3D Mechanical Earth Model Research Articles

Simulation-Based Optimization Workflow of CO2-EOR for Hydraulic Fractured Wells in Wolfcamp A Formation

Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study proposes an optimization workflow for the CO2 huff-n-puff process for multistage-fractured horizontal wells in the Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO2 sequestration simultaneously was addressed using a coupled geomechanics–reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. A fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO2 injection. After the primary production phase, various CO2 injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO2 storage efficiency. The simulation approach proposed by this study provides a comprehensive and systematic workflow for evaluating and optimizing CO2 huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

1D Geomechanical Model and Wellbore Stability Analysis for Kafr El-Sheikh Formation at Sapphire Field, West Delta Deep Marine, Egypt

The Messinian Abu Madi Formation considered the most prospective reservoir target in the Nile Delta, is situated under the Pliocene Kafr El-Sheikh Formation, where most non-productive time takes place. Nevertheless, reaching the desired reservoir presents a greater level of complexity than first perceived. To mitigate the occurrence of significant non-productive time caused by wellbore instability problems, including stuck pipes, tight holes, pack-offs, and jarring or fishing operations, there has been an increased focus on geomechanical analysis. Therefore, this work aims to offer a comprehensive 1D mechanical earth model for a specific set of wells situated in the sapphire field, which is situated inside the West Delta Deep Marine region. The mechanical parameters of the rock were determined by the use of empirical equations, since the absence of core sample data necessitated reliance on wireline data. The analysis of the borehole image has provided clarification that the orientation of the maximum horizontal stress is aligned with the NNE-SSW direction. The calibration of this model was conducted using data obtained from wellbore stability events that occurred during the drilling operations of these wells. This model would be valuable in forecasting and minimizing prospective problems by predicating the proper safe mud window. Sapphire-Da, the primary key, is utilized in this particular piece of writing.

Building 1D Mechanical Earth Model for Subba Oilfield in Iraq

At the Subba oil field, wellbore stability is the main concern while drilling. The wellbore's instability causes several issues, including: (inefficient hole cleaning, tight hole, stuck pipe, mud losses, caving, bad cementing, and well kick or blowout). This increases Non-Productive Time (NPT) and well-drilling costs; hence the operator's main goal is to create a drilling program that reduces these problems and therefore reduce drilling cost. The study aims to build a 1D mechanical earth model to predict the wellbore failure and design optimum mud weight to improve the drilling efficiency for future wells. The model includes pore pressure, stress state, and rock mechanical parameters (such as UCS, angle of friction, Young-Modulus, and Poisson-Ratio). To achieve this aim, the study utilised offset well data including log data (Gama-Ray Logs (GR), Caliper Logs (CALI), Density Logs (RHOZ), and Compressional Sonic (DTCO) and Shear Sonic (DTSM)), Core tests, Mini-frac field tests, Drilling Reports, Mud Reports, and Mud Log Reports (master log) to estimate and calibrate the profiles of formation pore pressure, rock mechanical properties, and in-situ stresses. The 1D mechanical earth model was built using the Excel program for three wells data set, where all the necessary parameters to create the model was calculated, calibrated for the calculated variables with core data and pressure test points, and finally the safe mud window was detected. The results showed that the Eaton Slowness method to predict pore pressure perfectly matches the pressure test points. The most common fault regimes in the Subba oilfield are normal and strike-slip faults. The Modified Lade criteria showed a compatible match with drilling events and calliper log in predicting the failure zones, so it is the best criterion in determining minimum and maximum mud weight. Based on the results of this study and in comparison with the mud window used in drilling operations in the field, it is necessary to change the mud window used in drilling and adopt the safe MWW of this study in drilling new wells in this field and the area adjacent to the field.

The fluid flow modeling procedure including a critically stressed fracture analysis of coalbed methane reservoir: a case study of Upper Silesian Coal Basin, Poland

The geomechanical modeling turned out to be an essential component of the hydrocarbon exploration assisting reduction of risk of drilling issues and optimization of hydraulic fracturing treatment. This study provides a workflow of critically stressed fracture (CSF) analysis dedicated for coal layers. The main focus of the paper is applying the 1D mechanical models and following modelling of hydraulic fracturing treatment to describe the fracture behavior under the impact of the stresses at the wellbore scale. Another objective of the presented study is demonstration of benefits of 1D and 3D CSF analysis to understand fracture contribution to gained volume of hydrocarbon after fracturing of coal seam. Interpretation of fracture orientation and their behavior is vital to effective development of coal bed methane (CBM) resources as the CSF can be responsible for considerable part of CBM production. Natural fractures and faults contribute to fluid flow through rock. It is often noted that natural fractures may not be critically stressed at ambient stress state. However, during stimulation, the optimally oriented natural fracture sets have the inclination to become critically stressed. Hence, understanding of the recent stress state and fracture orientations is significant for well planning and fracturing design. The outcome of this study are comprehensive 1D mechanical Earth models (MEMs) for analyzed wells and explanation of behavior of identified CSF under variable stress state as well as understanding of the connectivity of natural fractures within zone subjected to fracturing treatment.

In Situ Stress Distribution in Cretaceous Ultra-Deep Gas Field From 1D Mechanical Earth Model and 3D Heterogeneous Geomechanical Model, Kuqa Depression, Tarim Basin, NW China

The Kuqa Depression boasts rich cretaceous ultra-deep hydrocarbon resources. However, it is in complex geological conditions. At present, sufficient understandings on the in situ stress distribution and influencing factors are lacking, which restricts the process of hydrocarbon exploitation. Therefore, in this study, the Bozi gas field is selected as an example, and a 1D mechanical earth model (1D MEM) is established with the drilling data and logging data through the geomechanical method to clarify the in situ stress distribution of the wellbore. A 3D heterogeneous geomechanical model (3D HGM) is established with the constraint of 1D HEM to clarify the distribution characteristics of the 3D in situ stress field in the Bozi gas field and discuss its influencing factors. The results show that: 1) the Bozi gas field is in an extremely strong in situ stress condition with high stress values. The minimum horizontal principal stress (Sh) of the cretaceous system is 153∼180 MPa, and the maximum horizontal principal stress (SH) is nearly 200 MPa; 2) the in situ stress in the Bozi gas field has obvious vertical stratification characteristics, which can be divided into three stress sequences of “low–high–low”, with great differences in interlayer stress; 3) the in situ stress distribution of the Bozi gas field is greatly affected by the types of faulted anticline. Different types indicate different stress distribution; 4) within the influence range of overthrusts, the in situ stress in the footwall is lower than that of the hanging wall. The greater the fault offset, the greater the in situ stress difference between the hanging wall and footwall. Moreover, the lower the stress in the footwall, the higher is the degree of overthrust, and the larger is the range of footwall stress area; and 5) the means of highly deviated wells is more helpful to the Bozi gas field for hydrocarbon exploitation.

Quantitative risk assessment of wellbore collapse for volcanic rock formation in Sichuan Basin

Drilling and completion practices for Permian volcanic formation in Sichuan Basin show that the volcanic formation is usually featured by complex lithology, strong heterogeneity, and strong uncertainty. Consequently, a huge risk of borehole collapse is observed during drilling and completion, which seriously affects the safety, efficiency, and costs of natural gas wells. However, the classical analysis method of wellbore stability cannot effectively evaluate the wellbore stability of Permian volcanic formation. Therefore, in view of the complex lithology and strong heterogeneity of volcanic formation, the reliability theory is introduced to conduct the quantitative risk assessment of wellbore collapse for volcanic rock formation. First, the uncertainty analysis model for borehole collapse was introduced based on the reliability theory. Second, the 1D mechanical earth model (MEM) of Permian volcanic formation was proposed by using logging interpretation. Third, the uncertainty of the MEM was assessed by fitting the logging interpretation results. Then, the Monte–Carlo method was used to quantitatively assess the collapse risk of Permian volcanic formation, and the finding was compared with the field testing result. Finally, the sensitivity parameter of borehole collapse was analyzed for Permian volcanic formation. The results indicated that the cohesive strength, internal friction angle, and maximum horizontal stress conformed to a loglogistic distribution; the minimum horizontal stress conformed to an InvGauss distribution, whereas the pore pressure conformed to a Weibull distribution. The equivalent mud weight of critical collapse pressure was approximately 1.88 g/cm3 when the collapse risk was 5% (i.e., reliability: 95%), which is consistent with the actual situation of the YT-1 well. The sensitivity ranking of wellbore stability parameters were as follows: maximum horizontal in-situ stress > pore pressure > internal friction angle > cohesive strength > minimum horizontal in-situ stress. The present method and results can provide theoretical guidance for the prevention and treatment of wellbore collapse incidents in Permian volcanic formation.

Inversion of Full Waveform Sonic Data Assists Calibration of Geomechanics Model

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202260, “Inversion of Advanced Full Waveform Sonic Data Provides Magnitudes of Minimum and Maximum Horizontal Stress for Calibrating the Geomechanics Model in a Gas Storage Reservoir,” by Zachariah J. Pallikathekathil, SPE, Xing Wang Yang, and Saeed Hafezy, Schlumberger, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. In 1D geomechanics projects, calibration of stress is extremely important in the construction of a valid mechanical earth model (MEM). The effective minimum horizontal stress (Shmin) data usually are available from traditional measurements, but these have a few deficiencies. The complete paper presents a technique for deriving stresses in which the radial variation of acoustic velocity from an advanced dipole sonic logging tool is inverted to obtain stress. These derived stresses are then used to calibrate the 1D MEM for a gas storage field. Regional Geology The field is in the Otway Basin in Western Victoria. Gas is trapped in the Late Cretaceous Waarre formation at depths between 1155 and 1200 m subsea. The reservoir is sealed by the overlying marine Belfast mudstone, which is the common seal in the stratigraphy across the onshore Otway Basin. The reservoir has excellent reservoir quality and has proved ideal for gas storage. Challenge Posed by the 1D MEM Challenge Posed by the 1D MEM Well 1 was recently drilled in the basin. A 1D MEM - a numerical representation of the geomechanical properties and stress state of the earth at any depth - was planned to be constructed to obtain the current-day far-field principal stresses (Shmin), effective maximum horizontal stress (SHmax), and effective vertical stress (SV)] in the Belfast and Waarre formations. Understanding the stress field was important, especially in the caprock (Belfast) and in the reservoir (Waarre) so that the pressure limits for safe gas-storage operation could be defined better. However, for a variety of reasons, no conventional stress measurements were available to calibrate the modeled stress in the 1D MEM. Without any calibration of the stress, the geomechanics model would feature high uncertainty to be used to define the pressure operational limits for gas-storage operation. Fortunately, a new wireline sonic tool was recorded in the reservoir section and the overburden sections of the borehole in Well 1. A quick dispersion analysis of the waveforms showed that the Paaratte formation, above the Belfast formation, was acoustically stress-sensitive and that advanced processing could be performed to invert the acoustic information to stress values.

3D mechanical earth model for optimized wellbore stability, a case study from South of Iraq

Wellbore instability issues represent the most critical problems in Iraq Southern fields. These problems, such as hole collapse, tight hole and stuck pipe result in tremendous increasing in the nonproductive time (NPT) and well costs. The present study introduced a calibrated three-dimensional mechanical earth model (3DMEM) for the X-field in the South of Iraq. This post-drill model can be used to conduct a comprehensive geomechanical analysis of the trouble zones from Sadi Formation to Zubair Reservoir. A one-dimensional mechanical earth model (1DMEM) was constructed using Well logs, mechanical core tests, pressure measurements, drilling reports, and mud logs. Mohr–Coulomb and Mogi–Coulomb failure criteria determined the possibility of wellbore deformation. Then, the 1DMEMs were interpolated to construct a three-dimensional mechanical earth model (3DMEM). 3DMEM indicated relative heterogeneity in rock properties and field stresses between the southern and northern of the studied field. The shale intervals revealed prone to failure more than others, with a relatively high Poisson's ratio, low Young's modulus, low friction angle, and low rock strength. The best orientation for directional Wells is 140° clockwise from the North. Vertical and slightly inclined Wells (less than 40°) are more stable than the high angle directional Wells. This integration between 1 and 3DMEM enables anticipating the subsurface conditions for the proactive design and drilling of new Wells. However, the geomechanics investigations still have uncertainty due to unavailability of enough calibrating data, especially which related with maximum horizontal stresses magnitudes.

Fault and fracture reactivation analysis by 4D geomechanical integrated modelling in one of a depleted carbonate oil field, southwest of Iran

ABSTRACT The study field has been an oil-producing area in southern Iran for nearly 50 years. Complex geological structure and varying levels of depletion scenarios require geomechanical analysis of the reservoir to enhance its production and mitigate geomechanical risks. This paper describes creating a time-lapse (4D) integrated geomechanical model by generating 3D maps of mechanical properties and a 3D stress state that can be altered over time as pore pressure changes, then explores pressure depletion and related stress changes effects on faults and fractures reactivation. The first phase of the study was an integrated stress analysis using Image logs and sonic anisotropy interpretation. 1D–3D Mechanical Earth Model was built by gridding the reservoir and populate the model with mechanical properties. The third phase provided a distribution of stresses and associated strains under initial conditions using finite element calculations. Ultimately, stress and strain changes associated with depletion simulated by the reservoir flow model were determined during the fourth phase of study. In the resulting model, different critical coordinates points from the initial year (1992) to 2045 were selected five time-steps. Results show no critical faults reactivation but by increasing production time the instability of fractures gradually rises by stress regime changes.

First Multistage Fracturing of a Horizontal Well Drilled in a Tight Carbonate Reservoir in UAE

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203226, “First Multistage Fracturing of Horizontal Well Drilled in a Conventional Tight Carbonate Reservoir in an Onshore Field in the UAE: Challenges and Lessons Learned,” by Muhammad Aftab, SPE, Noor Talib, and Maad Subaihi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The reservoir upon which this case study is focused is a tight, low-permeability carbonate reservoir with thin layers. The objective of the field case was to increase and sustain productivity of a pilot well consisting of an openhole completion. The complete paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. The study may provide a potential approach for selecting the proper hydraulic fracturing method and technique in similar cases. Introduction Reservoir X is divided into six layers. Layers X-3 through X-6 have reasonable porosity development; valid pressure points exist in X-3 and X-6. Pumpout was performed while collecting samples from X-3 and X-6, followed by short buildups. Production-logging-tool measurement was performed and found two major oil-producing layers across X-3 (60% of total production) and X-6 (40% of total production). The remaining intervals of the perforation were almost inactive. Petrophyscial and testing results of vertical Well A resulted in a decision to drill a horizontal oil producer (Well B) through Layer X-3. Well B was steered with a 2,220-ft horizontal length, out of which 1,930 ft was inside X-3 and 290 ft were above X-3 be-cause of a fault throw of 16 ft true vertical depth. The well was steered with a horizontal length of 2,080 ft in X-6. Well B was completed with a 3½-in. completion and horizontal section as an openhole. Matrix stimulation using coiled tubing was performed with 15% hydrochloric acid in Well B. The well ceased to flow after 2 weeks of declining production. Rapid pressure depletion was observed in Well B. Localized depletion around the wellbore was anticipated because of poor matrix/matrix connectivity. After comprehensive studies and risk assessments, the decision was made to recomplete Well B with a cemented fracturing string to perform hydraulic fracturing with the plug-and-perf technique. This technique will allow flexibility of stage count and stage spacing and a multi-cluster design to maximize the stimulated reservoir volume (SRV) along the upper, middle, and lower layers. In addition, the operator and service provider collaborated to enhance this design through a zero-overflush technique with diverting agents. The complete paper provides a detailed discussion of the core measurement and 1D mechanical Earth model used in the hydraulic fracturing design. Hydraulic Fracturing Design The main challenge in fracturing Well B was to ensure that the fracture generated is contained within the reservoir. Well B is completed in two layers (X-3 and X-6). The bottom part of the well is in X-6 and close to another underlying reservoir (Fig. 1).

Stress Distribution in the Upper Shihezi Formation from 1D Mechanical Earth Model and 3D Heterogeneous Geomechanical Model, Linxing Region, Eastern Ordos Basin, Central China

AbstractThe Upper Shihezi sedimentary rocks in the Linxing region has been estimated with a significant volume of tight sandstone gas. However, lateral distribution of the present‐day stress magnitude is poorly understood, which limits further gas production. Hence, a one‐dimensional mechanical earth model and a three‐dimensional heterogeneous geomechanical model are built to address this issue. The results indicate that the strike‐slip stress regime is dominant in the Upper Shihezi Formation. Relatively low stresses are mainly located around wells L‐60, L‐22, L‐40, L‐90, etc, and stress distributions exhibit the similarity in the Members H2 and H4. The differential stresses are relatively low in the Upper Shihezi Formation, suggesting that complex hydraulic fracture networks may be produced. Natural fractures in the Upper Shihezi Formation contribute little to the overall gas production in the Linxing region. In addition, the minimum principal stress gradient increases with Young's modulus, suggesting that the stiffer rocks commonly convey higher stress magnitudes. There is a strong interplay between stress distribution and heterogeneity in rock mechanics. Overall, the relative error between the predicted and measured results is less than 10%, implying that the predicted stress distribution is reliable and can be used for subsequent analysis in the Linxing region.

Reservoir Wellbore Stability Analysis and Weak Zones Identification Using the 1D MEM, Swelling Tests and UCS: A Case Study From Mumbai Offshore, India

Reservoir geomechanical studies play a decisive role in identifying wellbore instability and weak zones in offshore petroleum reservoirs. In this study, an integrated workflow developed with 1D Mechanical Earth Models (1D MEM), uniaxial compressive strength and swelling tests using well logs, drilling, and core data of production and exploratory wells from the North-Heera field, Mumbai offshore, India. Lithology-based correlations are utilized for calculating continuous profiles of rock mechanical properties by taking well logs as a primary source of input. Insights of fracture gradients and stresses are generated by interpretation of the pore pressure. UCS created from the well logs shows the low value of 15 MPa and high Poison's ratio of 0.38–0.45. Fracture pressure analysis of the wells specifies the lower fracture initiation pressures at 300 m are 5ppg–15ppg, which are shale and clay formation. Shale swelling tests are performed to know the hydration properties of shales present at shallow depths. The core samples' loading tests' results are very close to the UCS models constructed from the well logs. The combined analysis examines fracture pressures around wellbores, hydration of shales, weak zones identification, and wellbore instability.

1D mechanical earth modeling in the Permian Lucaogou Shale of the Santanghu Basin, Northwest China, from a complete set of laboratory data

Understanding various properties of unconventional shale plays is important for successful field operations and development. We have comprehensively examined a total of 11 core plugs from the productive unit of the Middle Permian Lucaogou Formation in the Santanghu Basin with various experimental tools. Mineral assemblages were detected, and we found that samples are in the oil window with a combination of type I and II kerogens. After static and dynamic geomechanical analysis, we established a correlation between ultrasonic and static geomechanical parameters. The results indicated that the samples have a brittle behavior with hydrostatic compressive strength ranging from 177.68 to 419.63 MPa, and static Young’s modulus from 9.93 to 53.24 GPa. In the next step, using the measured data we calibrated the only existing well log from where the samples were retrieved and we built an 1D mechanical earth model throughout the entire target formation. Ultimately, by using partial least-squares regression analysis, we determined that feldspar and calcite are the main stiff minerals that would affect the mechanical properties positively, whereas clay minerals and organic matter could have a negative impact on the rock mechanical parameters.

Field-scale fully coupled simulation of fluid flow and geomechanics: Gas storage/recovery process in a depleted sandstone reservoir

This work addresses a field-scale model, in which the equations of multiphase/multicomponent fluid flow and geomechanics were fully coupled, to simulate natural gas successive storage/recovery processes in an Iranian sandstone depleted gas reservoir. First, a 1D mechanical earth model was developed for the reservoir wells and then converted to a geomechanical 3D model of the reservoir, through sequential Gaussian simulation. The fully coupled simulation of the fluid flow and geomechanics - validated by the analytical solution of the Mandel's problem - was then performed for ten years of gas injection/production cycles in a section of the reservoir between two wells. Variations of different parameters including porosity, permeability, subsidence and effective stress were investigated versus time and compared to those of the non-fully coupled model, within the 10-year period in the studied section of the reservoir. Moreover, the results of the fully coupled model were compared to that of the non-fully coupled one in terms of the gas production rate and bottom-hole pressure in a single well. The results showed that the maximum rate of gas production as well as the maximum bottom-hole pressure predicted by the fully coupled model were 9.5 and 15% lower than those of the non-fully coupled model, respectively.

Building 1D and 3D Mechanical Earth Models for Underground Gas Storage - A Case Study from the Molasse Basin, Southern Germany

Hydromechanical models of gas storage in porous media provide valuable information for various applications ranging from the prediction of ground surface displacements to the determination of maximum reservoir pressure and storage capacity to maintain fault stability and caprock integrity. A workflow to set up such models is presented and applied to a former gas field in southern Germany for which transformation to a gas storage site is considered. The workflow comprises 1D mechanical earth modeling (1D MEM) to calculate elastic properties as well as a first estimate for the vertical and horizontal stresses at well locations by using log data. This information is then used to populate a 3D finite element model (3D MEM) which has been built from seismic data and comprises not only the reservoir but the entire overburden up to the earth’s surface as well as part of the underburden. The size of this model is 30 × 24 × 5 km3. The pore pressure field has been derived from dynamic fluid flow simulation through history matching for the production and subsequent shut-in phase. The validated model is ready to be used for analyzing new wells for future field development and testing arbitrary injection-production schedules, among others.

Building 1D and 3D Mechanical Earth Models for Underground Gas Storage—A Case Study from the Molasse Basin, Southern Germany

Hydromechanical models of gas storage in porous media provide valuable information for various applications ranging from the prediction of ground surface displacements to the determination of maximum reservoir pressure and storage capacity to maintain fault stability and caprock integrity. A workflow to set up such models is presented and applied to a former gas field in southern Germany for which transformation to a gas storage site is considered. The workflow comprises 1D mechanical earth modeling (1D MEM) to calculate elastic properties as well as a first estimate for the vertical and horizontal stresses at well locations by using log data. This information is then used to populate a 3D finite element model (3D MEM) which has been built from seismic data and comprises not only the reservoir but the entire overburden up to the earth’s surface as well as part of the underburden. The size of this model is 30 × 24 × 5 km3. The pore pressure field has been derived from dynamic fluid flow simulation through history matching for the production and subsequent shut-in phase. The validated model is ready to be used for analyzing new wells for future field development and testing arbitrary injection-production schedules, among others.

Building 1D Mechanical Earth Model for Zubair Oilfield in Iraq

Many problems were encountered during the drilling operations in Zubair oilfield. Stuckpipe, wellbore instability, breakouts and washouts, which increased the critical limits problems, were observed in many wells in this field, therefore an extra non-productive time added to the total drilling time, which will lead to an extra cost spent. A 1D Mechanical Earth Model (1D MEM) was built to suggest many solutions to such types of problems. An overpressured zone is noticed and an alternative mud weigh window is predicted depending on the results of the 1D MEM. Results of this study are diagnosed and wellbore instability problems are predicted in an efficient way using the 1D MEM. Suitable alternative solutions are presented ahead to the drilling process commences in the future operations.

An integrated petrophysical and geomechanical characterization of Sembar Shale in the Lower Indus Basin, Pakistan, using well logs and seismic data

Shale gas reservoirs are generally exploited through horizontal drilling and hydraulic fracturing. Petrophysical and geomechanical parameters help to determine horizontal well orientation, to select drilling mud densities for stable drilling operations, to assess the suitability of specific zones in a formation for hydraulic fracturing, and to assess required hydraulic fracturing pressures. The primary objective of this work was to characterize a shale interval in the Early Cretaceous-age Sembar Formation in the Lower Indus Basin of Pakistan, using only readily available data. A workflow was developed for the estimation and mapping of geomechanical properties using logs from multiple wells and relevant post-stack seismic reflection data. Mineralogy data from well cuttings, core testing results for elastic properties and hydraulic fracturing test data (mostly obtained from one key well) were utilized to constrain the values of the properties estimated from geophysical data. The following results obtained at the well-scale suggest that the Sembar Shale is favorable for development: high gas saturation, good porosity (up to 10%), moderate quantity of thermally mature organic matter (2%–4% TOC), a number of brittle intervals separated by thicker intervals that fall slightly below the brittle-ductile threshold, and a strike-slip stress regime. At the scale of the study area, robust statistical techniques were used to invert seismic stacks and develop a 3D mechanical earth model. This model shows a trend of increasing shale brittleness towards the northeastern portion of the study area, hence suggesting that this area might be most prospective for initial shale gas development. The results of sensitivity analyses are presented, which illustrate the potential errors in the estimated geomechanical properties. Future work to improve confidence in the shale gas potential of the Sembar Formation is given, including extensive coring and laboratory testing, in-situ stress and natural fracture characterization, and better delineation of shale thickness.

3D mechanical earth model for Zubair oilfield in southern Iraq

During drilling operations, wellbore instability is one of the reasons that increase nonproductive time (NPT). Maintaining a stable wellbore is the primary importance during drilling by applying a proper geomechanical model to analyze and understand the distribution of stresses around the wellbore in order to minimize drilling risk and NPT. The lack of any geomechanical studies in Zubair oilfield in southern Iraq is one of the reasons that lead to wellbore stability-related problems and thus an increase in NPT. Petrel Geomechanics 2018 was used to show the distribution of the stresses and the mechanical properties. Showing the distribution of stresses in 3D MEM has big advantages in several ways, and one of them is to select the best path for any future directional wells. To mitigate wellbore stability problems and depending on the 1D mechanical earth models (MEM) results, a detailed 3D MEM was built for Zubair oilfield as the method to precisely pinpoint and diagnose those problems. The results of this study show two points; first is an abnormally pressured zone in Tanuma shale formation, and second, a narrow mud weight window in front of the Tanuma formation. As a conclusion, the mechanical earth model was an efficient tool in diagnosing and predicting geomechanics-related problems, thus suggesting an alternative mud weight program for the problematic zone, which is more important to reduce the most essential factor in the NPT.

Integrating Multi-Disciplinary Data for Building Fit-For-Purpose 3D Mechanical Earth Model

Understanding geomechanics influence early in the field development phase facilitates reservoir management planning. To capture complex geology and associated field development, a 3D Mechanical Ear...