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Collaborating Authors
NOV
Abstract Asset integrity is vital for any rig activity, and the drillstring is a critical part of these assets. Monitoring and controlling the integrity of your drilling tubulars is important to prevent well control incidents and to reduce Non-Productive Time (NPT). It can also help reduce Invisible Lost Time (ILT), as having the correct information available will improve operational efficiency. This paper describes procedures and available technologies that allow for efficiently managing drill pipe lifecycle integrity. The paper will discuss the possibilities that digital asset tracking provides, including location and details from the latest inspection, both at the rig site and while in service. The paper will show how the same technologies can feed the rig control system operating the pipe handling machines, where a software application will process the data of each asset. This integration increases safety by removing human interaction with the assets. The information is used to optimize pipe handling activities, resulting in faster connection times while maintaining control of all assets downhole and in the setback area. It can also be used to store pipe dimensions, which can be checked against equipment capacity so that the right auxiliary equipment (i.e., elevators) is properly engaged. These tools and procedures allow for placement optimization, ensuring integrity and optimizing the lifetime of the drillstring. The tools presented in this paper permit identification of any incident on the connections and provide safer, more efficient asset management with reduced overall risk of failure and lost time. The paper will also present how, if the right downhole data is available, such input could be incorporated into the final assessment of drill pipe use and string configuration. This proves to be important as severe drilling dynamics events could be the reason for premature fatigue failure, especially when combined with other factors like higher dogleg severity (DLS), abrasive formations, etc. Case studies will be presented for the different technologies, both from real life operations and simulator development work. Finally, the paper will discuss the next level of enhanced drill pipe handling practices by introducing robotics and how consistency within pipe handling and doping could play an important part in asset integrity.
- Information Technology > Artificial Intelligence > Robots (0.68)
- Information Technology > Architecture > Real Time Systems (0.47)
ABSTRACT A previously developed geomechanical model for a drilling test site was updated for a new, innovation test well drilled on the same site. New offset loss circulation data were evaluated and updated for the minimum horizontal stress profile. Critical mud weight window considering different well orientations and the temperature effect are presented. It was demonstrated that critical bottom-hole pressure data were missed during real-time pulsing but recorded in the PWD (pressure while drilling) tool memory. Multiple loss circulation data during drilling and cementing, real-time and memory ECD (equivalent circulating density) data, updated formation tops and formation geothermal gradient measured from a permanent fiber-optic cable are incorporated into the updated model. 36+ additional vertical/directional/horizontal wells up to โผ11,500 ft (3505.2 m) TVD (true vertical depth) were drilled from four different surface hole locations since publishing the last model. It is demonstrated in this paper that geomechanical study is critical to maintaining wellbore integrity during different stages of the well operations even for non-hydrocarbon-bearing drilling design and executions. INTRODUCTION OF THE TEST RIGS AND THE TEST FACILITY At the time the paper was written, a total of 66+ wells have been drilled from four different surface hole locations on the premise of the drilling test facility since October 2014. The testing facility is located in Navasota in Grimes County, Texas. The testing facility is permanently equipped with an automated Ideal Prime 1 drilling rig (1500 hp) and a 5C mobile completion rig (200 kips or 100 US tons static hook load capacity). The Prime 1 rig consists of an automated Iron Roughneck (ST-100) and 3 permanently installed Robots for pipe handling automation. The first floor Robot (RTX-L1, RTX = Robotic Transfer of Material) handles pipe tailing between the well center and the setback area as well as picking up a single joint from the Pipecat. The second floor Robot (RTX-L2) handles ancillary work which includes two different handling tools. The first tool is to operate the mud bucket to contain drilling fluid coming to the rig floor during pulling out of the hole after the pipe connection is broken down. The second combination tool includes two alternate tools, i.e., a doper tool to apply the thread compound to the pipe connection threads and a stabbing guide to align two joints (or stands) of drill pipe before making up the threads. A single rig crew member can operate the above automated equipment from the driller's cabin using multiple HMIs (human-machine interface).
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (4 more...)
Abstract Subsea seawater treatment modules that use electrochlorination as pre-treatment were deployed with more than 20,000 hours of subsea operational run-time. Operational data and lessons learned indicate that the pre-treatment stage is key to the longevity of the overall subsea seawater treatment plant. A self-cleaning, 4 years maintenance-free electrochlorination system has been refined and tested for six months. This paper will present the test set up, test results, findings, and lessons learned from current testing and previous operations, specifically around longevity. An operational mode that allows for long-term subsea operation, without the need for system retrieval for cleaning with acid or alkaline is described in detail. Full-scale testing performed for 6 months established the various process parameters (current density, flow rate, polarity intervals and duration, electrode material, etc.) for minimizing and controlling the scale formation process to minimize subsea maintenance and proving the longevity. An automatic self-cleaning process and sequence have been established using the exact cell and power supply intended for real field application. Electrochlorination is the process of producing hypochlorite by passing electric current through seawater. When producing sodium hypochlorite (disinfective agent) in situ by electrolysis, precipitation of insoluble salts like calcium carbonate and magnesium hydroxide will happen on the cathode. In the industry, this precipitate is typically called scale. The scale should be removed frequently from the process system, since this may otherwise reduce the confidence in cell longevity (if scale formation is not controlled). Therefore, electrochlorination is impacted by scale. The electrochlorination test setup is identical to what is intended to be used in actual field application. Condition monitoring was established through video recording, camera pictures, continuous voltage, electrical current, and process flow parameter trends. The continuous data collection for the 6-month operation was analyzed on a weekly basis. The test data was compared to operational data collected during two subsea deployments and showed that there is a significant improvement in electrochlorination system performance to achieve the minimum four-year, maintenance-free intervention period set for the subsea pre-treatment system. This testing established operating parameters such as current densities, polar reverse sequence, etc. Also, intervals and duration for operating the cells to guarantee long-term maintenance-free subsea operation are part of the findings of this testing. The test data will feed into the operation, maintenance, and sparing philosophy for subsea seawater treatment systems. Typical electrochlorinator (EC) systems are known to require frequent maintenance, requiring manpower and chemicals which are practically incompatible with subsea systems. The novelty of this paper is that a methodology for a maintenance-free, self-cleaning electrochlorination system has been successfully tested and proven for 6 months, enabling a minimum of 4 years maintenance-free subsea seawater treatment system operation. This would lead to significant capex and opex reductions for field applications.
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract Objectives/Scope Over the years, FRP Grating has provided significant weight reduction and cost savings on many projects contributing to the success of offshore oil and gas projects. However, the use of other structural FRP products such as FRP handrails, ladders, tertiary structures offshore has been held back by the lack of similar rules and guidance. The objective of this project was to devise proposed guidance for a Type Approval of FRP handrails in fire integrity applications. Methods, Procedures, Process The FRP Industry Group (IG) promoted the extended use of existing FRP Products into new applications and locations offshore. Taking into account the life cost cycle concept connected safely operation, in January 2019, the Industry Group began the development of a Fire Integrity Matrix for FRP handrails offshore. The IG recognized that the Structural Fire Integrity Matrix format of the FRP Grating had over the years been widely adopted and therefore decided to adopt a similar structural Fire Integrity Matrix for FRP handrails. Heat flux and duration requirements for the R0, R3, R2 and R1 performance levels were then proposed, based on industry practice. The FRP handrail Fire Integrity Matrix sets out a series of fire integrity tests which give performance data for owners/engineers to use in risk assessments. Results, Observations, Conclusions An FRP handrail product was subsequently subjected to the Fire Integrity Matrix tests by recognized laboratory certified by a classification society. The tests were followed by IG and found to meet all the test requirements. The data was subsequently assessed by Classification Society and the product was awarded a new Type Approval allowing, for the first time, use in fire integrity applications offshore. Novel/Additive Information The work by the Industry Group in devising the Fire Integrity Matrix for FRP handrails is a highly significant step forward for the extended use of FRP offshore, with classification society approval.
Abstract Carbon capture and storage (CCS) projects are increasingly being announced as companies strive to reach new sustainability targets. The dehydration of CO2 streams from carbon capture is a critical step to ensure safe and effective CO2 transport and storage. The most common dehydration methods are Triethylene Glycol (TEG) absorption and solid material adsorption. Silica gel, activated alumina, and molecular sieves are different types of adsorbent materials that can be used for gas dehydration. In this paper, the authors present a case study requiring a <100 ppmv H2O outlet specification and evaluate the technologies on capital and operational costs. There are factors beyond treated gas water specification to consider when choosing the ideal dehydration solution, including treated gas glycol specification, plot space, module weight, maintenance intensity, energy duty, and start-up time. When these factors are considered, aluminosilicate gel adsorption technology has benefits over TEG. No one factor can be used to make the decision on which dehydration solution is best; those factors holding more weight depend on the specifics of a given project.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
Correlating Sour Gas Testing with Successful Field Operations of High Strength Quenched and Tempered Coiled Tubing
Elliott, Kevin (NOV) | Davis, Scott (Essential Energy Services) | Rentas, Chris (Essential Energy Services) | Hayworth, Jason (Essential Energy Services) | Woitas, Tyler (Essential Energy Services) | Meadows, Erica (NOV)
Abstract Inhibition is considered critical to successful operations using high strength quenched and tempered coiled tubing in sour environments. Prior laboratory test results did not correlate well with initial field successes in Western Canada. The objective of this paper is to provide further testing that more closely matches real world applications and to provide additional field results from Western Canada. Similar to prior work in Elliott et al (2022), the overall approach to this paper is twofold. The first part focuses on C-ring testing of quenched and tempered tubing to provide confidence, coiled tubing will not fail due to sulfide stress cracking (SSC) when properly inhibited. Testing was performed with a limited exposure time to account for the short window for CT operations and a reasonable inhibition effectiveness period. The second portion of the paper discusses best practices for coiled tubing operations in sour wells. Laboratory C-Ring test results will be provided showing the effectiveness of the inhibition program as well as discussing the possible outcomes of utilizing coiled tubing in sour wells without inhibition based on the tests performed without inhibition. Discussion of the laboratory results will also describe the lessons learned in test plan development with respect to inhibitor effectiveness windows. Following the practical best practices for sour well CT operations, the paper will also discuss field history of quench and tempered coiled tubing building on the initial trials reported in Elliott et al (2022). The paper will conclude with a qualification for each grade of quenched and tempered coiled tubing when used with inhibition for sour operations. This paper expands upon the learnings of Elliott et al (2022) with testing program results that matches the field history of effective inhibition systems for high strength quenched and tempered coiled tubing in sour wells. This publication also explores the effects of sour exposure without the aid of inhibition, which serves to document the risks of forgoing inhibition in sour operations.
- North America > United States > Texas (0.31)
- North America > Canada > Saskatchewan (0.24)
Abstract This paper will present an update on the operational benefits of utilizing anti-cracking inhibitors in sour wells. Multiple papers have shared the details of a Joint Industry Project which resulted in a one-size-fits-all fatigue derating factor by the service supplier. In recent years, additional testing has challenged that practice and a greater variety of improved derating factors are utilized in fatigue tracking software. The testing process of exposing samples to sour conditions for 72 hours and conducting bend fatigue testing post exposure remains the method used in this paper. The process updated the JIP practice of one-time coating of the sample with the addition of an anti-cracking inhibitor to the sour fluid. This update more closely replicates real-world operations. In addition, there was a greater focus on the test sample size, stress and strain to reduce fatigue testing time and reduce the effects of any outgassing leading to a more accurate and repeatable test. A comparison of three typical test methods will be presented: non-inhibited sour tests by the original equipment manufacturer, inhibited field specific partial pressure testing by an operator and globally applicable inhibited testing conducted at the maximum apparatus test level by a service provider. Comparison of prior anti-cracking inhibitor and a North Sea approved inhibitor results will be detailed. The practice for conducting the tests with a high yield material and extending the results to a lower grade material with similar chemistry will be detailed. Note that the results of separate tests conducted on the pipe body and bias welds will be compared and detailed. A brief summary of the service providers record of global sour pipe operations will illustrate these practices have proved suitable in the field. The updated practices and procedures for sour testing have not been shared in prior papers. The improved pipe life will assist the industry with efficient and safe operational planning in sour wells. Finally extending pipe life will reduce the amount of raw steel required for operations and ultimately reducing carbon dioxide emissions, a global challenge from which we can all benefit.
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- (2 more...)
Abstract Many threshold metrics in the well intervention industry's standard operating procedures (SOP) require monitoring and tracking of difficult-to-sensor operational components. Gathering this important job data is challenging due to the cost and/or availability of technology. This paper will outline how manually tracked parameters can be applied to complex equations inside derived channels and used to make real- time decisions. Traditionally important variables such as return rate, density, and viscosity are tracked and documented manually. These metrics are needed to calculate thresholds such as annular velocity, Reynolds number, and bottoms-up time to surface, all of which are required to ensure debris is effectively transported to the surface during coiled tubing operations. Using the previously mentioned derived metrics in a live platform, users can set up warnings and alarms to make real-time decisions. This methodology enables the user to easily capture manually tracked variables in a singular job data set for post-job evaluation. Because the industry has traditionally relied on handwritten and manually tracked data, the acceptance of digitally calculated results based on manual inputs has become commonplace. What was once minutes of calculation time to obtain a snapshot view of job-specific variables is now instantly available and tracked throughout the job so that time-sensitive decisions can be made using snapshots and tracked deviations from the SOP thresholds. Readily available information enhances overall job performance. Real-time availability of job metrics to the equipment operator and remote engineering support makes completions cleaner, reduces stuck instances and non-productive time (NPT), optimizes chemical usage, and maintains rate of penetration (ROP). True identification of annular velocity in singular and multi-sized casings, measurement of turbulent flow, and fluid balance status determine the ability to remove cuttings from a wellbore, which reduces the overall job time and the production testing costs post-intervention. Job performance metrics can be set and analyzed during operations. Any changes to the project scope can be assessed onsite or remotely to ensure acceptable deviations will not negatively impact the project outcome. In previous years, technical papers have outlined how to optimize coiled tubing drillout efficiencies using SOPs, complex equations, and thresholds regarding fluid metrics, circulation times, differential pressures, and annular velocities. Still, these papers included manually tracked channels to document metrics for specific projects. Using the previously mentioned methods, manually tracked channels will display trends in complex equations, resulting in an improvement of the quality of data in a real-time platform and overall operational enhancement.
ABSTRACT This study investigates several NACE TM0177 test solutions adjusted to the pH relevant to flexible pipe applications. Due to the low ratio of solution-to-steel surface area for the annulus, the environment readily supersaturates with Fe, and the pH is consequently in the range of 5.0-6.5. This makes the choice of test solution not straightforward. Six types of carbon steel wires with known different mechanical properties and H2S resistance were exposed to pH-adjusted NACE TM0177 Solutions B, C, and D adjusted to the pH level of 5.1โ5.4 under the purging condition of 1.0% and 1.5% H2S in CO2 at ambient pressure for 720 hrs. The sour resistance results from the different solutions were evaluated and compared with results obtained in an unbuffered solution (5.0 wt% NaCl solution). The results discussed in this paper showed that the test solutions with different buffer capacities have a limited impact on the sour test result in conditions relevant to flexible pipe annulus and that results obtained in any of the solutions should be considered equally valid. INTRODUCTION Fossil fuel is still the main source of energy, despite ongoing attempts to replace it with renewable sources. Nowadays, the easily accessible fossil energy is depleting significantly onshore; and since the need for this source of energy remains, the extraction of oil and gas from subsea is increasing. Unbounded flexible pipes are largely employed for extracting oil and gas from subsea fields as well as for CO2 reinjection into the oil wells to enhance their efficiency. To transfer the extracted oil and gas, unbonded flexible pipes have superiority over rigid steel pipes because they can be installed faster, provide more freedom for potential changes of layouts, and require less maintenance. These advantages often make unbonded flexible pipes an economical and easy-handled option compared to rigid steel pipes.
- Europe (0.69)
- North America > United States > Texas (0.28)
Abstract Cost and operation effective selection of drilling Bits to drill the HPHT Wells sections in Block-09 field in one run with optimum parameters. Improvement in drilling performance leading to reduction in drilling time and costs without compromising the deliverability of well, is the primary objective of drilling engineers. Some of the major challenges faced by drilling engineers are drilling of hard and abrasive formations and selection of durable bits lasting for long while drilling each hole section. Traditionally in this part of south Iraq multiple Tricones and PDC bits were used for each section resulting in long tripping and drilling time. With recent advancement in drilling bits designs and careful and systematic approach for bits selection, these issues have been addressed and tremendous time and cost benefits have been realized. This paper will provide insight into the drilling bits performance for HPHT Wells which have been used in Block-09 field and optimization of bits design to drill and tackle the issues faced in each section with achievement of one bit per section successfully. Dull grading comparison of the bits with offsets wells will be discussed. The optimum bits are then selected by performing a more through response- by-response comparison and how this comparison has been used for next bits selection and outcome of this selection will be presented, in addition the latest technology in bits industry has been benchmarked. The paper will also review the formation types drilled in this block of south Iraq and will help to understand drilled formations and bits design relationship for drilling problematic zones especially sections containing Chert, high strength rocks, anhydrates, Asphaltene and argillaceous Limestone. This paper will discuss the technical challenges which results in major borehole limiters, the engineering design and the Realtime practices that have been developed, as well as the field results. This paper presents the accomplishment, experience and lessons learned related drilling in block-9 field south Iraq area where reduction in drilling time from 141 days to around 63 days is an outstanding outcome of "Pushing the Limits" concept and achieving one bit, one section target.
- Asia > Middle East > Qatar > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Block 6 > Al Khalij Field > Mishrif Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Ratawi Formation (0.99)
- Asia > Middle East > Iraq > Thamama Group > Shu'aiba Formation (0.99)
- (3 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drill Bits > Bit design (1.00)