Drilling with Aerated Drilling Fluid from a Floating Unit Part 2: Drilling the Well
Abstract: The biggest challenge of the aerated fluid drilling technology development was overcome with the well in Albacora being drilled with the semi-submersible platform Petrobras 17 (P-17). A previous paper1 described the stages before the drilling activity: planning, new equipment, rig modifications and all the preparation for drilling the well. This paper describes the drilling operation itself. All the important points and differences relative to the conventional drilling method are highlighted,… Show more
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Cited by 4 publications
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Recent development of Managed Pressure Drilling (MPD) Techniques for use from floating drilling rigs began in the late 1990's concurrent with the development of 5th generation offshore drilling vessels(1). During this period a number of industry efforts focused on developing "riserless" or dual gradient drilling systems employing subsea mud return pumping system. One of these efforts (2) culminated with the drilling of a test well in the Gulf of Mexico employing a subsea pump based Dual Gradient drilling method. Additionally, during this period another industry group employed aerated drilling fluid and a closed loop circulating system to drill a pressure depleted well section offshore Brazil from a floating drilling rig (3). While technically successful, these efforts did not result in commercially deployable drilling systems. Much of the initial industry focus has been on developing MPD methods for deepwater applications, many of the techniques are applicable to all offshore drilling operations and a number of recent applications of Constant Bottom Hole Pressure drilling methods have been employed from fixed installation in both the North Sea and US GOM (4, 5, 6). At the same time both Surface BOP and RiserCap™ equipment configurations (Fig 1) have been employed to implement Pressured Mud Cap Drilling from floating drilling rigs offshore South East Asia. Introduction A number of authors have presented studies of drilling non-productive time (NPT) suggesting that some 20 to 30% of total time spent drilling is non productive (7, 8). Further these studies indicate that as much as 50% of this NPT is well bore pressure related. By solving many of the technical challenges related to well bore pressure problems, MPD methods can significantly improve drilling efficiencies by minimizing the time spent monitoring and interpreting well conditions (flow checks, drilling fluid expansion, ballooning, influx and loss detection, etc). Further, having the ability to manage the well bore pressure profile may enable changes in well design minimizing the requirement for close tolerance casing programs, and contingencies such as drilling liners and expandable casing. In other instances these methods may enable wells to be drilled where application of conventional drilling practices would not be technically or economically feasible. As MPD methods gain broader application offshore, opportunities to combine various techniques will emerge enabling further optimization of well design and operations yielding significant improvements in well construction efficiency and reduction in cost (9). Background Most of the drilling practices now referred to as Managed Pressure Drilling have their origins in land based drilling operations. These drilling practices can be categorized as; over balanced or under balanced with respect to pore pressure depending on the pressure regime maintained in the wellbore while employing a particular method. Generally MPD refers to overbalanced or, at balance operations, and is defined (10) as: "... an adaptive drilling process used to more precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly"
Recent development of Managed Pressure Drilling (MPD) Techniques for use from floating drilling rigs began in the late 1990's concurrent with the development of 5th generation offshore drilling vessels(1). During this period a number of industry efforts focused on developing "riserless" or dual gradient drilling systems employing subsea mud return pumping system. One of these efforts (2) culminated with the drilling of a test well in the Gulf of Mexico employing a subsea pump based Dual Gradient drilling method. Additionally, during this period another industry group employed aerated drilling fluid and a closed loop circulating system to drill a pressure depleted well section offshore Brazil from a floating drilling rig (3). While technically successful, these efforts did not result in commercially deployable drilling systems. Much of the initial industry focus has been on developing MPD methods for deepwater applications, many of the techniques are applicable to all offshore drilling operations and a number of recent applications of Constant Bottom Hole Pressure drilling methods have been employed from fixed installation in both the North Sea and US GOM (4, 5, 6). At the same time both Surface BOP and RiserCap™ equipment configurations (Fig 1) have been employed to implement Pressured Mud Cap Drilling from floating drilling rigs offshore South East Asia. Introduction A number of authors have presented studies of drilling non-productive time (NPT) suggesting that some 20 to 30% of total time spent drilling is non productive (7, 8). Further these studies indicate that as much as 50% of this NPT is well bore pressure related. By solving many of the technical challenges related to well bore pressure problems, MPD methods can significantly improve drilling efficiencies by minimizing the time spent monitoring and interpreting well conditions (flow checks, drilling fluid expansion, ballooning, influx and loss detection, etc). Further, having the ability to manage the well bore pressure profile may enable changes in well design minimizing the requirement for close tolerance casing programs, and contingencies such as drilling liners and expandable casing. In other instances these methods may enable wells to be drilled where application of conventional drilling practices would not be technically or economically feasible. As MPD methods gain broader application offshore, opportunities to combine various techniques will emerge enabling further optimization of well design and operations yielding significant improvements in well construction efficiency and reduction in cost (9). Background Most of the drilling practices now referred to as Managed Pressure Drilling have their origins in land based drilling operations. These drilling practices can be categorized as; over balanced or under balanced with respect to pore pressure depending on the pressure regime maintained in the wellbore while employing a particular method. Generally MPD refers to overbalanced or, at balance operations, and is defined (10) as: "... an adaptive drilling process used to more precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly"
Surface Applied Back Pressure Managed Pressure Drilling (MPD) systems provide a potentially game changing technology for Deepwater Gulf of Mexico drilling applications by means of annular pressure manipulation for drilling through narrow margins, cementing across potential loss zones, assisting in running completions, and mitigating non-productive time. The technology however, is not without cost and the challenge remains to build the business case to utilize MPD in Deepwater applications. Recently several wells were successfully drilled using this technology to the planned target depth accessing reserves that would not have been possible otherwise. This type of scenario where using MPD to stay within a narrow margin has been the means to justify the upfront costs to get a rig outfitted with MPD and the operating costs of the system during use. Once a rig is outfitted with MPD, the economics for a project shift, however, justifying the business case purely based on NPT savings is still not typically viable. This paper will provide the operator's perspective of the cost-benefit analysis for MPD use and provide business case examples for the use in Deepwater Gulf of Mexico. The impact of lessons learned on an ongoing campaign and the savings viable for this and other implementation scenarios will also be discussed to develop a robust case for MPD adoption.
Summary This paper summarizes an extensive experimental program to determine effective foam drilling conditions in horizontal wells. The program included foaming-agent selection (considering optimum concentration and salt/oil contaminants), rheological characterization of foams, development of a flow loop to test the foam-carrying capacity in high-angle wells, definition of the test procedure and matrix, and analysis of the results. After 60 bed tests were performed at a cuttings-transport flow loop, correlations were proposed to predict the cuttings-bed erosion capacity in horizontal wells as functions of the foam quality and the mixture's Reynolds number. Introduction Among the several applications of lightweight fluid drilling, one of the most attractive is the drilling of reservoirs in underbalanced or near-balance conditions. This technique allows the drilling of producing zones with minimum damage. Of course, a good knowledge of hydraulics and cuttings transport mechanics of such complex systems is a must for safe and economical drilling. Nowadays, producing reservoirs in an economical way very often requires the drilling of high-angle, horizontal, and other wells with more complex trajectories. For these well trajectories, several experimental and modeling studies have been done to understand hydraulics and cuttings transport with incompressible fluids.1–4 This paper presents an initial experimental and modeling effort to determine and predict cuttings-transport performance of foamed systems in horizontal and inclined wells. Lab and pilot scale equipment were used as tools for the evaluation of foam stability, rheology, and cuttings-bed erosion capacity. Based on the experiments, comprehensive curve-fitting functions were proposed for explaining the flow- and cuttings-transport behavior observed. This work was conducted as part of the Joint Industry Project "Offshore Drilling with Light-Weight Fluids" (Nakagawa et al.5), which aimed at the drilling of a well with aerated fluid from a floating vessel.6 Foam Stability One major aspect concerning the applicability of a foaming system is the stability of the foam in downhole conditions. An important point to be investigated is the optimization of the system regarding the proper choice of the foamer agent and its optimum concentration. The evaluation of foam stability was performed by an adaptation of a standard method.7 The method is based on the measurement of the liquid phase drained volume as a function of time in ambient conditions. Foams were prepared by stirring 100 mL of the liquid phase for 30 seconds at 5,200 rpm in a controlled-velocity blender. The foam is then immediately transferred to a 1000-mL graduated cylinder, and the drained volume is registered at 1, 2, 3, 5, 7, 10, 14, 20, and 25 minutes. Also, the time (in seconds) when half of the total liquid phase volume (50 mL) is drained was recorded. This value is called the time half-life (t1/2). Effect of Concentration and Type of Foamer. Fig. 1 illustrates the variation of time half-life with concentration for the three foamers studied, called A, B, and C here. The foamers were selected from several commercial products available in the oilfield industry. No chemical characterization or purity analysis was performed or provided by the suppliers. Results show that for the three foamers tested, there is not a direct relationship between increasing foamer concentration and enhancing stability. In all cases, the use of 2% vol/vol foamer concentration resulted in a less stable foam (shorter half-life times) than in smaller concentrations. However, Foamer C showed a higher half-life time than the others. No foam stability testing was carried out under downhole conditions because no equipment was available to operate in such conditions. Effect of Salt Concentration in the Liquid Phase. Another important point to be analyzed is the ability of a foamer to keep foam stable in the presence of salt when brines are the liquid phase. Drilling with brines is a common practice for reservoir hole sections. Fig. 2 illustrates stability results for the three foaming agents with NaCl present in the liquid phase. Results indicate that Foamer A was stable, while the others showed half-life times dependent on the salt concentration. Foamer C half-life times were comparable to Foamer A with less than 5% wt/vol NaCl but increased for salt concentrations greater than 5% wt/vol. Foamer B seemed inadequate to generate stable foam in the presence of salt, which is indicated by half-life times that dropped dramatically with an increase in the salt concentration. Effect of Oil Concentration. The applicability of the three foaming agents for drilling in underbalanced conditions in oil reservoirs was evaluated. Fig. 3 compares the behavior of the half-life time for the three foaming agents in the presence of crude oil. Results indicate that both Foamers B and C were stable in the presence of 30% oil by volume, while Foamer A began losing its stability in concentrations of greater than 20% oil by volume. Comments. Choosing a foamer for drilling operations requires the proper definition of the application for which it is being designed. Of the three foamers tested, Foamer C proved to be applicable for a wider range of situations. Foamer B showed some restriction to use in the presence of salt, while Foamer A showed poor results in the presence of oil. For the flow-loop tests described in the following sections, Foamer B was used, owing to good results and operational convenience. Foam Carrying Capacity in Horizontal and High-Angle Wells Cuttings transport is a major issue in drilling high-angle and horizontal wells. In these situations, there is a tendency to deposit a solids bed in the lower part of the annulus. The excessive amount of solids may create problems, such as abnormal torque and drag, the necessity of redrilling, and, in many cases, drillstring sticking. The objective of this section is to describe the experimental work performed at a pilot-scale cuttings-transport flow loop on bed erosion with foamed fluids in horizontal and inclined wells. Cuttings-bed erosion capacity was measured for several combinations of gas and liquid flow rates at three different inclinations.
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