During the last 10 years, more than 2,000 horizontal wells have been drilled and completed in the Middle Bakken formation, which is sandwiched between the two Bakken organic-rich shales. Although most of the debate about this reservoir has centered on the lateral length, stimulation treatment, and the number of treatments, little work has been performed to explore the variations of rock properties and the effect of natural fractures along the 6,000 to 10,000 ft lateral lengths. Maintaining the horizontal well between the two Bakken shales is easily accomplished with only a gamma ray tool. There are, however, two important questions to be addressed. First, is this an optimal practice for well placement? Second, is there a "sweet spot" layer in which the horizontal well should be placed to increase production? In a recent well, an azimuthally-focused resistivity (AFR) tool and an azimuthal deep-reading resistivity (ADR) tool were run as a final wiper trip to investigate the location of natural fracture swarms and the variations of rock properties along the 10,000-ft lateral. The goal of this exercise was to test the concept of improving production by using a "smart" horizontal completion technique, spacing the swellable packers, and locating fracture stages based on horizontal reservoir data. The AFR image log identified more than 839 individual fractures in four fracture swarms. The ADR mapping showed approximately 40% of the lateral in the sweet spot layer. The evaluation of a post-stimulation oil tracer indicates that these sweet spot layers provide 70% of the production after stimulation. If the well had been geosteered to remain within the sweet spot using a smart completion technology, the production modeling suggests that production could have been increased by 20%.

Drilling expensive and challenging wells in deepwater requires significant prewell planning to mitigate risks. Understanding the regional drilling hazards that nearby operators have encountered and correlating them to the current project must be done to gain a clear appreciation of potential problem hole sections. This paper describes a deepwater well drilled by Agip where significant efforts were taken to fully evaluate the potential for a shallow water flow in the top-hole section.Another operator in a nearby block had recently lost well to a shallow water flow. This heightened the concern of the Agip asset team so an extensive pore-pressure analysis of the surface seismic data was undertaken. The results of this analysis indicated that there was also a strong potential for a shallow water flow on this well. In order to build the best possible understanding of the pore pressure profile the surface seismic pressure analysis was taken much deeper than what is customary, in this case to the top of the salt. Prewell pore pressure models confirmed Agip's surface seismic pore pressure assessment. As a result, real-time pore pressure monitoring services were deemed essential to closely monitor the progress of the well and, with that information, make real-time adjustments to the drilling parameters (i.e. mud weight) as they became necessary.An extremely important and sometimes overlooked aspect of real-time interactivity is the definition of the role each team member has and how each team member interacts with the others. Assembling a team and defining each member's roles and responsibilities in the planning phase streamlines the time-critical decision-making process and allows for a decisive, unambiguous, work flowpath. Figure 1 shows the communication and workflow organization assigned by Agip before the well was drilled. Rig-based personnel are highlighted in green and office-based personnel in blue. The operations geologist was the decision-making focal point and received multiple inputs of data and assessments from the rig. The operations geologist had, as well, responsibility for managing input from other members of the asset team and from partners in the well. It was his responsibility to make a final interpretation of the pore pressure assessment and to communicate any changes in the drilling plan to the company man on location.Because a flow of real-time information was critical in the pore pressure/hazard avoidance interpretation, Agip ran LWD tools that provided gamma ray, propagation resistivity, borehole annular and internal pressures (PWD = pressure while drilling), and sonic compressional ∆t measurements. This particular well was the first successful use of any 9 1 ⁄ 2-inch sonic logging-while-drilling tool in a 30-inch hole. This paper will discuss the operational aspects and lessons learned in acquiring and interpreting LWD compressional ∆t data in large boreholes.Logging tool selection and description. The 9 1 ⁄ 2-inch LWD sonic tool was run in combination with 9 1 ⁄ 2-inch directional, annular and b...

Azimuthal variations in sonic logs have been observed for many years, both in wireline and LWD data. Rudimentary reactive geosteering methods have been used in the past, including drilling until real-time sonic log detected a change in formation velocity and subsequently altering the wellbore trajectory.We propose taking sonic geosteering a step further by providing real-time azimuthal images showing the velocities as they vary around the wellbore. Images can also be transmitted at both shallow and deep depths of investigation to determine how close an approaching boundary may be.While more traditional geosteering measurements, such as resistivity and gamma ray, are highly suitable in many cases, there are instances where the resistivity or gamma ray contrast between beds may be low or the depth of investigation very shallow, making geosteering problematic. However, in such environments, there may well be a porosity contrast, detectable as velocity differences by the sonic tool, which are more suitable to geosteer with. In addition, sonic logs are an ideal way of determining gas contact points in a reservoir, as compressional velocity measurements are highly sensitive to gas.For unconventional shale reservoirs, sonic anisotropy and its relationship to rock mechanical properties are a principle determinant of a well-placement strategy.In this paper, we explore some key factors of sonic geosteering, such as depth of investigation, azimuthal resolution, and compressional vs. shear velocity responses. A workflow for integrating azimuthal sonic measurements into existing visualization and geosteering software is described. Field data examples are presented, showing the feasibility of sonic geosteering as well as its current limitations. IntroductionLWD sonic tools have been used in simple geosteering scenarios since their introduction in the 1990s. The measurements used were typically limited to the compressional arrivals and (if available) refracted shear velocities. The methodology in using real-time information was limited to simple correlation or direct interpretation techniques. The practicality of using these measurements was limited by the complexity of the measurement in terms of environmental conditions (Market and Canady 2007). As a result, the tools have not enjoyed the same popularity in geosteering applications as other tools.In recent work in shale reservoir systems, including the Haynesville (Buller et al. 2010), Eagleford, Woodford, and Marcellus, these tools have found new application and utility. In addition to using the compressional and shear data, these measurements are processed to provide dynamic Young's modulus and Poisson's ratio . The tools are then used to produce a real-time brittleness index that can be used to land and geosteer within the optimal production zone.This paper begins with a review of the measurement considerations to keep in mind when acquiring and analyzing azimuthal sonic data for geosteering. We then discuss the application of sonic geosteering in conventional reservoirs. ...

Unconventional shale environments have traditionally been evaluated with wireline logging tools. Recently, it has become more common to evaluate these wells with logging-while-drilling tools because of challenges such as wellbore stability problems that make it risky to leave the hole uncased long enough to run wireline. This paper discusses when it may be appropriate to log unconventional shale environments with LWD tools, the services that are available, and the possible advantages of real-time data while drilling. It also describes the possible differences in the LWD and wireline measurements, including such factors as openhole vs. cased hole data acquisition, time-lapse effects, and anisotropy responses of sonic, resistivity, and nuclear tools. The paper presents examples from the Bakken and Haynesville shales, including azimuthal resistivity, density, caliper, and sonic data. Special considerations for interpreting logs in these environments are discussed, particularly regarding log interpretation in high angle wellbores. Finally, details about the optimization of the logging program and tool configurations are provided for ideal data acquisition in unconventional shale environments.

No abstract