This article discusses estimation of stresses encountered during drilling that could cause fracturing or formation damage in the near wellbore area. Ballooning is a process that occurs when wells are drilled with equivalent static mud weights close to the leakoff pressure. It occurs because during drilling, the dynamic mud weight exceeds the leakoff pressure, leading to near-wellbore fracturing and seepage loss of small volumes of drilling fluid while the pumps are on. When the pumps are turned off, the pressure drops below the leakoff pressure, and the fluid is returned to the well as the fractures close. This process has been called "breathing" or "ballooning" because it looks like the well is expanding while circulating, and contracting once the pumps are turned off.
The packer forms the basis of the cased-hole completion design. The packer is a sealing device that isolates and contains produced fluids and pressures within the wellbore to protect the casing and other formations above or below the producing zone. This is essential to the basic functioning of most wells. Packers have four key features: slip, cone, packing-element system, and body or mandrel. The slip is a wedge-shaped device with wickers (or teeth) on its face, which penetrate and grip the casing wall when the packer is set. The cone is beveled to match the back of the slip and forms a ramp that drives the slip outward and into the casing wall when setting force is applied to the packer. Once the slips have anchored into the casing wall, additional applied setting force energizes the packing-element system and creates a seal between the packer body and the inside diameter of the casing. Production packers can be classified into two groups: retrievable and permanent. Permanent packers can be removed from the wellbore only by milling. The retrievable packer may or may not be resettable; however, removal from the wellbore normally does not require milling. Retrieval is usually accomplished by some form of tubing manipulation. This may necessitate rotation or require pulling tension on the tubing string. The permanent packer is fairly simple and generally offers higher performance in both temperature and pressure ratings than does the retrievable packer. In most instances, it has a smaller outside diameter (OD), offering greater running clearance inside the casing string than do retrievable packers. The smaller OD and the compact design of the permanent packer help the tool negotiate through tight spots and deviations in the wellbore.
This can create length and force changes in the tubing string that can potentially affect the packer and downhole tools. After the packer is installed and the tubing landed, any operational mode change will cause a change in length or force in the tubing string. The length and force changes can be considerable and can cause tremendous stresses on the tubing string, as well as on the packer under certain conditions. The net result could reduce the effectiveness of the downhole tools and/or damage the tubing, casing, or even the formations open to the well. Potential tubing-length changes must be understood to determine the length of seal necessary to remain packed off in a polished sealbore packer, or to prevent tubing and packer damage when seals are anchored in the packer bore.
ABSTRACT: This paper focuses on the development of a technique for the determination of actual fracture length of a hydraulic fracture. Existing hydraulic fracture simulation software may make predictions of fracture length in shale reservoir without considering the volume of natural fractures, which has to fill up before propagation continues. The technique discussed here is limited to shale reservoirs but could be applied to conventional reservoirs with natural fractures. The moving reference point (MRP) technique is used in the analysis of the first three stages of a fracture treatment. With the aid of a fracture length-time plot generated from a hydraulic fracture simulator that matches the data, the distance from the wellbore to the natural fractures, which also translates to the actual fracture length for the stage, could be determined. An algorithm for this technique is developed. From the results obtained, natural fractures in the shale formation were identified and the length of the hydraulic fracture was determined. It can be seen that after 7 mins, the actual fracture length is about 45.72 m, (150 ft.) instead of 76.20 m (250 ft.) predicted by the simulator output.
The real-time analysis of fracturing data using the moving reference point (MRP) technique (Pirayesh, et al, 2013) is used to carry out the analysis of the pressure-time data from a hydraulic fracture job of shale plays used in this paper. Unlike conventional reservoirs, shale plays are characterized by lots of natural fractures. Soliman, et al, (2014) analyzed data for the Marcellus shale and the Eagleford shale, and this paper extends that work by analyzing two new wells on the Eagleford and making calculations of actual fracture length. The technique can help us determine when the hydraulic fracture intersects a natural fracture during treatment, and can further aid us in determining the distance from the wellbore to the natural fractures and the volume of these natural fractures. The technique involves the use of the time-exponent (e) to predict the behavior of the fracture during treatment and can be applied to both conventional and unconventional reservoirs that have been hydraulically fractured.
Nolte-Smith (1981) in his paper came up with a technique for interpreting pressure-time data from a hydraulic fracture job. In his technique (Fig 1), the net pressure (defined as the difference between the pressure inside the fracture and the fracture closure pressure) is plotted against treatment time on a log-log plot.
Barbosa, Alberto (Weatherford) | Gallego, Gilbert (Weatherford) | Clemente, Fabricio (Weatherford) | Padilla, Rivelino (Weatherford) | Mondragón, Gabriel Enrique Garcia (PEMEX) | Balderas, Jose Antonio (PEMEX)
This paper presents a case history that demonstrates the benefits of drilling using automated managed pressure drilling (MPD) technology rather than conventional equipment. Primary factors for the comparison include drilling time, volume of fluid losses to the formation, and performance drilling statistics.
Automated MPD technology provided a non-conventional approach to achieve the main objective during this project. The goal was to reach the planned total depth (TD) in the 8 1/2-in. well section that has a high-pressure zone while reducing pressure-related nonproductive time (NPT). An automatic monitoring and reaction system was used to identify and control undesirable events—such as influxes, losses, ballooning, or all of the above—even when there was no longer a visible operational drilling window available (judging from the pore pressure, collapse pressure, and fracture pressure). Using the automatic MPD system enabled the driller to exercise precise control over bottomhole pressure (BHP) during the entire drilling process, to locate the perfect balance point, to minimize fluid losses and potential influxes, and to drastically reduce NPT.
Al-Muhailan, Mohannad (Kuwait Oil Company) | Patil, Dipak (Kuwait Oil Company) | Aljarki, J. (Kuwait Oil Company) | Mahesh, V. S. (Kuwait Oil Company) | Shehab, A. (Kuwait Oil Company) | Al-Azmi, Salah (Kuwait Oil Company) | Alshammari, Faisal (Baker Hughes) | Al-Jaber, Mohammed (Baker Hughes) | Ababou, Mounir (Baker Hughes)
This paper highlights the design, planning, challenges, operational complications and successful execution of coil tubing application in active deep well in West Kuwait. The aim of coil tubing job is to clear the pipe from inside to recover the stuck pipe to eliminate the sidetrack in highly pressurized complicated Salt/Anhydrite sequence.
In one of the West Kuwait wells, during drilling the well got a kick with high gain rate. During shutting in and at starting of killing the well, it was observed that the pipe & annulus were plugged. Pipe puncture job was carried out & the well was killed off bottom with 19.7 ppg mud. Throughout running in hole with the free point locator tool prior to back off job, the held up was observed at 12,490 ft i.e. 1,300 ft above the bit. It was then selected to clean inside drill pipe to avoid sidetracking.
The well conditions presented challenges to the design and operation of coil tubing in this well. Challenging factors included: Use of high weight and yield strength, 15 ksi coil tubing, high mud density of 19.7 ppg, high pumping pressures, deep well, ID restriction 3 ½ in DP with 2 in ID, active well, deviated well of around 57 degrees. The coil tubing job design was critical for success of the operation. It included selection and analysis of coil tubing material, size, wall thickness; managing potential coil tubing burst and collapse pressures, calculation of coil tubing stretch, circulation pressure with high density mud, coil tubing force analysis, and wellbore solids removal with very minimum clearance & minimum pumping rate.
Initial simulations with 1.5 in coil tubing showed that circulation pressures would go above the 15 ksi rating. It was then decided to switch to high pressure 1.75 in coil tubing with which simulation showed that pressures at the rotating joint would be at 8,000 psi, using a jetting nozzle. While lowering with jetting nozzle, held up was observed at overshot due to the deviation. After changing jetting nozzle with the 1 11/16 in kick off tool, the coil tubing was able to pass through the gelled mud with circulation. To keep under check, high circulating pressure with aid of hydraulics analysis, related to dynamic circulation rate to 0.2 bpm at 7,500 psi & static rate to 0.35 bpm with 8,500 psi. Resulting in successfully clearing the drill pipe from inside to 12,974 ft, below the observed settling of hard barite.
Coil Tubing intervention with the restricted pipe diameter and heavy mud at high inclination well using a kick off tool was done for the first time in Kuwait. It achieved the purpose of cleaning the pipe to definite depth enabling back off operation below the jar & enhanced the chance of pipe recovery.
Wellbore ballooning (or wellbore breathing) is a pertinent drilling issue in exploration wells where the formation lithology, geo-mechanics, pore pressure and fracture pressure regime is not fully understood. This phenomenon is generally observed in formations with micro-fractures. While the pumps are on the ECD is just sufficient to open up the natural micro-fractures allowing the mud to enter the formation. As the pumps are switched off the dynamic pressure effect is lost and the static mud weight is insufficient to keep the fracture open, resulting in the mud lost in the formation to flow-back as the fracture closes. A flow back of mud is observed on the surface with pumps off, which can be misinterpreted as wellbore influx or kick.
Misinterpreting a wellbore ballooning phenomenon as a well kick can lead to the application of standard well control procedure which can aggravate the problem and may have severe implications even to the extent of well failing to meet its objective and being prematurely abandoned.
This paper presents case studies of two wells, viz. NJ North East-1 and Raag Deep Main-1, drilled by the operator in the same block. Severe ballooning was observed in the first well wherein delayed identification of the phenomenon resulted in high NPT and consequential cost impact. The lessons learnt from this experience were implemented in the second well with similar ballooning issues, along with close real-time well monitoring while drilling resulting in smooth drilling operation and successful achievement of objectives as per plan This paper also summarizes suitable in-field drilling practices to be adopted and implemented to mitigate wellbore ballooning, which can be a low-cost alternative to expensive technologies used to counter this phenomenon.
Scale-squeeze remediation has been used extensively for removing scale from production strings in offshore and deepwater environments. During scale remediation treatments, the affected tubulars undergo displacement and stress that can affect the effective seal length and integrity of the completion system. Numerous laboratory simulations can be performed to help determine the effectiveness of the treatment fluids, injection volume, scale-inhibitor retention time, fluid composition, and shut-in time; however, sufficient research has not been conducted regarding the effects of these important parameters on the structural integrity of completion systems during an actual scale-inhibition squeeze treatment.
This paper studies the effects of these important parameters on completion system integrity by (1) performing wellbore thermal simulations of the treatment operations, (2) investigating how much tubing movement has occurred during these operations, (3) analyzing stress on the tubulars during different operations, (4) investigating the effects of scale-inhibition application methods on tubing movement, and (5) recommending a fit-for-purpose tubing movement workflow for the scale remediation process based on laboratory and field data.
This paper investigates six cases using data from a Gulf of Mexico deepwater well. The parameters studied include injection rate, injection pressure, shut-in "soak period" time, and volume of injected treatment fluids. The results show that shut-in time, injection pressure, and injection rate are sensitive parameters that can significantly affect tubing movement and wellbore stress on tubulars.
The method of application by means of squeeze treatment or continuous pumping is proven to be an important requirement for these types of operations and should be seriously considered when designing scale-squeeze treatments. These findings also provide the necessary information for optimizing the design treatment, developing good completion spaceout and design, as well as improving operational procedures for scale-remediation applications.
To achieve a high level of drilling efficiency, it is paramount to correctly identify reasons of drilling events from available data in a timely fashion. Many surface or downhole events share common root causes. Drilling fluid thermal expansion, wellbore ballooning and formation kick share similarities in terms of surface observation such as pit gain volumes. However, resolution for each of them is completed in a totally different manner. Treating a wellbore ballooning effect in the same way as a kick will likely result in losing the current borehole after days or weeks of unsuccessful operations.
In this study, pressure while drilling technologies and software simulations are discussed to analyze variances in the wellbore parameters over time to investigate drilling fluid thermal expansion, wellbore ballooning and formation influx during flow checks in riserless drilling operations. A transient simulation software was used to study the fraction of gas in the annulus and fluid level inside the drillstring on several flow checks following flow and gas bubbles at the well head. Availability of continuous pumps off annular pressure while drilling measurement helps calibrate the simulations and verify its validity.
A new workflow combining modelling, simulations and downhole annular pressure profiling measurement was successfully applied to a riserless pilot hole deep water well Gulf of Mexico. The flow contribution from each drilling fluid thermal expansion, wellbore ballooning, formation influx and u-tube flow was identified and decomposed.
Transient flow simulator working together with pressure while drilling data gave the operator an exact knowledge of wellbore dynamics in an operation usually performed with limited information. This proved extremely valuable in the pursuit of drilling prospect.