Wellbores drilled on US land today are geosteered predominantly using total gamma ray measurements and periodic survey data. This approach results in a number of ambiguous scenarios whereby not enough data are available to make the correct interpretation decisions. It is for this reason that many horizontal wells are unknowingly in different locations from where they are reported to be both positionally and stratigraphically. Geosteering techniques employing high-quality azimuthal gamma imaging and continuous inclination measurements address some of the main challenges plaguing accurate wellbore placement in the Wolfcamp A and Wolfcamp B of the Southern Midland Basin. Azimuthal gamma image examples of stratified and non-stratified bedding are related to lithofacies observed in core, bringing visibility to internal geometries and demonstrating how depositional environment influences tool response from a gamma radiation standpoint. Azimuthal gamma logged in conjunction with an accurate continuous inclination measurement to reduce TVD error enhances the benefits to geosteering interpretation and bed dip calculation, resulting in higher confidence wellbore placement. Furthermore, azimuthal gamma and continuous inclination MWD tool designs are discussed in the context of the critical elements needed for accurate and high resolution measurements.
Houston-based Surge Energy drilled the Medusa Unit C 28-09 3AH well in the Midland Basin to a TMD of 24,592 ft, with a total horizontal displacement of 17,935 ft, or 3.4 miles. Oil companies generate an enormous amount of data but are reluctant to share it. But more sharing of information may be required in the future to keep up with a rapidly changing energy landscape. The discovery is world’s third-largest natural gas discovery in the past 2 years. A drilling team has focused on increasing lateral lengths in the Marcellus Shale.
JPT Technology Minute Poll: To Which of the Top Five UN Sustainability Development Goals Do You Think the Oil and Gas Industry Will Contribute the Most? Flaring and emissions challenges have recently made news headlines around the world. The goal of this article is to engage you with this important topic by presenting a selection of recent SPE papers which address these challenges through various approaches. Operators face a dilemma in balancing the need for mud weight (MW) to remain below the fracture gradient to avoid losses, while also providing sufficient density to block influxes into the well. JPT Technology Minute Poll: Which Technology Would You Choose for Offshore Compression?
Kisku, Sayanima (Oil & Natural Gas Corporation Ltd.) | Santhosh Kumar, R. (Oil & Natural Gas Corporation Ltd.) | Dayal, Har sharad (Oil & Natural Gas Corporation Ltd.) | Chadha, Harish Kumar (Oil & Natural Gas Corporation Ltd.) | Srivastava, Anil (Oil & Natural Gas Corporation Ltd.)
Infill drilling is an integral part of brown field management for exploiting un-drained areas with good oil saturation. In a matured field on water-flood, the primary objective is optimized wellbore placement of infill wells in areas with better petro-physical characteristics, bypassing flooded region. It is also important to design a robust completion strategy to safeguard the longevity of these wells by curtailing produced water. This approach assists in dramatic increase in production by isolating water charged sections and thereby restricting rise in water production.
The use of advanced Logging-While-Drilling techniques during horizontal drilling provides an opportunity for effective well planning. Real-time Logging-While-Drilling instruments during directional drilling gives us the opportunity to acquire information pertaining to the reservoir in a single run. Interpretation from the real-time data acquisition boosts the planning during wellbore drilling.
This paper discusses a case study of a field in western offshore, India, which focuses on the applications of geosteering and the use of swell packers for zonal isolation to augment oil production. In this study, two wells have been deliberated where the real-time information has been extracted and included in the decision making process. The bottom-hole assembly used in this case, comprised standard Logging-While-Drilling services such as gamma ray, resistivity, neutron porosity, density and density imaging services and also formation pressure testing.
Since the field under study is a carbonate reservoir that has been on waterflood for the last twenty eight years, chances of early breakthrough of water in the infill wells has posed a high risk in spite of the presence of good bypassed oil saturation. Geosteering has enabled to restrict the horizontal section safely within the desired zone of better oil saturation and geological features, as interpreted from the Logging-While-Drilling data. Further isolation of suspected water bearing zones with swell packers have assisted in healthy well completion by diminishing chances of sharp rise in water cut in the infill wells.
In Vietnam, there was a need of a lean surface casing due to restricted drift inside diameter (ID). The 2nd slot of the splitter conductor only have 13-1/2" ID max pass through. The practical option is to drill with 12-1/4" bit and open to 14-1/2" hole to set 11-3/4" casing OD. Similar reasoning for the intermediate hole that will require to under ream the hole from 10-5/8" bit to 12-1/4" hole and set 9-5/8" casing OD. Although these under reaming operations are commonly practiced, the technical limitations are still inefficient and compromising. Conventional reamers still have limited activation/deactivation cycle for operational flexibility and long rathole of the reamer to bit depth for casing shoe placement.
The long awaited technology is now available with the presence of intelligent reamers that have unlimited activation & deactivation cycles and can be placed directly above the rotary steerable system for shortest possible rathole. The setup is to combine two intelligent reamers in a single BHA. The 1st reamer placed strategically on top of the MWD & LWD tools while the 2nd reamer is directly above the rotary steerable system tool. As both reamers can be both activated and deactivated through downlinking, the reamer has to be activated simultaneously to control the risks associated with hole opening and LWD data acquisition. The 1st intelligent reamer will be activated first while drilling the section formation and the 2nd intelligent reamer will then be activated at section TD to ream and shorten the rathole. For the purpose of cleaning the hole effectively, both reamers can be deactivated to execute high flow and RPM without creating new cuttings from the reamer blades and avoid making a bigger hole at the low side.
This enabled shoe to shoe drilling while under reaming and achieving less than 10m rathole. These operational capabilities saved at least 50% of the section rig time compared to having a 2 trip system. Combination of reduced casing shoe rathole and open hole exposure mitigated the well bore instability risks and helps in managing mud weight for both hole section intervals. The unlimited activation cycle provided flexibility in operations particularly in dealing with hole cleaning and wiper trips. Plus, the intelligent reamer provides realtime reamer diameter which gives confidence on the drilled hole size for casing running preparation and decisions.
Intelligent reamers have unique tool features that differentiate from the rest of current industry technologies. This feature helps to eliminate the risk of under-reamer balling, which improve the rate of penetration. The success of the operation has spread throughout operators in Vietnam, and now the intelligent reamer is considered as a game changer application in drilling lean casing profiles.
Positive displacement motors (PDMs) have been extensively utilized in the North America unconventional market. PDMs are frequently run with aggressive parameters in challenging drilling environments to increase drilling performance. Because PDMs are typically rental equipment, there is often not much information givento the equipment owners when tools are returned after use. This situation limits the opportunities for failure investigation, preventive maintenance, and tool design optimization. Furthermore, measurement-while-drilling (MWD) tools in PDM bottom hole assemblies (BHAs)only measure dynamics of the drill collars, considerably above the motor, often without sufficient resolution to understand adverse drilling dynamics and to design remedial actions for the operations.
A dynamics measurement data recorder was developed and introduced for this type of operation. The data recorder is a small, low-cost, and battery-powered device. It is installed in the rotor catch of a conventional PDM in such a way that no additional component is added to the BHA length. The recorder is fitted with a triaxial vibration accelerometer, a triaxial shock accelerometer, a gyroscope and a temperature sensor. The recorder can log data over a full PDM operation cycle, including shipment, rig-side handling, and downhole operation.
The data recorder has been deployed in North American land operations since 2016. One case study is presented, and the data analysis showed that PDM operation cycles were captured from the installation of the recorder in maintenance bases to the return of the tools. Torsional vibrations and stick-slip generated by mudmotors during sliding phases were effectively captured. In several cases, bit dull grade conditions were correlated with recorded drilling dynamics data as part of failure analyses to understand the root cause of the problem.
The use of advanced solid-state gyroscopic sensors has now become both a viable and practical option for high accuracy wellbore placement, with the potential to out-perform traditional mechanical gyroscopic systems. This paper describes how the contributions of the new gyroscope technology are causing service providers to reconsider current survey practices, and to examine how the new gyroscopic survey tools can be best used for wellbore surveying and real-time wellbore placement.
The simultaneous application of multiple survey tools, largely made possible as a result of the unique attributes of solid-state gyroscopic sensors (including small size and significant power reduction), has clear benefits in terms of enhanced well placement, reliability and the detection of gross errors in the survey process. Further benefits accrue through the combination of different, but complimentary survey methods. This paper focuses mainly on the benefits of combining gyroscopic and magnetic measurements to reduce or remove the known errors related to the Earth's magnetic field to which magnetic survey systems are susceptible; errors in total magnetic field, declination and dip angle.
In this context, the use of statistical estimation techniques based on performance models of the survey systems used is described. For post-drilling surveys (using drop survey tools or wireline-conveyed tools for example), post-run analysis of the data using least-squares estimation techniques is appropriate. Alternative methods capable of achieving real-time data correction during drilling are also described and results are presented to demonstrate the potential for enhanced magnetic survey performance.
The principles described may be used when running basic magnetic measurement while drilling (MWD) systems, and for systems that employ field correction methods, such as the various in-field referencing (IFR) techniques, that are frequently used. The proposed methodology is of particular benefit in the former case, allowing enhanced magnetic surveying to be achieved without the need for expensive and complex magnetic field correction procedures. The potential also exists either to identify or to correct possible errors in the IFR data when such methods are used. This information may be of great value for the safe drilling of additional wells in the same region.
Screenshot shows how rock property data and acoustic-based fracture property data are integrated into a commercial petrophysical interpretation software (CGG PowerLog). The multi-colored wellbore represents different grades of stiffness while the blue bi-wings and green spheres represent an analysis of the fracture network. Two companies, C&J Energy Services and Seismos, have teamed up to combine their fracture characterization technologies into a single service. They say their technology tandem was recently used in the field by a completions team to customize almost two-thirds of the stimulation stages in a horizontal shale well. Under the partnership, C&J is responsible for analyzing drilling data from horizontal wells to describe rock properties along the lateral section.
Franquet, Javier Alejandro (Baker Hughes, a GE company) | Singh, Rudra Pratap Narayan (ADNOC offshore) | Diaz, Nerwing (Baker Hughes, a GE company) | Anurag, Atul (ADNOC offshore) | Balooshi, Mohamed Ali Al (ADNOC offshore) | Jefri, Ghassan Al (ADNOC offshore) | Hosany, Khalid Ibrahim M (ADNOC offshore) | Cesetti, Mauricio (ADNOC offshore) | Kindi, Rashid Khudaim Al (ADNOC offshore) | Zhunussova, Gulzira (Baker Hughes, a GE company) | Bradley, Tom (Baker Hughes, a GE company) | Kirby, Cliff (Baker Hughes, a GE company)
An injector well drilled from an artificial island in UAE left a non-magnetic fish during well control operations across lower Cretaceous reservoirs below the 9�?-in. casing shoe, exposing all upper Jurassic reservoirs flow units. The situation was a serious concern to field developing and reservoir integrity as aquifer, gas and many layers of oil reservoirs were connected through the borehole below the fish. It was decided to sidetrack around the fish to intersect the original 8½-in. open-hole section. The sidetrack was accomplished, but the first attempt to intersect the mother hole was unsuccessful. Therefore, an innovative solution was needed for detecting the mother hole to intersect it.
A combination of cross-dipole deep shear acoustic, high-resolution induction and orientation wireline measurements were advised. These measurements would be used to update the wellbore survey and to detect acoustic reflections from the mother hole for identifying its relative orientation with respect to the sidetrack hole. Detailed measurement-while-drilling (MWD) wellbore survey analyses were conducted for the original and sidetrack holes beside typical corrections, such as Sag and drillstring interference. The deep shear wave imaging data recorded in the side-track hole was processed at multiple X-dipole polarization directions to detect shear reflection from the mother-hole and back calculate its relative position.
The high-resolution induction data could not detect the fish from the sidetrack, but few dipole reflections of the mother hole were detected in two locations. The orientation of the reflectors was consistent with the revised wellbore survey analysis, and this information was used to make the directional drilling corrections required to intersect the mother hole. The use of deep shear wave imaging data to identify a nearby open hole was a non-conventional application of this technology, but it definitely facilitated directional drilling operations to successfully intersect a mother hole that cannot be left uncompleted. After the openhole intersection, a good borehole condition was encountered due to the non-damaging fluid system, allowing the well to be completed as per original plan. Achieving this challenging directional drilling objective was critical for the field development plan of these offshore UAE reservoirs.
This case study represents the first documented field experience of using deep shear wave imaging data in the petroleum industry for assisting directional drillers to intersect an open hole mother wellbore after sidetracking a fish.
Muecke, Nick (Vermilion Oil and Gas Australia) | Wroth, Andrew (Vermilion Oil and Gas Australia) | Zharkeshov, Sanzhar (Merlin ERD Limited) | Anton, Richard (Merlin ERD Limited) | McCourt, Iain (Merlin ERD Limited) | Armstrong, Neil (Merlin ERD Limited)
N. Muecke and A. Wroth, Vermilion Oil and Gas Australia; and S. Zharkeshov, R. Anton, I. McCourt, and N. Armstrong, Merlin ERD Limited Summary This paper shows how the implementation of a continuous-improvement process, in combination with precampaign-engineering and planning-optimization efforts, allowed the operator to expand the existing drilling-and-completion envelope in a mature offshore field. This provided a cost-effective means to access the remaining attic and undrained oil in a very shallow reservoir. Application of new technology, extended-reach-drilling (ERD) practices, complex completions, detailed engineering, good-quality real-time data, and execution support at the rigsite drove the evolution of well designs for the operator during the last 8 years, enabling the life of this mature asset to be extended. This paper highlights the evolutionary process applied to enable economic infield development, with an emphasis on relevant transferable learnings that might be ...