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Quantitative subsurface prediction and uncertainty analysis are critical success factors in all phases of exploration, development, and production projects, including regional evaluation, leasing, prospect maturation and drilling, appraisal and development planning, system selection, and reservoir management. Today, the E&P industry is moving into more frontier oil and gas provinces, such as deepwater and very deep plays, where well costs are very high. Consequently, the regional and in-field well densities are generally very low compared with historical exploration and development. Such sparseness of well control poses a challenge for quantitative subsurface analysis because it is difficult to establish spatial correlations of rock and reservoir properties with confidence, when the distances between wells are too large to assume geostatistical stationarity of earth model parameters.An effective approach to reduce subsurface uncertainty due to well sparseness is to build a 3D shared earth model using seismic data as "spatial glue." Under this approach, self-consistent 3D models are built for all interdependent earth model parameters that span a wide range of spatial scale and subsurface disciplines, and are constrained by physical laws and geologic scenarios. The self-consistency conditions of a 3D shared earth model provide tighter constraints and improved reservoir, rock and fluid property predictions, and more robust uncertainty analysis. This approach has been piloted in a number of play settings Figure 1. Pressure prediction workflow, incorporating all geophysical, geologic, and petrophysical data and analysis.Figure 2. Traverse through Mars-Ursa Basin (Mars-Princess-Ursa-Crosby) showing the original PSDM velocity model used as input to pressure prediction and an assortment of pressure diagnostic cubes that follow. (Color scales run from low to high values from bottom to top.)

The use of Distributed Acoustic Sensing for Strain Fronts (DAS-SF) is gaining popularity as one of the tools to help characterize the geometries of hydraulic fracs and to assess the far-field efficiencies of stimulation operations in Unconventional Reservoirs. These strain fronts are caused by deformation of the rock during hydraulic fracture stimulation (HFS) which produces a characteristic strain signature measurable by interrogating a glass fiber in wells instrumented with a fiber optic (FO) cable cemented behind casing. This DAS application was first developed by Shell and OptaSense from datasets acquired in the Groundbirch Montney in Canada. In this paper we show examples of DAS-SF in wells stimulated for a variety of completion systems: plug-and-perforating (PnP), open hole packer sleeves (OHPS), as well as, data from a well completed via both ball-activated cemented single point entry sleeves (Ba-cSPES) and coil-tubing activated cemented single point entry sleeves (CTa-cSPES). By measuring the strain fronts during stimulation from nearby offset wells, it was observed that most stimulated stages produced far-field strain gradient responses in the monitor well. When mapped in space, the strain responses were found to agree with and confirm the dominant planar fracture geometry proposed for the Montney, with hydraulic fractures propagating in a direction perpendicular to the minimum stress. However; several unexpected and inconsistent off-azimuth events were also observed during the offset well stimulations in which the strain fronts were detected at locations already stimulated by previous stages. Through further integration and the analysis of multiple data sources, it was discovered that these strain events corresponded with stage isolation defects in the stimulated well, leading to "re-stimulation" of prior fracs and inefficient resource development. The strain front monitoring in the Montney has provided greater confidence in the planar fracture geometry hypothesis for this formation. The high resolution frac geometry information provided by DAS-SF away from the wellbore in the far-field has also enabled us to improve stage offsetting and well azimuth strategies. In addition, identifying the re-stimulation and loss of resource access that occurs with poor stage isolation also shows opportunities for improvement in future completion programs. This in turn, should allow us to optimize operational decisions to more effectively access the intended resource volumes. These datasets show how monitoring high-resolution deformation via FO combined with the integration of other data can provide high confidence insights about stimulation efficiency, frac geometry and well construction defects not available via other means.

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.

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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.