An HP/HT exploration well was evaluated offshore in the Norwegian Sea. The temperatures of the deepest reservoirs exceeded 180 degree C and pressure over 800 bar. The well was drilled with oil-based mud. A formation pressure while drilling tool (FPWD) was deployed. Subsequently conventional wireline formation pressures, samples and mini-DST,s were acquired followed by standard DST tests.
This was the first application of the FPWD tool in a vertical well from a floating rig. The data obtained demonstrate an ~ 83 psi decrease in stabilised (not building) pressure, at the same depth, with decreasing circulation rate and increasing exposure time. This reflects the equilibration process that diffuses the mud invasion with time. The effect of circulation (annular pressure) can be observed on some pressure build-up plots, reflecting the dynamic effect on the near well bore region. The last FPWD point, obtained with no circulation, falls within 3 psi of the gradient obtained from subsequent wireline formation tester acquisition. Subsequent attempts to obtain wireline formation pressures failed (tight tests) in the region where FPWD data was successfully acquired.
The dual packer elements of the RCI tool were successfully deployed (at the time a world first temperature for these packers) in an HPHT environment for transient pressure testing (mini-DSTs). Permeability was successfully investigated and was in close comparison with core permeabilities, given the uncertainties in each measurement. This provided valuable early productivity information with which to optimise the further well data acquisition (full DSTs), in addition to providing productivity data in zones not subjected to full DST.
Fluid samples acquired were successful in identifying fluid types, were of low OBM contamination by volume reservoir fluid, and successfully detected H2S despite relatively low concentrations in the reservoir fluid (as indicated from DST). After correcting for OBM contamination, the CGR results were within 2-4 bbl/MMCF from the well tests. WFT cannot measure CGR values lower than 1.5 to 2 bbl/MMCF, when sampled with OBM, due to unavoidable contamination inside the tool. The compositions derived from the RCI across the same intervals as DSTs, were mostly in agreement. Mudlogging isotope data can be an aid in reconciling separate datasets.
WFT evaluation objectives were largely met, a significant achievement given the challenges involved. Uncertainties in the reservoir quality and fluid properties still remain. We will review the planning and execution of the wireline campaign and the comparison to the well test results with a view to further appraisal
Kristin is a HPHT gas/condensate field in the Norwegian Sea. Deep, hot wells have contributed to depth differences between wireline and LWD depths of up to 20m, as well as significant variations between different bit runs. Such differences introduce unacceptable depth uncertainty for both reservoir modeling and well operations. Special procedures were implemented to help understand observed depth differences. Radioactive markers were installed in casing strings and logged routinely with both LWD and wireline. Intervals were relogged on subsequent LWD runs to allow comparison, including logging in upwards direction. Primary depth control procedures were adopted for all WL descents. GR correlation logs were recorded during all relevant runs/passes to allow depth comparisons.
The first two wells had fairly low inclination and wireline depths between runs were consistent, with simple block shifts resulting in good match between up- and downlogs. Meanwhile, LWD depths had large local variations and up to 5m difference between runs. Wireline downlogs were selected as depth reference and all other WL/LWD runs were shifted to match. Resulting depth shifts from LWD to WL showed systematic trends increasing with depth and with local features apparently coinciding with well trajectories. LWD depths were consistently shallow compared to wireline and also somewhat shallow compared with casing tallies. Our initial hypothesis was that pipe tally depths were yielding too shallow depths because pipe stretch was not accounted for. Local variations in LWD depths were believed to result from variations in drilling parameters and logging direction.
With the above methodology shifts up to 20m were obtained on the third well. Because of the high well angle we questioned the validity of the downlog depths and thus the validity of our procedures. Formation tops based on wireline depths resulted in questionable local corrections to seismic time-depth maps, with significant implications for mapped reservoir volumes.
Subsequent high inclination, LWD-only wells left us without a similar wireline depth reference. Given the large uncertainty involved in correcting LWD depths based on trends from earlier wells only, an alternative approach was sought. Simplified models available in literature were adopted to estimate pipe stretch/compression due to temperature, string weight and drilling parameters. Results obtained could explain only about 1/3 of earlier estimated pipe stretch. A similar methodology was applied to correct wireline depths for stretch, with estimated corrections far exceeding standard assumptions. Following run/pass-specific correction of both LWD and WL logs, depth uncertainty has been significantly reduced.
Azimuthal logging while drilling (LWD) tools and real-time operations (RTO) were used effectively to geosteer the horizontal section on a well recently drilled in the Norwegian Sea. It was possible here to efficiently change the well path in real-time to avoid non-productive zones and to maximize the productive interval.
The paper will document novel work processes and procedures regarding direct communication between the geosteering expert and the drilling personnel offshore. These procedures were critical in allowing rapid response to changes in drilling targets. Critical items for success were the azimuthal LWD sensors that produced real-time images for analysis of bed boundary dip and for relative angle between the well bore and the formation.
This paper will explain utilization of these sensors and their images to change a well profile while drilling in order to achieve optimized production. Rotary steerable drilling tools were invaluable too as they allowed rapid changes in well profile without affecting rate of penetration. Real-time data exchange software and an in-place network infrastructure was also essential in making it all possible.
First-generation LWD formation pressure testing technology has been deployed during the last three years at a number of locations. The driving force for the development of a second-generation system was the industry need to operate LWD formation pressure tester in any kind of environment, without interaction from the surface, in hole sizes from 5¾” to 17½”. Difficult applications such as pressure testing in tight formations, testing in unconsolidated sands as well as applications involving positive displacement motors can now be addressed. The challenges in these applications are to achieve and maintain an effective seal and to acquire high-quality data. The technology discussed allows individual and continuous control of the test cycle along with the drawdown pump. An intelligent closed-loop control of the pad pressure enables optimum sealing efficiency, saving significant time for “lost seal” retesting and avoids formation damage. A smart test function reduces shock effects while drawing down on tight formations, but also avoids sanding in highly unconsolidated formations. Performing self-learning, optimized test sequences improves accuracy of the pressure and mobility data.
The results are presented in case histories from the two main operators on the Norwegian Continental Shelf, Statoil and Hydro. In Statoil’s Heidrun field as well as Hydro’s Oseberg field, the discussed second-generation formation pressures tester allows determination of fluid contacts and gradients, all within challenging LWD environments. The data are additionally used for ECD management by updating predicted pore pressure models and assessing reservoir connectivity. In the discussed applications, the sealing efficiency is significantly improved, in some cases when compared to wireline acquired data, even in difficult motor applications. This improvement in sealing efficiency leads to time and cost savings for operators and allows the acquisition of pressure and mobility data in long ERD wells.
To maximize production, the industry has developed intelligent Rotary Steerable Systems (RSS) and sophisticated Logging While Drilling (LWD) technologies that have both lowered well cost through non-productive time (NPT) reduction and given the operator the opportunity to position the well path optimally in the reservoir, based on real-time logging data. This environment has placed an increased reliance on LWD measurements. In this presentation, we will review wells drilled and logged on the Hydro-operated Grane field and show how the application of a number of advanced LWD technologies have maximized both reservoir charaterization and well placement answers by acquiring full-formation evaluation in a single pass. We will discuss the importance of having an integrated LWD system engineered for diverse drilling applications and also designed as a compact, modular system with sensors close to bit for increased flexibility in acquiring a wide range of measurements. The real-time aspects of LWD are important in delivering valuable answers. Two case wells from the Grane field will be presented, which demonstrate the value of these technologies in accurately estimating reserves, well positioning, reducing NPT and mitigating drilling hazards. For the two case study wells, the reservoir sections were drilled using the rotary closed loop system (RCLS) and a range of LWD technologies that included standard ‘triple combo’, multiple borehole imaging measurement, advanced acoustic LWD and formation pressure as well as extra deep resistivity measurements. With such a complex, integrated system, a thorough approach to pre-job planning, real-time follow-up and post-well analysis is a key factor in achieving full-formation evaluation data acquisition with cost efficient operations through reliable and high-performance drilling.
Over the last 20 years, the oil industry has seen a dramatic increase in the complexity and the reach of production wells. These advances have been made possible by the introduction of sophisticated rotary steerable drilling and formation evaluation systems, enabling Hydro and other operators to place wells into targets in a more accurate and cost-efficient manner than ever before. This environment has placed an increased reliance on Logging-While-Drilling (LWD) measurements. In this paper, we will review a number of high-angle and horizontal wells drilled and logged on one of Hydro's mature North Sea fields and how the application of a number of advanced LWD technologies have enhanced answers through acquiring comprehensive formation evaluation data in a single run.
The LWD technologies that will be presented range from standard measurements such as Gamma Ray (GR), multiple propagation resistivity, neutron porosity and density to real-time GR and density imaging, formation pressure and mobility and acoustic LWD compressional and shear measurements in both fast and slow formations. During late stages of field development where bypassed oil is to be drained, the data acquisition program will change substantially to acquire relevant information to ensure both optimal wellbore placement and maximum hydrocarbon drainage. Maximum available technology on LWD is applied to such complex horizontal and extended reach wells. The economic advantage with respect to time saving operations in the high-cost environment of the North Sea is obvious. The wells that are drilled in these offshore brownfield environments would not be possible without the high level of accuracy available from LWD tools today. The real-time aspect of LWD data acquisition is key to delivering answers while drilling that reduce reservoir and drilling uncertainty. Also, handling of the data in real time to ensure service quality and pro-activity, along with the post-processing of LWD data, are discussed and illustrated with examples to demonstrate the value of these technologies in achieving the goal of optimized reservoir access and productivity. The benefits from accessing the data while drilling will be discussed, including how real-time formation pressure measurements identify type of reservoir fluid early in the drilling process, as well as lithostratigraphic and petrophysical interpretation in horizontal wells to determine key petrophysical parameters, structural interpretation from LWD imaging and acoustic LWD including soft rock shear input to improve seismic resolution and well tie.
A new template is installed on Smørbukk Sør as a part of an IOR project. First phase is to develop the Garn 2.2 Fm. which is poorly drained by the existing production wells. Next phase is to develop the Ile and Tilje reservoirs. To achieve sufficient production potential horizontal wells are necessary. Examples of geosteering and formation evaluation based on the Schlumberger scope tools series will be presented.
This talk gives an overview of how petrophysical data are used in geological reservoir models with examples of both good and bad practice. The assumptions embedded in upscaling and spatial property modelling are discussed along with approaches for handling N/G ratios and cut-off criteria.
Metre-scale models of sedimentary bedding (using SBED) are proposed and a way forward to improved property prediction. The method has been successfully applied in thin-bedded reservoir units for estimation of directional permeability, for correction of bias in core plug data, and for improved interpretation of wireline and well-test data. The future potential of "small-scale” shared earth modelling is to provide realistic models of sub-seismic and sub-reservoir-gridcell scale architecture that properly integrate petrophysical well data with reservoir models.
Numerical modelling based on particle scale description of rock is becoming more and more relevant as a tool in petrophysical evaluation. Discrete particle modelling is based on a force - displacement law and a failure criterion for the contacts between individual particles. This is computationally a fully dynamic approach, so complex processes like faulting and fracturing emerge directly from the cooperative behavior of the many-particle system. Also, wave propagation may be readily studied in the particle assembly.
In this presentation, we will show a few examples of the use of this tool, which is being developed in a research program at SINTEF Petroleum Research. We will show how 3D µCT image data may be transferred into a discrete particle model and used for computation of stress - strain behavior. We will also show examples of stress dependent wave velocities in uncemented and cemented granular media, with comparison to controlled laboratory experiments. The numerical model may further be used to simulate processes that can not easily be verified experimentally. Here we show example simulations of stress evolution during drill-out of a core sample, of very long-term deformation (creep) of geomaterials, and finally on the use of the discrete element approach beyond the particle scale.
Borehole sonic data can be useful for various design decisions in the oil and gas industry; e.g., well planning, wellbore stability, and reservoir management. Optimal well completions require both the detection and estimation of the radial extent of near-wellbore alteration in reservoir intervals. We have analyzed borehole sonic data from a new tool that contains 8 azimuthal receivers at 13 axial positions with an inter-receiver spacing of 6 in. The large number of receivers together with new processing algorithms enables reliable modal decomposition and slowness dispersion estimates. We present results from the Backus-Gilbert inversion of cross-dipole and Stoneley dispersions that yields radial profiles of three shear slowness in the three orthogonal planes. We show theoretical validation of the dipole and Stoneley radial profiling of the shear slowness algorithms using synthetic dispersions for known variations in the compressional and shear slownesses. The inversion algorithms account for the sonic tool effects on dispersion data. Inversion of cross-dipole dispersions yields radial profiles of the fast and slow dipole slownesses averaged over the two opposite quadrants. In contrast, the Stoneley radial profiling algorithm outputs azimuthally averaged shear slowness in the cross-sectional plane of the borehole. Inversion of cross-dipole and Stoneley dispersions yields three shear slowness logs at various radial positions away from the borehole surface. Near-wellbore softening and stiffening are characterized by larger and smaller shear slownesses than those in the far-field. Identification of near-wellbore softening caused by mechanical damage aids depth selection for wireline pressure measurements to avoid sections that are prone to seal failures. In addition, it can help identify mechanically competent depth intervals for stimulation. We illustrate shear slowness profiling results from sonic data acquired in a few wells in the North Sea. This study has demonstrated a consistent correlation between a negligibly small difference between the near-wellbore Stoneley and dipole shear slownesses and negligibly small fluid mobility implying tight zones where fluid samples could not be extracted. The radial extent of mobility impairment is estimated from radial profiles of both the Stoneley and dipole slownesses that help in designing optimal perforation tunnels extending beyond the damaged annulus.