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.

Geomechanical analysis of horizontal wells in terms of stability for drilling — A case study from the Peri-Baltic Syneclise

This paper presents a shale gas field geomechanics case study in the Peri-Baltic Syneclise (northern Poland). Polish Oil and Gas Company drilled a vertical well, W-1, and stimulated the Silurian target. Next, a horizontal well, W-2H, drilled the Ordovician target and partially collapsed. The remaining interval was stimulated, and microseismic monitoring was performed. A second horizontal well, W-3H, was drilled at the same azimuth as W-2H, but the well collapsed in the upper horizontal section (Silurian). A geomechanical earth model was constructed that matches the drilling experiences and well failure observations found in wells W-1, W-2H, and W-3H. The field was found to be in a strike-slip faulting stress regime, heavily fractured, with weak bedding contributing to the observed drilling problems. An analysis of safe mud weights, optimal casing setting depths, and optimal drilling directions was carried out for a planned well, W-4H. Specific recommendations are made to further enhance the model in any future studies. These recommendations include data acquisition and best practices for the planned well.

Prior Analysis in Determination of TI Anisotropy Type through Well-Based Modelling: A Case Study on the Deep Water Environment

The existence of anisotropy phenomena in the subsurface will affect the image quality of seismic data. Hence a prior knowledge of the type of anisotropy is quite essential, especially when dealing with deep water targets. The preliminary result of the anisotropy of the well-based modelling in deep water exploration and development is discussed in this study. Anisotropy types are modelled for Vertical Transverse Isotropy (VTI) and Horizontal Transverse Isotropy (HTI) based on Thomsen Parameters of ε and γ. The parameters are obtained from DSI Logging paired with reference δ value for modelling. Three initial conditions are then analysed. The first assumption is isotropic, in which the P-Wave Velocity, S-Wave Velocity, and Density Log modelled at their in-situ condition. The second and third assumptions are anisotropy models that are VTI and HTI. In terms of HTI, the result shows that the model of CDP Gather in the offset domain has a weak distortion in Amplitude Variation with Azimuth (AVAz). However, another finding shows a relatively strong hockey effect in far offset, which indicates that the target level is a VTI dominated type. It is supported by the geomechanical analysis result in which vertical stress acts as the maximum principal axis while horizontal stress is close to isotropic one. To sum up, this prior anisotropy knowledge obtained based on this study could guide the efficiency guidance in exploring the deep water environment.

The Mechanical Stratigraphy of Kerendan Field in Upper Kutai Basin: Implication to Field Development with Massive Carbonate Tight Gas Reservoir

Understanding of field mechanical stratigraphy in terms of formation behavior due to coupled interaction between formation pressure depletion and state of stresses is crucial to achieving successful field development. These provide technical advantages of having a solid foundation for implementation in advanced well construction and completion strategy, especially in light of emerging and challenging plays related to unconventional reservoirs. This paper describes full-field interaction between formation behavior in 4D Geomechanical analysis of Kerendan Field located in Upper Kutai Basin, Central Kalimantan area on gas-condensate production from massive carbonate tight gas reservoir. Integrated 1D/3D/4D geomechanics study workflow result has enabled characterization of each mechanical stratigraphy unit, as follows: The overburden section is comprised of Miocene deltaic clastic succession which is characterized as “soft formation” with low stiffness (Static Young’s Modulus of 0.5 to 1.8 Mpsi) and low - medium rock strength (UCS of 800 to 2000 psi); Reservoir section comprised of Oligocene tight carbonates platform which characterized as “hard formation” with medium stiffness (Static Young’s Modulus of 3.0 to 4.5 Mpsi) and medium rock strength (UCS of 5000 to 6900 psi); Underburden section comprised of Eocene mixed-carbonate clastic succession and Pre-Tertiary metasediments which characterized as “very hard formation” with high stiffness (Static Young’s Modulus of 4.5 to 5.0 Mpsi) and medium rock strength (UCS of 6500 to 7900 psi). The Kerendan field would require implementation of special drilling and stimulation techniques in order to achieve optimum full field development potential owing to its reservoir characteristics. The field’s exhibit a large areal extent and massive tight limestone reservoir with relatively high Young’s Modulus, which is favorable for the utilization of extended reach drill (ERD) / horizontal wells followed with multi-stage acid fracturing stimulation. 3D/4D Geomechanical analysis is essential to assess the drillability and engineering limits of various development scenarios which will be strongly controlled by geomechanical fabric, pre-existing deformation/local discontinuities, prevailing principal stress tensor and stress changes during field production.

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.

Integrated Workflow Solutions Deliver Breakthrough in Sichuan Shale Gas Drilling

The Sichuan shale gas deposits are in remote, mountainous regions and the gas-bearing rocks are deep and in tectonically complicated areas. The plan to make shale gas account for more than 40% of the Chinese total natural gas production by 2040 requires shorter well delivery periods and higher well productions. It is therefore crucial to improve the overall drilling efficiency with the limited rig capability and geological challenges. To improve capital efficiency, a multi-disciplinary approach integrating subsurface understanding with well engineering and drilling practices was implemented. Central to this drilling optimization effort are risk mitigation strategies, utilizing solutions based on robust geomechanical understanding and critical drilling experience reviews, engineered to improve wellbore placement, drilling fluid formulation, and bit and BHA designs. A novel wellbore-strengthening oil-based mud system was implemented to maintain shale stability. A rotary steerable drilling system and reservoir navigation technology were deployed together with the application of specific poly-crystalline diamond compact (PDC) bit design. A new-generation advanced cuttings analysis method was also applied with the lithology, organic matter and fracability of rock could be evaluated in real time to assist the reservoir navigation during the drilling. This integrated solution was deployed in the drilling of 8 ½" holes of Changning Shale gas field. A cross-functional team was formed so that the operator, the drilling contractor and the service company can collaborate closely with expertise across multiple functions and disciplines. Suitable mud weight was provided by the detailed geomechanical analysis to account for the high pore pressure and near bed-parallel drilling conditions. To place the laterals in the thin targeted sub-layer with high TOC, a rotary steerable system (RSS) with azimuthal GR provide not only precise steering and directional controls, but also enable increased reservoir coverage by expanding the lateral section as well as drilling the build and horizontal sections in a single run without BHA trips. The combination of RSS with specialized bits as an optimized bit and BHA system maximizes the steering performance while delivering superior borehole quality by reducing drill string vibration and the minimizing mechanical specific energy, all of which contribute to the overall improvement in the well delivery efficiency. This integrated drilling solution has achieved remarkable results by doubling the average rate of penetration (ROP) to 15.5m/h compared to an offset well on the same pad of 7.4m/h. The well was placed successfully in the targeted zone with a 100% reservoir contact. And the total drilling time was shortened by 40% compared to similar wells nearby. The integrated solution has brought breakthrough to improve the well delivery efficiency in the China shale gas development. This paper describes the integrated workflow solutions and detailed technical optimizations of the 8 ½" section drilling process.

Geomechanics Insights for Successful Well Delivery in Complex Kutch - Saurashtra Offshore Region

Subsurface lithofacies sequences encountered in the Kutch & Saurashtra Basin has its own set of challenges brought about due to its complex geological settings. These challenges are related to drilling, logging and completion and demand rigorous planning for the upcoming wells with detailed analysis of hazards associated with the overburden and reservoir rocks. In the study, these challenges are found to be linked with three prime geological sequences. Detailed integrated geomechanical analysis with inputs from drilling parameters, real-time formation experience, geophysical and geological are conducted for the improvement in borehole condition and improvising the effective drilling rate. A customized geomechanical workflow has been adopted to construct Mechanical Earth Model (MEM, Plumb et al., 2000) for strategic wells across the basin. Wellbore stability events related to geomechanics were reproduced and analyzed. The cause of the events was established and mitigatory methods were proposed. In addition, stress orientation along the wellbore trajectory and across the basin was estimated using breakouts identified on images and multi-arm calipers. Fast shear azimuth from Dipole Shear Sonic anisotropy analysis was also integrated to provide more robust and accurate estimates. Wells in the region are characterized by slow ROP, high torque and drag, wellbore instabilities (severe held ups, cavings, stuck pipes, string stalling etc.) and challenges while logging and running casing. The study has characterized these challenges and identified required solutions linked to the three geological sequences - weak Tertiary, Late Cretaceous Deccan Trap and Early Cretaceous to Jurassic clastic formations. The Tertiary formations are relatively weak (UCS∼300 to 1500psi) and prone to sanding and cavings due to breakouts. MEM based mud weight window estimation predicts that shear/failure hole collapse can be prevented using 10ppg to 11ppg mud weight. The formations below the Deccan Trap are locally categorized under Mesozoic sequence. The Deccan Trap and Mesozoic formations are extremely hard, tight, extremely stressed, heavily fractured and in some areas are also of HPHT nature. Rock strength shows a wide variation (UCS ∼5,000psi to 25,000psi) making bit selection a difficult task. Borehole failure is complex and cuttings analysis shows the signature of both shear and weak plane failure. Fractures on the image logs, rotation of breakouts, and fast shear azimuth support this theory. Mixing fracture sealing agents along with the use of optimal mud weights is found to be the most likely drilling solution. The understanding developed in the region and implementation of recommended steps assisted in successful drilling of two recent wells wherein gun-barrel shape borehole condition in both Tertiary and the Mesozoic sequence was achieved. The non-productive time was reduced by nearly 40 days increasing the effective ROP by 40%. In addition, smooth borehole prevented any major issues while carrying out casing and cementing operations.

Fracture Hits Mitigated Successfully in High-Pressure Stimulation Offshore Black Sea

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 201422, “Successful Mitigation of Fracture Hits in High-Pressure Stimulation Using Bottomhole Gauges and an Optimized Engineering Design, Offshore Black Sea,” by Gabrijel Grubac, SPE, Radu Patrascu, and Peter Janiczek, SPE, OMV, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. This paper presents a case study of fracture interaction mitigation in a multistage horizontal stimulation of an offshore Black Sea well. The authors discuss a multifaceted approach in applying lessons learned and pre-job geomechanical analysis of depletion-induced stress differential and its effects on fracture interactions. Intrastage fracture interference presents unique challenges that typically are managed on a case-by-case basis. This study aims to present critical analyses that are paramount to planning stimulation treatments in highly depleted segments and reservoirs with close-proximity wells. Project Background The operating company began a field redevelopment project in 2013 for a field in the Black Sea that was already producing from horizontal wells with multi-staged fractured wells. The project comprises three treatment wells (A, B, and C) and seven offset wells (1 through 7). Because of time-critical operations and related costs, the original treatment wells and sidetracks (5,000-m-long measured depth horizontals) were completed with multistage stimulation sleeves and were operated by a ball-drop system from the surface. Infill drilling was implemented with the newly added sidetracks because of the maturity of the field and the desire to optimize the hydrocarbon drainage process. Well C was the first infill well. A multi stage fracturing campaign for Well C began in 2015. The complete paper presents a detailed discussion of issues—including strong fracture communication—identified, and mitigation steps attempted, during the infill project. Various simulation methods and depletion models that were tried and later rejected are also discussed. Several investigations were begun into how to predict, and subsequently avoid, fracture-driven interactions. Industry practice with huge quantities of water injection in the offset wells was not feasible because of the already-low economics of the treatment wells. A half-iterative process between reservoir modeling and fracture modeling was begun, and an actual reservoir pressure-depletion map was created on a sector basis. Similarly, the fractures were simulated using a grid-oriented fracture simulator in full 3D. Using this approach, it was also possible to match previously identified communication between wells and highly nonsymmetric fracture growth. The initial plan for the recent multi-stage fracturing campaign was to drill all wells closer in time to reduce localized depletion and to allow initial fractures from offset wells to act as a stress barrier to mitigate fracture growth in the direction of those wells. A matched reservoir and geomechanical model was used for the fracture simulation, and the actual depletion map for different time regimes was introduced. It was decided to redesign the fracture treatments and to shut in the offset wells 36 hours before the treatment, and to keep them shut in during the entire stimulation operation. At that point, it became clear that reservoir pressure depletion was one of the main causes of communication and also impeded optimal fracture geometries and hydrocarbon recovery.