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.
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.
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.