Second EAGE/SPE Geosteering and Well Placement Workshop

The field of interest is located in Volgo-Ural Region of Russian Federation. Its size is 4x4 kilometers. Hydrocarbon reserves are accumulated in the carbonate and clastic formations of the Carboniferous and the Devonian. Multilayer Bed Boundary Detection Technology was successfully implemented in that field. In the well drilled into the clastic formation Bb (the Visean of the Carboniferous), Multilayer Bed Boundary Detection technology enabled Well Placement team to steer inside heterogeneous reservoir interval, mapping interbedded sedimentological features in real time.

Drilling horizontal wells is becoming an increasingly practice in hydrocarbon field development. Technology evolution reduced risks associated to drilling operations and increased accuracy in well placement operations.

Despite this, uncertainty related to subsurface geological and structural setting remains significantly high, and represents a risk factor that can compromise well results.

Moreover, in presence of complex or heterogeneous geological scenario, relying on offset well correlation or drilling pilot hole could not be the proper solution.

The introduction of an ultra-deep directional resistivity tool has provided the industry’s first reservoir-scale imaging while drilling, allowing landing or geo-stopping operations being less critical than in the past. This tool investigates a large volume of the target reservoir, providing different output like 2D map of the resistivity formation around the borehole, supporting real time decision-making processes.

Through the description of three case histories (Sahara Desert, North-East Africa and offshore Timor Sea), it will be demonstrated that the use of the ultra-deep directional resistivity tool in horizontal wells, supports strategic decisions in hazardous geological environment, enabling the elimination of pilot hole and resulting in a significant project’s risks decreasing and costs saving

Surface “shape” conformance in geological models is important for structural grids, tying grids to horizontal wells, well planning, geosteering, property modeling and volumetric calculations. We outline several metrics applicable to reservoir model surface conformance measurement that allow for rapidly highlighting problem areas and correcting reservoir shapes relative to highly deviated and horizontal wells. This allows geoscientists to QC data from 1000’s of legacy wells while updating the surfaces in real-time during geosteering resulting in a “living” model that can also serve as an input for reservoir simulation.

In a mature asset, lies an undrilled but high PoS target. This Jurassic sandstone target has an estimated pressure of 9,500 psi and is directly overlaid by a Paleocene chalk field that has been on production for the last 20 years, depleting the chalk reservoir pressure from 6,000 psi to 1,000 psi.

How can we safely drill a well to appraise and produce the hydrocarbons from this untapped deeper reservoir located below the highly depleted reservoir? Significant challenges such as the fixed surface location, large offset to the target, complex overburden has been taken in account. A number of trajectory concepts have been studied and several options have been ruled out based on feasibility.

Based on an in-depth integrated assessment, the selected well concept to appraise and develop the opportunity is a well drilled from the existing platform with a low development cost related to facilities modifications.

The ultra-deep azimuthal EM LWD technology consists of a modular system design tailored initially for landing, geosteering and reservoir mapping applications. It features a depth of investigation that can exceed, in the most favorable cases, 100 ft [30 m] in radius around the borehole. Recently the tool’s capacity of boundary detection has also been applied for detecting resistivity variations ahead of the bit, in vertical or low angle wells. The plan of using the EM Look-Ahead service in an upcoming well in the Norwegian sea, combined with the standard look-around capability, allowed, during the well planning phase, to largely reduce the risk of setting the casing atop a highly depleted reservoir in the 17 ½’’ phase and to avoid the drilling of a pilot hole while landing the 12 ¼’’ section. A thorough pre job model (feasibility phase) permitted to precisely asses the applicability of the approach in the specific geological scenario for the two cases; being the target formations quite heterogeneous, in terms of resistivity response, some alternative scenarios were built and evaluated. This example describes the effectiveness of new LWD technology application, in order to contribute to safest operations and in significant cost saving.

The Greater Enfield Project, with Joint Venture participant Mitsui E&P Australia, involves the development of three oil accumulations: Laverda Canyon, Norton over Laverda and Cimatti, through the drilling and completion of twelve horizontal development wells (six oil production wells including three tri-laterals and six water injection wells). All wells are targeting stratigraphically complex reservoirs with narrow drilling windows situated within thin (<15m TVD) oil columns across multiple fault blocks. We discuss how extensive pre-drill planning in combination with identifying and implementing innovative technology solutions has enabled the Greater Enfield Project to plan for success by drilling and completing challenging well profiles in these technically complex reservoirs.

Drilling high angle or horizontal wells through complex channel systems is a challenging issue that many operators face in field development. There are several areas where uncertainty in the planning stages cannot be overcome by conventional means such as drilling pilot holes, relying on seismic models and using log data from offset wells.

An operator on the UK continental Shelf employed the use of extra-deep azimuthal resistivity to mitigate the planning uncertainties and successfully drill through a series of turbidite channels without the use of a pilot hole. Extra-deep azimuthal resistivity increased the probability of drilling a successful well in an area with seismic uncertainty and a lack of offset well data.

This paper will describe how the use of extra-deep azimuthal resistivity, from the pre-well planning stage, through the drilling phase and post well analysis enabled the successful drilling of such a well where net sand drilled exceeded expectation, costs were reduced and an enhanced understanding of the reservoir geology resulted.

Extra Deep Azimuthal Resistivity logging (EDAR), while drilling (LWD) enables detection, measurement and visualization of the reservoir architecture and multiple bed boundaries up to 30m (100ft) distance from the wellbore. Whilst this technology successfully allows the user to understand reservoir architecture, heterogeneity and fluid contacts, it is challenging to distinguish shale from water due to very similar resistivities.

On the Grane field, the Heimdal reservoir sand is injected into the Lista shale resulting in irregular reservoir base and roof topographies. The reservoir sections are planned with respect to minimizing the risk of drilling into shales and faults as well as to optimize drainage of initial and slumped oil in the area. The Lower Lista has a resistivity of 0.8–1.1 Ohmm, and the water in the ‘slumped Oil’ or produced oil zone has a similar resistivity range. Identifying and thus avoiding the Lower Lista shale is challenging and critical for the success of the well. Because shale resistivity is anisotropic, meaning the resistivity value is not equal in all directions, we can use this to distinguish shale from water, which is isotropic.

This case study illustrates that by using EDAR supported by multi-component inversions, how it was possible to ascertain the anisotropy value for each resistive layer thus identify and shale from water. This approach can differentiate between water and shale up to 5m TVD above the conductive boundary, and then used to optimally place the well and accurately predict the shale entry and exit.

This abstract aims to illustrate, how the GeoSphereTM was used for the first time in a horizontal Maastrichtian Tor well on the Halfdan Northeast Field in the Danish North Sea. The tool helped to ensure optimal well placement and improved reservoir understanding.

The formation in this area was interpreted as “disturbed chalk,” and associated with large uncertainty on reservoir geometry. Well- and seismic data show that the reservoir could have an apparently complex and mixed stratigraphy, making it difficult to navigate during drilling.

The real time MWD results allowed for a change in interpretation and successful placement and navigation of the well through more than 60 small-scale closely spaced conjugate normal faults to planned TD. Production is above expectations.

Post drilling, the MWD results integrated with multiple datasets including 3D- and 4D-seismic data, standard log interpretations, biostratigraphy and cutting analysis, provided valuable additional information on the reservoir structure. This allowed for a different an improved interpretation of the nature of the chalk in the area, which is only obtainable by integrating multiple datasets: Top Ekofisk is much more uneven, the Tor is significantly faulted, and no evidence of re-sedimentation processes was found in this part of the disturbed chalk area.

Goliat is the first oil producing field in the Barents Sea (Norway) and it consists of multiple stacked Middle to Late Triassic siliciclastic reservoir levels containing oil and a limited gas cap. The two main developed reservoirs are both characterized by complex compartmentalization and heterogeneous distribution of the fluvial-deltaic sands distributed in several stacked sequences. Due to these complexities, the field development strategy called for the drilling of several horizontal production wells to ensure an effective drainage of the reservoirs. The use of the most advanced drilling and logging technologies, with regards to well placement, proved to be very effective to successfully land the wells and optimize the sand exposure and for the integration of the ultra-deep EM inversion results in the reservoir models. The reservoir mapping capabilities of the deep EM technology was applied in several situations in both Goliat reservoirs and provided valuable information for understanding, updating and improving the reservoir models: the identification of fluid contacts, different scale faults detection, mapping of reservoir top, internal stratigraphy and sand bodies geometries proved to be vital information to overcome the difficulty in drilling such complex reservoirs and meet the success criteria of the development wells.