The Use of Real-Time and Time-Lapse Logging-While-Drilling Images for Geosteering and Formation Evaluation in the Breitbrunn Field, Bavaria, Germany
- Hendrik Rohler (RWE Dea) | Ted Bornemann (Schlumberger) | Alexis Darquin (Schlumberger) | John Rasmus (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 2004
- Document Type
- Journal Paper
- 133 - 138
- 2004. Society of Petroleum Engineers
- 1.2.3 Rock properties, 1.2.2 Geomechanics, 1.7.1 Underbalanced Drilling, 1.12.1 Measurement While Drilling, 1.6.1 Drilling Operation Management, 4.3.4 Scale, 1.11 Drilling Fluids and Materials, 5.5.2 Core Analysis, 4.6 Natural Gas, 1.6.9 Coring, Fishing, 1.6 Drilling Operations, 3.3.2 Borehole Imaging and Wellbore Seismic, 3 Production and Well Operations, 2.2.2 Perforating, 5.6.1 Open hole/cased hole log analysis, 1.8 Formation Damage, 1.1 Well Planning, 5.1.5 Geologic Modeling, 5.8.7 Carbonate Reservoir, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 4.1.5 Processing Equipment, 1.12.2 Logging While Drilling, 2.4.3 Sand/Solids Control, 1.10 Drilling Equipment, 4.1.2 Separation and Treating, 5.10.2 Natural Gas Storage, 1.6.7 Geosteering / Reservoir Navigation
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Six horizontal wells were drilled into the Tertiary Chatt Sand reservoir of the Breitbrunn gas field in Bavaria, Germany. The purpose of this campaign was to develop part of the depleted reservoir into a gas-storage sand. A detailed geological and petrophysical study was prepared before drilling and resulted in the identification of high-quality reservoir layers that were targeted by the horizontal wells. Despite the simple anticline structure of the field, geometric drilling was ruled out because of remaining geological and directional uncertainties. The geosteering approach adopted relies on real-time resistivity-at-bit images, which were used for the first time during this drilling campaign. The image data are compressed downhole and transmitted to the acquisition computer on the rig, where they are decompressed and analyzed. The images allow the precise placement of the borehole relative to the geology. Layer heterogeneity such as tight streaks, concretions, or patchy porosity can be identified as such and is not interpreted as a different layer entered by the hole, which would lead to a wrong geosteering decision. Logging-while-drilling (LWD) azimuthal data are acquired during drilling and during washdown passes that follow a bit change. A comparison of these time-lapse data sets can provide invasion profiles through time and around the borehole.
The Breitbrunn/Eggstatt gas field was discovered in 1975 in southern Bavaria, Germany (Fig. 1). The northeast/southwest-striking anticlinal structure covers approximately 30 km2 and consists (from top to bottom) of sands A through H, with sands A through D being the original gas producers. The lower sands are wet. The individual reservoir layers range in thickness from approximately 5 to 15 m and are separated by impermeable calcareous shales. The immature sands were deposited immediately north of the rising Alpine orogen during the Tertiary. Mineralogically, they consist of carbonate sand (principally dolomite, quartz, and micas). The sands were deposited in a fluvial/deltaic setting.
Initial production was by vertical wells drilled on the top of the structure. After depletion of the reservoir, layers A and B were converted into a gas-storage reservoir, with layer B being the storage sand while layer A functions as the monitoring unit for gas-leak detection. During that campaign, five horizontal wells were drilled underbalanced and completed openhole. Geosteering decisions were then based on cutting analyses then.1 The demand for natural gas in the region led to the second drilling campaign, discussed here, with the aim of increasing the storage capacity of the reservoir. The remaining original gas sands C and D were targeted for storage development because it was known that they possessed sufficient porosity and permeability, although with greater geological and petrophysical heterogeneity than the upper two sands. Reservoir quality in this field deteriorates from the top sand downward.
The drilling phase of sands C and D was preceded by geological, petrophysical, and geomechanical studies.
The goal of the geological study was to achieve a structural accuracy of 0.1 percent, which translates into a maximal depth inaccuracy of 1.5 m. This was achieved by resurveying well locations and using gyroscopic and ring-laser directional surveys from cased-hole runs for adjusting all log-derived marker picks to a common baseline. The vertical pilot well and the subsequent horizontal development wells confirmed that this depth accuracy was achieved.
Petrophysical evaluations and the depositional setting of the reservoir sands predicted that the sands are present in lenticular form, with additional complication provided by the presence of calcareous concretions occurring suspended in the sands as well as present in horizons with varying concretion packing density. Core and borehole images taken in the pilot well provided conclusive evidence for this interpretation. These findings demanded the development of storage sands with horizontal wells designed to penetrate as many of the potentially isolated reservoir lenses as possible.
Three horizontal wells were planned and drilled for each of the two sands. The trajectories of the horizontal wells, initially designed to penetrate the sand subhorizontally up to 300 m in length, were drilled in a gentle U-shaped profile, which allows the well to transverse the sand from top to bottom and back to the top within each horizontal section. The adopted geosteering concept led to horizontal wells reaching up to 1000 m in length (Fig. 2).
Geomechanics and Well Planning
Sanding during production cycles is of greatest concern and requires a detailed geomechanical study before drilling these storage wells. The maximum horizontal stress is oriented north/south, and the minimum horizontal stress is east/west, with the vertical principal stress being the intermediate stress typical for a strike/slip regime. Well azimuths based on the direction and magnitudes of the principal stresses alone suggest drilling north/south wells and minimizing drilling-induced formation damage during drilling and the production phase of the wells.
An intensive rock-strength testing program was conducted to verify assumed rock-strength isotropy. The uniaxial compressive strength of 10 differently oriented plugs taken from one continuous core section was measured. The tests showed distinct strength anisotropy. Minimum strength reaches approximately one-third of the maximum strength value. The maximum-strength component runs approximately north/south parallel to the maximum horizontal stress, while the minimum-strength component runs in an east/west direction. Additional tests on moist cores showed a significant reduction of rock strength compared to dry core. In situations like this, it is important to consider in-situ water saturation for geomechanical calculations.
The optimum orientation of the horizontal storage wells cannot be derived from the orientation of the stress field alone. Rock-strength anisotropy must be taken into account as well. Another aspect for planning the trajectories is structural position. Stress is likely to increase at the anticlinal flanks, and wells placed closer to the anticlinal axis away from the lower flanks will be more stable.
The final calculations concluded that the optimum well azimuth is along the northeast/southwest-striking axis of the anticline. This direction is perpendicular to what would have been arrived at assuming isotropic rock subjected to the described stress regime.
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