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

2021 ◽  
Author(s):  
Umesh Prasad ◽  
Amer Hanif ◽  
Ian McGlynn ◽  
Frank Walles ◽  
Ahmed Abouzaid ◽  
...  
Keyword(s):  
Mechanical Properties ◽  
Public Domain ◽  
New Method ◽  
Rock Properties ◽  
Upper And Lower Bounds ◽  
Geomechanical Model ◽  
Volume Fractions ◽  
Fluid Properties ◽  
Tight Formations ◽  
Rock Mechanical Properties

Abstract 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.

scholarly journals Mechanical Rock Properties Estimation for Carbonate Reservoir Using Laboratory Measurement: A Case Study from Jeribe, Khasib and Mishrif Formations in Fauqi Oil Field

2021 ◽  
Vol 54 (1E) ◽  
pp. 88-102
Author(s):  
Qahtan Abdul Aziz ◽  
Hassan Abdul Hussein
Keyword(s):  
Mechanical Properties ◽  
Bulk Density ◽  
Depositional Environments ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Well Logs ◽  
Rock Properties ◽  
Petrophysical Properties ◽  
Empirical Correlations ◽  
Rock Mechanical Properties

Estimation of mechanical and physical rock properties is an essential issue in applications related to reservoir geomechanics. Carbonate rocks have complex depositional environments and digenetic processes which alter the rock mechanical properties to varying degrees even at a small distance. This study has been conducted on seventeen core plug samples that have been taken from different formations of carbonate reservoirs in the Fauqi oil field (Jeribe, Khasib, and Mishrif formations). While the rock mechanical and petrophysical properties have been measured in the laboratory including the unconfined compressive strength, Young's modulus, bulk density, porosity, compressional and shear -waves, well logs have been used to do a comparison between the lab results and well logs measurements. The results of this study revealed that petrophysical properties are consistent indexes to determine the rock mechanical properties with high performance capacity. Different empirical correlations have been developed in this study to determine the rock mechanical properties using the multiple regression analysis. These correlations are UCS-porosity, UCS-bulk density, UCS-Vs, UCs-Vp Es-Vs, Es-Vp, and Vs-Vp. (*). For example, the UCS-Vs correlation gives a good determination coefficient (R2= 0.77) for limestone and (R2=0.94) for dolomite. A comparison of the developed correlations with literature was also checked. This study presents a set of empirical correlations that can be used to determine and calibrate the rock mechanical properties when core samples are missing or incomplete.

scholarly journals Estimation of Mechanical Rock Properties from Laboratory and Wireline Measurements for Sandstone Reservoirs

2021 ◽  
Vol 54 (2D) ◽  
pp. 125-137
Author(s):  
Mustafa Adil Issa
Keyword(s):  
Mechanical Properties ◽  
High Performance ◽  
Rock Strength ◽  
Friction Angle ◽  
Rock Properties ◽  
Empirical Correlations ◽  
Threshold Criterion ◽  
Static Young’S Modulus ◽  
Sandstone Reservoirs ◽  
Rock Mechanical Properties

Mechanical rock properties are essential to minimize many well problems during drilling and production operations. While these properties are crucial in designing optimum mud weights during drilling operations, they are also necessary to reduce the sanding risk during production operations. This study has been conducted on the Zubair sandstone reservoir, located in the south of Iraq. The primary purpose of this study is to develop a set of empirical correlations that can be used to estimate the mechanical rock properties of sandstone reservoirs. The correlations are established using laboratory (static) measurements and well logging (dynamic) data. The results support the evidence that porosity and sonic travel time are consistent indexes in determining the mechanical rock properties. Four correlations have been developed in this study which are static Young’s modulus, uniaxial compressive strength, internal friction angle, and static Poisson’s ratio with high performance capacity (determination coefficient of 0.79, 0.91, 0.73, and 0.78, respectively). Compared with previous correlations, the current local correlations are well-matched in determining the actual rock mechanical properties. Continuous profiles of borehole-rock mechanical properties of the upper sand unit are then constructed to predict the sand production risk. The ratio of shear modulus to bulk compressibility (G/Cb) as well as rock strength are being used as the threshold criterion to determine the sanding risks. The results showed that sanding risk or rock failure occurs when the rock strength is less than 7250 psi (50 MPa) and the ratio of G/Cb is less than 0.8*1012 psi2. This study presents a set of empirical correlations which are fewer effective costs for applications related to reservoir geomechanics.

Successful Implementation Of Geomechanics In Deep Water Setting: A Case Study From KG Offshore, India

2021 ◽  
Author(s):  
Sarah Bhimpalli ◽  
Ashok Shinde ◽  
Bayye L Rao ◽  
Satya Perumalla ◽  
Anjana Panchakarla ◽  
...  
Keyword(s):  
Mechanical Properties ◽  
Deep Water ◽  
Added Value ◽  
Reservoir Rock ◽  
Successful Implementation ◽  
Drilling Mud ◽  
Geomechanical Model ◽  
Rock Mechanical Properties ◽  
The Impact

Abstract Geomechanics has an important role in assessing formation integrity during well construction and completion. It also has its effect when the wellbore is in production mode. Geomechanical study evaluate the impact of the present day in-situ stress and related mechanical processes on reservoir management. The study field ‘K' belongs to Plio-Pleistocene sequence of deep-water environment with hydrocarbon prospects. This belongs to Post-Rift tectonic stage of evolution with hydrocarbon occurring in structurally controlled traps. As a part of exploration activity, four offset oil wells were drilled earlier which were considered for the geomechanical model construction. Field (K) development plan comprising of six hydrocarbon producers and four water injectors was prepared. Considering the thick water column (300m-650m) in this deep water area of offshore and young unconsolidated sedimentary sequence in the sub-surface, expected pore-pressures can be high whereas the fracture gradient can be low. As a result, the safe drilling mud window can be narrow. Upon successful drilling of a well in such challenging environment without NPT (Non-Productive time), completing the well with best possible technologies suitable to the reservoir's mechanical behavior is utmost important for maximizing the production and minimizing the risk. To mitigate these problems in developing this field, an integrated reservoir geomechanics approach is adopted to optimize the drilling plan and reservoir completion parameters for the planned well. This paper covers the geomechanical study of four wells namely W, X, Y & Z drilled in the field ‘K'. The principal constituents of the geomechanical model are in-situ stresses, pore pressure and the rock mechanical properties. Geomechanical model for the field ‘K' was built utilizing the available data by integrating drilling, geology, petrophysics and reservoir data. Methodology adopted in this paper also highlights how a reliable geomechanical model can be built for a field, which is having data constraints. Constraining of stress magnitudes, orientation and anisotropy added value for efficient well planning in deep waters reservoirs. Calculating well specific reservoir rock mechanical properties, it made possible to identify the most optimal completion strategy. Approach contributed knowledge of geomechanical parameters based on the data of four offset wells has been used for successfully drilling and completion of all the subsequent wells without major challenges. Overall, geomechanical modeling has played a major role in drillability and deliverability of the reservoir. Integrated approach adopted in this paper can be used for well planning and drilling of future wells in East Coast of India with similar geological set up.

Bounds on low‐frequency seismic velocities in partially saturated rocks

Geophysics ◽  
1998 ◽  
Vol 63 (3) ◽  
pp. 918-924 ◽  
Author(s):  
Gary Mavko ◽  
Tapan Mukerji
Keyword(s):  
Low Frequency ◽  
Pore Fluid ◽  
Rock Properties ◽  
Upper And Lower Bounds ◽  
Small Scale ◽  
Seismic Velocities ◽  
Fluid Properties ◽  
Seismic Frequencies ◽  
The Individual ◽  
Wave Induced

The most common technique for estimating seismic velocities in rocks with mixed pore fluid saturations is to use Gassmann’s relations with an effective fluid whose density and compressibility are averages of the individual pore fluid properties. This approach is applicable only if the gas, oil, and brine phases are mixed uniformly at a very small scale, so the different wave‐induced increments of pore pressure in each phase have time to diffuse and equilibrate during a seismic period. In contrast, saturations that are heterogeneous over scales larger than the characteristic diffusion length, i.e., patchy saturation, will always lead to higher seismic velocities than if the same fluids are mixed uniformly at a fine scale. Critical saturation scales separating uniform from patchy behavior are typically of the order 0.1–1 cm for laboratory measurements and tens of centimeters for field seismic frequencies. For low seismic frequencies, velocities corresponding to patchy and homogeneous saturations represent approximate upper and lower bounds for given saturations and dry rock properties. For well‐consolidated rocks, both bounds can be estimated easily using Gassmann’s relations with Voigt and Reuss average effective fluids, respectively.

Effect of Cryogenic Treatment Thermal Shock on Rock Dynamic Elastic Properties and Permeability of Wolfcamp Core Samples – An Experimental Study

2021 ◽  
Author(s):  
Mahdi Ramezanian ◽  
Hossein Emadi
Keyword(s):  
Mechanical Properties ◽  
Thermal Shock ◽  
Elastic Properties ◽  
Cryogenic Treatment ◽  
Xrd Analysis ◽  
Rock Properties ◽  
Core Samples ◽  
Permeability Enhancement ◽  
Rock Mechanical Properties ◽  
Dynamic Elastic Properties

Abstract A few researches have been conducted to study effects of cryogenic treatment (known as thermal shocking) on unconventional rock properties, while they have been extensively studied in geothermal projects. The results show that cryogenic treatment significantly alters the rock mechanical properties by creation of new cracks owing to thermally induced stresses resulting in the permeability enhancement. In this laboratory study, effects of cryogenic treatment (thermal shocking) on permeability and dynamic elastic properties of three Wolfcamp core samples (one outcrop and two downhole samples) at downhole conditions were experimentally evaluated. Permeability and dynamic rock mechanical properties were measured before and after conducting each cycle of thermal shock. Using X-ray powder diffraction (XRD) analysis, the mineral compositions of the cores were determined. The results demonstrate that implementing the thermal shock technique on the core samples results in increasing their permeability and ductility.

Geomechanical Properties Estimation Utilizing Artificial Intelligence Prediction Tool

2021 ◽  
Author(s):  
Mohammed Alabbad ◽  
Mohammad Alqam ◽  
Hussain Aljeshi
Keyword(s):  
Mechanical Properties ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Significant Loss ◽  
Wellbore Stability ◽  
Rock Properties ◽  
Ann Model ◽  
Full Field ◽  
Geomechanical Properties ◽  
Rock Mechanical Properties

Abstract Drilling and fracturing are considered to be one of the major costs in the oil and gas industry. Cost may reach tens of millions of dollars and improper design may lead to significant loss of money and time. Reliable fracturing and drilling designs are governed with decent and representative rock mechanical properties. Such properties are measured mainly by analyzing multiple previously cored wells in the same formation. The nature of the conducted tests on the collected plugs are destructive and samples cannot be restored after performing the rock mechanical testing. This may disable further evaluation on the same plugs. This study aims to build an artificial neural network (ANN) model that is capable of predicting the main rock mechanical properties, such as Poisson's ratio and compressive strength from already available lab and field measurements. The log data will be combined together with preliminary lab rock properties to build a smart model capable of predicting advance rock mechanical properties. Hence, the model will provide initial rock mechanical properties that are estimated almost immediately and without undergoing costly and timely rock mechanical laboratory tests. The study will also give an advantage to performing preliminary estimates of such parameters without the need for destructive mechanical core testing. The ultimate goal is to draw a full field geomechanical mapping with this tool rather than having localized scattered data. The AI tool will be trained utilizing representative sets of rock mechanical data with multiple feed-forward backpropagation learning techniques. The study will help in localizing future well location and optimizing multi-stage fracturing designs. These produced data are needed for upstream applications such as wellbore stability, sanding tendency, hydraulic fracturing, and horizontal/multi-lateral drilling.

Field Scale Geo-Mechanical Analysis To Identify Fracture Sweet Spots Within Deccan Trap, Western Onshore, India

2021 ◽  
Author(s):  
Rajeev Ranjan Kumar ◽  
Sanjoy Kumar Mukherjee ◽  
S. K Biswal ◽  
Rajasekar V ◽  
Surej Kumar Subbiah ◽  
...  
Keyword(s):  
Mechanical Properties ◽  
Deccan Trap ◽  
Fracture Network ◽  
Fracture Analysis ◽  
Rock Properties ◽  
Main Challenge ◽  
Slip Tendency ◽  
Stress Profiles ◽  
Rock Mechanical Properties ◽  
Sweet Spots

Abstract Hydrocarbon exploration continues to venture into new avenues. This paper elaborates the 3D geomechanical study carried out to identify sweet spots in Deccan Trap Basalts in depth ranging from 500m-1100m in Cambay basin field of India. The main challenge is wide variation in the rock mechanical properties and stress profiles along various azimuths resulting from different tectonic incidents over the geological ages. Several drilling complications and held ups during electro logging in highly deviated wells are also reported. The normal fault tectonic framework has the imprint of two sets of faults viz., NNW-SSE and ENE-WSW. Deccan Trap acts as reservoirs due to the presence of connected open fracture network and to assess the potential reserves a comprehensive 3D Critically stressed fracture analysis has been performed using 3D numerical simulation-based rock properties, in-situ stress and seismic data. Open hole geophysical logs like sonic dipole and borehole images have been used to estimate rock mechanical properties and stress profiles in 18 key wells. Available core data of Basalt in the area have been used for dynamic to static rock properties estimation along with available published literature data. Critically stressed fracture analysis using 1D MEM outputs and dips dataset has been performed at well scale to history match production logging and testing results of 23 wells located in different fault blocks. 3D stress model has been built using plasticity model while taking into account faults and fracture sets. Utilizing 3D Geomechanical properties and Discrete fracture network model, critically stressed fracture sets have been identified across the field with slip tolerance and effective drawdown pressures. The study suggests that structurally high locations are good producers if seals are present above Trap. Sub-horizontal fractures have a higher closing tendency with decline in pressure in layers with SHmax>SHmin>Sv inside stiff Trap layer. There is variation of slip tolerance in the range of 0.2-1.4 in fracture sets which indicates slip tendency to be varying both vertically and laterally. Faults with ENE-WSW strike seem to be fluid migratory conduits and their intersection with NNW-SSE discontinuities are the areas where fracture sets have a higher slip tendency. Most of the producing layers are within 25m-55m of Trap with water being encountered at deeper depth intervals. These are mostly weathered fractured layers within the trap. The stress map suggests rotation of the maximum horizontal stress azimuth from NW to E which also affects fracture intensity in the field. Few fracture sets have tendency to be slip prone even with depletion up to 300psi-800psi while others will require stimulation or acid clean up job. Eight exploration wells drilled based on the study have shown good flow rate on initial well testing in the area providing validation to the study.

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