A liner-top test packer is a device that is used to verify the integrity of a liner top and cement job in the annulus of a liner. This operation can detect a liner top leak that could result in hydrocarbons migrating into a wellbore. One method to save a trip is to run a liner-top test packer in combination with casing cleanup tools in a combined test and wellbore cleanup run. This enables an operator to verify liner integrity, remove scale, debris, and metal shavings from a wellbore, polish a liner top, and displace fluids all in one trip.
As well integrity assessment becomes increasingly important, liner-top test packers must perform with reliability at higher temperatures and pressures, often in deviated wells, under high flow rate situations, and in aggressive muds and completion fluids. These high pressures require a tool that removes hydraulic loads from the liner top, while testing with up to 11,000 psi differential pressure.
Historically, liner integrity testing has been performed as an independent operation prior to running wellbore cleanup tools and displacing the well. Today, test packer tools are designed so these two independent operations may be combined into a single trip. Though value is added through reduction in operating time and risk, liner-top test packers must perform reliably while minimizing debris that could compromise subsequent completion operations.
This presentation will discuss typical high-pressure/high-temperature (HPHT) test packer applications and case studies for wellbore cleanup jobs. HPHT objectives were met by reliably sealing 11,000 psi pressure at 400° F and eliminating harmful loading on the liner top.
Inflow Testing Procedure
Inflow tests are generally carried out to verify if there is communication with the formation through the casing, a liner lap or past a cement plug (bridge plug).
Most of the applications are in connection with testing or squeezed off perforations and casing leaks, testing liner-laps, float shoes and float collars, cement plugs and bridge plugs.
An inflow test is performed by reducing the hydrostatic head above the item to be tested by circulating to a lighter fluid.
Procedure for Circulating to Lighter Fluids (Diesel etc.)
- RUN retrievable packer with circulating valve, safety joint and short tail on drillpipe, to depth to be advised by Operations Engineer.
- SET retrievable packer at advised depth and test annulus with 1000 psi in order to check that packer is properly sealing and that the tool assembly is functioning properly before RIH any further.
- Generally, the retrievable packer should be set at some 50 ft above the interval to be tested (or 50 ft above TOL) in order to minimise any possible influx. OBTAIN prior approval from the Head of Onshore/Offshore Operations for inflow testing during the hours of darkness.
- CIRCULATE the drillpipe to a lighter fluid until the required drawdown is accomplished. (An air cushion may be used)
- After having circulated the well to achieve the required drawdown, PERFORM the inflow test on the well for 15minutes as detailed in the Drilling Programme.
- REVERSE well to completion fluid.
- UNSEAT retrievable packer. CIRCULATE and OBSERVE well dead.
- POOH and L/D retrievable packer.
Interpreting Inflow Test Results
The “Horner Plot” method should be used for interpreting inflow tests to confirm the integrity of liner laps for over pressured gas wells. Traditional methods are often ambiguous and require unnecessary long rig time.
Traditional Interpretation method
The mechanical integrity of e.g. liner laps can be tested by creating a underbalanced situation over the zone of interest. This is usually done by displacing the well to water. Once the well has been displaced to water, the fluid returns are monitored for a duration of say 4 hrs. This back flow from the well is caused either by thermal expansion, or an influx into the well bore (leak) and thermal expansion
The observed flow rates are plotted against a time scale allow to determine if the situation is one with both an influx and thermal expansion or with temperature effects only. In order to positively determine whether and when zero flow will materialise, the inflow test has to be conducted for much longer than 4 hours.
The combined application of the ISO-MAX security packer and selective rotation and circulation tool (SRCT) helped a North Sea operator prevent losses during well displacement, thus ensuring well integrity and improving the chances of a successful completion.
Drilling mud displacement is a critical step in the well construction process to ensure completions operations are conducted in a clean, solids-free wellbore environment. However, displacement operations also introduce the risk of fluid losses that, if left unchecked, can lead to a poor completion and subsequent well control problems. While even minor losses have the potential to damage the formation and reduce production rates, more serious losses may lead to runaway well control problems in the form of a blowout.
Weatherford has worked closely with several operators to advance packers and wellbore cleaning tools that limit losses and validate well integrity during displacement operations, thus ensuring a successful completion operation. One such advancement, the ISO-MAX security packer, is a drillpipe-conveyed downhole liner-top test packer that enables the negative testing of a liner overlap and shoe track while used in conjunction with other wellbore cleanup activities such as mechanical scraping, debris removal and mud displacement to a completion fluid. Combining pressure testing and wellbore cleaning operations in a single trip avoids the need for a separate retrievable- packer run or wellbore displacement to a lower-density fluid through the choke, thus saving cost and risk. The packer can be run in hole (RIH) or pulled out of hole (POOH) without speed restrictions, and is set hydraulically, which avoids the need to apply excessive weight to the liner top to set the tool after drilling cement and before inflow testing. This setting feature also allows multiple sizes to be run simultaneously to test more than one liner on the same run—another cost-saving benefit over conventional systems. Once set, the packer seals the well below it up to a differential pressure of 5,000 psi; thus, any pressure loss in the annulus up to this pressure will have no effect on the formation. Bypass valves incorporated into the packer body enable test fluid to be pumped with the annulus sealed, and allow the packer to be set only once. The unique setting and unsetting features of the ISO-MAX security packer, also allows for drilling of shoetrack to be performed after the inflow test.
The packer can be run with several wellbore cleaning tools, such as the selective rotation and circulation tool (SRCT), a repeat-cycle, shear-activated flow tool primarily designed for wellbore cleaning in deviated wells with liners. The tool has a disengaging spline drive, which allows the operator to rotate the upper part of the drillstring while the lower part remains stationary, avoiding the risk of twisting off the lower (weaker) string while displacing to completion fluid and losing lubricity from the drilling fluid.
Rotation of drillstrings in wellbores containing small-diameter liners has historically proven difficult due to excessive torque, which hinders wellbore cleaning by preventing effective agitation of cutting beds and other debris. The SRCT contains flow ports that are closed during normal operations, which allows flow to be directed to the lower part of the string. Once the tool reaches a predetermined point such as a liner top, weight is set down on the string to activate / shear a shear ring that allows the disengaging of the spline from the lower portion of the string. The upper part of the string is then free to rotate, while the lower portion sees no torque and remains stationary. With the spline disengaged the flow ports are open, which divert flow to the annulus to increase fluid velocity. It should be noted that the SRCT can be opened or closed at any point in the displacement operation. Typically the SRCT will be opened when clean completion fluid is displaced to above the tool and friction in the liner is at its peak and there is a requirement for increased AV’s in the larger casing sections.
Preventing losses in North Sea wells
A North Sea operator had a history of fluid losses during circulating in several wells. As a result, the operator could not achieve the desired circulation rates to fully displace the well, resulting in a buildup of a water-in-oil emulsion created from the mixing of water with the oil-base mud, which contained an emulsifier package. The addition of more water into the emulsified fluid increased its viscosity, causing further displacement challenges. If this emulsified fluid is not fully displaced out of the wellbore, it may cause problems for the completion, such as plugging up valves and inflow control devices or preventing efficient setting of completion packers. The emulsified fluids then need to be shipped to shore for treatment or disposal, which can impact operations due to rig space and shipping.
Weatherford was called upon to help the operator to develop a cost-effective well cleaning solution that would avoid these possibilities. This began with a preplanning meeting in which the operator provided all relevant information for the next well to be drilled and completed using the new well cleaning strategy. Located at a water depth of 103m, the well was to be drilled to a measured depth of 4,550m and total vertical depth of 2,889m. The plug back total depth for the well was 3,846m and the bottomhole temperature was 114 °F. Both the mud provider and Weatherford engineers prepared a hydraulic simulation for the well, which estimated that the maximum allowable ECD (equivalent circulating density) would be exceeded when pumping at the required rate to effectively circulate and condition the mud system, resulting in the well going on losses.
Based on the simulation, Weatherford recommended the combined deployment of the security packer and SRCT to isolate above perforations in the 9-5/8-in. casing section of the well to prevent losses when circulating and subsequent formation damage. A full schematic of the drillstring configuration with the tools was developed and agreed to by the operator, and the deployment was planned.
After perforating the casing in the planned locations, cleanup runs with scrapers and magnets were performed to remove debris and prepare the wellbore to accept the packer and SRCT, and subsequent completion.
The configuration of the wellbore cleaning assembly consisted of a ported bullnose placed at the bottom of the drillstring, followed by the ISOMAX packer and SRCT, and finally, more drillstring to surface.
The wellbore cleaning string was then RIH to the desired setting depth. The ball was then dropped and pressure applied to set the packer, once the ball had landed on seat. The ball was left in place throughout the operation to provide complete isolation for the perforated sections below.
The annular BOP was then closed and 1,500psi applied to confirm successful setting of the packer. The test demonstrated that the wellbore below the packer was isolated up to the required pressure of 1,500psi. The annulus was then bled off and the annular BOP opened. The Weatherford operator then set down weight on the SRCT, which sheared the activation ring to collapse the tool, disengage an integral clutch and open the circulating ports, allowing the mud conditioning and displacement to commence by circulating out of the SRCT and rotating the string, without placing any torque through the packer.
The displacement stage consisted of pumping base oil as a lead spacer, followed by a viscous pill, then a wash pill, and finally, clean brine. Once clean brine was observed returning to the surface to signal complete displacement, the drillstring was picked up to close the SRCT ports, The ball seat on the ISO-MAX security packer was then sheared to allow communication from drill string to annulus in the event that any well control situations arose. The packer was released with overpull, and the entire assembly was then POOH without incident.
The operator was pleased with the packer and SRCT’s performance in fully isolating the lower wellbore and efficiently cleaning the well ahead of subsequent completion operations, and recorded a savings of one day in rig time, roughly US$500,000. This job validated the potential of using this combination of tools in any openhole application where losses are likely, and conditioning of mud or displacements are required.
