Saudi Aramco operates several deep gas reservoirs in the Kingdom of Saudi Arabia (KSA). Both vertical and horizontal K2 gas development wells have long 16-in. vertical sections. The 16-in. section is drilled as quickly as possible through several mid-depth hydrocarbon reservoirs to a competent seat in a dolomitic limestone. Since this section is fairly long (±5,000 ft) it represents one of the biggest challenges in the continuous drive for better rate of penetration (ROP) as well as reliability of downhole drilling assemblies. These sections are typically drilled with various positive displacement motors (PDM) in a simple performance bottomhole assembly (BHA) setup with two roller-reamer type stabilizers to mitigate mechanical stuck pipe risks. Drilling through the interbedded formations with varying hardnesses using very aggressive 16-in. bits has proven to be challenging in terms of wear and tear on the drilling motors. Damage to the motors, such as stator chunking, bearing failures and even catastrophic connection twistoffs have occurred during these drilling operations. One service provider currently uses 9½-in. motors in the 16-in. wellbores. To address tool integrity issues, the service provider upgraded to their standard offering, 12¾-in. motors. While incidences of housing and stator failure were eliminated, the combination of large, high flow rate tools in a land-based operation has not delivered the required performance on bottom. The drilling rigs currently employed for gas development drilling were not capable of pumping more than 1,300 gpm while optimum performance from the standard 12¾-in. motor comes with flow rates above 1,500 gpm. As a result, bit speed was too low, and ROP did not meet or exceed the 9½-in. motor runs and the standard 12¾-in. tools did not find widespread acceptance from the client.

The Upper Devonian-Lower Mississippian Bakken petroleum system, including the Bakken, Lower Lodgepole, and Upper Three Forks formations, is a widespread unit within the central and deeper portions of the Williston Basin in Montana, North Dakota, and the Canadian provinces of Saskatchewan and Manitoba. The USGS estimated that the U.S. portion of the Bakken Formation contains between 3 and 4.3 billion barrels of undiscovered, recoverable oil, 1.85 Tcf of associated/dissolved natural gas and 148 million barrels of natural gas liquid; the Upper Three Forks Formation is estimated to contain 20 billion barrels of oil, with approximately 2 billion barrels of recoverable oil. There are extensive horizontal drilling and multi-stage hydraulic fracturing activities targeting these two formations. Those horizontal wells typically have 10,000 ft lateral sections in pay zones and multi-stage hydraulic fracturing with 24 to 36 stages. The extensive well paths bring numerous challenges, including precisely landing the curve, enhancing drilling rig operating conditions to obtain measuring while drilling (MWD) system optimal performance, and avoiding drilling into undesirable formations. Overlooking some or all of these conditions could lead to unnecessary high dogleg severity (DLS), poor rate of penetration (ROP), unnecessary trips and sidetracks to name a few. All these conditions could ultimately add additional time and cost to the drilling and completion program of the well and in the worst-case lower future production rates to the operator. Several practical field techniques and technology applications are presented as solutions to help optimize ROP, reduce non-productive rig time and chances of sidetracks. Several field examples were analyzed. The techniques gained are valuable for developing optimal drilling practice procedures, and improving drilling operations and future well production.

The giant Pinedale gas field, which is approximately 35 miles long and 6 miles wide, is the largest structural feature in the northern Green River Basin of Wyoming, with conservative estimates of in-place natural gas at 159 Tcf. The Pinedale field ranks as the third-largest gas field in the United States by proved reserves. Gas production is primarily from a 5,500 ft-thick "Lance Pool" on top of the Ericson Sandstone. The pay zone consists of Upper Cretaceous sandstones of the Lance Formation, the Upper Mesaverde Group, and a Paleocene "unnamed" unit. The reservoir is classified as tight gas due to its low porosity and micro-Darcy permeability. The lenticular sands and stratigraphic nature of this area make horizontal drilling impractical, and deviated well drilling is prevalent.By 2010, the average drilling time was reduced to 15 days by application of automated vertical-seeking tools with limited availability and poor cost effectiveness. Design and reliability improvements to various downhole tools have further reduced the average drilling time to 12.8 days with a conventional adjustable kick-off sub (AKO) mud motor by 2012. However, due to the various downhole tools involved, a bottomhole assembly (BHA) result analysis is a key step to evaluate the effectiveness of each tool, improve BHA design, identify superior drilling strategy, and eventually optimize the overall drilling performance.Several field cases are presented in this paper to conduct BHA result analysis, and several suggestions are promoted for future operations. These suggestions can reduce bit trip, improve oriented drilling efficiency, increase rotation rate of penetration (ROP) and save substantial financial resources for customers. The valuable information and lessons learned are crucial for Pinedale drilling operations, and they may be readily applied in other tight gas fields with similar characteristics to optimize drilling performance.

The introduction of new, wear-resistant polycrystalline diamond compact (PDC) bit cutter technology in recent years has dramatically increased the demand for increased torque output from the positive displacement motor (PDM). The commercial introduction of pre-contoured (i.e., equidistant rubber thickness) stators in 2000 solved the theoretical technical challenge of developing very high torque output in a PDM. Yet, in cost-sensitive, land-based drilling markets where conventional power sections are still a major factor, the requirement for traditional motor power section construction restricted the rate of penetration improvements. Recent developments in the chemistry of the standard stator elastomer have enabled a step-change improvement in the performance and durability of the power sections in PDMs. This premium elastomer, manufactured in conventional stator cans, can generate higher differential pressure and subsequently more torque, while achieving increased durability, even in some of today's oil-based drilling environments. This higher level of torque and increased downhole durability is ideally suited for the increasing toughness and aggressiveness of today's premium PDC bit. This paper will review in detail this innovative motor technology, describe how it enables reaching higher performance levels, and present several case histories illustrating this performance enhancement.

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.