Technology improvements continue to advance the capabilities of coiled tubing directional drilling (CTDD). Alaska's North Slope, with its prevailing dedication to expanding the technological envelope, has served as a testing ground where advanced CTDD techniques mature into economically viable systems.
Even after over 500 successful CTDD sidetracks on the North Slope, impetus remains to further improve this economical drilling technique. Through a close working relationship between field operator and the service company, significant research and development has led to the introduction of novel tools and services to overcome the intrinsic hurdles of conventional CTDD.
Through a process of miniaturization and innovation, small-diameter systems have been developed for CTDD. The most recent introduction of tools and services includes rib steering technologies, bidirectional wireless mud pulse telemetry, gyro-based MWD services, and ultra-slim, high-resolution, real-time resistivity.
Straighter, longer horizontal laterals, improved steering, and real-time resistivity in openhole sizes as small as 2 3/4-in. ID has been achieved, consequently improving precision in geosteering within the narrowest of payzone.
This paper highlights two case histories describing CTDD technology, real-time formation evaluation, and multilateral drilling processes used to access previously unreachable oil-bearing rock on Alaska's North Slope. While proven in this region, CTDD advances are applicable in other mature fields for the economical extraction of additional reserves.
Ever since CTDD started off in the year 1994 in the North Slope of Alaska, it has become an ongoing desired method for slimhole re-entry from existing wells in the region to access additional reserves. The continuous use of CTDD for re-entry in Alaska, because of the operators' persistent and innovative culture, has made it a proving ground for newer drilling and completion techniques and advanced bottomhole assemblies (BHAs). It has proven itself as the most efficient and cost-effective method of sidetracking and re-entering existing wellbores with cost savings of up to 40% compared to conventional rotary drilling in the region.5
What started off as selecting simple candidates for re-entry with CTDD has now evolved several folds into routine selection of complex candidates presenting just as complex drilling techniques. The vast experience gained in the region and the development of advanced BHAs have made returns from these once "hard candidates?? an economically sound and successful CTDD campaign.
A number of these candidates have an existing 3½-in. tubing, which required the development of advanced tools in sizes as small as 2 3/8-in. to re-enter through these wells without a tubing retrieval operation. The development and usage of these tools in the 2 3/8-in. size redefined the meaning of slimhole drilling and opened up drilling opportunities to many additional wells.1
Key benefits gained from the development of such CTDD tools is the acquired knowledge and experience in re-entry and the drive to push the application into complex and sometimes fragile formations such as those found in the Kuparuk River Unit.
The dynamically overbalanced drilling (DOD) technique-where the drilling fluid is underbalance, yet the surface pressure is adjusted to maintain at-balance condition on bottom-also sometimes known as the managed pressure drilling technique, is a significant improvement in successful drilling technology in such fields. Monitoring of downhole conditions to maintain at-balance conditions, especially the annular pressure, with fastest data update rate, and the ability to steer the BHA as required without any pressure fluctuations were necessary to drill using the DOD technique.2 These BHA requirements apply also to the underbalanced drilling candidates in Alaska.
Fast update rates could only be achieved by an e-line system of steering tools, which had to be in the 2 3/8-in. size to re-enter a number of these complex wells and formations. Hence, the application led to the development of e-line BHAs with downhole dynamics, pressure monitoring, real-time downhole weight on bit, and the functionality to steer and navigate the wellbore in the right path while on bottom drilling.
Frac-pack is a pervasively used completion technique in wells targeting high permeability, poorly consolidated and depleted sandstone formations located in Bachaquero, Tía Juana and Lagunillas fields in West Venezuela. This technique combines stimulation and sand production control in a single treatment by placing a short and wide fracture which bypasses the near-wellbore damage, while gravel-packing the zone of interest.
This paper describes a novel and economical frac-and-pack technique which consists of pumping a sand plug with the downhole tool set for circulation to isolate a bottom set of perforations, followed by conventional frac-and-pack. When this procedure is followed, the fracture is forced to propagate along the upper intervals. This novel technique is particularly useful for wells with water-producing zones near the bottom of the target zone, because it induces selective growth of the fracture along the upper intervals and mitigates the risk of growing the fracture into the water-producing zone.
A case study of a frac-and-pack performed in a Lagunillas field well with a water contact 40 ft below the target zone is reviewed. The intervention rendered an increase in well production rate from 27 to 173 net barrels per day with a reduction in water cut from 25% to 9%. In contrast, two wells in the same field and with very similar characteristics which were frac-and-packed conventionally rendered 100% and 63% water cuts, respectively.
Another application of this technique refers to frac-and-pack of wells with long perforated intervals where early wellbore screen-out may occur due to proppant bridging of the annular volume between the screen and the casing. Conventional frac-and-pack of twenty wells in these fields with perforated intervals exceeding 90 ft rendered a 40% early wellbore screen-out rate. The early wellbore screen-out rate was reduced to 12% in a sample of twenty eight wells with the new technique. The average production rate increased from 2 to 135 BOPD, whereas the average estimated after-treatment production was 130 BOPD, for which this technique was considered successful. A shortcoming of the technique for this application is the fact that the bottom of the perforated interval is not fractured. High-end frac pack techniques that overcome this issue such as use of shunt tubes were found to render higher normalized oil production rates.
In well testing, the subject of study is composed by the reservoir, wellbore and piping.
The traditional well testing interpretation approach focuses in the transient behavior of the pressure inside the reservoir. Flow rates are considered input information; generally assumed instantaneously constant during each flow period.
On the other side, the traditional nodal analysis concentrates in the pressure drops inside the wellbore and pipelines reducing the behavior of the reservoir to a pseudo-stationary state.
These simplifications can be applied for a limited period of time in high potential wells.
However, especially in low potential wells, the productivity index varies continuously, flow rates can not be approximated by constant values; the effects of liquid loading, slugging, and other regimes of multiphase pipe flow affect decisively the conditions in the reservoir. Understanding system's operation implies the analysis of every component and the relations between them.
The models can be concatenated in series so that the output of one model becomes the input of the next.
The purpose of this paper is to show that integrating the tools each method provides, solving the models as a system in a dynamic and simultaneous way, significant advantages are obtained:
A typical well testing procedure consists in measuring transient pressures and flow rates simultaneously while inducing changes to the flow conditions.
As can be seen in Figure 1 the hydraulic system is composed of the reservoir, connected to the wellbore that conveys the fluid to surface, a flow control device such as a Choke or restriction, a surface pipe line to derive the flow to a separator or other metering device where rates are measured.
Pressures are taken at several points: at bottom, using a pressure and temperature gauge, at the well head, after the choke or start of surface pipe line and at the separator. Flow rates are commonly measured after separation.
Elnaga, Aly Abou (Chevron San Jorge S.R.L.) | Almanza, Edgar A. (Halliburton Energy Services Group) | Batocchio, Marcelo Pavanelli (Halliburton Argentina S.A.) | Folse, Kent C. (Halliburton Energy Services Group) | Schoener-Scott, Martin F. (Halliburton Co.)
Chevron San Jorge S.R.L. operates in the Loma Negra area and El Trapial field located in the Neuquén Basin, Argentina.
El Trapial wells are characterized by stratified, shallow- to medium-depth reservoirs with permeabilities of 35md to 85md and porosities of 18 to 30%. The wells are completed in oil reservoirs that have been perforated using conventional methods, fracture stimulated to increase production, and later, completed with electro-submersible pumps (ESPs).
To effectively meet the operator's needs for a method that would help optimize well productivity, and at the same time, be cost effective without compromising the results of the operation, an improvement over traditional tubing-conveyed perforating (TCP) was required. A propellant-assisted (PA) perforating method that could optimize well productivity while maintaining stringent health, safety and environmental standards was proposed. The propellant-assisted perforating method uses standard perforating components and procedures, thus providing the same safety features available to the industry today when conventional TCP operations are used. The propellant is an oxidizer that creates carbon dioxide gas at extremely high peak pressures in the millisecond time regime to overcome in-situ stresses and create perforation breakdown and mild fracturing near the wellbore.
This paper will focus on two case histories describing the methods and improved results obtained from the application of the propellant perforating technique.
The information in this paper will verify that the technique was capable of satisfying the operational challenges in these reservoir types. Instrumental in the success of the propellant-assisted perforating methodology was 1) the proper screening of candidate wells, 2) good pre-job design modeling, and 3) adherence to industry accepted best practices with constant communication.
El Trapial Field was discovered in 1991. It is part of a near-shore, shallow marine environment. It is situated in the Neuquen Basin (Fig. 1) in the Northeast quadrant of the Neuquen Province of Argentina. The main reservoir in the El Trapial field is the Lower Troncoso where 57% of the total reserves reside. It is composed of sandstone in eolian faces, of a medium-grained clast-supported texture, scarce matrix and dolomite cement, with good to very good porosity and permeability.
New well logs were run, and when they identified increasing water cut in the production, Chevron decided to try a new technology to perforate these wells rather than the conventional tubing-conveyed perforating (TCP) techniques previously used followed by conventional hydraulic fracturing.) This new technology chosen included propellant sleeves with the TCP guns, which was capable of increasing the exposure area (fissures) created by the gas (CO2) in the propellant sleeves.
Loma Negra field complex on the Rio Negro Norte Block in southeastern Neuquen has hosted several discoveries since opening of Loma Negra field in 1997. Loma Negra, with reserves of at least 240 million bbl. could be one of Argentina's top producing fields of this decade. The formation is a sandstone called Punta Rosada with permeabilities in excess of 75md and porosities in excess of 15% and bottom hole pressures in the vicinity of 4000psi.
Description of Propellant-Assisted Perforating
Propellant-assisted perforating techniques have been in use for many years as a method to stimulate completions. Results have been somewhat mixed due to a lack of understanding of the physics involved during the propellant burn event. Advances in the propellant technology have continued to evolve, and these have led to improvements in techniques for well candidate selection, and subsequently, stimulation results. The propellant-assisted perforating technique is used in many different applications with positive results, as described by Boscan ET al.1
The propellant-assisted perforating process combines perforating and perforation breakdown with propellant in a single tool and operation.