Towards successful drilling operations through geomechanical modelling and wellbore stability analysis: a case study on the Ouan Kasa reservoir in the Ghadames Basin, Libya

A high pressure well with a high risk of encountering a loss zone is a challenging drilling operation and requires a proper pre-drill study incorporating drilling practices, an understanding of the subsurface, and geomechanical modelling. This paper presents a case from the West Tuban Block. This block is within the East Java Basin, one of the prolific basins in Indonesia and a proven hydrocarbon reserve. The major challenge is drilling through the shale overpressure zone and the carbonate loss zone safely and successfully. This paper describes the building of a pre-drill geomechanical model, the subsequent wellbore stability analysis and how the results and recommendations were applied during drilling. The geomechanical model was built using data from seven offset wells and also incorporated regional knowledge. The offset well review of the drilling experiences showed that the key challenges that will need attention are significant drilling problems such as pack-off and tight hole while POOH, RIH with casing and while wireline logging. Added to this are instances of losses and gains while drilling the carbonate reservoir section. The geomechanical modelling process involves using petrophysical, geological, geophysical and drilling data to constrain the magnitudes of the overburden, pore pressure, rock mechanical properties and the two horizontal principal stresses. It is also important to constrain the azimuth of the maximum horizontal stress. The final model is verified using stress-related drilling problems and observations of wellbore failure in shale interpreted from caliper data. The resultant geomechanical model suggests that the planned well is associated with a strike-slip stress regime. The magnitudes and azimuths of the stresses play an important role in successful drilling because the well is directional in the reservoir section with a maximum inclination ∼26°. The wellbore stability analysis was used to optimise mud weights for each hole section of the planned well. Recommendations were also made regarding additional data gathering (cores for conducting rock tests, extended leak-off tests, full suite of logs, etc.) to reduce uncertainty in the geomechanical model. The mud weight and drilling practice recommendations, that were an outcome of the study, were followed meticulously by the drilling team so the well was able to safely overcome the overpressure zone and the loss zone. The effort contributed to the operator's success in the onshore development campaign with timely execution within budget and no reported HSE events.

Multiple issues have arisen during drilling in southern Iraq’s (F) oilfield. Most of these issues are connected to wellbore stability, including differential sticking, tight hole, and lost circulation. These issues have rendered nearly one-third of drilling operations fruitless. The development of a one-dimensional geomechanical model addresses these challenges and improves future drilling operations in this area. This work utilizes the geomechanical model to optimize drilling operation parameters and plan them in a way eliminate the wellbore stability problems. The approach adopted in this work is a 1D geomechanical model to predict the appropriate casing design and suggest a better mud weight using mechanical rock properties and stress analysis. The used geomechanical model evaluate the rocks mechanical properties and the primary stresses by using data and historical recorded drilling operations problems. Moreover, the rock strength parameters are also determined used extended leak off studies and empirical formulas. To estimate the mud pressure conditions for different wellbore inclinations, azimuths, and formations, the geomechanical model alters the in-situ stresses. This comprehensive research about mud pressure prediction allows for optimizing mud weight for each formation, and casing design in every area. Direct measurements (bulk density log, compressional slowness log, shear slowness log, gamma ray log, caliper log, and geological formation information) and petrophysical quality control checks are needed to develop the geomechanical model. Sonic log values are 55–120 s/ft, while gamma ray readings are 15–72 GAPI. From the formations geological evaluation, the density log provides an information about electron density. Where, in weak formations, in spite of UCS and Tensile Strength are 3000–4200 Psi, the Young’s Modulus and Poisson’s Ratio are low. Formation stiffness is positively connected with friction angle (sandstone, dolomite, shale, and limestone). Young’s Modulus and Poisson’s Ratio rock stress study yields vertical, maximum horizontal, and minimum horizontal stress values and pore pressure readings. Shale formations have 7550 Psi vertical stress, 6200 Psi maximum horizontal stress, and 5200 Psi lowest horizontal stress. The limestone layers have a vertical stress of 7800–8200 Psi, however the maximum horizontal stress is around 7000–7900 Psi, and a minimum horizontal stress is around 6000–7000 Psi. On the other hand, the pore pressure can be estimated direct and using hydrostatic methods. In this work case study, drilling mud used was heavy, therefore a pipe got trapped in the Dammam Formation and narrow regions in the Lower Fars Formation. Moreover, the pressure depletion in the Mishrif Formation caused wellbore differential sticking and washouts. The study using correlations and local data to determine the geomechanical features. The poro-elastic approach determines major horizontal stresses, however the extrapolation method determines vertical stress. The goemechanical model assesses mud pressure conditions and recommends mud weight and casing design for each formation segment. This assessment can work as a geo-proactive drilling model which help to prevent frequent wellbore stability issues, improve drilling efficiency and lower costs

Field Cluster E has a number of producing and non-producing fields. While drilling exploration and development wells in this block, there exists numerous wellbore instability issues. Major wellbore instability issues include total and partial losses in shallower overburden, shale instability in intermediate section, and depleted reservoirs in development wells. These wellbore instability issues lead to drilling operations related non-productive time (NPT). In order to minimize NPT related to wellbore instability issues, Geomechanical study is initiated. This paper discusses the role of Geomechanical modeling for successful well delivery in ongoing exploration and development targets. Understanding the state of stress and rock strength is very important for wellbore stability design. Comprehensive drilling analysis is carried out for number of offset wells to identify the drilling hazards. 1D Geomechanical models are built by integrating the data from drilling, geology, geophysics, petrophysics and reservoir engineering disciplines. Vertical stress is estimated by integration of density log from surface to reservoir TD. Pore pressure is constrained using Normal Compaction Trend (NCT) techniques, calibrated by formation pressure measurements. Formation Integrity Tests (FITs) are acquired and doesn't give any idea about minimum horizontal stress. In the absence of LOTs & rock mechanics tests, regional Oman experience is utilized. Orientation of maximum horizontal stress is determined using Caliper, Image logs and World Stress Map. Magnitude of Maximum horizontal stress is constrained using Stress Polygon Methodology. Knowing the magnitude and orientation of in-situ stresses, pore pressure and rock strength can help in evaluation of wellbore stability. 1D Geomechanical models are then calibrated against actual failure observed in Caliper log and wellbore instability events. These calibrated 1D geomechanical models are then utilized for predicting mud weight in upcoming exploration and development wells. Wellbore stability analysis has helped to predict optimum mud weight for a number of exploration and development wells. Detailed drilling hazard analysis and Geomechanical Modeling also helped to design optimum mud type for solving wellbore instability issues using specialized mud additives. Design and implementation of optimum mud weight and mud type using integrated geomechanical modeling and drilling fluid design has helped to drill number of vertical and highly-deviated wells with reduced NPT. The study has also helped to reduce or remove associated drilling hazards and facilitated successful well delivery by proactively working together between sub-surface and drilling engineering teams. This paper discusses the implementation of study results to one planned well in detail.

The Ordovician fractured carbonate reservoir in the Shunbei field is buried ~7300m below ground level and has presented great challenges for the drilling of extra deep, deviated development wells. Borehole instability-related drilling problems including pipe stuck, pack-off, and mud losses have been experienced frequently during drilling, with many wells being sidetracked three or four times before reaching the target. To understand the failure mechanism and optimize the drilling design to mitigate the drilling risk has become crucial for the field development. As the basis of the investigation, detailed geomechanical modelling was conducted for a selected area with the most representative drilling problems. Laboratory core tests, wireline logs, image data and drilling experiences were used to build geomechanical models characterizing the in situ stress, pore pressure and rock mechanical properties in both the overburden and reservoir sections. Stress-induced borehole failures observed in the image logs were analysed to help diagnose the failure mechanisms together with the cavings recovered from the problematic wells, which provided significant insights into the likely nature of instability problems in the wells. The geomechanical modelling from a series of wells revealed that the stress magnitudes in the selected area vary based on the structural location. The wells near the major fault system appear to be in a normal faulting stress regime in the Ordovician reservoir, while the wells nearby the secondary fault system are in a strike-slip faulting stress regime. Different stress regimes and horizontal stress anisotropies have resulted in different behaviors during drilling, with breakouts seen in some vertical wells while not in other vertical wells despite using similar mud weights. during drilling. The variable stress conditions plus the highly developed fractures have caused serious borehole collapse in some wells, but reasonably good hole condition in other wells. Wells using higher mud weight are not necessarily the ones having fewer drilling problems. Although the complex lithology, great depth, and unpredictable distribution of intrusive rocks has complicated the drilling problems, a proper definition of suitable mud weight to control borehole collapse and understanding of the natural fractures might play a bigger role in maintaining borehole stability and mitigating drilling risk. A good understanding of the stress condition and rock mechanical properties appears to be helpful in defining the proper mud weights and optimizing other drilling parameters to help mitigate the complex drilling problems encountered during drilling in the Shunbei field. However, additional work on the fracture distribution and trend of stress change in the field might be required to help investigate the problem further.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202146, “Successful Implementation of Geomechanics in a Deepwater Setting: A Case Study From KG Offshore India,” by Sarah Bhimpalli, ONGC; Ashok Shinde, Baker Hughes; and Bayye L. Rao, ONGC; et al. The paper has not been peer reviewed. _ Geomechanics plays an important role in assessing formation integrity during well construction and completion. In the complete paper, study field K belongs to a Plio-Pleistocene sequence in a deepwater environment with hydrocarbon prospects. As a part of exploration activity, four existing offset oil wells were considered for geomechanical model construction. The geomechanical model for the field was built by integrating available drilling, geology, petrophysics, and reservoir data. The methodology adopted in this paper highlights how a reliable geomechanical model can be built for a field with data constraints. Introduction The present study block is in deep water off the eastern Indian coast in the KG basin, with several hydrocarbon discoveries in a clay formation. These reservoirs have been deposited under marine conditions, and source rock is thought to be Eocene to Oligocene marine shale. During drilling, as the rock on the wellbore track was drilled and brought out of the hole, the drilling fluid would exert a corresponding pressure on the wellbore wall and the stress of the rock surrounding the wellbore would be redistributed, generating induced stress. To maintain wellbore stability, use of a drilling fluid of appropriate density (mud weight) to control induced wellbore stress is essential. Shear and tensile failures are the major causes of mechanical instability in boreholes. If it rises past the appropriate upper limit, drilling-fluid pressure can cause tensile failure in the wellbore wall; if lower than the appropriate lower limit, drilling-fluid pressure can cause shear failure in the wellbore wall. Because of several drilling complications and nonproductive time experienced during the exploratory phase, building of a geomechanical model for safe and cost-effective drilling during the development phase is necessary. The existing four wells (W, X, Y, and Z) targeted the hydrocarbon play. Using the data from the four offset wells, a comprehensive geomechanical study was completed. The main objectives of the study included pore-pressure prediction, wellbore-stability analysis, well-trajectory optimization, and sanding prediction. 1D Geomechanical Modeling To analyze wellbore stability, well logs, laboratory test results, and drilling reports of the wellbore were used to determine geomechanical characteristics of the drilled formations. The elastic properties, rock strength characteristics, in-situ stresses, and pore pressures are the most important geomechanical characteristics to be measured or calculated. The geomechanical model was built by integrating drilling, geology, petrophysics, and reservoir engineering data. The work flow to build the geomechanical model is presented in Fig. 2 of the complete paper. Vertical stress (Sv) was estimated by integration of density logs from seabed to reservoir. Pore pressure was predicted using normal compaction trend (NCT) on log data. Minimum horizontal stress (Shmin) was constrained using leakoff tests (LOTs) and mini- and microfracturing data. No rock-mechanical testing data were available, and rock properties were estimated from petrophysical logs using regional experience. Magnitude and orientation of maximum horizontal stress (Shmax) was constrained using the presence of stress-induced wellbore failures on image and caliper logs.

Successful underbalanced drilling (UBD) operations are strongly dependant on the understanding of in-situ stress condition in addition to rock mechanical properties. Wellbore integrity, which plays an imperative role in all the oil and gas operations, requires accurate geomechanical modeling and wellbore stability analysis. Borehole failure problems, which are very likly specially when drilling underbalanced, cost the petroleum industry several billions of dollars each year. Prevention of these problems requires clear understanding of the interaction between formation strength, in-situ stresses and drilling practice. Since in-situ stress and rock strength are not controllable parameters, adjusting the drilling practices, i.e. selecting optimal trajectory and bottom-hole pressure, is the common way to inhibit wellbore failure, which can be achieved by performing specialized geomechanical studies. Drilling through some challenging formations in Kurdistan, has been always associated with several wellbore stability problems such as mud losses, borehole washout, stuck pipe, extra cutting/caving, and tight holes, which caused numerous nonproductive time to the drilling program and required drilling sidetracks in some of the wells. Review of the drilling reports and dual-caliper logs from 11 offset wells in the area revealed a huge amount of washouts in these formations. These events put a question mark on the feasibility of UBD in these intervals and required conducting a geomechanical modeling and wellbore stability study. In this study, data from offset wells was analyzed to estimate the local in-situ stress magnitudes and orientations, in addition to pore pressure. The mechanical properties of the formations were evaluated using sonic, density, and gamma ray logs. A rock mechanical properties database and data management software was applied to correlate the calculated dynamic elastic properties to the most appropriate static stiffness parameters for a base case wellbore stability model and subsequent sensitivity analyses. 2D elastoplastic and 3D linear elastic models were used to back-analyze the borehole failures in the selected offset wells to verify and calibrate the geomechanical model. Finally, an operating mud weight window was defined, and the optimum profile of the mud weight was recommended for drilling through each formations. This study showed that underbalanced drilling is feasible through the carbonate intervals, however, will encouter severe wellbore stability problems in the shaly and silty formations.

Geomechanical modeling using finite element method for prediction of in-situ stress in Krishna–Godavari basin, India

The state of stress in SW Iran and implications for hydraulic fracturing of a naturally fractured carbonate reservoir

One of the major drilling problems encountered during oilfield exploration and development phases is wellbore instability. This largely occurs as a result of mechanical failure of the subsurface underlying rocks; with problems such as stuck pipe incidences, lost circulation, clay swelling accounting for about 5%-10% of total drilling expenses and resulting in non-productive time (NPT) and equipment loss and environmental concerns. To address these concerns, a geomechanical model is defined. Geomechanical Modeling involves the study of in-situ stresses induced in rock, due to well drilling, completion, fluid injection, temperature changes and the associated deformations and failure that occurs. It takes into account the rock strength and the pore pressure whilst describing the behavior of rock under mechanical disturbance. Typically, a Geomechanical model comprises of six components: Unconfined Compressive Strength (UCS), Pore Pressure (Pp), Vertical Stress, Minimum and Maximum Horizontal Stress and the orientations of the horizontal stresses. Log-based Stress Modeling offers a practical approach to characterize in-situ stress state profile of the subsurface formations. The knowledge of the mechanical properties and in-situ stresses of the subsurface formations is important, as it provides insights to the determination of optimal mud weight window, stable well trajectories, casing set points so as to minimize wellbore stability related problems. The data required is obtained from a suite of logs such as density, sonic, porosity, caliper and image logs. Stress magnitude information is needed as a continuous function of depth to proper characterization. Information about Stress orientation and constraining its magnitude is based on the observation of failure at the borehole wall which can also be detected by borehole logging tools. This dissertation employs series of techniques to characterize the magnitude of in-situ stresses. A one-dimensional geomechanical model is developed, by combining the stress information obtained, rock mechanical properties, formation pressures, observation of wellbore failure and defining the failure criteria for both borehole collapse and fracture breakdown. A wellbore stability study was done to determine an optimal mud weight window and the sensitivity of the obtained mud weight window to the minimum and maximum horizontal stresses was investigated.

This paper shows how a geomechanical model helped to reduce risks and non-productive time experienced in the past in a field in the Neuquén Basin (Argentina) operated by Petrobras Energia S.A. (PESA). Tight hole and stuck pipe were common problems in spite of the tight and strong formations in the field. Gas inflows were also experienced when drilling through the overpressured formations. All these events made the decision of building a geomechanical model for the field in order to optimize the drilling time. Pore pressure, stresses and mechanical rock properties were constrained based on good quality data set from eight wells. After that, the geomechanical model was validated using the caliper data and drilling experience. A key part of the model building was the estimation of pore pressure using wireline logs, gas inflows during the drilling, production data and minifrac tests. Overpressured zones were identified improving the design of the casing depths for new wells, minimizing the risks of kicks while maintaining the wellbore stability. Based on the remaining uncertainties of the model, an update phase was recommended to be done after the collection of new data such as image logs in the well to be drilled. After drilling the new well using the recommendations of the geomechanical model, the drilling experience showed that the well was drilled almost without non-productive time (NPT) through the same formations where in the past tight holes and stuck pipes were experienced. A good image data collected in the drilled well showed that the breakouts stayed below the catastrophic limit, confirming that the mud weight was correctly recommended in the phase 1, maintaining the wellbore stability without reducing the ROP. Also, the observed breakout orientation and width confirmed the orientation and magnitude of the maximum horizontal stress constrained in the phase 1.

Analysis of wellbore stability by pore pressure prediction using seismic velocity

A preliminary study of the present-day in-situ stress state in the Ahe tight gas reservoir, Dibei Gasfield, Kuqa Depression

Hydraulic fracturing optimisation for tight sandstone requires a reliable geomechanical model in the reservoirs and bounding formations to achieve an optimum production after fracturing. This paper presents a case study of Upper Cibulakan tight sandstone reservoirs in an oil field located in Offshore Northwest Java, Indonesia. Field structure is composed of multiple reservoir sandstones with interlayer shales. Two sandstone units with gross thicknesses up to 60 feet, effective porosity of 15% and permeability of 8 mD were targeted for hydraulic fracturing. An integrated approach is proposed to use available offset wells data, real-time acoustic logs, calibrated geomechanical model, and miniFrac and Step-rate tests to optimise hydraulic fracturing parameters and treatment schedule. In pre-fracturing stage, geomechanical model was developed for target intervals using offset wells data including fracture closure pressures from past miniFrac tests. To estimate the reservoir and bounding formations Young’ modulus and Poisson's ratio, compressional and dipole shear wave slowness logs as well as bulk density logs from offset wells were used. Poroelastic minimum horizontal stress in the sandstone intervals was calibrated with closure pressure data while bounding shale stress was calibrated with regional leak-off pressures. The final stress model of offset wells was verified with the borehole condition and drilling experiences. Target well for hydraulic fracturing was drilled with a 12¼° wellbore, 45 degrees deviated and oriented sub-parallel to maximum horizontal stress azimuth (north south). Processed acoustic logs were used to revise the pre-frac rock mechanical properties which verified the low ranges of static Young's modulus. Analysis of mini fall-off tests revealed important information about reservoir pressure depletion of ~250 psi which was not captured by offset wells pore pressure data. Pore pressure profile across the reservoirs was modified and depletion induced poroelastic stresses were estimated. Stress profile calibrated with actual closure pressure data from miniFrac test integrated with actual reservoir pressure revealed the stress contrast of up to ~350 psi between reservoir sandstones and bounding shales, which is favorable for fracture containment. Calibrated Geomechanics model was used to update the treatment schedule for main hydraulic fracturing including optimisation of size, volume and concentration of injected proppants and volume of fracturing fluid. Integrated Geomechanics modelling with acoustic logging and fracturing design enabled to achieve a successful hydraulic fracturing stimulation by exceeding the planned production rate. Post fracturing production test showed initial rate of approximately 50-barrel oil per day (bbl/d) higher than expected production rate from stimulated reservoir volume. Calibrated geomechanics model provided valuable inputs for proppant size and conductivity optimisation to reduce the effects of proppant embedment as well as proper estimation of injected proppant volume based on robust minimum horizontal stress profile to minimize the risk of unwanted vertical fracture propagation to other zones such as water.

Knowledge of the distribution of the rock mechanical properties along the depth of the wells is an important task for many applications related to reservoir geomechanics. Such these applications are wellbore stability analysis, hydraulic fracturing, reservoir compaction and subsidence, sand production, and fault reactivation. A major challenge with determining the rock mechanical properties is that they are not directly measured at the wellbore. They can be only sampled at well location using rock testing. Furthermore, the core analysis provides discrete data measurements for specific depth as well as it is often available only for a few wells in a field of interest. This study presents a methodology to generate synthetic-geomechanical well logs for the production section of the Buzurgan oil field, located in the south of Iraq, using an artificial neural network. An issue with the area of study is that shear wave velocities and pore pressure measurements in some wells are missing or incomplete possibly for cost and time-saving purposes. The unavailability of these data can potentially create inaccuracies in reservoir characterization n and production management. To overcome these challenges, this study presents two developed models for estimating the shear wave velocity and pore pressure using ANN techniques. The input parameters are conventional well logs including compressional wave, bulk density, and gamma-ray. Also, this study presents a construction of 1-D mechanical earth model for the production section of the Buzurgan oil field which can be used for optimizing the selected mud weights with less wellbore problems (less nonproductive time ). The results showed that an artificial neural network is a powerful tool in determining the shear wave velocity and formation pore pressure using conventional well logs. The constructed 1D MEM revealed a high matching between the predicted wellbore instabilities and the actual wellbore failures that were observed by the caliper log. The majority of borehole enlargements can be attributed to the formation shear failures due to an inadequate selection of mud weights while drilling. Hence, this study presents optimum mud weights (1.3 to 1.35 g/cc) that can be used to drill new wells in the Buzurgan oil field with less expected drilling problems.

We evaluate the in situ stress field and consequent risk of fault reactivation in the Bight Basin in order to assess the risk of fault seal breach at seismically mapped prospects. Borehole breakouts interpreted from dipmeter and image logs in five wells in and around the Bight Basin indicate a 130° maximum horizontal stress orientation. The large variation in water depths across the Bight Basin requires the use of effective stress magnitudes. We use a depth-stress power relationship to define the effective vertical stress based on density log data from 10 wells. The effective minimum horizontal stress gradient is estimated at 6 MPa/km using effective pressures from leak-off tests. We determine an upper bound (18.7 MPa/km) for the effective maximum horizontal stress gradient, using frictional limits to stress. The upper bound to the effective maximum horizontal stress indicates the region is in a strike-slip faulting stress regime. However, a normal faulting stress regime cannot be ruled out. Pore pressure in wells in the region is hydrostatic except in Greenly 1 where mild overpressure occurs below a depth of 3600 m.We use the FAST technique to evaluate the risk of fault reactivation in the Bight Basin. The risk of fault reactivation and consequent seal breach is expressed in terms of the pore pressure increase that would be required to induce failure. We consider three different stress regimes. These include a strike-slip faulting stress regime, a normal faulting stress regime, and a case on the boundary of strike-slip and normal faulting stress regimes. In all three cases, faults striking 40° (±15°) of any dip are the least likely to be reactivated.