Pore Pressure Profile Research Articles

Optimizing Deep Geothermal Drilling for Energy Sustainability in the Appalachian Basin

This study investigates the geological and geomechanical characteristics of the MIP 1S geothermal well in the Appalachian Basin to optimize drilling and address the wellbore stability issues encountered. Data from well logs, sidewall core analysis, and injection tests were used to derive elastic and rock strength properties, as well as stress and pore pressure profiles. A robust 1D-geomechanical model was developed and validated, correlating strongly with wellbore instability observations. This revealed significant wellbore breakout, widening the diameter from 12 ¼ inches to over 16 inches. Advanced technologies like Cerebro Force™ In-Bit Sensing were used to monitor drilling performance with high accuracy. This technology tracks critical metrics such as bit acceleration, vibration in the x, y, and z directions, Gyro RPM, stick-slip indicators, and bending on the bit. Cerebro Force™ readings identified hole drag caused by poor hole conditions, including friction between the drill string and wellbore walls and the presence of cuttings or debris. This led to higher torque and weight on bit (WOB) readings at the surface compared to downhole measurements, affecting drilling efficiency and wellbore stability. Optimal drilling parameters for future deep geothermal wells were determined based on these findings.

Fluid effects in model granular flows

Pore fluid plays a crucial role in many granular flows, especially those in geophysical settings. However, the transition in behaviour between dry flows and fully saturated flows and the underlying physics that relate to this are poorly understood. In this paper, we report the results of small-scale flume experiments using monodisperse granular particles with varying water content and volume in which the basal pore pressure, total pressure, flow height and velocity profile were measured at a section. We compare the results with theoretical profiles for granular flow and with flow regimes based on dimensional analysis. The runout and the centre of mass were also calculated from the deposit surface profiles. As the initial water content by mass was increased from zero to around 10%, we first observed a drop in mobility by approximately 50%, as surface tension caused cohesive behaviour due to matric suction. As the water content was further increased up to 45%, the mobility also increased dramatically, with increased flow velocity up to 50%, increased runout distance up to 240% and reduced travel angle by up to 10° compared to the dry case. These effects can be directly related to the basal pore pressure, with both negative pressures and positive pore pressures being measured relative to atmospheric during the unsteady flow. We find that the initial flow volume plays a role in the development of relative pore pressure, such that, at a fixed relative water content, larger flows exhibit greater positive pore pressures, greater velocities and greater relative runout distances. This aligns with many other granular experiments and field observations. Our findings suggest that the fundamental role of the pore fluid is to reduce frictional contact forces between grains thus increasing flow velocity and bulk mobility. While this can occur by the development of excess pore pressure, it can also occur where the positive pore pressure is not in excess of hydrostatic, as shown here, since buoyancy and lubrication alone will reduce frictional forces.Graphical abstract

Overpressure characteristics and geological origin of the paleogene in Baiyun Sag, Pearl River Mouth Basin

The accurate understanding of the origin of overpressure is the basis of formation pressure research and the core work of determining the distribution of formation pore pressure in drilling design. The deep water area of Baiyun Sag in the Pearl River Mouth Basin in the northern margin of the South China Sea has been proved to be a hydrocarbon rich depression. In recent years, overpressure has been encountered in the middle and deep layers, but the geological origin of the overpressure in the deep water area are still unclear. Therefore, the pore pressure profile of the Baiyun Sag was evaluated using the data of drilling and seismic velocity, and the relationship between overpressure and the generation mechanism was established. Most of the surrounding and shallow strata of Baiyun Sag show normal pressure, while the middle and deep strata generally show overpressure, with the maximum pressure coefficient up to 1.55. The overpressure zone mainly develops from the middle of Zhujiang Formation to the upper member of Enping Formation. The mudstone resistivity and density values of the two typical Wells deviated from the normal trend. The density showed a constant trend with the increase of depth, while the resistivity showed a certain degree of reversal. The upper layer of the overpressure zone showed abnormally high resistivity values, corresponding to the overgland and transition zone formed by high carbonate content. There is no obvious increase of porosity in the overpressured sandstone strata of Baiyun sag, which does not have the characteristics of undercompaction. The velocity in the overpressure section of the two Wells varies greatly, and the density is basically unchanged or slightly decreased. It is concluded that the overpressure is caused by fluid expansion from hydrocarbon-generation. The large-scale and long-term fluid expansion caused by hydrocarbon generation and expulsion of source rocks provides the power source for the formation of overpressure in Baiyun sag. The distribution of effective source rocks has a controlling effect on the distribution range of overpressure. The tight sandstone strata in the Zhuhai, Wenchang and Enping formations become the cover layer of the overpressure system in the longitudinal direction.

A multi-proxy approach to detect the pore pressure and the origin of overpressure in sedimentary basins: An example from the Gulf of Suez rift basin

The pore pressure gradient and fracture gradient (PPFG) are critical parameters for drilling mud weight design in the energy industry. Successful drilling operations can be achieved successfully through the understanding of the pore pressure and fracture pressure in the subsurface succession. The scope of this research is to use an integrated approach that encompasses well-logging, basin modeling, drilling-based interpretations, and reservoir measurement methods to gain a reasonable PPFG model and decrease the drilling uncertainties in the El Morgan oil field in the Gulf of Suez. Moreover, it investigates the overpressure generation mechanisms in the basin, which have not been studied before in this area. In this work, PPFGs of more than 16 km of cumulative thick sedimentary succession were modeled and evaluated using an integrated approach. This study utilizes Eaton’s sonic and resistivity-based methods for pore pressure evaluation, while vertical stress was calculated based on the composite density profile. The study revealed that the top geo-pressure was detected at a depth of 1,030 m of Tortonian sediments. Late Miocene sediments reveal hard over-pressure with a maximum gradient of 0.55 PSI/feet, while Middle Miocene sediments exhibit mildly over-pressured, normal, and sub-normal pore pressure zones. The lowest pore pressure values were measured in the Langhian-Serravalian Kareem reservoir with a gradient of 0.29 PSI/feet. With the exception of a slight difference in the reservoir section, the pore pressure profiles in the northern and southern parts of the El Morgan oil field are relatively similar. Reservoir connectivity is believed to be the main reason behind pore pressure magnitude differentiation in the Middle Miocene reservoirs. The key mechanism for generating overpressure has been identified as disequilibrium compaction, and reservoir overcharging may contribute as an excess-pressure generation mechanism at the reservoir level. The presented approach can be applied in PPFG studies for both development and exploratory geomechanical studies in other areas of the Gulf of Suez basin or elsewhere in the world.

Prediction of hydraulic conductivity parameters of slurries from centrifuge consolidation settlements

Slurry materials such as mine tailings and dredged clays undergo large, self-weight consolidation settlements. Compressibility and hydraulic conductivity characteristics of such slurries are essential for the estimation of their settlements and settlement rates for the safe maintenance of the storage facilities. These two constitutive functions of slurry materials are frequently estimated from laborious large-strain consolidation tests. Centrifuge consolidations tests are receiving great attention, therefore, to circumvent the time-consuming consolidation tests in the 1 g environment. However, the inverse analysis of settlement–time data for the estimation of compressibility and hydraulic conductivity functions is computationally expensive due to the requirement of a large number of forward analyses and thus is not available yet for the centrifuge environment. In this work, for the first time, two existing back analysis procedures for 1 g column tests were explored for predicting the hydraulic conductivity parameters of several slurry materials from the centrifuge test data. These procedures require well-defined and time-invariant compressibility functions of the slurry materials. These methods need only time–settlement data from a single centrifuge test, and do not depend on the excess pore pressure profiles. A finite difference solution of the analytical model for finite strain consolidation behavior of samples in centrifuge environment was utilized for the forward analysis. Four simulated synthetic temporal settlement curves and four centrifuge consolidation test data from the literature were utilized for validation of the studied methods. The methods were simple, computationally inexpensive due to the requirement of only a smaller number of forward analyses, and effective in accurately predicting the hydraulic conductivity constitutive parameters.

How to Improve Accuracy of a Kick Tolerance Model by Considering the Effects of Kick Classification, Frictional Losses, Pore Pressure Profile, and Influx Temperature

Summary Kick tolerance (KT) calculation is essential for a cost-effective well design and safe drilling operations. While most exploration and production operators have a similar definition of KT, the calculation is not consistent because of different assumptions that are made and the computational power of KT calculators. Dynamic multiphase drilling simulators usually provide KT estimates with a minimum number of assumptions. They are much more accessible nowadays for use in predicting the behavior of multiphase flow in drilling and well control operations. However, as far as we observed, the simulation services are mainly used for complex and marginal wells in which low KT may impose additional casing strings, unconventional costly drilling practices, or a high risk of major well control events. Thus, companies often use simplified steady-state models for relatively uncomplicated wells through their own KT calculation worksheets. This practice is usually justified by the misconception that simplified models are always conservative and give less KT than actual conditions. In contrast, some simplifications may lead to higher operational risks due to an overestimated KT, depending on well conditions and parameters. The primary objective of this work was to perform a quality assurance/quality control on KT calculation practices in Company P. Later on, based on our findings, we determined some solutions to improve accuracy in the simplified KT worksheets commonly used by engineers across the company. This became a driver for generating a new KT worksheet (Company Model), in particular for situations in which engineers do not have access to a kick simulator. However, it should not mislead readers about the requirements of the simulator for complex and low-KT wells. Quality assurance/quality control and subsequent investigations found that there are some important criteria and parameters that affect KT calculations, but they are missing in many simplified models or ignored by engineers because they are unaware of or lack adequate references. After reviewing relevant academic literature, common practices and assessing several off-the-shelf software programs, we generated a computer program using Visual Basic for applications to address KT sensitivity to different parameters in steady-state conditions. The newly developed program is based on a single gas bubble model that applies the effect of annular frictional losses, influx temperature, gas compressibility factor, well trajectory, and bottomhole assembly (BHA). Moreover, the program differentiates between swabbing and underbalanced conditions. A logical test is applied to determine the type of kick before computing the relevant influx volume. This kick classification concept is ignored in many KT models; this is a common mistake that leads to misleading results. The annular pressure loss (APL) parameter is sometimes assumed to be zero in KT spreadsheets, while as an additional stress load on the wellbore, it affects the kick budget and must be considered.

Development of one dimensional geomechanical model for a tight gas reservoir

Estimating rock-mechanical, petrophysical properties and pre-production stress state is essential for effective reservoir planning, development, and optimal exploitation. This paper attempts to construct a comprehensive one-dimensional mechanical earth model (1D MEM) of the Mandapeta gas reservoir of Krishna Godavari (KG) basin, India. The methodology comprises a detailed stepwise process from processing and analysis of raw log data, calibration of log-derived dynamic properties with static ones using regression models developed from tested core samples, and final rock mechanical property estimation. Pore pressure profiles have been estimated and calibrated with the Repeat formation tester (RFT) data for every thirty-five wells. Overburden and horizontal stresses have also been evaluated and calibrated using data from the Leak-off Tests (LOT) or Extended Leak-off Tests (XLOT). A menu-driven program is developed using PYTHON code for visualization and on-time revision of 1D MEM. The resulting comprehensive 1D MEM predicts and establishes the rock-mechanical properties, pore pressure, and in-situ stress values of the basin. Besides its use in planning future wells, development of the field, and yielding insight into the various well challenges, it can also be used to develop a 3D MEM of the reservoir.

3D Geomechanics Characterization in V Field

Upstream oil & gas operators faced many challenges in drilling activities during a field development phase where the reservoir pressure depletion might disturb the stresses equilibrium in the formation and triggered stress redistribution in the reservoir and its surrounding rocks. These changes could lead into more problematic drilling experiences such as the narrowing of safe drilling mud weight windows and potential operating losses due to related wellbore instability issues. 3D Geomechanics analysis conducted to identify the stress redistribution and predict the field wellbore instabilities behaviour that honour the geological features in the area. The 1 D Geomechanics model is created for offset wells which consist of rock strength and elastic properties, pore pressure and stresses profiles. Seismic inversion volume is used to populate the properties in the 3D static model and field Geomechanics simulation conducted to obtain the field stresses profile. V field data is used as the data available in this field is complete to support this study (wire-line logs, petrophysical interpretations, VSP, core analysis, production log, drilling reports, and the seismic velocity cube). The results of the integrated reservoir Geomechanics characterization with seismic inversion managed to predict the wellbore instabilities model in the offset wells.

Improving drilling speed and borehole quality in ultra-deep complex formations through rock mechanics research

Halahatang oilfield in Tarim Basin is a typical ultra deep fractured vuggy carbonate reservoir, which is the main production area of crude oil in Tarim Basin. The wellbore instability is serious in Triassic and lower strata (the borehole enlargement rate is 22% - 31%). Due to the complex rock characteristics, the drilling cycle for single well is long (124 days on average), and it is difficult to speed up. Based on the log interpretation curves, the calculation methods of pore pressure, collapse pressure and fracture pressure profiles established, and the spatial distribution characteristics of three pressures in this area were analysed; The rock drillability, rock hardness, compressive strength and abrasiveness of the roller bit and PDC bit single well measured by laboratory tests. Based on the statistical regression method, the relationship between the above drilling rock mechanical parameters and logging acoustic time difference and the formation drillability profile single were studied. The research results guide the drilling design optimization and operation of 15 wells in Ha 8 and Ha 12 blocks, The average drilling cycle is reduced by 21% (from 124 days to 98 days), and the hole enlargement rate is reduced from 24% to less than 10%.

Present-day overpressure in southern Tunisia: Characterization, possible causes and implications for drilling operations

Formation pore pressure in sedimentary basins is known to vary with depth. These variations are caused by one or more sedimentary, tectonic or diagenetic mechanisms. In Mesozoic basins of southern Tunisia, a detailed study has been carried out in order to characterize the regional pore pressure profile. The results show an over-pressure interval ranging from upper Triassic to lower Jurassic salts series.The study of possible overpressure mechanisms allows us to conclude that the present-day overpressure can be explained by the active compressional tectonics that is affecting the North African margin. Nevertheless, other past overpressures have been interpreted from this study and have been attributed to different mechanisms. One of the most important paleo-overpressure mechanisms was gypsum dehydration. This diagenetic reaction has led to pore pressure approaching lithostatic pressure, demonstrated by hydraulic fractures and beef veins observed in fields.In this study, we established a method based on a depth chart diagram enabling the identification of the likely mechanism involved in reservoir overpressure build-up and/or the prediction of a potential mechanism. This result could be important in the analysis of unexplored basins to predict the anticipated pressure profile and thereby reduce the risk of encountering unexpected overpressured zones and related drilling hazards. This method could be applied to other sedimentary basins with standard geological backgrounds.

Experimental Study of the Effect of Solvent Addition and Temperature on Two-Phase Bitumen/Water Relative Permeability

Summary The expanding solvent-steam-assisted gravity drainage (ES-SAGD) is a newly proposed thermal recovery technique showing promising efficiency in terms of a smaller steam-to-oil ratio and greater production rate to recover heavy oils and bitumen from oil-bearing formations, where a solvent is coinjected with the steam in the SAGD process. Numerical simulation of the ES-SAGD process requires reliable relative permeability data. The number of reported measurements of relative permeability involving bitumen systems is limited in the literature, mostly because of the experimental difficulties involved in such measurements. The relative permeability data sets for Canadian bitumen, in the presence of solvents, are simply not available in the open literature. The fluid-flow behavior of bitumen/water systems in the presence of solvent is an important matter that must be assessed before the implementation of any ES-SAGD process; therefore, the objective of the current study is to evaluate the impact of a light hydrocarbon solvent (n-hexane) on bitumen/water relative permeability under SAGD conditions. For this purpose, two-phase bitumen/water relative-permeability measurements were conducted in sandpacks over a wide range of temperatures from 70°C to 220°C using Athabasca bitumen, deionized water, and a light hydrocarbon solvent. A well-instrumented experimental setup was developed to perform the relative permeability measurements with the capability of applying confining pressure on the sand and measuring the pore-pressure profile with several intermediate pressure taps. Isothermal oil-displacement tests were carried out with solvent premixed with bitumen. The history-matching approach and Johnson-Bossler-Naumann (JBN) method were used to translate the oil displacement data into the relative-permeability curves. The results obtained with a solvent from this study and without any solvent reported in our previous study are compared to assess the solvent's impact on relative permeability. In addition, the steady-state relative permeability was measured to assess the reliability of unsteady-state relative permeability. The interfacial tension (IFT) and contact-angle measurements using the same fluids were carried out to determine the fluid/fluid interaction and wettability state of the system under high-pressure/high-temperature (HP/HT) conditions. The results of the present study confirmed that the two-phase diluted bitumen/water relative permeability is sensitive to temperature, especially in terms of the endpoint relative permeability to bitumen and water. Furthermore, adding normal hexane (below the asphaltene precipitation threshold) not only improves the displacement efficiency of water flooding because of the significant decrease in oil viscosity but also modifies the wettability and IFT of this system. At the same temperature, the two-phase oil/water relative permeability for bitumen/water systems is significantly different when the oil is diluted with the solvent. Also, the impact of solvent is more pronounced at lower temperatures. Furthermore, the consistency between the steady-state and unsteady-state relative permeability data proved that the effect of viscous fingering was small enough.

Landslide hazard assessment by smoothed particle hydrodynamics with spatially variable soil properties and statistical rainfall distribution

Rainfall-induced landslides have caused significant damage to structures and casualties in the past decades, and it is of great importance to assess the post-failure behavior of slopes. This study proposes a probabilistic framework to evaluate the hazards associated with landslide runout arising from loose-fill slope failures. The failure process is simulated by the smoothed particle hydrodynamics (SPH) method, which is capable of capturing large deformations of landslides. The shear strength parameters of the soils are modeled as random variables, and random field simulations are performed to explore the effects of soil variability on the runout distance. In addition, the uncertainty in rainfall characteristics is represented by the Gumbel distribution, with the ensuing rainfall infiltration simulated in multiple seepage analyses to obtain pore pressure profiles in the slope, which are then adopted as initial conditions for the SPH method. Combining these various sources of uncertainty, the hazard factors indicating the risks for nearby structures are quantified based on the response uncertainty in landslide runout distances. To demonstrate this framework, the hazard levels associated with two typical layouts of loose-fill slopes are evaluated, and the results may serve as risk zoning indicators for adjacent developments.

Analytical solution for one-dimensional electro-osmotic consolidation of double–layered system

Abstract Electro-osmotic consolidation can be used as a valid and innovative technique for ground improvement. Considering the limitation of previous studies that layered soil heterogeneity was not taken into account, this paper presented an analytical model for one-dimensional(1D) electro-osmotic consolidation of double-layered soil, and a computer program of fully explicit solutions for excess pore pressure and degree of consolidation was developed. In order to validate its accuracy, a series of verification examples were conducted using analytical approach and the finite difference method. Comparison results demonstrated excellent accuracy of the proposed solutions. Furthermore, parametric studies were conducted to investigate the influence of relative permeability and compressibility relationship on the consolidation behavior. It can be found that the differences of hydraulic conductivities and electro-osmosis conductivities in the two layers will lead to a sharp change of the excess pore pressure profiles at the interface of two layers. A larger value of coefficient of volume compressibility in the second layer will slow down the dissipation process of excess pore pressure. A thicker layer with higher compressibility will result in a slower the rate of dissipation of the excess pore pressure, and a thicker layer with higher permeability causes a smaller value of the excess pore pressure, while in the layer of lower permeability, the opposite occurs.

Digitized Uncertainty Handling of Pore Pressure and Mud-Weight Window Ahead of Bit: North Sea Example

SummaryA digitized workflow from predrill pore-pressure modeling with a Monte Carlo approach until update of the pressure prognosis while drilling from (for example) sonic or resistivity data is described. The approach has the potential to reduce the uncertainty in the predicted mud-weight window ahead of the bit.For the 3D pressure modeling, a basin modeling software is used, where the pressure compartments in the study area are defined by faults interpreted from seismic. Pressure generation and dissipation are calculated for the study area over millions of years, as the basin was subsiding and compaction was taking place. Key input parameters such as minimum horizontal stress, vertical stress, and frictional coefficients for failure criteria are varied. The output is pore-pressure profiles along the planned well path, with uncertainties.The work presented in this paper was carried out on a North Sea data set. The results show that the uncertainty in the pore pressures will highly influence the uncertainty span in both the fracture gradient and the collapse gradient. Representing the mud-weight window in terms of the most likely collapse and fracturing curve, with corresponding minimum and maximum pore-pressure-derived limits on each side, makes for a more realistic prediction. It presents the uncertainty in the result in a simple visual form, using a “traffic light” approach.While drilling, log data will automatically be used to update the pressure and mud-weight prognosis ahead of bit. The digital updated prognosis can help the drilling crew in decision making during drilling campaigns.

Geopressure evaluation using integrated basin modelling, well-logging and reservoir data analysis in the northern part of the Badri oil field, Gulf of Suez, Egypt

The evaluation of pore and fracture pressures represents the gist of well planning and execution in drilling operation and exploration, where accurate pore and fracture pressures modelling enables the oil and gas companies to drill targets safely. The scope of this paper is to evaluate pore and fracture pressures in the northern part of the Badri Field, in the Gulf of Suez, Egypt to determine the convenient pore pressure fracture gradient model (PPFG) and to define the pore pressure regime in the subsurface within the Zeit, South Gharib, Belayim and Kareem formations from the top downwards.The pore pressure and fracture gradient model has been assessed using integrated data that include: burial history, well logs (sonic, resistivity and density), offset wells drilling problems, and reservoir pressure. The Amoco overburden equation and Eaton's sonic and resistivity methods were used to estimate the overburden stress and the pore pressure values respectively, while fracture pressure was calculated using the Eaton method. Results show that the maximum pore pressures is in the South Gharib Formation and the lowest pore pressure is within the reservoir sections. Six abnormal pressure zones were detected, these includes four overpressure zones and two sub-normal pressure zones, where the maximum estimated pore pressure was up to 10.5 pound per gallon (ppg) equivalent gradient, which was recorded in the South Gharib Formation. While the minimum measured pore pressure value was recorded at 4.7 (ppg) in the Kareem sandstone reservoir. The fracture gradient ranged between 11.5 and 13.1 (ppg) equivalent density for both the Belayim (Hammam Faraun Member) and Kareem sandstone reservoirs.The main conclusions of this study are, 1) the pore pressure profile is normal, sub-normal and over-pressurized in the study area, 2) the integration of basin modelling, well-logging, drilling problems and direct measurements allow us to evaluate the geopressures in the subsurface horizons, 3) the use of low mud density while drilling into the depleted reservoir zones is the best solution for fluid losses mitigation, 4) the modified surface, intermediate and production casing seats is adequate for the future planned wells profile. 5) providing insights on downhole pressure behavior across stratigraphy in the area of study, to achieve optimum drilling mud designing and adequate casing seats as well as safe and successful operational planning.

Pore Pressure Prediction in Onshore West Niger Delta Using Inverted Seismic Velocity and Derived Velocity (Vp) - Vertical Effective Stress (VES) Coefficients

In this study, pore pressure has been predicted using seismic data and derived compressional wave velocity (V p ) - Vertical Effective Stress (VES) coefficients. Post Stack Time Migration (PSTM), angle stack gathers, seismic horizons, checkshot, wireline logs, drilling and pressure data from six wells in the Onshore West Niger Delta, Nigeria were analysed and interpreted. Using generated velocity and density crossplots, the active overpressure generating mechanisms for the studied area were deduced. The V p -VES coefficients were modelled using the direct pressure data and the overburden profile computed from density log. Post stack seismic inversion was performed to improve the seismic resolution as well as derive acoustic impedance using well velocities and stacking velocities from velocity analysis of the 3-D seismic data. The derived V p -VES coefficients were used to transform the seismic acoustic impedance velocity into seismic pore pressure volume. Pore pressure profiles were accordingly extracted along well paths so as to test the accuracy of the model. Interpreted density-velocity crossplots revealed a decrease in velocity at constant density of 2.4 g/cc, an indication that unloading mechanisms contribute to overpressure in the field. The Bowers’ V p -VES coefficients of 7.43 and 0.77 were determined for A and B parameters respectively. Based on the results obtained, the top of overpressure occurred at a depth of 3750 ft and 3800 ft in UMO-001 and UMO-002 wells respectively with a corresponding average pore pressure gradient of 0.47 psi/ft for both wells, indicating that the wells are mildly overpressured. Onsets of unloading were observed in UMO-001 and UMO-002 wells at depths of 6250 ft and 6800 ft with pore pressure gradients of 0.51 psi/ft and 0.60 psi/ft respectively. The Derived Seismic Pore Pressure (DSPP) matched the measured pressure value (kick) of 5300 psi at a depth of 7450 ft and this validated and further increased confidence on the values of the V p -VES coefficients derived. These results show that the derived seismic acoustic impedance volume, vertical effective stress and overburden model produce high resolution seismic pore pressure cube in both time and space. The derived models when applied especially, with seismic acoustic impedance volume can be used to plan and drill future wells with great successes in the studied area. Keywords: pore pressure, vertical effective stress, seismic velocity, acoustic impedance DOI : 10.7176/JEES/9-10-07 Publication date :October 31 st 2019

Technology Focus: Offshore Drilling and Completion (October 2019)

Technology Focus Measured-pressure approaches (drilling, cementing, and completions) have offered much promise for some time but have been slow to reach widespread application. A spate of technical developments, deployments, trials, and applications, however, recently has pushed measured-pressure drilling (MPD) and its nuanced variants to their full potential as viable well-construction methods. Development of fully integrated drilling, control, and management systems, along with surveillance and data-processing enhancements, have brought the idea of fully functional real-time measured-pressure management to reality. Increasing experience, design feed-back, validation, and enhancements are making a number of derivatives of the approach widely applicable. As well as the drilling operations themselves, experience has increased to include all aspects of the well-construction process, including both cementing and completion running operations. Increasing equipment automation and surveillance and control systems is now providing confidence and accuracy with well-calibrated models of in-situ behavior. Additionally, the real-time management of operations creates a feedback loop that allows continuous improvement to be at the heart of execution and learning. As broader industry experience and case history volume increases, the ability to deploy and use these approaches will provide additional flexibility to operators as they develop increasingly challenging formations and tight or complex pore-pressure fracture-gradient profiles and windows. Measured-pressure techniques and variants now appear to be coming of age, and wider application will continue to enhance and enrich their functionality. Continued automation, data management, and personnel training and experience will support the continued and increasing deployment of these approaches. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 194538 The Business Case for Use of Applied-Backpressure Managed-Pressure Drilling in Deepwater Gulf of Mexico by Sharief Moghazy, Shell, et al. SPE/IADC 194541 Acoustic Telemetry Network Provides Real-Time Downhole Data Transmission During Drilling, Cementing, and Completion Installation for Use in Depleted Reservoirs and During Managed-Pressure Operations by Andy Hawthorn, Baker Hughes, a GE company, et al. SPE/IADC 194554 Using Managed-Pressure Drilling and Early Kick/Loss Detection System To Execute a Challenging Deepwater Completions Job in the Gulf of Mexico by Julian Hernandez, Weatherford, et al.

Pore pressure assessment from well data and overpressure mechanism: Case study in Eastern Tunisia basins

Independent and complementary methods were used for pore pressure assessment in the eastern Tunisian basins. Drilling data and surveys allow settling the pore pressure profile in these basins. The main used parameters are mud weights, formation pressure surveys, drilling parameters, well logs, fluids exchange with formation and borehole issues. In the eastern Tunisia platform, the pore pressure profiles show changes in overpressure magnitude in all the three dimensions of the basin (location and depth/stratigraphy). We highlighted two overpressure intervals form bottom to top: The late Cretaceous in the North-eastern part, and the Tertiary overpressure interval hosted in the Palaeocene to Miocene series. The structural analysis of overpressure location shows that the Tertiary interval is likely to have originated in a disequilibrium compaction in Cenozoic grabens. Pore pressure cross sections and maps confirm the link between active normal faults that segmented the basin to grabens and highs and pore pressure anomalous area. In the Senonian interval, we noted mature source-rocks that can explain the overpressure in the late Cretaceous interval. In addition, the recent to active compressive tectonics may have contributed to both pore pressure anomaly generations. The fluid overpressures characterization in the eastern Tunisian sedimentary basins helps in hydrocarbons exploration. Indeed, the overpressure interval in the reservoir levels stimulates and improves the production in the oilfields and contributes to hydrocarbon trapping. Moreover, the adequate prediction of pore pressure profile contributes to reduce drilling cost and enhance the drilling operations safety.

Mechanical earth modeling and fault reactivation analysis for CO2-enhanced oil recovery in Gachsaran oil field, south-west of Iran

There is a huge potential for CO2-EOR and CO2 storage in depleted carbonate reservoirs in the south-west of Iran. In the first step of a CO2-EOR operation, a geomechanical assessment is needed to find out geological conditions, mechanical and strength properties of formation rocks (e.g., reservoir rock and caprock), in situ stress magnitudes and orientation and in situ pore pressure profile. An integrated analysis is performed in this work for geomechanical assessment of a reservoir–caprock system in Gachsaran oil field, south-west of Iran. A one-dimensional mechanical earth model (MEM) is built for 47 wells in the studied field based on drilling and logging data, laboratory and in situ tests. Static elastic and strength parameters of various formation rocks (limestone, dolomite, anhydrite, gray marl and salt) are evaluated from laboratory experiments. Empirical correlations are obtained to convert dynamic rock properties and well-log data to static elastic properties and strength parameters. The initial in situ pore pressure is calculated using modified Eaton method. In situ stresses state is evaluated based on the poroelastic method and calibrated using LOT and XLOT tests. The orientation of in situ stresses is obtained based on image logs. Fractures and faults analysis is performed to determine their orientations. An analytical analysis is performed to estimate the maximum sustainable CO2 injection pressure to prevent fault reactivation. This study presents a comprehensive method to reservoir and caprock characterization using laboratory and well-log data and 1D mechanical earth model. It helps the analysis of the geomechanical problems during CO2-EOR and provides the necessary information to build 3D geomechanical model for numerical simulations.

Development of a model to predict consolidation of tailings

Understanding tailing consolidation behaviour is critical for proper management of tailing impoundments. Extensive research has been conducted in order to resolve the economic and environmental considerations of tailing management facilities. Many researchers have developed numerical solutions which explain the difference between the behaviours of soft soils, such as tailings, and natural soils with respect to one-dimensional (1D), two-dimensional and three-dimensional consolidation theories. In this study, a fully implicit model was developed by introducing a new compressibility equation to predict the long-term 1D consolidation behaviour of tailings. This study also presents the numerical development of the model and subsequent validation by comparing the model’s predictions to previously published field and laboratory test data. Finally, a case study was carried out for tailings from two different tailing impoundments to predict the consolidation behaviour. The case study consisted of statistical analysis followed by numerical modelling. The statistical analysis indicated that the newly developed model has a better goodness of fit with the initial studies’ results compared with other widely used functions. The model was then used to generate settlement, void ratio, excess pore pressure and effective stress profiles.