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Krishna, Shwetank (Petroleum Engineering Department, Universiti Teknologi PETRONAS, Malaysia) | Ridha, Syahrir (Institute of Hydrocarbon Recovery and Petroleum Engineering Department, Universiti Teknologi PETRONAS, Malaysia) | Vasant, Pandian (Fundamental and Applied Sciences Department, Universiti Teknologi PETRONAS 32610 Seri Iskandar, Malaysia) | Ilyas, Suhaib Umer (Institute of Hydrocarbon Recovery, Universiti Teknologi PETRONAS, Malaysia)
Surge and swab pressure generated during pipe tripping operations tends to result in various wellbore stability and integrity problems. To monitor these problems, prediction of these differential pressure is required for the smooth functioning of drilling operations. An analytical predictive model is presented in this research for surge and swab pressure. This model is developed under steady-state condition for Yield Power Law fluid. A fluid filled wellbore with drill-pipe/casing is considered as two concentric cylindrical pipes for developing this model. In this concentrical cylinder inner pipe is moving at certain velocity and the outer pipe is stationary. Due to movement of inner pipe, drilling fluid will start displacing in annulus and results in pressure surges. A predictive model is developed by analytically combining the frictional pressure loss and mud clinging effect to forecast this pressure surge due to couette fluid flow phenomena in wellbore. The newly developed model (NDM) is validated with two existing analytical models and reported experimental data that are available in the published literature. A parametric analysis is carried out to identify the effect of various parameters on pressure differential. This research suggests that with the increase in pipe tripping velocity, surge pressure also tends to increase because of high viscous drag of fluid. It is also found that the increase in diameter ratio surge pressure also tends to increase due to large shearing effect between pipe wall and fluid. In conclusion this model is predicting the suitable range of tripping speed and diameter ratio under tolerable wellbore pore and fracture pressure to assure downhole wellbeing. Unlike most of the existing model, NDM requires less numerical analysis which make it easier to understand and apply in real case situation. The model considers mud clinging effect for precise prediction of surge/swab pressure gradient.
ABSTRACT: The wellbore instability problems can rise significantly if the downhole pressure is fluctuated during the tripping operation due to surge and swab effects. Even though the borehole pressure was estimated accurately by geomechanical model, the inappropriate tripping variables could reduce the proposed pressure to hold back mechanically the wellbore wall. Therefore, it is essential to include a safety factor or trip margin to account for the surge and swab pressure in the well construction stage. In this work, Numerous of wellbore instabilities in term of pipe sticking were investigated in a field in southern Iraq that revealed the drilling events experienced while pulling the string out of the hole. Thus, the swabbing effect on the bottom hole pressure was considered depend on the drilling observations and empirical equations. Swapping parameters from twenty-two wells in southern Iraq were implemented to investigate the influence of drilling practices, tools, and rheological properties on the borehole pressure variation. The combination of the drilling fluid density, yield point, plastic viscosity, BHA size, slip to slip time, tripping speed and the depth of investigations was used as input data. The mathematical formulas that account for most sensitive tripping factors were utilized in this research to consider the swabbing effects during the tripping. Afterward, commercial software was used to construct a statically derived swabbing model based on tripping data from offset wells to predict the drilling fluid reduction for particular tripping variables. The software was fed with Mud weight MWT, Flow rate FL, Weight on bit WOB, Total flow Area TFA and Revolution Per Minute RPM to get the drilling density reduction by swabbing effect based on standard linear least square method. Then, suggested tripping variables and the geomechanical model densities were plugs in the swabbing empirical model to mitigate this effect. The swapping data showed the drilling fluid density by swabbing was propositionally increased with the static fluid density and slip to slip time (TT), but the swabbing density is negatively affected by the plastic viscosity, flow rate, and the drill collar outside diameters. However, The yield point does not change the swabbing effect much. The recommended tripping variables were proposed to ensure best drilling practice and problems mitigation for the proposed mud density in the upcoming well. Therefore, tripping margin was also suggested to prevent the wellbore collapse while tripping operation in southern Iraq fields.
The downhole pressure is fluctuated during the tripping operation due to surge and swab effects. These phenomena can result in different wellbore instability issues such as drilling fluid losses or pipe sticking (Mitchell, 1988). Physically, the surge pressure can be defined as the increment in bottom hole pressure due to the drill tools (casing, drill pipe) being lowered into the well. The drilling fluid is displaced out of the hole during tripping in the hole operation leading to increase in fluid annular velocity and consequently the friction pressure loss. Contrarily, the swab pressure is described as the reduction in the bottom hole pressure because the drilling tools are pulled out of the hole (Bourgoyne, 1986). As the drilling tool tripping out of the hole, the drilling fluid flows inside the hole to replace the occupied volume by steel being pulled leading to reduction in the fluid annular velocity subsequently the friction pressure loss. These increment and reduction are related to friction pressure losses alterations by pipe movement. Therefore, it is essential to include a safety factor or trip margin to account for the surge and swab pressure in the well construction stage. Different factors contribute in tripping related pressure alterations, such as tripping velocities, drilling fluid properties, drill string eccentricities, wellbore geometry variations, and types of flow regimes (Mitchell, 1988; Srivastav et al., 2012). The high tripping speed induces an increase in surge and swab pressure while low tripping speed leads to no-productive time escalation. The viscosity and destiny of drilling fluid have a significant impact on the severity of the surge and swab pressure. The lower the clearance between the hole and drilling tool the higher the surge and swab pressures. The drill string and the types of the flow regimes are out of paper scope. Numerous mathematical model has been innovated base on different disciplines to consider the drilling fluid density alterations by the tripping operation. In this work, the drilling fluid reduction by swabbing effect have considered mitigating the mechanical wellbore instability in a field in southern Iraq. Figure 1 shows drilling time breakdown for several wells in southern Iraq, and it can be observed the tripping operation worth 30% of the total drilling time. Therefore, the tripping operation should be optimized to minimize the tripping-related wellbore failure as well as the tripping non-productive time in the shale interval specifically in the production section.
Managed pressure drilling is a process that utilizes friction pressure and annular back-pressure in addition to conventional hydrostatic column pressure to allow drilling of difficult formations. There are many parameters that play a part in the managing of wellbore pressure during fluid flow. Wellbore pressures are impacted by fluid density and rheologic properties, injection rates, cuttings transport, influx while drilling, wellhead or choke pressure, hole geometry and drillstring configuration. The effects of these parameters on wellbore pressure are different, but interact with one another. Therefore, careful consideration is needed when choosing which parameter(s) should be adjusted to manage the wellbore pressure during any particular operation.
A good understanding of the effects of these operating parameters on wellbore pressure is essential in the optimum design of an MPD project. This is especially true of the rheologic properties of MPD fluids. Rheologic properties of drilling fluids play important roles in the variation of wellbore pressure during any MPD operation. Most drilling fluids (WBM, SBM, or OBM) currently used in the field have a nonzero yield point (YP). A non-zero YP causes a sudden bottom hole pressure (BHP) jump when fluid starts to move or when fluid is about to stop moving. It also causes a sudden BHP jump when the drillstring starts to move up or down during tripping or connections regardless of how slow the pipe
moves. The sudden pressure jump makes it difficult to minimize BHP variations.
This paper discusses the effects of various operating parameters on wellbore pressure and provides guidelines for managing wellbore pressure by adjusting those operating parameters. A simple equation to predict the sudden pressure jump caused by YP is provided. Field cases are used to
illustrate managing wellbore pressure by adjusting various operating parameters.
When preparing for MPD, careful consideration is required to choose the parameters that can be controlled to ensure those parameters that make the biggest difference are selected for control. Whether drilling or designing the MPD application, the interaction between all controllable parameters must be kept in mind during the process.
To better understand how the controllable parameters interact with one another, a typical offshore well will be used as an example (Figure 1). This well is located in approximately 5,900 ft of water. The wellbore interval used for illustration is the 8-1/2 in wellbore drilled directionally below 9-5/8 in casing from 9,300 ft MD to total depth of 15,775 ft MD (10,920 ft TVD.)
Often parameters that might otherwise be controllable are dictated or fixed prior to the realization that MPD will be required to enable the prospect to be drilled.
The prime example of such a parameter is the operating pressure window, which is not commonly considered a controllable parameter. The window itself is defined by a lower limit, which may be either pore pressure or wellbore stability (collapse) pressure and an upper limit, which in the case of most MPD is defined by the fracture gradient exposed to the wellbore.
Figure 2 shows the pressure window for the example wellbore. The upper limit, designated as fracture pressure in the figure, is simply sea water gradient down to the mud line. Below that point the upper limit of allowable pressure in the wellbore is the actual fracture gradient, while the lower limit is the pore pressure. The casing seat indicated at approximately 9,300 ft in the figure serves to isolate a narrow pressure operating window above that point from a wider window below that point.
Weatherhead, S. (Suncor Energy Oil and Gas Partnership) | Djidjelli, A. (M-I SWACO, a Schlumberger company) | Leeds, M. (M-I SWACO, a Schlumberger company) | Mujumdar, H. (M-I SWACO, a Schlumberger company)
Interest in the unconventional shale gas plays continues to grow in Western Canada. The Montney formation found in North Eastern British Columbia can be particularly challenging due to drilling in the Canadian Foothills. Wells in the area are known for deep, hard, abrasive and abnormally pressured formations. Further challenges include unexpected fractures, lost circulation and coals seams. The combination of these drilling issues can cause a significant increase in expected drilling times (slow ROP and NPT).
Following some difficulty drilling offset wells due to well control issues, future designs incorporated a higher, more conservative mud weight. This let to slower ROP and corresponding NPT.
A new approach with MPD and lighter mud weight was proposed. For the intermediate sections, the first well changed from a weighted to un-weighted invert emulsion. The second well was drilled with a pure base oil system to lower the fluids solids content. The horizontal section was initially planned to drill with a density of 1400kg/m3 weighted invert. A MPD program was proposed drilling with a 1250kg/m3 weighted invert for the next two wells and adjusting backpressure to match the required bottom hole ECD.
The key operational objectives for the operator were increased ROP and a reduction of NPT. This was accomplished by lower ECD associated with lower mud densities, lower drilled solids and lower viscosities. A secondary benefit was the reduction of whole mud losses. Mud losses were reduced in manner that allowed for fast safe well control in the event a pressured fracture (kick) was encountered.
A reduction of more than 7.4 days vs AFE from spud to rig release was largely attributed to utilizing MPD technique and the team work of everyone involved on location. NPT was reduced from 100 hours to 8 hours on the final well of the project. The second MPD well of the project was considered a big success, with the following results (refer
MPD2 vs Best Conventional well Performance Data
MPD2 vs Best Conventional well Performance Data
As the activity in NE British Colombia's Montney play continues to grow, it is important that other operators learn the benefits of utilizing MPD. This includes safely decreasing days on the well by increasing ROP and reducing influx and losse related NPT caused by excessive mud weight.
Heavy Mud Weight (MW) to control HP gas and Loss Circulation zones at the same time is not something operators look forward to. COP's Red Rock field in South Wapiti, Alberta had been a victim of this combination which resulted in high operational costs primarily due to additional casing string, high MW and severe mud losses. On average, AFE's came at a minimum of 20% higher as anticipated bringing the drilling program of the area to being uneconomic.
A review of MPD technology with the team created a spark to look at improving performance in the area. A number of objectives were identified for this project which were later categorized as
1. Drill to TD with reduced mud weights (MW) in a safe manner
2. Set the intermediate casing on top of HP gas zones utilizing wellbore strengthening
3. Drill ahead into HP zones without any massive mud losses
4. Bring the cost of the wells down in order to save the drilling program of the area
5. Eliminate the Intermediate Casing for a significant cost reduction in future wells
1. Conduct Real Time Formation Evaluation in some formations to verify their potential
2. Increase ROP
3. Cement the Intermediate Casing using a single stage method
4. Assess and evaluate the benefits of a new technology
5. Rig crew training and changes in HSE concepts for an MPD operation
A dedicated Engineering team was formed who worked on data collection, research of the area, drilling practices and well engineering. This team was supported by COP's experienced Operations team. A great deal of up front discussion and work was done in planning this project to ensure success. Several well design scenarios were looked at the very initial phase of project, out of which the best design in terms of well engineering, well control, area's known risks and HSE was chosen. During this process COP's engineering team introduced "Fountain Chart Method?? which uniquely identifies operating envelope of an MPD operation using optimum mud weights