Quantitative subsurface prediction and uncertainty analysis are critical success factors in all phases of exploration, development, and production projects, including regional evaluation, leasing, prospect maturation and drilling, appraisal and development planning, system selection, and reservoir management. Today, the E&P industry is moving into more frontier oil and gas provinces, such as deepwater and very deep plays, where well costs are very high. Consequently, the regional and in-field well densities are generally very low compared with historical exploration and development. Such sparseness of well control poses a challenge for quantitative subsurface analysis because it is difficult to establish spatial correlations of rock and reservoir properties with confidence, when the distances between wells are too large to assume geostatistical stationarity of earth model parameters.An effective approach to reduce subsurface uncertainty due to well sparseness is to build a 3D shared earth model using seismic data as "spatial glue." Under this approach, self-consistent 3D models are built for all interdependent earth model parameters that span a wide range of spatial scale and subsurface disciplines, and are constrained by physical laws and geologic scenarios. The self-consistency conditions of a 3D shared earth model provide tighter constraints and improved reservoir, rock and fluid property predictions, and more robust uncertainty analysis. This approach has been piloted in a number of play settings Figure 1. Pressure prediction workflow, incorporating all geophysical, geologic, and petrophysical data and analysis.Figure 2. Traverse through Mars-Ursa Basin (Mars-Princess-Ursa-Crosby) showing the original PSDM velocity model used as input to pressure prediction and an assortment of pressure diagnostic cubes that follow. (Color scales run from low to high values from bottom to top.)
Drilling the gas-bearing shales in the Bossier and Haynesville formations in northwestern Louisiana presents many drilling challenges. Pore pressures increase from slightly elevated levels to a surprisingly high geopressures over short intervals. These pressures, if not correctly predicted, can lead to dangerous gas kicks and potentially blowouts. In the shale gas formations, conventional log-based pore pressure prediction techniques did not work well. The presence of gas in the shales adversely affected the compressional velocity. The impact of the Sabine uplift also reduced the ability of conventional pore pressure techniques to quantify pressures adequately in the objective formations. Instead we analyzed 54 kicks and other downhole measurements across the field to analyze the abnormal pressures. This approach yielded consistent results and provided a reliable basis for pore pressure prediction. The pore pressures in the lower Bossier and Haynesville shale gas formations show highly overpressured after a overpressure transition in upper Bossier shales, and unloading effect on pore pressure in those formation are also identified. Using the kick derived pore pressure model and improved log-based effective stress models, we developed a comprehensive pore pressure prediction method.
Understanding pore pressure prediction in unconventional plays is important for executing a safe drilling strategy and for accurate production modeling. Experience from several unconventional plays highlights key aspects of pore pressure prediction work that are different from conventional exploration settings. In conventional exploration, the most common source of overpressure is disequilibrium compaction, where porosity is preserved in mudrocks as pore fluids take on additional overburden load. Traditional petrophysical methods use resistivity, sonic and density data to measure porosity and associate it with vertical effective stress (VES), which is overburden minus pore pressure. In unconventional plays, secondary pressure mechanisms and uplift require other methods because of two influences on pore pressure:hydrocarbon generation andvariations in burial and uplift history. Both of these situations mean that the relationships between vertical effective stress (VES), velocity, density and resistivity will follow unloading paths, not compaction trends. The unloading paths vary depending on the amount of hydrocarbon generated and the amount of uplift. In organic-rich sections, an additional complication arises because pore pressure cannot be de-convolved from total organic carbon (TOC) and gas effects on shale compressional velocity and resistivity. In conventional settings, fluid gradients and contacts are used to translate measured pressure data from one location to another. In unconventional tight reservoirs, the fluids are not connected and this method will not work. Pressure data must be inferred from drilling event and diagnostic fracture injection test interpretations, and a different way to translate data between locations is required. The majority of pressure data in unconventional reservoirs shows that often, the way to translate pressure information from one location to another in the same tight rocks is to use a constant VES. This method combined with understanding variations in uplift history and hydrocarbon generation has been used to successfully predict pressure ranges in multiple unconventional plays. Introduction Unconventional resources plays in shale and tight rocks have become a substantial resource in North America. They are now rapidly being explored and developed outside the United States and Canada in a trend that will likely continue to grow. To economically develop these plays, wells must be drilled as cost effective as possible. To produce from these plays and forecast production, the mechanical properties of the rocks and their stress conditions need to be understood to best stimulate and complete the wells. Pore pressure prediction is integral to both of these activities.
Factors that affect downhole temperature while drilling (TWD) were modeled with a comprehensive in-house drilling mechanics and hydraulics model to help explain field observations in a GoM deepwater well. In a long, near-horizontal well section, the TWD from measurement while drilling (MWD) was much hotter than the surrounding formation temperatures, an important issue due to observed dependence of reduced bottom-hole temperature (BHT) and lost-circulation events, and also effects on downhole tools and non-productive time (NPT.) The model used is an in-house suite of drilling modules capable of modeling hydraulics, torque and drag, drillstring dynamics, and their interactive effects. Heat generation and temperatures are calculated in a coupled manner, by considering factors that include:○Mud-formation heat transfer and mechanical friction of the drillstring against the formation/casing wall;○Heat from pressure drop across bit nozzles, and the mechanical rock cutting action of the drillbit;○Friction in all drilling situations - making hole, tripping etc, depending on annular clearance;○Heat generation from mud-motor operation and operating inefficiencies. Results indicate that the rotary speed is very important; the higher the RPM, the more the BHT increases. The annular clearance is also a strong factor; the less the clearance, as in casing/liner drilling (CLD) or from tight-clearance downhole tools, the higher the BHT. Other factors in varying degrees of importance are flow rate, mud type, and weight on bit. Results of this work will support on-going attempts at deepwater NPT reduction. Introduction and Background Deepwater drilling is fraught with challenges, including borehole integrity and lost circulation. Investigators (Ref. 1–3, among others) have identified temperature effects as contributing to hoop stress increase and lost circulation mitigation. This is important because in tight drilling margins, ECD management within the pore-pressure/fracture-gradient window can be difficult, and one may possibly resort to novel methods of increasing the fracture gradient. In this paper, we have used a comprehensive in-house drilling mechanics model, along with field data and published experience, to investigate factors that affect well BHT with a view to potentially controlling these factors in order to manage the BHT and reduce lost-circulation events. The example well is in deepwater Gulf of Mexico (GoM) where relatively cold formations often experience lost circulation. Fig. 1 illustrates this vividly where mud losses were observed in zones with reduced temperature, all other factors remaining the same. Fig. 2 shows a temperature-trend match for a section of the well with TWD data. The data scatter is related to pipe connection events, rotating and non-rotating modes, changes in circulation rates, etc. On the other hand, formation temperature decrease through salt zones helps reduce salt movement (creep) and tar flow. Though critically important to NPT management in subsalt wells, the low-temperature effect along with salt-induced casing collapse is outside the scope of this paper. Work is underway on these technologies.
Some rock properties show surprisingly stable relationships, to the extent that any deviation therefrom should be regarded as a signal of anomalous behavior. One of these stable relationships is the linear trend between compressional (Vp) and shear velocities (Vs), which is observed for both sandstones and mudstones. We infer that anomalous stresses, notably deviations from the basin-wide relationship between horizontal and vertical effective stresses, may cause deviations from the basin-wide Vp-Vs trends. An anomalously high or low shear velocity can therefore be indicative for an anomalous stress regime.
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