North American market with growing trend of unconventional shale gas reservoirs has warranted rapid development in hydraulic fracturing technology. The long horizontal wells are completed using multi zone plug and perf method that requires multiple zones to be fracked optimally to minimize nonproductive time (NPT). Frac plugs plays vital role in hydraulic fracturing in isolating the multiple zones of the wellbore for operations up to 10,000 psi pressure and 250°F temperature. In this paper advanced computational analysis is conducted to optimize the composite frac plug design for successful operations. Comprehensive laboratory testing is conducted, and digital solutions are compared against the test data to validate the new composite frac plug design. The traditional frac plug design requires effort in milling out the plug and further flushing out the cuttings that adds to the operational time. An alternative is to utilize composite plug that allows ease in milling and reduction in cuttings than traditional design. Numerical analysis is conducted to evaluate the feasibility of composite frac plug design utilizing three-dimensional finite element analysis (FEA) simulations to predict the slip holding capacity. Extensive laboratory testing is conducted for the composite frac plug to validate the digital analysis results. FEA simulations are performed for different configurations of frac plug design by varying number of slip buttons and composite material for slips. FEA results underscored best possible slip button configuration that can successfully work at desired pressure and temperature. Laboratory testing corroborated with digital analysis results and indicated as efficient design that reduced NPT and ensured successful hydraulic fracturing operations. This work assisted in optimizing design quickly and reduced time and cost associated with laboratory testing. This work elucidates use of digital solutions along with laboratory testing for design optimization of composite frac plug. This frac plug has been successfully utilized for several jobs in Marcellus shale play.
A new cased-hole porosity measurement has been developed for a four-detector pulsed-neutron logging tool. The measurement is based on a capture count rate ratio from two different detectors. To determine an accurate porosity, the ratio is characterized in the laboratory in order to establish a ratio-to-porosity transform. To account for varying measurement conditions in the field, environmental corrections, based on laboratory studies and computer simulation, are applied. As an alternative to environmental corrections, the capture ratio can also be actively compensated for the environment by using the results of a dual-exponential fit to the capture time decay spectrum. In particular, we can compensate for the borehole fluid salinity by using the borehole component of the dual-exponential fit, and we can compensate for the effective density of the borehole environment by using an inelastic ratio derived from the capture subtracted burst yields. The final porosity measurement has been shown to provide accurate results in the field through a comparison with data from open-hole logs.
Murdoch, Euan (Weatherford Completion Systems) | Walduck, Steve (Weatherford UK Ltd) | Munro, Chris (Weatherford UK Ltd) | Edwards, Andrew (Weatherford) | Choquet, Caroline (Weatherford Energy Services)
Successfully deploying a single trip completion system in a deep-water environment requires an innovative technical solution to address the risks that come with this environment. Following a request from the operator for a deep-water single trip solution, a number of different system options were proposed. Each system was evaluated against the operator’s requirements, and a Radio Frequency Identification (RFID) technology-based system was selected as it offered the greatest flexibility in both activation and contingency methods to meet the demands of the project.
It was proposed to hold a 2 stage System Integration Test (SIT) at a test rig in Aberdeen. The first SIT was performed with a small number of tools that could be setup in different modes to prove the system’s logic against the operator’s expectations. Whilst this was conducted successfully a number of learnings and operational optimisations were captured. These were fed into a full-scale SIT which was deployed at the same test rig. This second SIT involved a complete representation of the single trip system and was designed to test the final system logic prior to deployment into an offshore environment.
The system was then installed successfully in November 2018, on a subsea well, offshore Nigeria with no intervention. It resulted in an operational time saving of at least 60% over the previous best recorded time for a conventional two-trip completion from the same rig. This represented a step change in operational efficiency and will now be the operator’s base case completion methodology as they develop the field further.
This is the first time a single trip completion has been deployed in this fashion in a deep-water, offshore environment. The demonstrable step change in operational time and resultant project OPEX savings, proves that the use of RFID and remote actuated tools within completions offer excellent alternatives to traditional methods.
Openhole logging tools have been used without wireline in memory logging for 20 years, in an important and growing market. A new system in field trials in Canada and Russia in 2019 further expands the operating envelope overlap between wireline and logging-while-drilling by making step changes in communications, autonomy, performance, and reliability. The new approach advances the logging of horizontal and challenging wells, and permits operations in managed pressure drilling and foam drilled wells.
The vast majority of openhole memory work is achieved with a hydro-mechanical system that indicates successful deployment but lacks two-way communication between the engineer at surface and the tools downhole. Pressure-pulse communications have been used for 10 years with a wide range of measurements including memory logging with wireline formation testers. The experience gained from operating these systems informed the development of a new system that uses drillpipe rotation to communicate to the tools, pressure pulses to reply for the uplink, and a more powerful downhole processor. These enhancements in autonomy and communication improve the outcome of logging jobs.
The system incorporates a new rotation downlink method which employs data from an angular rate sensor to identify a series of commands sent by rotating the drillstring. Control software in the downhole tools executes the commands, and replies are transmitted uphole by pressure pulses. The toolstring is released from a safe ‘garage’ position inside the drillpipe and deployed into openhole, with the top of the toolstring retained by a no-go. The engineer is supplied with far more diagnostic information than previously, including the axial position of the tools, with context sensitive encoding to provide maximum troubleshooting information to the surface over a limited bandwidth channel. The pressure-pulse downlink remains in place as a secondary method. Other material improvements include high data sampling rate, debris tolerance and downhole recovery strategies. All of these advances improve the autonomy of the downhole memory equipment as well as the real-time communication and control from the surface.
Autonomous memory logging toolstrings, with powerful downhole software and rotation downlink communications, are important components in improving the performance and reliability of these successful and innovative formation evaluation systems.
A long-term suspended subsea exploration well within a producing gas reservoir needed to be decommissioned after 21 years. During a pre-decommissioning diving campaign, bubbles confirmed as reservoir gas were observed to be percolating from the well bore through a hard silt / cement debris plug inside the wellhead. A pressure study established that the reservoir may have re-charged to 2,200 psi. An alternative pressure controlled well re-entry method was required to safely re-enter, tie-back the well to surface with 16-in. high pressure riser, install BOP while preventing gas from reaching the rig floor from seabed. Two existing cement plugs would then be drilled out under controlled conditions due to the potential for high-pressure gas beneath the plugs. Casing integrity evaluation and cement bond logging would be carried out to establish the path of gas ingress into the wellbore. Remedial work would be conducted, and permanent abandonment barriers installed in the well. Casings and wellheads would then be recovered from a depth below the seabed.
A customized managed pressure drilling (MPD) system was designed using a rotating control device (RCD) and modified drilling chokes. A pioneering plan was developed to meet the specific well re-entry requirements of the percolating suspended well to account for the potential for virgin reservoir pressure at seabed and the wellhead silt plug preventing deployment of BOP test tools. A hazard and operability study (HAZOP) was conducted with key personnel, which supported development of well-specific operating procedures and decision matrices. Successful deployment included MPD system calibration, well behavior fingerprinting, and training of rig personnel at the well site.
The combination of experienced personnel, innovative MPD equipment, specific procedures, team interactions and risk analyses were key to safely completing this well re-entry and decommissioning scope. The strategy enabled drilling out of two cement plugs with potential high-pressure gas trapped beneath them. Both cement plugs, 356ft and 669ft long, were drilled without any well-control or plugged-choke events. Throughout the process, the well was monitored using MPD equipment, which included an RCD on top of rig's BOP, modular drilling chokes and multiple pressure gauges and sensors installed at critical points. Additionally, temporary modifications were made to the rig and new lines of communication between the rig crew and the MPD team were established to ensure all pressures were correctly interpreted and the decision matrix was correctly applied. An effective close partnership developed between the equipment service provider, well operator and drilling contractor was a key enabler to deliver this very challenging novel implementation of MPD technology within eight weeks. The MPD approach was estimated to have saved 9 days of rig time, when compared to alternative coiled tubing-based solutions.
This paper describes the first MPD-assisted well re-entry for well decommissioning in the UK North Sea sector. The novel application of existing technology can help operators to cost effectively re-enter and decommission troublesome legacy wells without harm to people, environment or assets. This new approach resulted in the safe unconventional re-entry and decommissioning of a potentially live gas well.
It is often stated that necessity is the mother of invention. Never is this proverb more relevant than in the offshore oil and gas environment we currently operate in where real step changes leading to reduced capital and operational expenditure opportunities are sought and embraced by field operators. This paper discusses the pre-job planning, field execution and lessons learned from one such technology that challenged conventional thinking of sand faced completion, casedhole completion and well integrity to successfully deliver a single-trip, interventionless, sand control completion in deepwater Bonga Field, located on the continental slope of the Niger Delta.
Convention dictates that the vast majority of offshore completions be run in two and sometimes three trips which routinely takes in excess of eight to ten days to deploy. Given the day rate of high specification rigs capable of drilling in deep water environments, the ability to reduce this time was deemed paramount to the economics of the project. Utilizing a collaborative approach to initial concept design, risk assessment, extensive testing and contingency planning at component and system level, a single-trip, interventionless, sand control completion system was designed and successfully installed. This paper describes the completion architecture, operational sequence and challenges leading to the installation of an interventionless completion.
A clearly defined set of deliverables and design principles were drawn up to guide the direction of the project including: successfully deploying the upper and lower completion in one trip, and testing all barriers. Adopting a simple, low risk and high reward design, meeting clients well barrier requirements and utilizing proven cost-effective technology are examples of design principles used. The system was tested and evolved through a number of iterations in an onshore trial well environment on a number of occasions leading to the first successful deployment completed in the second half of 2018, resulting in an average completion installation time of 5 days, versus the average 10 days for deploying multi-trip completions. Details of the successful installations, lessons learned, along with planned future activity are outlined within the body of this paper. While several of the components incorporated in the single-trip system had been run previously in isolation, this paper also discusses the steps taken to facilitate the first full-system approach to the application of radio frequency identification (RFID) enabled tools in the first single-trip, interventionless sand control completion system. Several components within the completion have been equipped with this technology including a multi-cycle ball valve, wire wrapped screens fitted with inflow control device (ICD), remote operated sliding sleeve for annular fluid displacement.
Ali Khan, Farhan (Weatherford) | Antonio Sierra, Tomas (Weatherford) | Gabriel Imbrea, Robert (Weatherford) | Robin Edwards, Michael (Weatherford) | Al-Rushoud, Ali (Kuwait Oil Company) | Al-Abdulhadi, Fahad (Kuwait Oil Company) | Shehab, Abdulaziz (Kuwait Oil Company) | Al-Ajeel, Fatemah (Kuwait Oil Company)
Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline. A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches. Operations were divided into six parallel processes as follows: 1. Equipment logistics 2. Gravel foundation preparations 3. Concrete foundation installations 4. Unit Pre-assembly 5. Pre-assembled units dispatches 6. Final unit installations Daily output targets were set for each process prior to the commencement of operations.
Multilateral drilling technology offers a highly effective method of enhanced oil recovery in fields characterized by complicated geological structure. This paper describes the analysis of sidetracks in an open hole by annular ledge formation with the use of a downhole motor in multilateral wells in Vostochno-Messoyakhskoye field.
Since May 2018, more than 130 sidetracks have been drilled in Vostochno-Messoyakhskoye field with the use of bottomhole assembly (BHA) with a downhole motor in open hole by annular ledge formation. The fundamental difference between this method and conventional sidetracking with a downhole motor is that during sidetracking the entire drill string constantly rotates, rather than just bit rotation produced by downhole motor operation. In the process of technology introduction a comparison was made on how different downhole and geological conditions influence the time and performance results.
The technology introduction resulted in the sidetracking time reduction from 9 hours to just 3 to 4 hours.
A number of additional advantages of sidetracking with annular ledge formation were confirmed in the process of operations:
The constant rotation of the drill string enables smooth weight transfer to the bit smooth, without failures. This contributes to effective and uniform ledge formation. Such sidetracking can be carried out at an extended length of open hole when it is difficult to ensure a free movement of the BHA which is necessary of conventional sidetracking. Constant rotation mitigates the risk of differential sticking. More favorable conditions are created for BHA movement in an interval of the holes diversion and subsequently for liner running in. It is possible to sidetrack with the use of a stiff BHA including a complete set of logging tools. In case of conventional sidetracking, it is preferable to use a short and flexible BHA.
The constant rotation of the drill string enables smooth weight transfer to the bit smooth, without failures. This contributes to effective and uniform ledge formation.
Such sidetracking can be carried out at an extended length of open hole when it is difficult to ensure a free movement of the BHA which is necessary of conventional sidetracking.
Constant rotation mitigates the risk of differential sticking.
More favorable conditions are created for BHA movement in an interval of the holes diversion and subsequently for liner running in.
It is possible to sidetrack with the use of a stiff BHA including a complete set of logging tools. In case of conventional sidetracking, it is preferable to use a short and flexible BHA.
The experience gained in Vostochno-Messoyakhskoye field can be extrapolate to other fields where multilateral wells are drilled with annular ledge formation.
Al-shammari, Baraa Sayyar (Kuwait Oil Company) | Rane, Nitin (Kuwait Oil Company) | Ali, Shareefa Mulla (Kuwait Oil Company) | Sultan, Aala Ahmad (Kuwait Oil Company) | Al Sabea, Salem Hamad (Kuwait Oil Company) | Al-naqi, Meqdad (Kuwait Oil Company) | Pandey, Mukul (Weatherford) | Solaeche, Fernando Ledesma (Weatherford)
The Kuwait Integrated Digital Field project for Gathering-Center 01 (KwIDF GC-01) at Burgan Field acquires real-time data from wells and processing facilities as input for its production-surveillance program. Live data from the field is fed into an integrated production model for analyzing and optimizing pump performance. An automated workflow process generates alarms for critical well and facility parameters to identify wells with potential scaling issues. KwIDF workflows are integrated with updated well models to visualize the effect of scale build up on the wellhead performance and thereby assist in quantifying the associated production losses caused by scale deposition. A sensitivity analysis is also performed to identify current and optimal pump operating conditions and prioritize scale cleaning jobs.
The exception-based surveillance of key real-time parameters for wells utilizing electrical submersible pumps (ESPs) in Burgan field has significantly improved diagnostics of scale deposition at wellhead chokes and flowlines. Automated workflows calibrate an integrated production model in real-time, which enables engineers to run a quick analysis of current pump operating conditions and make a proactive plan of action. The application of real-time data and automated models has aided the operator's production team in making informed and timely decisions that enable them to run pumps at optimal operating conditions, with the result that they are able to sustain well production at target levels.
This paper describes an innovative approach to applying real-time data and integrated models in an automated workflow process for enhancing capabilities to diagnose scale deposition in the surface flow network. Examples are presented to demonstrate the application of integrated technology for identifying scaling at wellhead chokes and flowlines and prioritizing a scale removal program for optimizing pump performance.
The complex downhole tools in upstream oil & gas industry are subjected to internal and external pressure due to variety of fluids ranging from drilling mud to reservoir fluids which dictates downhole tool performance in the well bore. Extensive laboratory testing is needed to quantify the downhole tool performance which can be cost and time intensive process. An alternative approach is to conduct numerical simulations to investigate the real operating scenarios and predict the downhole tool performance including high pressure high temperature (HPHT) conditions which are difficult to set up in laboratory environment. The objective of this work is to underscore importance of advanced simulation technology in evaluating down-hole tool performance. To attest usage of simulations two examples are presented, the first one is utilization of computational fluid dynamic (CFD) simulations to analyze the performance of flow regulation inflow control device (ICD) for challenging multi-phase flow operations to predict onset of cavitation and second is to analyze the hold-down slip indentation dynamic operation using advanced explicit finite element simulation methodology.
The completions ICD tool aids in maintaining uniform inflow of production fluid in horizontal and deviated wellbores by providing pressure drop utilizing nozzles. Advanced flow modeling is critical to understand the flow behavior through ICD and check for onset of phase change/cavitation of the production fluid. Three dimensional CFD simulations are conducted using pressure based algorithm for numerically solving mixture multi-phase model coupled with Reynolds-Averaged Navier-stokes (RANS) equation and k-ε turbulence model to predict onset of cavitation for given operating conditions.
The dynamic hold down slips operation is important to set up a packer and during this step casing gets indented with the carbide buttons. The setting up of slips can cause localized permanent deformation in the casing and estimating the setting force along with hanging load capacity of the slip system is important to avoid permanent damage to the casing. Three dimensional explicit non-linear FEA is conducted to predict the stresses and deformations in the casing.
Multi-phase simulations for ICD are conducted with different nozzle configurations and operating conditions. CFD results highlighted velocities, pressure drop through ICD and also indicated onset of cavitation for provided operating conditions. Advanced modeling results helped in configuring the ICD and operating conditions to avoid cavitation.
FEA conducted for hold-down slip predicted the load needed to cause ~0.030" button indentation on casing and also provided insights in collapse analysis of the casing. A detailed presentation of the stress field helped in identifying the loading limits for this system and also probable failure locations due to loading. Advanced simulations helped in assessing the downhole tool performance for given operating envelopes and provided critical insights that delivered confidence in utilizing these tools for field operations.