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Second EAGE Workshop on Pore Pressure Prediction
- Conference date: May 19-21, 2019
- Location: Amsterdam, Netherlands
- Published: 19 May 2019
32 results
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Pore Pressure Uncertainty, Practices and Pragmatism for Well Planning
Authors P. Rouillé, T. Harrold, S. Martinez, G. Saceda and J.M. JimenezSummaryDuring the last decade, markets have imposed significant operational cost savings to the oil industry. With a given annual upstream budget and commonly overestimated exploratory well AFEs, some projects can be compromised or postponed. Defining with more accuracy the exploration wells AFE can allow to drill an extra well on the same annual budget. Pore Pressure and Geomechanical studies directly drive the well design (including contingencies), the drilling strategy, the rig selection or the equipment necessary to achieve the given objectives safely. The cost of the well is directly impacted, therefore, by these inputs. Optimising and lowering the PPFG uncertainties are key factors to reduce the allocated budget and final cost of a well. Reducing the uncertainty too much, however, can result in a well design not sufficient to handle the conditions with disastrous consequences. To solve this complex equation, the engineer needs to understand how all the sources of uncertainty are propagated. From the well Kick Off meeting to the final PPFG delivery to drilling team, every single step includes uncertainties: geological / prospect definition, offset well analysis and lessons learnt, seismic velocity, overpressure mechanisms and scenarios, fluid type, depth uncertainties, lithology effects amongst others.
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Pore Pressure Predictions in Ultra-Deepwaters of Sergipe Sub-Basin, NE Brazil
Authors C. Cuartas, A. Barbosa, H.E. Martínez Carvajal, A.F. Do Nascimento and F.L.D. SantanaSummaryPrediction of pore pressures in large parts of a basin is very important to assure advancement of exploration, within safety limits, and to avoid risks related to anomalous pressures found in deep water frontiers. In Brazil, the Sergipe Sub-basin is located in the northeast of the country, corresponds to an Atlantic-type rifted basin with deep grabens controlled by large distensive rotational faults. The sub-basin represents one of pioneer and important areas of oil and gas production in this country with a renewed interest in the last decade for deep and ultra-deepwater opportunities. Despite that, the pore pressure in that area still little known. Thus, in these research we estimate the pore pressures throughout the stratigraphic units drilled by the P978-11 well, hoping in that way to contribute for future models of pore pressure in the basins of NE Brazil. For that, we applied on the sonic log of the P978-11 well the traditional Gardner and Eaton equations, but with own parameters values for the area, and then smoothed and calibrated the final results by loess regression. Four pore pressures zones were found ranging from 28 MPa to 89.4, suggesting an overpressure behavior in the Zonas 3 and 4.
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Overpressure Mechanisms and Lateral Fluid Flow in the Taranaki Basin, New Zealand
Authors S. O’Neill, S. Jones and P. KampSummaryAll wells in the Taranaki Basin drilled in excess of 4500 mTVD experienced relatively rapid increases in pore pressure. Hydrocarbon generation and in particular cracking to gas at high maturities, has been interpreted to be contributing to the overpressures encountered, alongside an increase in mudrock volume (reduced permeability). Lateral drainage of overpressures has been demonstrated across the Western Platform and Southern Taranaki Inversion Zone, while lateral transfer is suggested to be occurring in the Tarata Thrust Zone. The poor prediction of both lateral transfer and lateral drainage in wells from across the basin has resulted in numerous well control issues that could have been avoided if knowledge from offset wells was included in the pore pressure prediction and well design.
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Geological Interpretations of Vertical Effective Stress-Compressional Sonic Transit Time Cross-plots for Pore Pressure Prediction
By D. TassoneSummaryRelationships between vertical effective stress (VES) and compressional sonic transit time (Δt) are widely used in the petroleum industry to predict pore pressures to ensure safe drilling operations and robust well designs. Whilst on most occasions trends can be established on VES-Δt plots to model mudrock pore pressures, there are increasingly more frequent examples where VES-Δt plots contain highly scattered data for which simple trends are difficult to establish.
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The Application of Double Normal Compaction Trend to Improve Overpressure Estimation in the East Java Basin
Authors A. Ramdhan, T. Atarita, G. Titaley, A. Ardjuna and L. HutasoitSummaryThe East Java Basin is an overpressured basin in Indonesia. The LUSI mudvolcano is one of the evidences of overpressure occurrence in the basin. Hydrocarbon drillings in the basin have been experiencing some operational problems due to the presence of overpressure such as drilling-pipe stuck, hole cavings, and kicks, leading to nonproductive drilling time. In this paper, we offer additional analytical analyses to estimate overpressure magnitude in the basin, on the basis of understanding of overpressure generating mechanism and mudrock compaction stages. The analysis shows that overpressure in the study area, at least down to the depth ∼ 3 km is caused by disequilibrium compaction, and the mudrocks has experienced transformation from smectite (S) to illite (I) at the depth ∼1.6 km. The conventional method of overpressure estimation commonly used in this basin is to use single normal compaction trend (NCT) to estimate overpressure for the entire section. This method seriously underestimates overpressure magnitude at depth. By constraining S-I transformation, we propose double NCT (smectitic NCT and illitic NCT) to estimate overpressure magnitude in the basin. We have proved that this technique can estimate overpressure reasonably accurate.
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Pressure, Seals and Traps: the Bases for the Petroleum System to Work Efficiently
By J. BiteauSummaryHydrocarbon trapping is the result of a contrast of a reservoir having a low entry pressure and a seal having a highest entry pressure. If there is an important overpressure or if the HC column is high the pressure can be close to the hydraulic fracturation criterion and there is a possible leakage.
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Challenges of Pore Pressure Prediction for Unconventional Reservoirs in Active Operational Settings
Authors I. Eggenkamp and A. SummittSummaryPore pressure prediction in unconventional plays presents a unique set of challenges and uncertainties. These are the result of uncertainty in the measurements, the low permeability of the reservoir, and changes caused by industry activity. Slow pressure changes during production tests or diagnostic fracture injection tests (DFITs) require significant extrapolation to obtain the reservoir pressure. A third source of data comes from the mud weight required to control a kick. Unconventional reservoirs are often drilled underbalanced and if the kick is the result of encountering a natural fracture, the mud weight required may be lower than the reservoir pressure due to the limited hydrocarbon volume of the fracture. The uncertainty in the measurements result in a wide range of pressures that can make it difficult to identify important outliers caused by geological differences or by industry activity in the area. Kicks close to lithostatic pressure can be encountered when drilling into a hydraulic fracture of a nearby well. This can have major safety and financial implications. Regulations have been put in place requiring operators to identify offset wells that could be affected by hydraulic fracturing operations and work together with their competitors to stay safe.
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Impact of Geological Model Uncertainties on Pore Pressure Prediction: A GOM Case Study
Authors A. Isiakpere, M.B. Skaug, L. Sirgue, B. Benazet and A. ChiapperoSummaryThis paper aims to demonstrate how the understanding of the reservoir extent, connectivity, facies as well as varying burial in a complex sub-salt context plays a role in determining the magnitude of overpressure in the inboard part of the Gulf of Mexico.
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Impact of Geologic Description on Pore Pressure and Well Design
By J. VillinskiSummaryThe combination of rapidly deposited sediments and compressional forces result in a highly complex pore pressure - fracture gradient profile for Caspian fields, with Shah Deniz as a type example. Changing horizontal stresses with depth and structural position and widely varying pressures in permeable layers require a sophisticated drilling and fluids engineering approach.
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Quantification of Uncertainties in Pore Pressure Prediction: Is there any one Best Practice?
By S. BordoloiSummaryUncertainties in pore pressure models arises due to a combination of various reasons: poor quality input data, challenging geological settings, dearth of sufficient predrill information, lack of geological understanding are some of the critical ones. Moreover, being a multi-disciplinary effort and in some cases due to a lack of sufficiently experienced resources - some of these challenges can get amplified. However, having an awareness regarding the effect of various geologic parameters on overpressure generation as well as its maintenance or dissipation through time plays a very critical role in influencing our overall interpretation of the ‘uncertainty envelope’. Many times it has been experienced that ‘knowing what we don’t know’ could be a key factor in how good we can quantify these uncertainties.
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Pore-pressure Prediction Using Multiresolution Analysis
By H. Al SalmiSummaryExisting pore-pressure methods are empirical or semi-empirical relations that predict pore-pressure in clastic rocks. However, these methods produce inaccurate results in carbonate rocks because the mechanism of pore-pressure generation in carbonate rocks is different from that in clastic rocks (Atashbari and Tingay, 2012). Pore-pressure variation causes small changes in the P-wave velocity of carbonate rock. In this work we present Pore-pressure prediction using frequency data from multi-resolution analysis.
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Dealing with the Uncertainty in the Prediction of Fracture Gradient
More LessSummaryIn Geomechanics for drilling engineering, there are two possible methods for predicting the FG: i) method based on the calculation of stress around the wellbore, ii) method using depth correlation established for a specific field from a set of leak-off pressure (LOP) data recorded on offset wells. In Total E&P, the method of calculating stress around the wellbore in order to predict the FG has been used and developed for a decade. It primarily consists of building and calibrating a ID MEM, using proprietary ID poro-mechanical earth model named PoroMEM. The calculation of the FG from the in situ stress model uses two conceptual models of fracturing: shear fracture and tensile fracture. From there, we define two limits for FG: one called FIPmax and the other FIPmin. Such conceptual models help to deal with the uncertainties of rock mechanical behavior because of vertical variability of lithology, help the preparation LOT/FIT during drilling operation, and also aid the interpretation of LOT/FIT. The in situ stress model from PoroMEM also provides the FCP gradient which is useful for well control and is sometimes as the FG. In this paper, we present the conceptual models and an example of FG prediction.
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Determination of the Fracture Pressure from CO2 Injection History
Authors B. Bohloli and L. GrandeSummaryFracture pressure of geological formations is a major controlling parameter for many engineering operations, such as drilling, water injection, CO2 geological sequestration and gas storage. Fracture pressure is usually obtained based on analytical calculations and/or interpretation of water injection tests. This paper presents an approach to determine the actual fracture pressure of a sandstone reservoir at In Salah, Algeria. The injection data were employed and plotted in various domains. In this way, the transition from matrix injection to fracture injection could be determined, which was not evident from initial analysis of injection data. Therefore, iterative analysis of injection data plays an important role in understanding the performance of a reservoir during the early stages of an injection project. Further analyses of data showed that fracture pressure of formation increased with time. This implies that fracture pressure is a dynamic parameter in reservoirs with limited permeability and may reflect the history of pore pressure development in the target formation.
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Reducing Uncertainty in Overpressure Prediction in the Norwegian Barents Sea
Authors G. Markham, S. O’Connor, P. Milstead and H. RasmussenSummaryPore pressure prediction in the Barents Sea is challenging for a variety of reasons including a complicated and variable burial history (leading to varying magnitudes and timings of burial, hiatus and uplift from well to well), variation in mudrock lithology and depositional environments. These factors can all create uncertainty when predicting pore pressure. Here are introduced two independent methodologies for present day shale pressure prediction across the Barents Sea, focussing in particular in the Southwestern Barents Sea where high overpressure is often recorded. Independent velocity log based and geological modelling based shale pressure prediction methods are used. Comparison of the two models generally shows good consistency in results, helping to validate the predictions and models and reduce uncertainty. This reinforces the need to integrate multiple techniques in order to reduce uncertainty in what is a challenging area for pore pressure prediction. The results also show that understanding the complex and variable burial history in each well is vital for pore pressure prediction, as this history defines the present day pressures. The models developed have clear implications for design of wells in the Barents Sea, and are also important for understanding reservoir overpressure variation (and potential reservoir fluid flow).
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Alternate Ways to Determine Pore Pressure Information: A Multi-Pronged Approach Enhances Conventional Real-Time Techniques
More LessSummaryA conventional pore pressure prediction workflow bases the prejob model on surface seismic data, assumes under-compaction is the primary pressure mechanism and that changes in pore pressure can be monitored while drilling using available log measurements. This workflow can perform well in the conditions where it applies but it is limited in that it ignores many other sources of information that can tell the analyst something about the current pore pressure regime to help constrain the uncertainties in the model and that can work in situations that are not caused by under-compaction alone. A more comprehensive approach considers the response of any available source of information while drilling that could be affected by changes in pore pressure. These include event gas peaks and their component ratios, annular pressure profiles, cavings analysis and the multitude of drilling parameters available at the wellsite. These can help the analyst determine if the well is under-balance or ballooning and can provide indications of pore pressure concerns before they may affect conventional log responses. The inclusion of these indicators in the analyst’s workflow can aid in managing risk and improve drilling safety.
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Managed Pressure Drilling for Pore Pressure Detection, Two Case Studies
Authors J.M. Jimenez, T. Harrold, P. Rouillé and G. SacedaSummaryThe oil industry is moving towards increasingly complex plays with challenging uncertainties and narrow drilling windows. To meet such a challenge Managed Pressure Drilling is increasingly being used to manage narrow pore pressure windows and drill deeper, higher pressure and higher temperature wells than was previously possible. At the same time the industry is facing stronger environmental and safety regulations that demand an improvement in risk characterization and pore pressure detection. While the new data from such techniques is valuable in constraining the pore pressure, it comes in new formats and often replaces or excludes some of traditional data such as connection gas that are normally used in real time pore pressure detection. Two cases are presented from two oil & gas exploratory wells in which the application of MPD (Managed pressure drilling) technique was critical for the success of the operation and where valuable pore pressure information was obtained to characterize and manage the drilling window. We conclude that MPD is an important tool in drilling wells with a narrow pore pressure and fracture gradient window. While MPD complicates some of the traditional methods of pore pressure estimation, it can be used proactively to get more accurate estimates.
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Managed Pressure Drilling (MPD) — A Help or Hindrance for Real-time Pressure Detection in Exploration Wells?
Authors T. In ‘t Veld-Brown, S. Petmecky and B. WagnerSummaryManaged pressure drilling (MPD) technology promises many advantages regarding pressure detection during well construction. This presentation describes recent experiences with a MPD system on a high pressure/high temperature (HPHT) exploration well.
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PP Follow-up While Drilling: Seeking a Pressure Transition Zone in a Back Arc Basin
Authors A. Isiakpere, M. Dougherty and B. BenazetSummaryPressure transition zones are often expected when reservoir and cap rock pressures are thought to be in pressure disequilibrium. This could be either a pressure drainage effect on the cap rock due to drained underlying reservoirs or a pressure increase in the cap rock due to higher pressured underlying reservoirs. However, these transition zones are rarely seen nor verified with available data. As a result, such transition zones are modelled based on concepts from the 3D geological model and connectivity / lack of connectivity with calibration points. The case study aims to show a pre-drill prediction model where the transition zone within the shale dominated cap rock (due to drainage effect from the underlying reservoirs) was critical in order to ensure the optimal placement of the 13-3/8” casing string.
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Integrating Geomechanics and Geochemistry to Quickly Estimate Pore Pressure near Salt Diapirs
Authors F. Ferrari, A. Consonni, E. Previde Massara and P. TemponeSummaryTraditional pore pressure prediction methods, which are based on seismic velocities, allow accounting for overpressure generated by compaction disequilibrium. Although several other sources of overpressure has been widely recognized, they are still poorly quantified. This abstract presents a workflow for quantifying the overpressure due to both the lateral strain exerted by a salt diapir and the clay diagenesis (smectite to illite transformation). The former is modelled using geomechanical analytical approach, based on the Geertsma method. The latter is instead derived from geochemical lab tests carried out on bottom-hole cores. The overpressures resulting from the three mechanisms (i.e., under-compaction, lateral strain and clay digenesis) have been superimposed to a post-drilling pore pressure interpretation. The sum of the calculated overpressure fits quite well with the pore pressure interpretation down to a certain depth, below which the considered mechanisms are not enough to fully justify the measured overpressures.
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Evidence of Extreme Overpressure Generated by Source Rock Maturation: Case Study, Deep-Offshore GOM, USA
Authors F. Poeymarie and T. RivesSummaryOnly very few overpressure prediction accounting for hydrocarbon generation processes are actually based on real well results and data. This paper will show a case study example where both compaction disequilibrium and hydrocarbon generation participate to the generation of overpressures. This case study was built using standard log derived method as well as drilling observations and well events.
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Pore Pressure at the Post-Salt Albian Carbonates in Santos and Campos Basins
SummaryThis work analyzes the pore pressure regimes in the Albian carbonates deposited above the salt layer at the Southeast Atlantic margin in Brazil. The study area consists in Santos Basin shallow waters and in Campos Basin deep waters. The settings are carbonate layers folded over anticlinal salt dome structures. An effort has been done to associate the wells pore pressure data with the carbonate layers structures interpreted from seismic sections. At each dome the Albian carbonate reservoirs are found at a local pore pressure regime either at normal or slight overpressure or at high overpressure. One possible way for a high pore pressure increase is lateral and vertical pore pressure transfer from a deeper interval down the flanks of the anticlinal dome structures. The pressure connection may be restricted just to the Albian or it may involve the pre-salt Aptian interval through salt windows around the domes. Another possible scenario for overpressure mechanism consists on oil or gas generation in the Albian. The prediction of the Albian carbonates pore pressure is necessary for well drilling design to both exploratory targets the post-salt and the pre-salt.
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Integrated Pore Pressure Prediction with 3D Basin Modeling
Authors Z. Nagy, M.K. Baracza and N.P. SzaboSummaryBasin scale examination of pressure conditions is important from many aspects. On one hand well planning requires the understanding of the pressure regime, on the other hand abnormal pressure conditions could affect the behavior of the petroleum system. The upper boundary of the overpressured zone was identified on wireline logs. Comparison of the pressure trends with the lithology sensitive logs suggested that the overpressure generation relates to shaly strata. Two sedimentary environments were formed during the Late Miocene sedimentation cycle where shale rich sediments were deposited: delta slope and foreground of turbidite systems.
As the formation of abnormal pressure regime relates to low permeability sediments the main overpressure generation mechanism might be the non-equilibrium compaction. This theory is confirmed by the well log signatures of these sections. Beside the non-equilibrium compaction at least two other mechanisms could improve the overpressure, i.e., clay mineral transformation and lateral transfer. The basin modeling is an alternative methodology for the pressure regime investigation. A 3D basin model was built to test the technique. This approach allowed to investigate the effect of the lateral transfer and the hydrocarbon generation too. Furthermore, information about the timeframe of the overpressure emergence was gained.
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Pore Pressure Prediction in HPHT Wells
By Y. GorbunovSummaryPore pressure prediction has been a vital concern to the oil and gas industry for many decades. Most petroleum provinces exhibit overpressures, and as the industry explores for deeper targets, encountering substantial overpressures are becoming more common. As deeper, hotter and more complex geology is drilled, the technical difficulties in predicting pressure, designing a well and safely drilling through complex overpressures. This specially caused by multiple mechanisms in “wildcat” settings have become extremely challenging and require innovative technique to be utilized. Several of the recentiy drilled wells encountered strongly over-pressured intervals which caused operational challenges and required finetuning of the pre-drill models based on the real time data.
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Minimum Stress Trends in Stacked Mass Transport Deposits, Deepwater Guyana
Authors T. Fitts, S. Hoffmann, S. Karner and M. SundbergSummaryIn pressure predictions for early Stabroek exploration wells, minimum stress was calculated using the Terzaghi soil mechanics method (Matthews and Kelly, 1967) and a standard range of effective stress ratios according to Shmin=K0(Sv-Pp)+Pp, where Shmin is minimum stress, Sv is the overburden, PP is the pore fluid pressure and K0 is the effective stress ratio. These calculated profiles were compared to minimum stress estimates obtained from leak-off tests, pressure integrity tests, and lost return events. In several cases, the well data suggested significantly higher minimum stresses than predicted, with most tests in the deeper MTDs approaching the estimated overburden stress. To address the applicability of these estimates for minimum stress to future well planning, several interpreted mechanisms for these elevated stresses were proposed and investigated.
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PPFG Prediction in Complex Tectonic Settings: The North Alpine Thrust Front and Foreland Basin, SE Germany
Authors M. Drews and H. StollhofenSummaryEstimation of pore and fracture pressures in complex tectonic settings, such as fold-and-thrust belts and their adjacent foreland basins, is usually challenging and often requires local calibration. The Cenozoic North Alpine Thrust Front and Foreland Basin in SE Germany provide an interesting and challenging example for such a complex system, comprising overpressured sections in the thrust belt, the overthrusted foreland sediments below the main detachment and the undeformed foreland basin. Based on the synthesis of recent research in the study area and new analyses of additional well data from the thrust front, pore and fracture pressure models will be presented for the different parts of the North Alpine Thrust Front and Foreland Basin in SE Germany. The results demonstrate, that understanding of the geological history, stress regime variations and overpressure generation are key to estimate pore and fracture pressures in complex tectonic settings, such as the North Alpine Thrust Front and Foreland Basin in SE Germany.
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Identification of Two Loading Trends in Offshore Nile Delta, and the Implication on Pore Pressure Risking
By T. SinclairSummaryAnalysis of offset wells in WDDM offshore Nile Delta, Egypt shows that there are two identifiable loading trends differentiating the Plio-Pleistocene from the Miocene mudstones. These two trends represent a secondary pore pressure mechanism beibg active in the basin with an unloading trend being observed in one of the offset wells showing the transitional phase.
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FES Pressure Prediction Workflow Coupling Velocities with Geomechanical Modeling
Authors M. Nikolinakou, M. Heidari, P. Flemings, A. Bere and J. KatoSummaryWe evaluate the FES pressure prediction workflow using results from an evolutionary transient geomechanical model. The FES workflow couples velocities with geomechanical modeling to incorporate the effects of both mean and shear stress to pressure generation. The FES method predicts pore pressure and the full stress tensor. Because the FES workflow is iterative and requires data available on different grids (e.g., velocity vs. geomechanical results), we have developed a new tool in Horizon/Elfen to streamline the prediction process. In order to evaluate the workflow, we consider the end stage of the evolutionary model as the real basin. We use the geometry to build a static model. We use the evolutionary porosity field to calculate our real velocity field. We apply the VES method using this velocity field and the FES method using the velocity field and the static model. We find that the FES method predicts pressure values closer to the real basin pressures and performs better near a source-layer weld, where both mean and shear are non-uniaxial.
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From Well to Basin Scale Pore Pressure Prediction - Using the Full Potential of Seismic Velocities
Authors A. Isiakpere, M. Juilla, L. Sirgue and B. BenazetSummaryThis paper aims at demonstrating how we may account for variability of the spatial distribution of sediment loading rates to establish a continuum between offset wells and the prediction area. We will show how this information may be used, along with seismic velocities, either in 2D or 3D, to provide beyond the desired to-be-drilled location, an understanding of the spatial evolution of pressure at the basin scale accounting for spatial variation of burial history.
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3D Pore Pressure and Geomechanics: Work Smarter and Faster Integrating Geoscience with Machine Learning
Authors S. Green and E. Zabihi NaeiniSummaryIn unconventional plays, given the comparatively short drilling times and the likelihood that operators have multiple active rigs, wells are drilled and data are acquired at an unprecedented rate whereby a new well is completed every 1–2 days at a cost of $6–9M per well. Therefore, performing manual workflows for petrophysics, pore pressure and geomechanics prediction can be impractical due to turnaround considerations and the multiple personnel required. This, together with technical challenges of complex stratigraphy, multiple facies, variable rock properties, and the interaction of pore pressure and geomechanics, calls for more consistent, sophisticated, and faster analytical tools. A supervised deep neural network approach is presented as an innovative tool to devise solutions which simultaneously integrate myriad data types. Furthermore, an algorithm was developed to predict a certain number of attributes solely from a facies-based seismic inversion, namely Vp, Vs, and Rho. The application of these algorithms on various blind wells from a Permian Basin case study, both within and outside the seismic survey, shows a reasonable accuracy when compared to manually interpreted counterparts but were obtained in a fraction of the time, hence, provide a promising outlook for the application of deep learning in integrated studies.
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2D vs 3D Geomechanical Modelling Comparison to Influence Pore Pressure and Fracture Gradient Analysis
SummaryGeomechanical modeling can be an important tool in constraining pore pressure and fracture gradients in exploration wells, especially in areas of salt tectonics. Full 3D modeling can be time consuming and impractical for planning so knowing that 2D modeling can achieve similar results can be significant. We predict the stress and strain description around a salt structure from the West African Coast using a 3D static geomechanical model and compare the results to a 2D model. The 3D model uses the present-day basin geometry and a series of inputs (pore pressure, material properties assuming poro-elastic behavior for sediments and visco-plastic behavior for salt, boundary constraints and initial vertical to horizontal effective stress ratios). The 2D model uses geometry from the 3D model and the same input parameters. Both models predict similar sediment and salt displacements and stress ratio reduction above the salt structure although the displacements and stress ratio reduction are larger in the 2D model. The results of our analysis indicate that 2D geomechanical models, if selected correctly, can represent more complex 3D geometries. In addition, less computationally expensive 2D model allow a more complete sensitivity analysis and the identification of the mechanism of stress / pore pressure reduction.
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RhoVe T Method Empirical Velocity-Density-Temperature-Effective Stress Transform
By M. CzerniakSummaryThe rhob-velocity-effective stress (RhoVe) method represents an empirical approach to pore pressure analysis and calibration that utilizes a series of model-driven, genetically-linked “virtual” rock property relationships. The method is fundamentally a two-parameter approach (a-term and α), that is used to construct a velocity-vertical effective stress (VES) and density-VES family of curves that can be applied to a well of interest where convergence of the two transformed properties offers a robust solution. Once calibrated, the construct represents a fully-populated” petrophysical (shale-only) model volume that can be queried and interrogated to perform advanced calculations leading to a new empirical approach for calculating pore pressure from temperature that both frames the structural-stratigraphic history of fine-grained clastics in a sub-regional setting and allows for an interpretation of local diagenetic effects. The method utilizes a single master power law relationship between temperature and α’ that is applied as an instantaneous series. The same temperature — α’ power law function transforms sonic and density data for the entire stratigraphic section. Accounting for the effects of ongoing chemical compaction and diagenesis using alternate associations like temperature extends the predictability of high-velocity, high-density, low-effective
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Uncertainty Modelling of Minimum Horizontal Stresses and Porepressures in Deeply Buried Grabens. What’s Next in Modelling?
Authors A.E. Lothe, A. Grover, O. Roli, G. Leirdal and T. Golder KristiansenSummaryThree-dimensional pore pressure modelling over geological time scale has been carried out for a deeply buried possible reservoir in the Vana and Volve Sub-Basin, Viking Graben. The magnitude of the minimum horizontal stresses has been varied, and the input stress gradient has been calibrated with observed Leak-Off Tests. The simulation results show varying misfit to observed overpressures in different wells. The methodology can in future be used with a Monte-Carlo approach.
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