Coiled tubing drilling (CTD) is an economical method of re-entering existing cased wells in mature fields to exploit bypassed reserves because of its versatility in accommodating a variety of candidates and its technological edge in drilling more efficiently. In re-entry drilling, kicking off with the right bearing attenuates the single biggest issue when drilling long laterals---weight transfer problems. Correct re-entry wellbore placement from vertically cased wells has traditionally required many single-function trips. The magnetic interference from the steel casing makes the acquired magnetic tool face measurements from traditional instruments inaccurate. Verification of the kickoff direction is usually performed with a wireline multi-axis gyro instrument. This process can be time-consuming and still requires additional correctional runs or directional changes prior to beginning drilling in the desired direction toward the target. Hence, the entire process of intervention, from setting a whipstock in the right orientation to drilling in the least tortuous direction from these vertically cased wells, requires a more efficient approach if CTD is to be a viable option in marginal projects. This paper assesses the limitations in the current methods of kicking off and details an innovative approach to improve re-entry wellbore quality through the use of an integrated coiled tubing gyro measurement-while-drilling (MWD) instrument. Introduction The majority of re-entry candidates are existing wells in mature fields, a significant percentage of which are onshore and vertical. These wells are re-entered either to extract reserves from compartmentalized, thin zones or to recover bypassed hydrocarbons. In vertical wells, magnetic tool face measurement from the conventional directional tool is used for orienting the bit in the direction of desired kickoff. The challenge, however, is to be able to kick off in the right bearing from vertically cased wells where magnetic interference from steel casing results in inaccurate magnetic tool face measurements acquired from traditional MWD instruments. Because the drilling is done in a blind condition, there is an increased risk of kicking off in an undesired bearing. Traditionally, the kick-off assembly for the build section consists of a downhole drilling motor with its initial adjustable kick off (AKO) set to give a reasonable amount of curvature to land the well horizontally in the target payzone. In most cases where the initial kick-off direction is not accurate due to unreliable magnetic tool face reading caused by proximity to the cased vertical well, direction correctional changes have to be made to the deviated well in the desired target direction. However, such directional adjustments can lead to increased friction loss because of the undesired localized doglegs in the wellbore. Wellbore directional nonconformity has a significant effect on the single biggest issue when drilling laterals: smooth weight transfer to the bit. Failure to adequately correct direction increases the risk of reducing overall potential payzone footage. Wellpath corrections required to compensate for the initial deviation initiate further problems in landing the well horizontally in the desired payzone because a significant component of the BHA's build-up rate capacity is consumed in just making turn adjustments. Therefore, the potential risk for creating a wellbore with impassable localized doglegs for completions is significantly increased. Since the kick-off assembly has a higher AKO setting on the motor in the build section than in the lateral section, directional adjustments in the build section are undesired as localized doglegs can compromise wellbore stability.

fax 01-972-952-9435. AbstractTechnology improvements continue to

Production in most wells follows a predictable pattern dictated by the decline curve. Initially high production is quickly followed by a long, measured decline. This potentially long decline in production, together with an ever-increasing demand for energy, has resulted in many mature, low production fields. To stem the decline in production in these wells and extend the viable economic life of these assets, operators are increasingly turning to advances in technology. Technologies such as improved slimhole re-entry drilling bottomhole assemblies (BHAs), enhanced reservoir navigation systems, and improved conventional drilling techniques are successfully meeting the challenges of developing mature fields in established oil and gas basins around the world. This combination of techniques and technologies is being used in the Williston Basin to increase the recoverable reserves and improve the present economic value of each asset. Production from the Williston Basin declined from the time of its initial discovery through the early 1990s. The introduction of horizontal re-entry drilling technologies then revitalized this region. Targeting these thin beds typically requires extending 4½-in. laterals from existing or new vertical 7-in. cased wells. In the recent past, re-entry performance was confined by well placement restrictions, water and salt zones, and available drilling technologies. These requirements restricted the wellpath to relatively tight radius build sections. Together with the drilling difficulties associated with slimhole tubulars, these tight builds often resulted in high drag in the hole, limiting the lateral section to 3,000 to 4,000 ft due to weight transfer and drag constraints. However, in recent applications that did not suffer from such restrictions or the consequences of the water/salt formation hole instability issues, larger radius curves could be incorporated into the wellplan. This increased radius reduced drag in the well program, which together with improved motor technologies and experienced wellsite execution, allowed the 4½-in. re-entry section to achieve world record open slimhole multilaterals. The successful completion of such multilateral wells provide for over 10,000 ft of potential reservoir exposure in this thin bed. Introduction The Williston Basin is a large, roughly circular sedimentary basin covering several hundred thousand square miles along the eastern edge of the Rocky Mountains straddling the northern U.S.A. states of western North Dakota, eastern Montana, as well as southern Saskatchewan, and Manitoba in Canada, as shown in Fig. 1. The scope of this paper will concentrate on the North Dakota portion of this basin. Oil production began in earnest in the North Dakota Williston Basin in 1951 when Amerada Hess completed and produced its first commercial well. Drilling continued in a cyclical nature for the next 50+ years with production mainly based upon the Mississippian Madison Group formations, although some Mesozoic strata are productive (see Fig. 2). Currently, 3,300 oil wells are still producing in North Dakota. Additionally, there are over 14,000 wells existing in the North Dakota Williston Basin, having produced over 1.5 billion barrels of oil. Annual oil production peaked in 1984 at more than 52 million barrels of oil, followed by the expected and inevitable steep decline, as shown in Fig. 3. The decline was temporarily arrested in the late 1980s with the introduction of horizontal drilling of the Bakken formation. Subsequent advances in horizontal drilling techniques and technologies allowed for further exploitation of other formations to alter the production decline again in the late 1990s and mid-2000s. Although production will probably never again reach the peaks achieved 30 years ago, the reversal is so drastic that production in North Dakota is currently on the rise (see Fig. 3). The Birdbear (Nisku) formation oil-producing payzones are characterized by compartmentalized secondary porosity thin beds locked in deep muddy limestone and dolomite formations. The Nisku ‘A’ dolomite is encased between two impermeable anhydrite beds, creating a large regional stratigraphic trap, ideally suited for horizontal drilling and subsequent viable economic development. In this particular area of the Williston Basin, formation thicknesses vary from 2 to 4 ft (0.7 to 1.2 m) when exposed with vertical wells. Traditionally, the Birdbear is relatively low on the list of most prolific oil-producing zones, ranking 10th overall in Table 1.

Having explored many methods to improve efficiencies in conventional drilling processes, operators in the traditional North American land market are ever more attracted to innovative and cost effective means to drill wells. These innovative operators have turned to coiled tubing directional drilling (CTDD), with its promising inherent efficiencies in tripping and connection times, and with its smaller, logistically simpler footprint to optimize the drilling process even further. New downhole drilling technologies found in the conventional drilling arena are being applied to this operation to overcome the intrinsic limitations associated with the non-traditional slide-only drilling method associated with coiled tubing drilling. Together with innovative modifications to traditional CT rigs to address the fit-for-purpose needs of drilling, this novel approach to cost reduction is being applied in a cost-sensitive land market in the Rocky Mountain region of the US. This paper provides an overview of the drilling application faced by the operator, of the specialized hybrid Coil Tubing drilling rig and of the novel application utilizing the modern, non-rotating rib-steering downhole drilling tools. The paper will benchmark the performance of the built-for-purpose operation compared to previous wells drilled with conventional rigs and directional motors, as well as other CTD systems. Additionally, a well to well performance of the drilling operation over a multi-well period will be evaluated, together with a discussion on lessons learned and a presentation of potential future improvements. The application of automated drilling systems with coiled tubing drilling heralds in a new age in developmental drilling in low spread cost markets. Overview Traditional drilling in North America is increasingly focused on developing natural gas reservoirs, whether they are conventional sandstone formations or unconventional shale plays. One of the most popular basins in recent years for unconventional shale and tight sands gas has been the Piceance Basin. The Piceance Basin is a geologic structural depression trending northwest - southeast in northwestern Colorado, in the United States (see figure 1). The basin is more than 100 miles (161 km) long and has an average width of over 60 miles (96.5 km), encompassing an area of approximately 7,110 square miles (18,415 sq. km). It includes geologic formations from Cambrian to Holocene in age, but the thickest section is comprised of rocks from the Cretaceous Period. The basin contains reserves of coal, natural gas, and oil shale. The basin has come to increasing public attention in recent years because of widespread drilling to extract natural gas. The primary target of gas development has been the Williams Fork Formation of the Mesaverde Group, or Cretaceous age. The Williams Fork is a several-thousand-foot thick section of shale, sandstone and coal deposited in a coastal plain environment. The formation has long been known to contain natural gas (see figure 2). However, the sandstone reservoirs have low permeability and limited areal extent, which made gas wells uneconomic in the past. Advances in hydraulic fracturing technology within the past decade, along with higher natural gas prices, have made gas wells broadly economic in the area. (Wikipedia 2007), (Colorado Geologic Survey 2007)