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.
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.
Loux, Fabrice (PTTEP) | Bunyak, Michael John (PTTEP) | Kongpat, Nitipong (PTTEP) | Pattanapong, Kamolchai (PTTEP) | Eagark, Pasuk (PTTEP) | Rubianto, Irwan (Schlumberger) | Gallo, Fernando (Schlumberger) | Intravichit, Jittipong (Schlumberger) | Charnvit, Kerati (Schlumberger) | Prasetia, Andi Eka (Schlumberger) | Houng, N. H. (Schlumberger)
PTTEP in the Gulf of Thailand faced costly challenges while conventionally drilling several narrow operating window ultra high temperature (ultraHT) wells with formation temperature up to 220°C (428°F). In the ultraHT sections, the operator encountered serious ballooning issues that resulted in severe non-productive time (NPT) and difficulty reaching well total depth (TD). Additionally, formation pressure uncertainty in the steep pressure ramp region posed additional drilling challenges due to high risk of influxes.
PTTEP decided to utilize managed pressure drilling (MPD) to overcome the complex ultraHT wells. The strategy involved designing a hydrostatically underbalanced mud weight to prevent ballooning and to enable optimal drilling flowrates. The automated MPD was used to continuously maintain bottomhole pressure (BHP) above pore pressure to avoid influxes. Furthermore, the MPD system was also used to safely identify formation pressures by performing static flow checks (SFC). Dynamic formation integrity tests (DFIT) and dynamic leak-off tests (DLOT) conducted while drilling accurately identified the losses limit and ballooning gradient. At well TD, special rollover procedures were implemented to displace trip mud weight in order to safely control the well prior to pulling out of hole, taking into account extreme thermal effects on bottomhole pressure (BHP) reduction.
PTTEP was able to drill through the narrow operating window and avoid problems associated with typical ultraHT condition, including ballooning, loss and influx events. Moreover, MPD allowed the operator to drill efficiently while identifying the actual drilling window to establish wellbore pressure boundaries. Importantly, the operator was able to log the well to obtain the necessary geological data. As a result, the operator cut well costs by 50%, a total of USD 5 million, and saved 20 days of drilling time.
The paper will share the success story of MPD application in drilling challenging ultraHT wells in the Gulf of Thailand. The paper will describe the drilling solutions to solve the well problems and the lessons learnt as part of knowledge sharing.
Real-time analysis of fracturing data is an invaluable tool for determining whether a fracturing job is progressing as planned. Since early days, understanding of fracturing pressure was emphasized and practiced by the industry. The most well-known fracturing-pressure-analysis tool is the Nolte-Smith technique. To predict the geometry of a hydraulically induced fracture, the Nolte-Smith technique analyzes the pressure response of a formation during pumping. Extensive application of this technique has proved reliable to interpret fracturing events. However, the compression of data imposed by logarithmic scale may make the detection of some events difficult. In addition, the Nolte-Smith technique necessitates prior accurate knowledge of formation-closure pressure.
In this paper, we present a real-time fracturing diagnostic. This method, which is based on a modification of the Nolte-Smith technique, has proved reliable in the interpretation of fracturing behavior while a fracturing job is being carried out. In addition, it eliminates the shortcomings of the original technique, meaning that while making the interpretation of fracturing pressure faster, the new technique does not require prior knowledge of formation in-situ stresses. This technique was reached by a new innovative moving-reference-point concept assembled with the power-law fracture-propagation theory. Application of the new technique in the analysis of a variety of field cases, including several frac-pack and regular fracturing treatments, proved successful.