Determination of Safe Mud Weight Window in Rumaila Oilfield, Southern Iraq

The oil and gas industry, wellbore instability plays an important role in financial losses and stops the operations while the drilling which leads to extra time known as non-productive time. In this work, a comprehensive study was carried out to realize the nature of the instability problems of the wellbore in Rumaila oilfield to improve the well design. The study goal is to develop a geomechanical model in one dimension by utilizing Schlumberger Techlog (Version 2015) software. Open hole wireline measurements were needed to develop the model. The model calibrating and validating with core laboratory tests (triaxial test), well test (Mini-frac test), repeated formation test. Mohr-Coulomb, Mogi-Coulomb, and Modified Lade are the three failure criteria which utilized to analyze the borehole breakouts and to determine the minimum mud weight needed for a stable wellbore wall. For more accuracy of the geomechanical model, the predicted profile of the borehole instability is compared with the actual failure of the borehole that is recorded by caliper log. The results of the analysis showed that the Mogi-Coulomb criteria are closer to the true well failure compared with the other two criteria and considered as the better criteria in predicting the rock failure in the Rumaila oilfield. The wellbore instability analysis revealed that the vertical and low deviated wells (less than 40º) is safer and more stable. While, the horizontal and directional wells should be drilled longitudinally to the direction of the minimum horizontal stresses at a range between 140º–150º North West-South East and the mud weight recommended is increased to 10.5 ppg to avoid most of instabilities problems. The results contribute in development plan of the wells nearby the studied area and decreasing NPT and cost.

Geomechanical properties of carbonate reservoir rocks and middle carbon cap rocks of the Ivinskoe oilfield

Laboratory studies of the geomechanical properties of rocks are an important and integral part in building a geomechanical model. This study resulted in a set of data on geomechanical and elastic properties of the rocks that compose the lower part of the Middle Carboniferous section of the Ivinskoye oilfield (Russia). Relationships between various elastic parameters were also established. The distribution of geomechanical properties correlates with structural/textural features of the rocks under study and their lithological type. This information can be used as a basis for geomechanical modeling and in preparation for hydraulic fracturing. Keywords: geomechanics; elastic properties; carbonate rock; laboratory core studies.

An Innovative Methodology for Estimating Rock Mechanical Properties from Weight or Volume Fractions of Mineralogy and its Application to Middle East Reservoirs

The influences of mineralogy on rock mechanical properties have profound application in oil and gas exploration and production processes, including hydraulic fracturing operations. In conventional resources, the rock mechanical properties are predominantly controlled by porosity; however, in unconventional tight formations, the importance of mineralogy as a function of rock mechanical properties has not been fully investigated. In unconventional tight formations, mechanical properties are often derived from mineralogy weight fraction together with the best estimate of porosity, assumption of fluid types, the extent of pore fillings, and fluid properties. These properties are then adjusted for their volumetric fractions and subsequently calibrated with acoustics or geomechanical lab measurements. A new method is presented that utilizes mineralogy weight fractions (determined from well logs or laboratory measurements). This process uses public domain information of minerals using Voigt and Reuss averaging algorithms as upper and lower bounds, respectively. An average of these bounds (also known as Hill average) provides a representative value for these parameters. Further, based on isotropic conditions, all the elastic properties are calculated. A typical output consisting of bulk-, shear-, and Young's - modulus, together with Poisson's ratio obtained from traditional methods of volume fractions and this new method using weight fractions is discussed and analyzed along with the sensitivity and the trends for individual rock properties. Furthermore, corresponding strengths, hardness, and fracture toughness could also be estimated using well known public domain algorithms. Data from carbonate reservoirs has been discussed in this work. This method shows how to estimate grain compressibility that can be challenging to be measured in the lab for unconventional tight rock samples. In low-porosity samples, the relative influence of porosity is negligible compared to the mineralogy composition. This approach reduces several assumptions and uncertainties associated with accurate porosity determination in tight rocks as it does not require the amount of pore fluids and fluid properties in calculations. The grain-compressibility and bulk-compressibility (measured by hydrostatic tests in the laboratory on core plugs or calculated from density and cross-dipole log) are used to calculate poroelastic Biot's coefficient, as this coefficient will be used to calculate in-situ principal effective stresses (overburden, minimum horizontal, and maximum horizontal stresses), which are, together with rock properties and pore pressure, constitutes the geomechanical model. The geomechanical model is used for drilling, completions, and hydraulic fracture modeling, including wellbore stability, and reservoir integrity analyses.

Proactive Decision-Making Through Real-Time Geomechanical Support Leveraging Drilling a Long Horizontal Section Through a Tight Unconventional Reservoir of an Oil and Gas Field: Middle East

This paper discusses the Integrated Role of Geomechanics and Drilling Fluids Design for drilling a well oriented towards the minimum horizontal stress direction in a depleted, yet highly stressed and complex clastic reservoir. There are multiple challenges related to such a well that need to be addressed during the planning phase. In this case, the well needs to be drilled towards the minimum horizontal stress direction (Shmin) to benefit multi-stage hydraulic fracturing. At the same time, the most prominent challenge is that this well orientation is more prone to wellbore failure and requires a maximum mud weight, due to the present strike slip stress environment. Well planning challenges in such an environment include (a) the determination of formation characteristics and rock properties, (b) the anticipation of higher formation collapse pressure during the course of drilling the lateral section within the reservoir, (c) the determination of the upper bound mud weight to prevent lost circulation due to a low fracture gradient against depleted sections, or due to the presence of pre-existing natural fractures, d) mitigating the higher risk of differential sticking against depleted porous layers, and determining appropriate bridging in the drilling fluids, (e) recognizing the prolonged exposure time of the formation due to the length of the lateral and the lower rate of penetration against the tight highly dense formations. For successful drilling, and to mitigate the above risks, the first step is to prepare a predrill GeoMechanical model along with adequate fluid design and drillers action plans to be considered during drilling. Offset well petrophysical logs and core data are considered for the preparation of the predrill GeoMechanical model, along with the drilling experiences in the offset locations. Based on the above, a predrill GeoMechanical model is prepared, a risk matrix is being established, and a representative mud weight window is recommended (Wellbore Stability Analysis). In most cases, the offset well locations considered are vertical- or inclined-, or lateral wells of different trajectory azimuth than the target well location and the predrill GeoMechanical model can incorporate such variations easily; however, any Geology uncertainty, leading to a different rock property- and stress set-up (or even different pore pressure than expected), at the actual well location will be part of the uncertainty of the predrill GeoMechanical model and Wellbore Stability Analysis. This is where the real time monitoring is playing out its full potential: giving an updated model and wellbore stability analysis during drilling. While drilling the lateral section, the wellbore condition is being monitored using LWD (logging while drilling) tools, e.g. Gamma Ray, Density, Neutron, Acoustic Caliper, Azimuthal density image and ECD (equivalent circulating density). While gamma ray helps in determining the lithology, density logs help to understand the formation hardness, and they can be used to generate a calibrated pseudo acoustic log. Based on this pseudo acoustic log, the rock strength and other rock mechanical properties of the pre- GeoMechanical model can be updated as soon as they become available. This gives insight into the model differences and helps to understand model variations and adjust Wellbore Stability recommendations accordingly. While the neutron log helps to determine the zones of high porosity, and thus potential risk zones for differential sticking, the azimuthal density image clearly indicates the breakout zones caused by the shear failure of the wellbore. The presence of wellbore failure (breakout) is further confirmed by acoustic caliper data, and accordingly wellbore stability related recommendations are communicated to the operator, for an increase in the specific gravity of the mud, and thus, to balance the wellbore. From a mud rheology perspective, high performance OBM (oil-based mud) parameters are maintained consistent with the formation properties, to minimize fluid loss, optimize wellbore strengthening characteristics and minimize at the same time solids concentrations in order to avoid excessive ECD (equivalent circulating density) which may open pre-existing natural fractures resulting in downhole losses and in consequence might lead to differential sticking. In the case study presented herein, the proactive implementation of GeoMechanics and its Wellbore Stability application as well as the integration of drilling fluids services, resulted in the smooth and successful drilling of the lateral section, and also in the delivery of an in gauge hole necessary for multi-stage fracturing (MSF) completion optimization.

Geomechanical Model as the Key Step to Proppant Fracturing Success in Shallow Carbonate Reservoir of Bahrain

Geomechanics play an important role in stimulation design, especially in complex tight reservoirs with very low matrix permeability. Robust modelling of stresses along with rock mechanical properties helps to identify the stress barriers which are crucial for optimum stimulation design and proppant allocation. Complex modeling and calibration workflow showcased the value of geomechanical analysis in a large stimulation project in the Ostracod-Magwa reservoir, a complicated shallow carbonate reservoir in the Bahrain Field. For the initial model, regional average rock properties and minimum stress values from earlier frack campaigns were considered. During campaign progression, advanced cross dipole sonic measurements of the new wells were incorporated in the geomechanical modeling which provided rock properties and stresses with improved confidence. The outputs from wireline-conveyed microfrac tests and the fracturing treatments were also considered for calibration of the minimum horizontal stress and breakdown pressure. The porepressure variability was established with the measured formation pressure data. The geomechanically derived horizontal stresses were used as input for the frack-design. Independent fracture geometry measurements were run to validate the model. The poro-elastic horizontal strain approach was taken to model the horizontal stresses, which shows better variability of the stress profile depending on the elastic rock properties. The study shows variable depletion in porepressure across the field as well as within different reservoir layers. The Ostracod reservoir is more depleted than Magwa, with porepressure values lower than hydrostatic (∼7 ppg). The B3 shale layer in between the Magwa and Ostracod reservoirs is a competent barrier with 1200-1500psi closure pressure. The closure pressures in the Ostracod and Magwa vary from 1000-1500psi and 1100-1600psi, respectively. There is a gradual increasing trend observed in closure pressure in Magwa with depth, but no such trend is apparent in the shallower Ostracod formation. High resolution stress profiles help to identify the barriers within each reservoir to place horizontal wells and quantify the magnitude of hydraulic fracture stress barriers along horizontal wells. The geomechanical model served as a key part of the fracturing optimization workflow, resulting in more than double increase in wells productivity compared to previous stimulation campaigns. The study also helped to optimize the selection of the clusters depth of hydraulic fracturing stages in horizontal wells. The poroelastic horizontal strain approach to constrain horizontal stresses from cross dipole sonic provides better variability in the stress profile to ultimately yield high resolution. This model, calibrated with actual frac data, is crucial for stimulation design in complex reservoirs with very low matrix permeability. The geomechanical model serves as one of the few for shallow carbonates rock in the Middle East region and can be of significant importance to many other shallow projects in the region.

Correlation of Mechanical Parameters in a Giant Carbonate Field, UAE

The rock properties in the reservoir rocks represent stiffness and strength properties, while the unexpected variation in the dense intervals varies with the fabric and other sedimentological and rock types. The purpose of this paper is to present the mechanical rock testing parameters of Lower Cretaceous reservoirs, including the tight intervals in a giant field of Abu Dhabi. In order to enable the evaluation of the mechanical parameters, there is a need to assess the reservoir rocks, as well as the stress configuration around and away from the wells. This paper introduces a workflow that integrates multidisciplinary data to develop a geomechanical model aiming to reduce drilling risks and optimizing reservoir appraisal. Cores, wireline logs, CT scans, SEM and thin sections were used to characterize the fracture systems and build the robust seismic driven geomechanical model. A conceptual model has been firstly developed, where reservoir heterogeneity has been quantitatively described in relation to tectonic deformation events, followed by incorporating a 1D-MEM's (Mechanical Earth Model), which used to calibrate the seismic based elastic properties. Results indicate good correlations developed between dynamic and static Young's Modulus, Biot's coefficient, Friction Angle and Unconfined Compressive Strength by incorporating the results of rock mechanics testing, leading to create a dynamic YME-driven correlation. Good correlations were also obtained between Effective Porosity, and Static Young's modulus, Biot's coefficient, Friction angle and Unconfined compressive strength, leading to create a Porosity-driven correlation. In addition, friction angle correlation increases if proper data is considered, making feasible to build a correlation in both dynamic YME and Effective Porosity. Finally, the presence of several partially conductive fracture sets within the reservoir, including both sub-vertical and moderately dipping conjugate sets, with gently dipping/bed-parallel fractures. They have been developed under a predominant strike-slip regime that swaps a normal faulting stress regime at depth. Fracture porosity is related to micro- and meso-scale fractures, and fracture permeability is more significant compared to the storage capacity of the matrix porosity. Rock fabrics are varied in different zones, which likely explains differences in the mechanical behaviour.

Geomechanical model and sanding onset assessment: A field case study in Vietnam

Sand production is a key issue when selecting and applying completion solutions like open holes, screens or perforated liners. This problem can be seen in several types of reservoirs such as weakly consolidated and non-consolidated carbonates. The paper presents a method to model wellbore failures for sanding prediction. Our study shows that the potential sand risk in this field is defined by the rock strength rather than the in-situ stress. If the rock is sufficiently competent, the potential of sand production is negligible, and the development wells can be completed conventionally without any downhole sand control for the reservoir pressure above 1,280 psi and the maximum drawdown pressure of 2,380 psi.

Uncertainties in geomechanical models – exhaustive vs. feasible approach

The stress state is a key component for the safety and stability of deep geological repositories for the storage of nuclear waste. For the stability assessment and prediction over the repository lifetime, the stress state is put in relation to the rock strength. This assessment requires knowledge of both the future stress changes and the current in situ stress state. Due to the limited number of in situ stress data records, 3D geomechanical models are used to obtain continuous stress field prediction. However, meaningful interpretation of the stress state model requires quantification of the associated uncertainties that result from the geological, stress and rock-property data. This would require thousands of simulations which in a high-resolution model is called an exhaustive approach. Here we present a feasible approach to reduce computation time significantly. The exhaustive approach quantifies uncertainties that are due to variabilities in stress data records. Therefore, all available data records within a model volume are used individually in separate simulations. Due to the inherent variability in the available data, each simulation represents one of many possible stress states supported by data. A combination of these simulations allows estimation of an individual probability density function for each component of the stress tensor represented by an average value and a standard deviation. If weighting of the data records can be performed, the standard deviation can usually be reduced and the significance of the model result is improved. Alternatively, a range of different stress states supported by the data can be provided with the benefit that no outliers are disregarded, but this comes at the cost of a loss in precision. Both approaches are only feasible since the number of stress data records is limited. However, it is indicated that large uncertainties are also introduced by variabilities in rock properties due to natural intra-lithological lateral variations that are not represented in the geomechanical model or due to measurement errors. Quantification of these uncertainties would result in an exhaustive approach with a high number of simulations, and we use an alternative, feasible approach. We use a generic model to quantify the stress state uncertainties from the model due to rock property variabilities. The main contributor is the Young's module, followed by the density and the Poisson ratio. They affect primarily the σxx and σyy components of the stress tensor, except for the density, which mainly affects the σzz component. Furthermore, a relative influence of the stress magnitudes, the tectonic stress regime and the absolute magnitude of rock properties is observed. We propose to use this information in a post-computation assignment of uncertainties to the individual components of the stress tensor. A range of lookup tables need to be generated that compile information on the effect of different variabilities in the rock properties on the components of the stress tensor in different tectonic settings. This allows feasible quantification of uncertainties in a geomechanical model and increases the significance of the model results significantly.

Automatic Calibration of a Geomechanical Model from Sparse Data for Estimating Stress in Deep Geological Formations

Summary In this study, we demonstrate geomechanical modeling with fully automatic parameter calibration to estimate the full geomechanical stress fields of a prospective US CO2 storage site, based on sparse measurement data. The goal is to compute full stress tensor field estimates (principal stresses and orientations) that are maximally compatible with observations within the constraints of the model assumptions, thereby extending point-wise, incomplete partial stress measurement to a simulated full formation stress field, as well as a rough assessment of the associated error. We use the Perch site, located in Otsego Country, Michigan, as our case study. Input data consists of partial stress tensor information inferred from in-situ borehole tests, geophysical well logs and processing of seismic data. A static earth model of the site was developed, and geomechanical simulation functionality of the open-source MATLAB Reservoir Simulation Toolbox (MRST) used to model the stress field. Adjoint-based nonlinear optimization was used to adjust boundary conditions and material properties to calibrate simulated results to observations. Results were interpreted through a Bayesian framework. The focus of this article is to demonstrate how the fully automatic calibration procedure works and discuss the results obtained but does not attempt a detailed analysis of the stress field in the context of the proposed CO2 storage initiatives. Our work is part of a larger effort to non-invasively determine in-situ stresses in deep formations considered for CO2 storage. Guided by previously published research on geomechanical model calibration, our work presents a novel calibration approach supporting a potentially large number of linear or nonlinear calibration parameters, in order to produce results optimally agreeing with available measurements and thus extend partial point-wise estimates to full tensor fields compatible with the physics of the site.

Influence of Rock Plastic Behavior on the Wellbore Stability

Currently, the standard approach to building a geomechanical model for analyzing wellbore stability involves taking into account only elastic deformations. This approach has shown its inconsistency in the design and drilling of wells passing through rocks with pronounced plastic properties. Such rocks are characterized by the fact that when the loads acting on them change, they demonstrate not only elastic, but also plastic (irreversible) deformations. Plastic deformations have an additional impact on the distribution of stresses in the rock of the near-wellbore zone on a qualitative and quantitative level. Since plastic deformations are not taken into account in the standard approach, in this case the results of the wellbore stability analysis are based on incorrectly calculated stresses acting in the rock. As a result, it can lead to misinterpretation of the model for analysis, suboptimal choice of trajectory, incorrect calculation of safe mud window and an incorrectly selected set of measures to reduce the risks of instability. The aim of this work is to demonstrate the advantages of the developed 3D elasto-plastic program for calculating the wellbore stability in comparison with the standard elastic method used in petroleum geomechanics. The central core of the work is the process of initialization of the elasto-plastic model according to the data of core tests and the subsequent validation of experimental and numerical loading curves. The developed 3D program is based on a modified Drucker-Prager model and implemented in a finite element formulation. 3D geomechanical model of wellbore stability allows describing deformation processes in the near-wellbore zone and includes the developed failure criteria. The paper shows a special approach to the determination of the mud window based on well logging data and core tests by taking into account the plastic behavior of rocks. An important result of this study is the determination of the possibility of expanding the mud window when taking into account the plastic criterion of rock failure.