Frantz, Joseph H. Deep Well Services. OnePetro January, Abstract Coiled tubing units CTU have been used to drill-out frac plugs in shorter horizontal shale wells for the last decade, but coil has mechanical limitations. The new innovative technology of Hydraulic Completion Snubbing Units HCU is gaining popularity across North and South America to drill-out frac plugs in long lateral, high-pressure, and multi-well pads.
The HCU is designed for drill-outs and interventions where coil may not be the best option. This paper will summarize the recent evolution of the HCU system.
Case histories will be provided from the Appalachian and Permian shale plays. The latest HCU consists of a stand-alone unit that mounts on the wellhead after completion.
Slickwater is used for the drilling fluid to carry out parts from the frac plugs while the tubing is rotated via the jack rotary table. Torque and drag modeling are performed to guide downhole expectations that allow most wells to be drilled in one trip and with one bit without short trips back to the heel or bottom- hole vibration assembly tools.
Finally, a remote telemetry data acquisition system has been added that summarizes the drilling data and key performance indicators. In , a North American operator drilled and completed the first super lateral in the Appalachian Basin, setting the completed lateral record at over 18, ft. Since then, many operators have been routinely drilling laterals between 12, ft and 16, ft. HCU technology has been used in the longest laterals in onshore North America, including the lower 48 U.
S records for completed lateral length LL at 20, ft and the total measured depth MD record at 30, ft. The average lateral contains between 60 to 90 plugs and can be drilled out in 3. The record number of plugs drilled out by an HCU is and took 5.
High-pressure wells are also routinely encountered where pressures range from to psi during operations. Operators are achieving faster drilling times per plug, less chemical usage, faster moves between wells, and running tubing immediately after the drill-out, thus eliminating the need for a service rig. Operator's desire to reach total depth with the least risk and as cost-efficiently as possible resulted in the HCU gaining market acceptance.
Add feedback. More like this By text By views By concept tags. OnePetro November, Abstract In the UAE, an Operator needed to perform a completion change out in a gas well, where the existing completion has been installed for over 30 years. Logging operations had revealed several leaks point in the production tubing due to corrosion.
To rectify the situation, a Hydraulic Workover HWO Unit was proposed integrating a punch ram in the Blowout Preventer BOP Configuration to manage the bleed off of potential pressure trapped between the isolated sections of the completion at surface. This document describes how the highly corroded completion tubing with eleven retrievable plugs set in a live gas well was recovered.
The HWO Unit was modified so that one of the cavities in the BOP stack was dressed with customized punch rams for five inch pipe, with the objective of allowing control of any potential leaks due to plug failure. The pressure relief operation could then be completed by means of punching the tubing in the controlled environment that a Stripping BOP Stack provides.
This paper compiles the details of the BOP configuration and operating procedures to recover the completion by stripping out of the well and operating the punch rams with the snubbing unit.
This includes the pre-job preparation required for a successful operation and the overall design with where to locate the collars and plugs for an accurate punch, and how to confirm that the plugs are holding the pressure to continue retrieving the next completion section.
In the end, a safe operation was completed with zero incidents or down time allowing the intervention to continue to the next stage of recompleting the well and putting it back to production. The customer was able to get the well back to production with an alternative solution to what was initially considered, representing a significant cost and time saving.
Petrowiki September, Remotely operated vehicles ROVs have facilitated the development of oil and gas resources in deeper water. By enabling access to areas that divers could not safely reach, they have extended capabilities for handling more complex situations and operations in deeper water. In the s, divers used saturated and pressurized systems to do almost all well and subsea equipment intervention, inspection, and repair. Subsea television systems were, and still are, used to inspect and monitor hulls and subsea equipment by use of running down guidelines, but they can only view not do repairs or other physical tasks.
Selecting surface equipment is the final step in designing an underbalanced drilling UBD operation. Hole size and reservoir penetration, as well as directional trajectory, determine whether coiled tubing or jointed pipe is the optimal drillstring medium Table 1.
Occasionally, the ideal coiled tubing for an operation may be excluded because of such factors as crane or transport limitations or that the life of the coil may not be economical. Generally, coiled tubing has several advantages and disadvantages compared to jointed pipe systems. OnePetro August, Wellhead manufacturers have various designs for Back Pressure Valves depending on the size and make of the hanger and wellhead.
The installation and removal of Back Pressure Valves should only be performed by specific personnel trained by wellhead manufacturers. These valves provide instantaneous shut-off against high or low back pressure and allow full fluid flow through the drill string.
Another advantage is that it prevents cuttings from entering the drill string, thus reducing the likelihood of pulling a wet string. Abnormal pressures and anticipated subnormal pressure zones should be the deciding factor regarding what type of valve to run or the possibility of not running any valve at all.
Expectations of abnormal pressures have shown the vented type of flapper valve to be the most popular because of the ease involved in recording shut-in drill pipe pressures. The disadvantages are that the pipe must be filled while tripping in, and reverse circulation is not possible. Components are listed reading upward from the uppermost piece of permanent wellhead equipment, or from the bottom of the BOP stack.
Test programs can include visual inspections, functional operations, pressure tests, maintenance practices and drills. Function tests may or may not include pressure tests. Function tests should be alternated from the drillers panel and from remote panels. Actuation times should be recorded for evaluating trends. A function test of the BOP control system shall be performed following the disconnection or repair, limited to the affected component.
Before the equipment is put into operational service; 2. After the disconnection or repair of any pressure containment seal in the BOP stack, choke line, or choke manifold, but limited to the affected component; 3.
Once per 21 days. All BOP that may be exposed to well pressure should be tested first to a low pressure of to psi and then to a high pressure. Full details as per API Standard Initial pressure tests are performed before the well is spudded or before the equipment is put into operational service.
Components that could be exposed to well pressure should be tested to the RWP of the ram BOPs or to the rated working pressure of the wellhead, whichever is lower. During the initial test, the ram BOPs shall be pressure tested on the ram locks with the closing pressure bled to zero.
Initial pressure tests shall be conducted with water. Subsequent pressure tests are carried out to the maximum anticipated wellhead pressure MAWHP for the hole section. Subsequent tests on subsea BOP stacks may be conducted with the drilling fluid in use.
Pressure Gauges Pressure gauges should be installed so that drill pipe and annulus pressures can be monitored at the station where well control operations are to be conducted.
Pressure gauges and chart recorders should be used and all testing results recorded. Test pressure-measuring devices shall be either pressure gauges or pressure transducers and shall be accurate to at least 1 0. There might be a number of different locations on the rig where pressures can be observed.
Due to height differences, frictional effects and slight inaccuracies, not all of these gauges will read the exact same values. Small differences between the gauges can be tolerated but for proper trend analysis it is important to use a single pressure gauge. A typical system offers a wide variety of equipment to meet the customers specific operational and economic criteria.
The following text gives a brief description of the equipment and some of its major components. The primary function of the accumulator unit module is to provide the atmospheric fluid supply for the pumps and storage of the high pressure operating fluid for control of the BOP stack.
It includes accumulators, reservoir, accumulator piping and a master skid for mounting of the air operated pumps, electric motor driven pumps and the hydraulic control manifold. These accumulators are available in a variety of sizes, types, capacities and pressure ratings. The two 2 basic types are bladder and float which are available in cylindrical or ball styles.
The accumulators can either be bottom or top loading. Top loading means the bladder or float can be removed from the top while it is still mounted on the accumulator unit. Bottom loading accumulators must be removed from the accumulator unit to be serviced. Bladder and buoyant float type accumulators can be repaired in the field without destroying their stamp of approval.
Surface BOP Control Systems Reservoir A rectangular reservoir is provided for storage of the atmospheric fluid supply for the high pressure pumps. It contains baffles, fill and drain ports and troubleshooting inspection ports. For filling and cleaning procedures see the Maintenance section.
It should be able to store 2 times the capacity of the usable fluid capacity. Accumulator Piping This piping connects the high pressure discharge lines of the pumps to the accumulators and the hydraulic manifold. Cylindrical type accumulators are mounted on machined headers to minimize line restrictions and leaks. Air Pump Assembly The air pump assembly consists of one 1 or more air operated hydraulic pumps connected in parallel to the accumulator piping to provide a source of high pressure operating fluid for the BOP Control System.
These pumps are available in a variety of sizes and ratios. It is connected to the accumulator piping to provide a source of high pressure operating fluid for the BOP Control System. It is available in a variety of horsepower and voltage ranges. Closing Units- Surface Installations Accumulator Requirements General Accumulator bottles are containers which store hydraulic fluid under pressure for use in effecting blowout preventer closure.
Through use of compressed nitrogen gas, these containers store energy which can be used to effect rapid preventer closure. There are two types of accumulator bottles in common usage, separator and float types. The separator type uses a flexible diaphragm to effect positive separation of the nitrogen gas from the hydraulic fluid. The float type utilizes a floating piston to effect separation of the nitrogen gas from the hydraulic fluid. Volumetric Capacity As a minimum requirement, all blowout preventer closing units should be equipped with accumulator bottles with sufficient volumetric capacity to provide the usable fluid volume with pumps inoperative to close one pipe ram and the annular preventer in the stack plus the volume to open the hydraulic choke line valve.
Usable fluid volume is defined as the volume of fluid recoverable from an accumulator between the accumulator operating pressure and psi above the pre-charge pressure.
The accumulator operating pressure is the pressure to which accumulators are charged with hydraulic fluid. An accumulator system which shall provide sufficient capacity to supply 1. A backup to the primary accumulator charging system which shall be automatic, supplied by a power source independent from the power source to the primary accumulator charging system and possess sufficient capability to close all BOP components and hold them closed.
The safety factor also allows for loss of fluid capacity due to interflow in the four- way valves and possible loss through the packing of 7.
A less demanding base is not recommended, but may be used with Class II stacks, provided prior management approval has been obtained. Requirements vary with the size of preventers and are principally controlled by annular preventer requirements. Hydraulically operated choke and kill line valves require added fluid capacity. The minimum recommended accumulator volume nitrogen plus fluid should be determined by multiplying the accumulator size factor refer to Table below times the calculated volume to close the annular preventer and one pipe ram plus the volume to open the hydraulic choke line valve.
Response Time The closing unit should be able to close each ram preventer within 30 seconds. Closing time should not exceed 30 seconds for annular preventers smaller than 18 inches and 45 seconds for annular preventers 18 inches and larger. Function Tests As per API, all operational components of the BOP equipment systems should be functional at least once a week to verify the components intended operations. Function tests should be alternated from the Drillers panel and from mini remote panels, if on location.
Operating Pressure and Pre-charge Requirements for Accumulators. The pre- charge pressure on each accumulator bottle should be measured during the initial closing unit installation on each well and adjusted if necessary. Only nitrogen gas should be used for accumulator pre-charge. The pre-charge pressure should be checked frequently during well drilling operations. Requirements for Accumulator Valves, Fittings and Pressure Gauges Multi-bottle accumulator banks should have valving for bank isolation.
An isolation valve should have a rated working pressure at least equivalent to the designed working pressure of the system to which it is connected and must be in the open position except when the accumulators are isolated for servicing, testing or transporting. Accumulator bottles may be installed in banks of approximately gallons capacity if required, but with a minimum of two banks. The necessary valves and fittings should be provided on each accumulator bank to allow a pressure gauge to be attached without having to remove all accumulator banks from service.
An accurate pressure gauge for measuring the accumulator pre-charge pressure should be readily available for installation at any time. Closing Unit Pump Requirements: Requirements for Closing Unit Valves, Fittings, Lines and Manifold Pump Capacity Requirements Each closing unit should be equipped with sufficient number and sizes of pumps to satisfactorily perform the operation described in this paragraph.
With the accumulator system isolated, the pumps should be capable of closing the annular preventer on the size of pipe being used plus opening the hydraulically operated choke line valve and obtain a minimum of psi pressure above accumulator pre-charge pressure on the closing unit manifold within two minutes or less. Pump Pressure Rating Requirements Each closing unit must be equipped with pumps that will provide a discharge pressure equivalent to the rated working pressure of the closing unit.
Pump Power Requirements Power for closing unit pumps must be available to the accumulator at all times such that the pumps will automatically start when the closing unit manifold pressure has decreased to less than 90 per cent of the accumulator operating pressure. Two or Three independent sources of power should be available on each closing unit. Each independent source should be capable of operating the pumps at a rate that will satisfy the requirement described above in Pump Capacity Requirements.
The dual source power system recommended is an air system plus an electrical system. A dual air system may consist of the rig air system provided at least one air compressor is driven independent of the rig compound plus the rig generator.
A dual air system may consist of the rig air system provided at least one air compressor is driven independent of the rig compound plus an air storage tank that is separated from both the rig air compressors and the rig air storage tank by check valves. The minimum acceptable requirements for the separate air storage tank are volume and pressure which will permit use of only the air tank to operate the pumps at a rate that will satisfy the operation described in the pump capacity requirements.
A dual electrical system may consist of the normal rig generating system and a separate generator. On shallow wells where the casing being drilled through is set at feet or less and where surface pressures less than psi are expected, a backup source of power for the closing unit is not essential. Requirements for closing Unit Fluids and Capacity: A suitable hydraulic fluid hydraulic oil or fresh water containing a lubricant should be used as the closing unit control operating fluid.
Sufficient volume of glycol must be added to any closing unit fluid containing water if ambient temperatures below F are anticipated. The use of diesel oil, kerosene, motor oil, chain oil, or any similar fluid is not recommended due to the possibility of resilient seal damage.
Each closing unit should have a fluid reservoir with a capacity equal to at least twice the usable fluid capacity or the accumulator system. Closing Unit Location and Remote Control requirements: The main pump accumulator unit should be located in a safe place which is easily accessible to rig personnel in an emergency.
It should also be located to prevent excessive drainage or flow back from the operating lines to the reservoir. Should the main pump accumulator be located a substantial distance below the BOP stack, additional accumulator volume should be added to compensate for flow back in the closing lines.
Each installation should be equipped with a sufficient number of control panels such that the operation of each blowout preventer and control valve can be controlled from a position readily accessible to the driller and also from an accessible point at a safe distance from the rig floor. Closing Unit Pump Capability Test: Prior to conducting any tests, the closing unit reservoir should be inspected to ensure it does not contain any drilling fluid, foreign fluid, rocks or other debris.
The closing unit pump capability test should be conducted on each well before pressure testing the BOP stack. This test can be conveniently scheduled either immediately before or after the accumulator closing time test.
The test should be conducted according to the following procedure: a. Position a joint of drill pipe in the BOP stack. Isolate the accumulators from the closing unit manifold by closing the required valves. If the accumulator pumps are powered by air, isolate the rig air system from the pumps.
A separate closing unit air storage tank or a bank of nitrogen bottles should be used to power the pumps during this test. When a dual power source system is used, both power supplies should be tested separately. Simultaneously turn the control valve for the annular preventer to the close position and turn the control valve for the hydraulically operated valve to the open position.
Record the time in seconds required for the closing unit pumps to close the annular preventer plus open the hydraulically choke line valve and obtain psi above the pre-charge pressure on the closing unit manifold. It is recommended that the time required for the closing unit pumps to accomplish these operations not exceed two minutes. Close the hydraulically operated valve and open the annular preventer. Open the accumulator system to the closing unit and charge the accumulator system to its designed operating pressure using the pumps.
The test should be conducted as follows: a. Open the bottom valve on each accumulator bottle and drain the hydraulic fluid into the closing unit fluid reservoir. Measure the nitrogen pre-charge pressure on each accumulator bottle using an accurate pressure gauge attached to the pre-charge measuring port and adjust if necessary.
Close off the power supply to the accumulator pumps. Record the initial accumulator pressure. This pressure should be the designed operating pressure of the accumulators. Adjust the regulator to provide psi operating pressure to the annular preventer d. Simultaneously turn the control valves for the annular preventer and for one pipe ram having the same size ram as the pipe used for testing to the closing position and turn the control valve for the hydraulically operated valve to the opening position.
Record the time required for the accumulators to close the preventers and open the hydraulically operated valve. Record the final accumulator pressure closing unit pressure. This final pressure should be at least psi above the pre-charge pressure. After the preventers have been opened, recharge the accumulator system to its designed operating pressure using the accumulator pumps. In an 11 gallon accumulator bottle the volume of nitrogen it contains before any fluid is pumped in will be 10 gallons the rubber bladder occupies a volume of 1 gallon.
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Flag for inappropriate content. Download now. Save Save 7. Original Title: 7. Related titles. Carousel Previous Carousel Next. IWCF Principles. Jump to Page. Search inside document. The operating system can be interlocked using sequence caps to ensure that the wedge-lock is retracted before pressure is applied to open the BOP 7. Table: 7. DVS rams are shearing blind rams which are similar to SBRs with the following features: DVS double V shear rams fold the lower portion of the tubular over after shearing so that the lower blade can seal against the blade packer DVS rams include the largest blade width available to fit within existing ram bores 7.
The hydraulic closing pressure required to shear commonly used drill pipe is below 1, psi for BOPs 7. Other features of the U II BOP include: Internally ported hydraulic stud tensioning system ensures that stud loading is consistently accurate and even. The seal carrier was designed, developed and performance-verified for use in newly manufactured BOPs or as a replacement seal assembly for BOPs where either the BOP bodyor the intermediate flange requires weld repair on the sealing surfaces Fig 7.
Hydril Type V Preventer Fig 7. When closing pressure is applied, the contractor piston moves upwards against the donut, which deforms 7. If these zones are shallow enough that it is not possible to obtain the necessary casing shoe integrity before encountering the pressure, then a kick cannot be shut-in and will 7. The system should operate as a remote station to the main accumulator system 7. The ring joint gasket and the ring groove should be cleaned, free of scratches 7. Type 6B flanges are not designed for face-to-face make-up; Type 6BX flanges are designed for face-to-face make-up; 7.
Choke Manifolds The choke manifold is an arrangement of valves, fittings, lines and chokes which provide several flow routes to control the flow of mud, gas and oil from the annulus during a kick.
Circulating from Cement unit to Choke line 7. The control for the auto chokes are from the choke panel normally situated in the Drillers dog house Choke panel Drill pipe Pressure gauge In a well control situation, the control panel readout gives the Driller information. Hand and Power tools safety. Endless Round Web-sling. Lifting Safety. Rig move safety. Koya university induction. Safety in working place. General overview of Petroleum Engineering Depatment.
Experiment no 3 surface tension. Related Books Free with a 30 day trial from Scribd. Related Audiobooks Free with a 30 day trial from Scribd. Elizabeth Howell. Well control equipment 1. Close the top of the hole. Control the release of fluids. Permit pumping into the hole. Allow movement of the inner string of pipe.
Preventer Requirement 5. API Bulletin D 13 7. Chock Manifold Thanks For Your Time and Attention. This technique involves the estimation of formation fluid pressures, the strength of the subsurface formations and the use of casing and mud density to offset those pressures in a predictable fashion. Koomy unnit -In the BOP stack they are always positioned in such way, that annular preventer is the working preventer positioned on the top of the stack, and -Ram preventer is on the bottom as thebackup -Working preventer is always positioned far from the source of danger, to be in position to change it if fails Rotational preventers are used: 1- For drilling in layers that are suspected to cause possible kick off.
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