widespread. These jobs have demonstrated that in specific applications, improved completion efficiency can be achieved over conventional perforating operations without impacting the operational integrity or safety of the operation. A specific area of focus is wireline-deployed perforating that is performed without killing the well. In these cases, innovative solutions have delivered significant cost savings to the operator with improved operational efficiency of the perforating operation as well as the post-perforating cleanup.
Corneal Toxicity Following Exposure to Asclepias Tuberosa
Authors: Mikkelsen Lauge Hjorth , Hamoudi Hassan , Gül Cigdem Altuntas , Heegaard Steffen 
Published: February 2017

Purpose:
To present a case of corneal toxicity following exposure to milky plant latex from Asclepias tuberosa.

Methods:
A 70-year-old female presented with blurred vision and pain in her left eye after handling an Ascepias tuberosa. Clinical examination revealed a corneal stromal oedema with small epithelial defects. The corneal endothelium was intact and folds in Descemets membrane were observed. The oedema was treated with chloramphenicol, dexamethasone and scopolamine.

Results:
The corneal oedema had appeared after corneal exposure to the plant, Asclepias tuberosa, whose latex contains cardenolides that inhibit the Na+/ K+-ATPase in the corneal endothelium. The oedema resolved after 96 hours. After nine months the best corrected visual acuity was 20/20.

Conclusion:
Corneal toxicity has previously been reported for plants of the Asclepias family. This is a rare case describing severe corneal toxicity caused by exposure to latex from Asclepias tuberosa. Handling of plants of the Asclepias family should be kept as a differential diagnosis in cases of acute corneal toxicity.
Antibiotic Prophylaxis in Orbital Fractures
Authors: Reiss Benjamin , Rajjoub Lamise , Mansour Tamer , Chen Tony , Mumtaz Aisha 
Published: February 2017

Purpose:
To determine whether prophylactic antibiotic use in patients with orbital fracture prevent orbital infection.

Design:
Retrospective cohort study.

Participants:
All patients diagnosed with orbital fracture between January 1, 2008 and March 1, 2014 at The George Washington University Hospital and Clinics.

Main Outcome Measures:
Development of orbital infection.

Results:
One hundred seventy-two patients with orbital fracture met our inclusion and exclusion criteria. No orbital infections were documented. Twenty subjects (12%) received no prophylactic antibiotic, and two (1%) received only one dose of antibiotics pre-operatively for surgery. For primary antibiotic, 136 subjects (79%) received oral antibiotics, and 14 (8%) received intravenous (IV) antibiotics (excluding cefazolin). Cephalexin and amoxicillin-clavulanate were the most prescribed oral antibiotics that are equally effective. Five-to-seven day courses of antibiotics had no increased infections compared to ten-to-fourteen day courses. Calculated boundaries for effectiveness of prophylactic antibiotics ranged from a Number Needed to Treat (NNT) of 75 to a Number Needed to Harm (NNH) of 198.

Conclusion:
Antibiotics for prevention of orbital infection in patients with orbital fractures have become widely used. Coordination between trauma teams and specialists is needed to prevent patient overmedication and antibiotic resistance. Should antibiotics be used, shorter courses and avoidance of broad spectrum agents are recommended. Additional studies are needed.
Effect of Water Quality and Temperature on the Efficiency of Two Kinds of Hydrophilic Polymers in Soil
Authors: Dehkordi Davoud Khodadadi 
Published: February 2017

ABSTRACT: In this study, evaluation of two‐superabsorbent effects, Super‐AB‐A‐300 and Super‐AB‐A‐200 in a sandy soil on the water retention capability and saturated hydraulic conductivity (Ks) at different water quality and soil temperature were done. The Super‐AB‐A‐200 was less effective in water uptake than Super‐AB‐A‐300. The efficiency of these polymers in water retention was negatively influenced by the water quality and temperature. The efficiency of these polymer treatments in water uptake reduced significantly (P < 0.05) with increasing soil temperature. In the control soil, the Ks stayed nearly constant with increasing soil temperature. As compared to the untreated control, the treated soil demonstrated a significant (P < 0.05) linear increase of Ks with increasing soil temperature. In the control soil, the water holding properties curve did not change with increasing soil temperature.