bluuebunny/crossref_metadata_2025_split huggingface dataset:
Best Practices for Design, Operation, and Maintenance of Wireline Intervention Tools for Sour Service
Authors: Giem Greg , Milkovisch Mark 
Published: March 2020

Abstract
This paper presents lessons learned from the design and field deployment of many different assets in sour environments. It will address the requirements and implications of design, operation, and maintenance of wireline intervention tools when exposed to H2S and CO2.
Many wells in the world are drilled in fields with high concentrations of H2S and CO2. Even low concentrations of H2S put wireline tools designed from conventional downhole materials at risk of catastrophic failure through sulfide stress cracking (SSC), stress corrosion cracking (SCC), and hydrogen induced cracking (HIC). These wells are also highly corrosive, so even materials that are not highly vulnerable to these failure modes may suffer from extensive corrosion that still renders them unusable in these environments. Wireline intervention tools are at especially high risk of failure because the high loads they experience during normal operations preclude practices that might be standard in lighter-duty equipment like wireline logging tools.
Wireline intervention tools that are intended for sour service should be designed from the beginning with corresponding requirements to avoid not only SSC, SCC, HE, and corrosion issues, but also any issues that may be related to the materials that are selected to avoid these failure modes. Materials capable of supporting high tensile forces in sour environments are extremely limited, and most of these are susceptible to galling. Care must be taken during the design to avoid situations where this galling would occur. Both H2S and CO2 are soluble in water to create weak acids, so the amount of water present is also an important factor when determining acceptable materials.
Operation of wireline intervention tools in sour service environments must be carefully planned and executed. Proper cleaning and maintenance procedures are also critical to maintaining tool reliability and longevity following sour operations.
Much historical wireline intervention design and material selection is based on tribal knowledge (i.e., unwritten knowledge and best practices). and standard ANSI/NACE MR0175/ISO 15156, Petroleum, Petrochemical and Natural Gas Industries—Materials for use in H2S-Containing Environments in Oil and Gas Production. Tribal knowledge is often suspect, and the application of the standard is difficult for wireline intervention equipment because factors other than cracking are important. This paper also moves beyond material selection to include guidance and best practices for mechanical design, operation, and maintenance of wireline intervention tools that are not directly addressed by NACE standards.
Shedding Light Upon Interventions in Wells with Conformance Control Completion
Authors: Stepanov Vladimir , Ramondenc Pierre , Mhiri Adnene , Abdrazakov Dmitriy , Burdin Konstantin , Konysbayev Yerzhan , Slobozhaninov Alexander , Amangeldiyev Anvar , Kinnear Campbell , Sultanov Bauken 
Published: March 2020

Abstract
It is becoming more common for operators around the world to use alleged conformance control completions as a means of managing inflow zones and controlling production. When this type of completion is introduced in a field, it is extremely important to analyze its effectiveness at very early stages of the project to achieve maximized zonal contribution together with proper compartmentalization in current and subsequent completions, since this will have a significant impact on the future life of the entire field. A thorough analysis should include understanding zonal isolation before and after acid stimulation, fluid distribution inside the compartments during the treatment, and confirmation of completion integrity.
Analyzing completion performance by introducing additional downhole monitoring systems or devices is costly and is more appropriate for the long term. Another option, surveillance with wireline technology, may not provide definite conclusions due to limited acquisition extent. Alternatively, coiled tubing (CT) can provide a fit-for-purpose integrated solution to data acquisition and analysis challenge. The proposed approach uses distributed temperature sensing technology along with real-time data streaming capabilities to provide an instantaneous insight on wellbore dynamics, thus enabling informed decisions on treatment optimization, as well as yielding reliable information on interzonal communication.
This study is based on a success story of intervening with CT on 10 wells, with a total of 40 compartments in a carbonate reservoir in the Caspian region. Distributed temperature evolution models are used to build a signature library characteristic of specific flow events in the wellbore. The study consists of distributed temperature surveys lasting from 30 minutes to 6 hours that were acquired before and during the acid stimulation of each conformance compartment. Unique temperature features are identified in specific flow events, such as communication between compartments, loss of completion integrity, and effective stimulated area determination, to name a few. Those events are hypothesized and corroborated using downhole point measurements. A significant finding is that communication between zones occurs through several possible paths (i.e., through the formation/matrix or via the completion). The stimulation strategy can be modified accordingly, leveraging downhole data to maximize completion efficiency.
This combination of transient distributed temperature and point measurement data provides an insight into wellbore and reservoir flow dynamics and facilitates an optimized stimulation strategy.
Gas Injection Well Zonal Isolation Achieved Despite Wellbore Restrictions, Increases Gas Injection by More than 30%
Authors: Laguado Maria Camila , Murphy Robert Allan 
Published: March 2020

Abstract
A gas injection well 31 was being utilized to aid in the condensate production from the Barco, Guadalupe and Mirador formations. The injection well utilized 15 MSCFD into the Mirador, Barco and Guadalupe formations. After some time in operation and following several injection evaluations, it became clear that most of the gas injected was entering the upper Mirador formation rather than being equally distributed across the three formations as planned.
After an extended review of the situation, the operator decided to work the well over in order to improve the condensate base curve that is associated with the Barco/Guadalupe formations of the neighboring wells. By closing off the perforations in the Mirador, all of the gas injection would enter the Barco and Guadalupe formations and be produced in the two adjacent wells, 40Z and H38. The Mirador had three sets of perforations requiring isolation, which are the intervals (15,500-ft – 15,630-ft) / 15,500-ft – 15,400-ft) / (15,290-ft – 15,390-ft). (See Figure 1).
Smart Reservoir Depth Correlation with Tubing Conveyed Wireless Gamma Ray Position Tool—Case Studies
Authors: Temer Elias , Catheline Sebastien , Zerpa-Mendez Nahomi , Merino Carlos 
Published: March 2020

Abstract
Depth correlation before perforation is crucial in reservoir testing, to minimize the uncertainties about the reservoir being tested. Currently, three main methods are used to correlate to depth: simple pipe tally, tag of a known element in the well, or a wireline gamma ray (GR) log—which is the most accepted method, owing to its precision and track record. Wireline GR correlation, however, requires additional time (6 to 8 hours), translating into cost for the operator. We describe a new depth correlation tool, which is mounted directly in the drillstem test (DST) string and is enabled by a downhole wireless acoustic telemetry system, that provides correlation algorithm in real time without the need for extra wireline intervention. The introduction of a wireless-enabled GR measurement into the DST string radically changes the workflow for DST operations and results in significant reduction of rig time, as shown by one of our latest job campaigns in Qatar.
The True Value of Open-Water Hydraulic Access Using Coiled Tubing
Authors: Avery Mike , Greenaway Robert , Large Robert , Rice Phillip 
Published: March 2020

Abstract
As the global well base continues to increase, it is becoming apparent that under-investment in maintenance has helped contribute to a decreasing average production per subsea well. To combat this trend, more focused and cost-effective intervention techniques have emerged such as open-water hydraulic access (OWHA) using coiled tubing (CT).
OWHA using CT provides operators with a fit-for-purpose solution to deliver fluids to a subsea well without the requirement for mechanical intervention. In scenarios which meet the requirements outlined within this paper, OWHA using CT offers an attractive alternative to conventional intervention approaches.
Three predominant configurations of OWHA CT systems are apparent, all developed around differing drivers: a conventional system using a CT injector head (IH), a specialized system using a CT IH, and a powered reeler with deployment sheave. Both the benefits and limitations of each are considered to guide the reader in selecting the correct configuration for their application.
The primary cost driver for hydraulic intervention is vessel selection. Factors including regional availability, mobilization requirements, and specification are key to the selection process. An advantage of OWHA using CT is the ability to use a vessel of opportunity due to the decreased equipment footprint and specification; this directly enhances service flexibility and cost management.
When compared to alternative oil sources, the comparative cost per barrel of oil unlocked by OHWA is at least 43% less than the closest alternative. When compared to alternative intervention approaches, the simplified equipment and requirements result in a reduced total cost thus enhanced return on investment with accelerated payback.
Using average global vessel rates and generalized assumptions, for a single well intervention the total costs can be in the order of the following magnitudes: floating rig USD 9-16M, light well USD 6-10M, OWHA USD 2-5M. Using an average well production gain of 1,950 BOPD this gives a typical payback time period of ~9 months for a rig and ~3 months for OWHA.
In scenarios which meet the requirements outlined within this paper, OWHA provides the most economical solution with the ability to provide positive returns in the same financial year.
Application of Downhole Tractor in Gas Well Zonal Isolation
Authors: He Li , McAllister James , Hawkins John , Turner Marissa 
Published: March 2020

Abstract
In high angle wells, downhole tractors can be used for electric line (e-line) deployed toolstring conveyance. This paper presents the job design, planning, and execution of a rigless zonal isolation in a gas well located in the Gulf of Mexico. Downhole tractors were used as the method of conveyance during this zonal isolation.
A deepwater direct vertical access gas well was suspected to have had a sand failure event. The well was assessed and identified to be a candidate for big-hole sidetrack (BHST). In preparation to the BHST, a zonal isolation was planned to be performed prior to the decomplete. This well is highly deviated with a maximum angle of 81.5 degrees. A downhole tractor was selected to be the method of conveyance for the required wireline operations. Due to well history, the wellbore was suspected to be obstructed by sand. Selection of mitigation methods to reduce the risk of sticking toolstring in sand fill is discussed. Methodology included the use of real-time video feedback to evaluate downhole condition, as well as the use of specific tension and release subs. Prior to execution System Integration Tests (SIT) were conducted between operator and service companies to ensure the e-line cable, tractors, and bottom hole assemblies (BHA) were fully compatible and operable.
As part of the zonal isolation work, a downhole camera was deployed on tractor to observe the condition of the wellbore from SCSSV to proposed cut depth. A thru-tubing packer with blow-out plug was deployed on tractor and set on depth. A jet cutter was deployed on tractor and activated on depth. The zonal isolation job was completed without excessive tractor misruns. The job added significant value by reducing rig time needed for decomplete and accelerating well handover to Production.
This case study demonstrates the capability of downhole tractor at deploying tools in a deep near-horizontal well, and downhole tractor’s compatibility with a variety of tools. Learnings relevant to the application of tractor conveyance are discussed.
Customized Subsea Production Flowline Cleanout with Coiled Tubing from a Floating Production Storage and Offloading Vessel
Authors: Delgado Eduardo , Rodrigues Vinicius , Fagundes Luis 
Published: March 2020

Abstract
The recovery of a pipeline inspection gauge (PIG) left in a subsea production flowline in an unknown location after a failed cleaning and inspection operation is discussed. Combined with paraffin deposits, the production flowline of the best offshore producer in northeast Brazil was completely blocked.
Extensive planning was necessary to spot the coiled tubing (CT) equipment to accommodate the deck configuration of the floating production storage and offloading (FPSO) vessel and to overcome dimensional and load capacity limitations. A customized extendable jacking frame was manufactured to support the CT injector and provide room for a work window. This fit-for-purpose rigging was necessary to enable the viability of the cleanout in the production flowline of the well. CT operation modeling software was used to analyze the hydraulic and force simulations to verify that the CT would reach the target depth with optimal jetting efficiency and would tailor the cleanout methodology.
Paraffin was successfully cleaned from the flowline, and the PIG was released and recovered on surface. The CT was efficiently and safely rigged up on a FPSO without any nonproductive time or service quality issues.
The versatility of CT services to not only deliver intervention services on conventional wells but to also adapt to rig up in extreme geometries and environments are showcased along with how CT services can be applied to flowline interventions.
For this case, a customized CT frame was manufactured to overcome the challenges of rigging up on a vessel with extremely limited deck space and load capacities and restoring hydrocarbon production after a failed PIG procedure.
Successful Retrieval of First Installed Velocity String – A Case Study from Middle East
Authors: Subaii Abdullah , Al Ghubayni Mutaz R. , Shawli Yasser , Sunagatov Rustem , Ahmed Danish , Arifin Mohammad , Pochetnyy Valentin , Santali Mohammed 
Published: March 2020

Abstract
Installation of 14,200 ft of 2 3/8-in. coiled tubing (CT) as a velocity string (VS) was performed to increase the fluid production velocity and avoid a liquid loadup problem in a gas well. After the successful installation, the well produced at economic rates for few years. Because this was a pilot project to ascertain the well's deliverability with the VS installed, the operator decided to retrieve the VS. The main challenge during the VS retrieval intervention was to retrieve such a long VS that had been in a sour well (40,000-ppm CO2, 40-ppm H2S) for more than 3 years. Low carbon 90,000 psi yield strength was chosen as a material for VS to withstand corrosion and Sulphur-stress cracking. A CT tower was utilized to have the access to the work area during pipe cutting and the bottomhole assembly (BHA) removal process.
The retrieval of the installed VS was executed in several stages. First, slickline was run in hole (RIH) to install the pump-through check valves at the bottom of the installed VS. Second, these check valves were inflow tested prior to CT equipment rig up. The CT unit was then rigged up on the wellhead and RIH with the VS retrieval assembly consisting of a GS pulling tool. The VS retrieval tool was latched onto the installed VS assembly, and, by applying a straight overpull, the packer that was used to hang the VS was unset. The VS was eventually pulled to surface along with the packer. The whole assembly was secured by pipe rams on blowout preventers (BOPs). After the required inflow tests on the BOP pipe rams were performed, the pressure control equipment (PCE) stack was opened and the CT was cut below the VS packer. All tools were disconnected, and a spoolable internal connector was made up to connect the retrieving CT with the VS. Eventually the VS was safely pulled to surface.
When the uphole VS BHA was retrieved to the surface, the quick connection used for pressure testing was opened and CT was cut with a hydraulic cutter. Uphole packer rubbers were found to be damaged during pulling out of hole (POOH). Internal spoolable connector was made and pull tested to 1.25 times of CT hanging weight. After opening pipe/slip rams CT was successfully spooled on the reel.
The retrieval of the VS was conducted in a single run with total operational time of 30 hours. The operation provided information will increase industry understanding of the use of VS in gas wells, including information about techniques, downhole tools, and procedures and risk control measures used during the retrieval of a VS from a live well.
Development and Testing an Electrical Drill-Stem Test Tool Conveyed by Coiled Tubing with a Real Time Control and Acquisition System
Authors: Affleck Michael , Bakke Malmin Monika , Almas Per Egil , Sach Manfred 
Published: March 2020

Abstract
Some exploration well testing operations are executed by performing multiple runs in hole using slick line and Coiled Tubing (CT). A new technology has been developed that combines many of these operations, including contingency stimulation activities into one run.
The Electrical Drill-Stem test (e-DST) Tool is an intelligent, surface-controlled tool designed to be run on coiled tubing that allows exploration well testing operations, including stimulation to be performed in one run. Existing operations involve rigging up slick line and coiled tubing in varying sequences depending on well conditions, such that the requirement for nitrogen lifting and acid stimulation through coiled tubing as well as gauge setting and retrieving by slick line can be established. In addition to saving substantial time, the new system is designed to optimize test quality through the display of real time bottom hole production logging data at surface, allowing the early ending of poor tests or the extension of interesting ones. Selective stimulation of zones through repositioning of the e-DST tool on coiled tubing eliminates costly trips into the well and the requirement for pre-planning of flow test durations is removed. The innovative tool includes: Cable head Connector, Upper Flow Port, Packer Element, Slips Anchor, Shut-In valve and real time instrumentation and control with monitoring from surface.
The paper will introduce the major system components and review challenges associated with design, manufacture and testing. A summary of the first trial test results, conclusions and lessons learned will also be presented.
World's First EGF Flapper Milling Via E-Line
Authors: Rosli Ahmad Faidzal , Md Noor Ahmad Syafiq , Foo Nicholas Kwang , Jelie Anie , Salleh Fairus Azwardy , Omar Mohd Zulkifli , Sulhi Ainur Husna 
Published: March 2020

Abstract
Diagnosing and resolving unknown well obstructions at high deviations presents significant challenges to Operators. Combining a downhole camera with an electric line (e-line) tractor enables operators to traverse high angles and view the camera feed in real time, options unavailable on conventional Coiled Tubing (CT) unless running expensive smart CT. Furthermore, with e-line already on site, the operator maintains the flexibility to rig up an e-line milling tool to mill the obstruction. This paper describes how e-line tools helped identify the obstruction in a shut-in well and successfully milled the EGF ceramic flapper for the first time.
Earlier this year, in a gas field offshore East Malaysia, an Operator needed to investigate probable sand intrusion from an open-hole gravel pack prior to design a remedial plan to reactivate the well. The well presented several challenges, such as high angles, unknown restrictions, restrictions within the inner diameter (ID), potential sand production, and uncertain flapper valves condition in the well. The Operator opted for an e-line tractor to convey a downhole camera to identify the obstructions and an e-line milling tool as a contingency to mill obstructions or faulty valves.
This operation was completed in six runs and comprised of the e-line tractor conveying the downhole camera for drifting or visually inspecting the completion until successfully logging down to the targeted intervals. During the first two runs, the tractor conveyed the camera through the lateral and found a fluid-loss control EGF flapper partially open but could not pass through because of the restricted ID. In the third run, the tractor worked on the string and tagged the flapper, attempting to close it. The next camera run showed in real time that the flapper valve had been closed. The milling tool was then run in hole (RIH) to mill the flapper on the fourth run. On the fifth run, the tractor and camera confirmed that the valve had been milled successfully and the toolstring could pass through the ID. Finally, the tractor conveyed the logging tool to the target intervals and pulled out with no overpull observed. Running this operation entirely on e-line enabled the Operator to access the well obstructions despite the high angles, view the camera feed in real time, and mill the EGF ceramic flapper valve.
This case shows the effectiveness of e-line operations to succeed in challenging well environments without the cost, risk, or time needed for traditional methods like CT or rigging units. The e-line tractor conveyed the camera at high angles to successfully identify the obstruction, and the e-line milling tool milled the EGF ceramic flapper to restore access to the horizontal section. The Operator completed the logging job, which was essential for future well rectification plans that also included setting plugs for zonal isolation.
High Risk Fishing Operations Recovers Well After 4 yrs Shut in
Authors: Heyn Tyler 
Published: March 2020

Abstract
Well was spudded on Sept. 8th, 1991 as a horizontal oil producer offshore Europe. The lower horizontal completion had multi stage proppant fracs and the well was handed over to Production on Dec. 14th 1991. The well was worked over in November 2011 when the upper completion was changed and subsequently was shut in in February 2015 when it failed Subsurface Safety Valve (SSSV) inflow tests.
As a result of the SSSV inflow test failures, it was treated with acid but without success and it was concluded that the flow tube was stuck in the open position possibly due to the presence of scale - as a result the decision was made to look into the possibility of re-activating the SSSV using wireline techniques. In October 2015 several gauge cutters, broaches and brushes were run in the well to clean scale down to the SSSV at 1560ft. A task Launcher was run into the well to treat the flow tube and reinstate the well into service, upon treatmeant with task launcher scale from above and dropped ontop of the task launcher and slickline was unable to move, and since it proved impossible to retrieve the tool string, a wire cutter was dropped and the slickline was retrieved - the fishing neck remaining was gauged and determined to be clean.
Subsequently when the fishing tool string and HD pulling tool were run the fish was latched and some 50-60 jars applied without movement of the fish being seen. Acid was dumped on top of the fish and an additional 60 jars applied without success. By this time some 26 days of operations had been completed without any progress being made operations were suspended and Bridge Plug was set to secure the well.