In the Marcellus Shale, Northeast USA operators are moving from a phase of exploration and appraisal of gas wells to the development phase using "factory" drilling techniques: bringing down overall cost per well, increasing the number of wells that can be drilled using the resources available and maximizing the production from the wells that are brought online. This paper describes how one operator teamed up with a drilling service provider to adopt new technology that led to a substantial reduction in the operational time required to drill complex 3D profile Marcellus area wells.Most horizontal wells in the Marcellus are currently being drilled with conventional motors and basic measurement while drilling (MWD) systems that are reaching the technical limit of their capabilities. Additionally, the area pad drilling requirement of the Marcellus further challenges the ability of conventional tools to drill the required complex 3D profiles. Traditional rotary steerable systems have not been able to offer operational enhancement in the curve section of the well because they lack the ability to deliver the build rates required to land the wells and then drill the lateral. The authors will use detailed case histories to show how a new rotary steerable system, which has been developed specifically to address the challenges seen in unconventional reservoirs, was utilized to provide a true step change in drilling performance and deliver the benefits expected from rotary steerable systems. The design of bit and bottomhole assembly (BHA) is crucial to ensure that the objectives are met (directional control, ROP, run duration, and hole quality). It will be shown that the new drilling technique will enable the development of reservoir blocks in the Marcellus shale from single pads using complex well profiles, including real-time reservoir navigation, while minimizing the time to drill the wells.

Although drilling horizontal wells in US-land unconventional shale plays has increased exponentially in the last few years, maximizing well productivity and improving drilling efficiency remains a major challenge. Well placement in the sweet spot and extended laterals help maximize productivity. Drilling a curve with higher dogleg severity (DLS) reduces its verticalsection and maximizes the length of subsequent lateral section in the productive zone. Wells in US shale plays demand a DLS of 10 to 14 deg/100 ft, but achieving high DLS presents numerous drilling challenges: rotating a steerable motor with a high adjustable kick-off sub (AKO) angle could result in bottomhole assembly (BHA) fatigue failure and premature damage to the bit; drilling in oriented mode limits the transfer of weight to the bit, reducing the rate-of-penetration.These challenges led to the development and successful testing of a new steerable optimized design motor (ODM) with a short bit-to-bend (BTB) distance. In some cases, the ODM drilled all sections, including high-DLS curves, tangents and laterals with precise directional control and well placement with one BHA. Using the ODM helped the operator achieve higher build rates at lower AKO angle settings; rotate the BHA in well profiles where previously used motors could be operated only in slide mode, and maximize the length of curve interval drilled in rotary mode at higher RPMs. The new system significantly improved drilling performance with excellent directional control. Drilling high-DLS curves increased the length of laterals, enabling additional recovery of gas. This paper will discuss the design, modeling and results of horizontal type wells drilled using the steerable ODM in the Marcellus unconventional shale play.

Implementation of video production logging in conjunction with the use of high molecular weight polymer gels, has led to successful water isolation operations in the Fayetteville shale. The dry natural gas field, located in northern Arkansas, is a horizontal play with the wells cased, cemented, and completed with multi-stage slickwater fracture stimulations using perforation and plug technology (Harpel, 2012).Accurate detection of extraneous water entry points along the wellbore is vital for precise water isolation treatment, while still protecting the hydrocarbon producing intervals. Conventional production logging tools have been utilized in the past but proved to be expensive, due to the wellbore configuration, and imprecise because of the horizontal trajectory and debris encountered in the wellbore, with the debris generally rendering the spinner tool inoperable. Video logging tools, deployed in combination with high frequency temperature and pressure gauges, have considerably improved identification of water entries along the wellbore. In addition, the use of a smaller logging assembly has also drastically reduced workover costs by permitting logging through the existing 2-3/8" OD production tubing whereas conventional production logging required the removal of the production tubing due to size limitations. By maintaining this wellbore configuration the flowing conditions remain undisturbed and increase the accuracy of the production log.Based on video production log results the proper water isolation operation is subsequently selected. While cement squeezes and mechanical isolation tools have been applied successfully in horizontal wells to isolate inflow from water producing perforations, they are limited in their applications due to the wellbore configuration and operational costs. Recently, treatment of water producing perforations with chrome (III) carboxylate acrylamide polymer (CC/AP) gel technology has allowed selective treatment in additional sections of the wellbore. These gel treatments have yielded strong results by isolating water production and increasing gas production by reducing the flowing bottomhole pressure. Evaluation and selection of the appropriate polymer gel is discussed along with design considerations and implementation.

Although drilling horizontal wells in US-land unconventional shale plays has increased exponentially in the last few years, maximizing well productivity and improving drilling efficiency remains a major challenge. Well placement in the sweet spot and extended laterals help maximize productivity. Drilling a curve with higher dogleg severity (DLS) reduces its verticalsection and maximizes the length of subsequent lateral section in the productive zone. Wells in US shale plays demand a DLS of 10 to 14 deg/100 ft, but achieving high DLS presents numerous drilling challenges: rotating a steerable motor with a high adjustable kick-off sub (AKO) angle could result in bottomhole assembly (BHA) fatigue failure and premature damage to bit; drilling in oriented mode limits the transfer of weight to the bit, reducing the rate-of-penetration (ROP). These challenges led to the development and successful testing of a new steerable optimized design motor (ODM) with a short bit-to-bend (BTB) distance. In some cases, the ODM drilled all sections, including high-DLS curves, tangents and laterals with precise directional control and well placement with one BHA. Using the ODM helped the operator achieve higher build rates at lower AKO angle settings; rotate the BHA in well profiles where previously used motors could be operated only in slide mode, and maximize the length of curve interval drilled in rotary mode at higher rotations per minute (RPM). The new system significantly improved drilling performance with excellent directional control. Drilling high-DLS curves increased the length of laterals, enabling additional recovery of gas. This paper discusses the design, modeling and results of horizontal type wells drilled using the steerable ODM in the Marcellus unconventional shale play.

Formation evaluation in low porosity, low salinity, and high temperature reservoirs poses many challenges. The environment is hostile to many logging tools due to their temperature limits and there is greater uncertainty related to petrophysical parameters compared with conventional formations. Additionally, in low porosity and low salinity reservoirs, resistivity contrast between hydrocarbon and water filled rocks is often missing. This extended abstract presents a case study from offshore WA where a petrophysical model has been created with logging while drilling measurements including spectroscopy data to improve estimation of mineralogy, clay volume and porosity, thereby reducing saturation evaluation uncertainty. Spectroscopy measurements can be analysed to derive dry weight elemental concentrations of various elements such as silicon, calcium, iron, and sulfur. These concentrations have been subsequently used as input to compute a multi-mineral petrophysical model using a least squares inversion technique. We demonstrate that spectroscopy can be used independently to obtain an accurate volume of clay instead of gamma ray, spontaneous potential, or porosity logs. Moreover, matrix properties such as grain density, which enhance the accuracy of porosity estimation derived from bulk density, are also derived from spectroscopy dataset. Good agreement with core validates the petrophysical model. Also demonstrated is how the petrophysical model reduces the uncertainty in clay volume and porosity, from which more accurate water saturation can be derived in these tight reservoirs. Calibrating the spectroscopy information to core data allows the mineralogical and geological model to be extended to the intervals where core data are not available.