In many maturing prospect around the world, operators are facing the challenge of having to drill through highly pressure-depleted formations in order to access lower-lying hydrocarbon-bearing zones. New technologies such as expandable casing are now becoming available to allow for extensions to conventional well designs in order to deal with depletion. However, before one can case off depleted formations, one first has to successfully drill them. This paper highlights key aspects in the planning and execution of the Ursa A-11 well, which was drilled through a 5500 psi depleted sand to a deeper horizon. Drilling complications included risks of excessive mud loss, internal blowout and differential sticking on the depleted sand. Moreover, fracturing of the depleted sand carried the risk of jeopardizing production at a nearby horizontal well. Key factors in the successful drilling of the Ursa A-11 well included special drilling fluid design, rock mechanics study, pro-active use of borehole strengthening technology, integration of supplier and operator expertise, and excellent communication between all parties involved. Introduction Producing a prospect's reservoirs "from the bottom up" may not always be feasible. Development economics often dictate that higher-reserves or better-quality reservoirs must be produced first before deeper-lying horizons can be accessed. In many maturing prospects operators are challenged to drill through zones that are severely depleted from past or ongoing production in order to unlock these deeper reservoirs. This situation applies to the deepwater prospect Ursa in the Gulf of Mexico (GOM). The main reservoir at Ursa is the Yellow sand, which is currently being depleted by three high-rate producing wells. Pore-pressures in the Yellow sand have typically dropped by 5000 - 6000 psi since production commenced in 1998. Production has not only reduced the pore-pressure but has also lowered the minimum horizontal stress in the Yellow sand (see Fig. 1). Such conditions greatly complicate accessing the Sub-Yellow reservoir, an untapped hydrocarbon-bearing zone at virgin pressure situated just below the Yellow sand. Significant challenges surfaced while planning the Ursa A-11 Sub-Yellow producer, for which the casing program is given in Fig. 2:The high GOM cost environment dictated the need for a high rate completion from a small Ursa template slot. Marginal economics on the Sub Yellow sand precluded any other development concepts (e.g. separate subsea well, use of a large Ursa slot etc.).Drilling risks included the possibility of an underground blowout from virgin-pressured sands above and below the Yellow sand (i.e. pore-pressures of adjacent sands are higher than the reduced fracture gradient / minimum horizontal stress in the depleted Yellow sand, see Fig. 1). Also, there was a high risk of differential sticking and associated loss of hole while drilling the Yellow sand at high overbalance (5500 psi).The optimum bottom-hole location for the Ursa A-11 well placed it in very close proximity (˜ 400 ft) to the high-rate Yellow horizontal producer Ursa A-6 (see Fig. 3 for a subsurface projection of the A-11 and A-6 wells). This introduced the significant risk of fracturing the A-11 well at the depth of the Yellow formation into the direction of the A-6 well. Propagation of drilling mud from A-11 to A-6 could result in impairment of the A-6 completion and thus compromise further production from A-6. To gain a proper perspective of the proximity of the A-11 and A-6 wells, it was estimated that hydrocarbons would be flowing by the A-11 well at an amazing rate of 2 ft/day due to ongoing production at the A-6 well. URSA A-11 Well Planning Significant effort went into the planning of the Ursa A-11 well to address the challenges associated with developing the Sub-Yellow sand. Planning was tackled by an integrated project team that included the Ursa prospect development team, drilling engineers and drilling fluids & cement team, R&D experts, and resources from various suppliers. Specific planning elements are discussed in detail below.
Summary This paper details the case history of the highly challenging extended-reach deepwater A-10 well, drilled in the Ursa (“Bear” in Latin) prospect in the Gulf of Mexico (GOM). This 30,000-ft well, drilled from the Ursa tension-leg platform (TLP) at a vertical depth of 18,000 ft and a horizontal displacement (HD) of 20,000 ft, targeted the Yellow sand in the Ursa-Princess section of the greater Mars-Ursa basin. During the drilling of the original hole (OH), two subsequent sidetracks, and two mechanical bypasses, a number of significant hole problems materialized that caused extensive nonproductive time (NPT) and an associated cost overrun. These problems were clearly associated with the drilling of a complex well that combined a high-deviation and extended-reach wellbore with a very narrow and pressure-depleted drilling window, characteristic of the GOM's challenging geopressured environment. In all, at least five independent borehole-failure mechanisms were encountered while drilling the OH and its successive sidetracks/bypasses, which were exacerbated by an additional complicating factor: Lost circulation in natural fractures, ultimately responsible for the loss of the Ursa A-10OH Lost circulation in induced fractures, with associated heavy mud losses Borehole fatigue, caused by stress cycling on weak formations caused by annular-pressure fluctuations Borehole instability caused by too-low downhole hydrostatic pressure, responsible for the loss of Ursa A-10 Sidetrack 1 Borehole instability caused by an in-situ fractured formation that proved hard to stabilize on wells Ursa A-10 Sidetrack 1 Bypasses 1 and 2, and ultimately forced the well to be completed in shallower Magenta sands Complicating factor: barite sag of synthetic-based mud in high-deviation wellbores, which led to exacerbation and complication of the previous failure mechanisms An extensive lookback study was carried out on the Ursa A-10 well, leading to the development of several important lessons learned and best practices [e.g., for hole cleaning, equivalent-circulating-density (ECD) management, sag control], and to the development of new systems (including novel, sag-resistant synthetic-based-mud formulations). A succinct overview of the Ursa A-10 case history and a comprehensive summary of its learnings are provided here to help the future drilling of extended-reach wells in geopressured, low-margin deepwater environments.
Riserless drilling poses numerous operational challenges that manifests itself in a number of ways, that can adversely affecting the efficiency of the drilling process. The problems include increased torque and drag, increased vibration, poor hole cleaning, tubular failures by buckling above the mud line, poor cement jobs, and associated problems during tripping operations. Drilling in deepwater and ultra-deepwater as well as extending the reach to a greater along hole depth in the riserless environment requires both improved models and comprehensive analysis, especially when the larger diameter casing pipes are run and cemented. The present calculations without proper modeling will gravely underestimate the hook load values when the casing strings are run in deepwater situations. This paper proposes a modeling approach, which uses scenarios in which the drillstring/casing strings are in open water and in openhole reservoirs under different operating conditions to arrive at appropriate hook-load values in addition to torque and drag calculations. Both combinations of soft and stiff string models are used for the tension-force estimation as well as the wellhead-side loading calculations. The research results also present the hook-load calculations for scenarios when casing and inner string are run with drilling mud inside the inner string, sea water in the outer string, and pad mud in the hole below the mud line. The study concludes that various parameters influence the results, such as wellhead offset from the rig center, wellbore inclination, curvature, wellbore torsion, angle of entry into the wellhead besides the complexity from wind, wave forces, and ocean currents. This paper documents the comparison between the predicted mathematical simulation results with the actual well data from different wells to explain the rigor of implementation.
This paper details the case history of the highly challenging extended reach deepwater A-10 well, drilled in the Ursa ("Bear" in Latin) prospect in the Gulf of Mexico. This 30,000 ft well, drilled from the Ursa TLP at a vertical depth of 18,000 ft and a horizontal displacement of 20,000 ft, targeted the Yellow sand in the Ursa-Princess section of the greater Mars-Ursa basin. During the drilling of the original hole, a subsequent sidetrack and two mechanical bypasses, a number of significant hole problems materialized which caused extensive non-productive time and an associated cost overrun. These problems were clearly associated with the drilling of a complex well that combined a high deviation and extended reach wellbore with a very narrow and pressure-depleted drilling window, characteristic of the Gulf of Mexico's challenging geopressured environment. In all, at least five independent borehole failure mechanisms were encountered while drilling the original hole and its successive sidetracks/bypasses, which were exacerbated by an additional complicating factor: Lost circulation in natural fractures, ultimately responsible for the loss of the Ursa A-10 original hole. Lost circulation in induced fractures, with associated heavy mud losses. Borehole fatigue, caused by stress cycling on weak formations due to annular pressure fluctuations. Borehole instability caused by too low downhole hydrostatic pressure, responsible for the loss of Ursa A-10 sidetrack 1. Borehole instability caused by an in-situ fractured formation that proved hard to stabilize on wells Ursa A-10 sidetrack 1 bypasses 1 & 2, and ultimately forced the well to be completed in shallower Magenta sands. Complicating Factor: barite sag of synthetic based mud in high-deviation wellbores, which led to exacerbation and complication of the previous failure mechanisms. An extensive lookback study was carried out on the Ursa A-10 well, leading to the development of several important lessons learned and best practices (for hole cleaning, ECD management, sag control etc.), and the development of new systems (including novel, sag-resistant synthetic-based mud formulations). A succinct overview of the Ursa A-10 case history and a comprehensive summary of its learnings are provided here in order to help the future drilling of extended reach wells in geopressured, low-margin deepwater environments.
Riserless drilling poses numerous operational challenges that adversely affect the efficiency of the drilling process. These problems include increased torque and drag, buckling, increased vibration, poor hole cleaning, tubular failures, poor cement jobs, and associated problems during tripping operations. Riserless drilling in deep and ultra-deep water, as well as drilling to deeper depths, requires improved models and comprehensive analyses, especially when larger-diameter casings are run and cemented in a deviated or directionally drilled tophole environment. Current methods that lack proper modeling will severely overestimate hookload values when casing strings are run in and underestimate in the pick-up load estimates. A new modeling approach is proposed to calculate appropriate hookload values, as well as torque and drag. This method can model situations in which the drillstring/casing string is in open water or in openhole under various operating conditions. Both soft- and stiff-string models are used in the hookload estimates and in the wellhead side-loading calculations. Hookload calculations and buckling limitations for the scenarios in which casing and inner strings are run with drilling mud inside the inner string, seawater in the outer string, and pad mud in the hole below the mudline, are presented. The study indicates that the results are influenced by various parameters, including depth of the mud line, offset of the wellhead from the rig center, wellbore inclination, curvature, wellbore torsion, and angle of entry into the wellhead, as well as by the complexity arising from wind, wave forces, and ocean currents. This study compares simulated predictions with actual well data from wells from Angola and the North Sea and describes the accuracy and applicability of the model. It also presents several examples of surface casing-string failure.
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