Regional In-Situ Stress Prediction in Frontier Exploration and Development Areas: Insights from the First-Ever 3D Geomechanical Model of the Arabian Plate

In this paper, we present results from the first-ever 3D geomechanical model that supports pre-drill prediction of regional in-situ stresses throughout the Arabian Plate. The results can be used in various applications in the petroleum industry such as fault slip-tendency analysis, hydraulic fracture stimulation design, wellbore stability analysis and underground carbon storage. The Arabian tectonic plate originated by rifting of NE Africa to form the Red Sea and the Gulfs of Aden and Aqaba. The continental rifting was followed by the formation of collisional zones with eastern Turkey, Eurasia and the Indo-Australian Plate, which resulted in the formation of the Eastern Anatolian fault system, the fold-thrust belts of Zagros and Makran, and the Owen fracture zone. This present-day plate tectonic framework, and the ongoing movement of the Arabian continental lithosphere, exert a first-order control on the of in-situ stresses within its sedimentary basins. Using data from published studies, we developed a 3D finite element of the Arabian lithospheric plate that takes into account interaction between the complex 3D plate geometry and present-day plate boundary velocities, on elastic stress accumulation in the Arabian crust. The model geometry captures the first-order topographic features of the Arabian plate such as the Arabian shield, the Zagros Mountains and sedimentary thickness variations throughout the tectonic plate. The model results provide useful insights into the variations in in-situ stresses in sediments and crystalline basement throughout Arabia. The interaction between forces from different plate boundaries results in a complex transitional stress state (thrust/strike-slip or normal/strike-slip) in the interior regions of the plate such that the regional tectonic stress regime at any point may not be reconciled directly with the anticipated Andersonian stress regimes at the closest plate boundary. In the sedimentary basin east of the Arabian shield, the azimuths of the maximum principal compressive stresses change from ENE in southeast to ~N-S in northern portions of the plate. The shape of the plate boundary, particularly along the collisional boundaries, plays a prominent in controlling both the magnitude and orientations of the principal stresses. In addition, the geometry of the Arabian shield in western KSA and variations in the sedimentary basin thickness, cause significant local stress perturbations over 10 – 100 km length scales in different regions of the plate. The model results can provide quantitative constraints on relative magnitudes of principal stresses and horizontal stress anisotropy, both of which are critical inputs for various subsurface applications such as mechanical earth model (MEM) and subsequently wellbore stability analysis (WSA). The calibrated model results can potentially reduce uncertainties in input stress parameters for MEM and WSA and offer improvements over traditional in-situ stress estimation techniques.

Influence of Rock Plastic Behavior on the Wellbore Stability

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

Complex Approach to Green Fields Development and Fracturing Strategy by the Example of Pilot on the Field by Name of Alexandra Zhagrina

The article describes an approach to creating, in conditions of limited input information, a strategy for performing the first hydraulic fracturing operations on deviated and horizontal wells in the A. Zhagrin field. The field is in the active phase of exploration, the planned count is mainly composed of horizontal wells with multi-stage hydraulic fracturing. Approaches to the design of pilot works with control of the height of hydraulic fractures, which have proved their effectiveness by well logging studies and the obtained oil productivity, they have been successfully introduced into the technology of multistage hydraulic fracturing in horizontal wells. Due to the minimum number of reference wells, a significant area of the field (100 km2), the uncertainty of the distribution of water-saturated zones in the target and adjacent formations, the spread in the thickness of clay layers from 10 to 30 m, there is a risk of unwanted introduction of these interlayers by hydraulic fractures. The project team was able to assess the risks in terms of hydraulic fracturing, depending on the geological and physical characteristics (thickness of the target formation and clay layers, saturation) and in joint cross-functional work (with geological, geomechanical and hydrodynamic support) to implement hydraulic fracturing technologies that have confirmed their efficiency in oil production. To test hypotheses at the initial stage, various scenario conditions with a probabilistic assessment of uncertainties were selected at the deviated wells, as a result, the matrix of technological solutions was developed. In directional wells, the capabilities of technologies selected for pilot testing were confirmed using methods for diagnosing the height of hydraulic fracturing. The performed correction of stress profiles in a modern corporate hydraulic fracturing simulator increased the correctness of the 3D geomechanical model, which made it possible to optimize fracture geometry and horizontal wellbore drilling direction. Due to a thorough study of the conditions for the applicability of the considered hydraulic fracturing technologies, it was excluded the inclusion of water-saturated horizons without losing the effective half-length of hydraulic fractures. The workflow, during the implementation of which a matrix of solutions for successful well development was created, will ensure the achievement of planned oil production rates in the future for a field without rich field practice in hydraulic fracturing.

Impact of High Resolution 3D Geomechanics on Well Optimization in the Southern Gulf of Suez, Egypt

Optimizing the number of casing strings has a direct impact on cost of drilling a well. The objective of the case study presented in this paper is the demonstration of reducing cost through integration of data. This paper shows the impact of high-resolution 3D geomechanical modeling on well cost optimization for the GS327 Oil field. The field is located in the Sothern Gulf of Suez basin and has been developed by 20 wells The conventional casing design in the field included three sections. In this mature field, especially with the challenge of reducing production cost, it is imperative to look for opportunites to optimize cost in drilling new wells to sustain ptoduction. 3D geomechanics is crucial for such cases in order to optimize the cost per barrel at the same time help to drill new wells safely. An old wellbore stability study did not support the decision-maker to merge any hole sections. However, there was not geomechanics-related problems recorded during the drilling the drilling of different mud weights. In this study, a 3D geomechanical model was developed and the new mud weight calculations positively affected the casing design for two new wells. The cost optimization will be useful for any future wells to be drilled in this area. This study documents how a 3D geomechanical model helped in the successful delivery of objectives (guided by an understanding of pore pressure and rock properties) through revision of mud weight window calculations that helped in optimizing the casing design and eliminate the need for an intermediate casing. This study reveals that the new calculated pore pressure in the GS327 field is predominantly hydrostatic with a minor decline in the reservoir pressure. In addition, rock strength of the shale is moderately high and nearly homogeneous, which helped in achieving a new casing design for the last two drilled wells in the field.

Shallow Gas Reservoir Development in Offshore Field, Myanmar: Tapping New Reserves with Novel Approach

Discovered on the shallowest formation in Myanmar offshore field at 500 meters subsea, this reservoir is perhaps one of the most challenging reservoirs to develop in many aspects such as; risk of fracking to seabed when performing sand control completion, cap rock integrity and risk of breaching due to completion and production activities, reservoir compaction, and depletion-induced subsidence. Generally, the producing reservoirs currently developed in this field sits between 700 to 2500 meter subsea, mTVDss. Cased Hole Gravel Pack (CHGP) as sand control completion method is selected to develop the reservoir from 700 to 1650 mTVDss. None of the shallow reservoirs (shallower than 700 mTVDss approximately) has been developed in the field before, due to some technical challenges previously mentioned. Owing to these reasons, reservoir engineer and well completion team initiated feasibility study focusing on advanced Geomechanical modeling and alternative way of sand control completion combined with full project risk assessment, ultimately, to unlock huge gas reserves trapped in this field. The reservoir is finally developed with infill well and new completion technique ever been used in the company. To develop this shallow reservoir, infill well drilling with sand control completion is required. The technical analysis on the following problems was comprehensively performed to ensure that the reservoir was feasible, doable and viable to develop. Reservoir compaction and subsidence occurring with stress and pressure changes associated with depletions would not create potential hazard to production facilities. Cap-rock is stable with no breaching over entire life of reservoir depletion. No potential fault is reactivated upon depletion. Sand control completion is able to be performed safely with well-confined fracpack (risk of frac growth to seabed). Upon depletion, integrity of casing and cement is acceptable when reservoir is compacted. Full risk assessment aspects of completion operation are scrutinized. These problems were mainly analyzed using coupled 3D Geomechanical model focusing on this shallow reservoir in the area of this particular wellhead platform. Briefly speaking, the 3D Geomechanical model was coupled with reservoir pressure depletion to find stress and displacement of reservoir rock and casing due to production. The methodology is called one-way coupled modeling. To be more precise, the pre-production stress of the reservoir at initial pressure was determined and used to calculate subsequent stress change from depletion (production). Pressure depletion will increase effective stress and hence create deformation of reservoir rock which may induce underground subsidence and casing integrity. On this study, four stress-steps of pressure depletion were computed i.e. initial pressure, 25% depletion, 50% depletion and 75% depletion. On each step, stress equilibrium was simulated using finite element software. This project makes the pending development of shallow reservoir in this field doable and viable. All risks associated with well completion and production-induced depletion were deliberately reviewed and mitigated. Based on this study, the most critical risk is gas leak through seabed due to sand control completion activity (CHGP). Apart from this, the other risks such as seabed subsidence, cap-rock breaching, fault reactivation, and casing integrity upon compaction were consciously addressed, reviewed and prevented. The major risk on sand control completion was finally mitigated. The conventional extension pack was avoided and replaced with the completion technique, a so-called circulating pack. Circulating Pack is one of CHGP technique where the pumping rate and pumping pressure maintained below fracture extension rate and fracture extension pressure. This pumping rate and pumping pressure will not introduce the fracture in the formation but still able to carry proppants and place them in the annular between screen and casing to provide sand control means. Although the sand control performance of circulating pack is not up to High Rate Water Pack (HRWP) or Extension Pack, together with control of minimum drawdown and production rate will enhance the sand control performance and prolong production life. Ultimately, unlock the potential in this shallow reservoir. The well has finally been successfully completed under tailor-made design and real-time data acquisition. The reservoir has been producing successfully with the rate of about 5 MMSCFD with good flowing wellhead pressure at 590 psi similar to the design. Ultimately, this alternative approach enables the development of this shallow reservoir where the new reserves of 20 BSCF has been added to the project. This project can be a good lesson for future development of other shallow reservoirs worldwide.

Application of 3D Geomechanical Research for De-Risk and Improve High Pressure and High Temperature Well Drilling

Exploration focus is moving into deeper targets of high pressure and high temperature (HPHT) regime due to the ever-increasing energy demand of China. Overpressure and wellbore instability related problems in such setting are mainly associated with narrow drilling margin resulting in severe well control incidents and increased drilling cost. In order to reduce drilling risks and operation costs, an accurate geomechanical model is necessary. The model provides technical support for drilling process and minimum reservoir damage due to optimal mud weight program. Well-scale (1D) Mechanical Earth Model (MEM) is constructed on the offset wells which consist of rock strength properties and stress profile by incorporating all available data including open hole log data, geomechanical core lab results, LOT/FIT, direct pore pressure measurements and drilling events. Furthermore, 3D geomechanics model is generated using available well-scale MEM data in the field and distributed throughout the field which guided by seismic interpretation data as distribution control. The 3D geomechanical model is used to design mud weight and casing program for the upcoming well. The offset wells in the study areas were drilled through complex geological settings with high overpressure (13500 psi) and high temperature (200-220 deg C). Therefore, drilling operations is also risky with different types of drilling events encountered frequently including stuck pipe, inflow, losses and connection gas etc. With 3D geomechanical model as the foundation, the integrated approach helps ultra-deep wells to reduce serious wellbore instability caused by abnormal formation pressure, wellbore collapse and other complex drilling problems. The implementation of systematic and holistic workflow has proven to be extremely successful in supporting the drilling of HPHT wells in China. The integrated solution has been applied in the ultra-deep well, recorded an improvement in ROP by 35.3% and decrease no-productive time (NPT) by 25.3% compared with offset well. The geomechanical approach provides a convenient means to assist field engineers in the optimization of mud weight, risk assessment, and evaluation of HPHT wells drilling performance. The findings will provide reference and guideline for de-risk and performance improvement in HPHT wells drilling.

DETERMINATION OF DEFORMATION PROPERTIES AND NATURAL STRESSES IN ROCK MASS BY UNDERGROUND GEODESY DATA

The authors have developed and implemented a 3D geomechanical model using the finite element method for a typical configuration of an underground space during room-and-pillar mining. The authors formulate and solve an inverse problem on determination of values and orientation of external horizontal stresses and deformation characteristics of structural elements of the geotechnology by the measurement data of sidewall convergence in rooms in the course of mining. The level curves of different objective functions are analyzed, the mixed inverse problem resolvability is demonstrated, and the equivalence domain size is correlated with the relative error of input data.

Numerical Investigation on Shape Optimization of Small-Spacing Twin-Well for Salt Cavern Gas Storage in Ultra-Deep Formation

Small-spacing twin-well (SSTW) salt caverns have an extensive application prospect in thin or bedded rock salt formations due to their good performance, while they are rarely used in ultra-deep formations. The target strata depth of Pingdingshan salt mine is over 1700 m, and it is planned to apply an SSTW cavern to construct the underground gas storage (UGS). A 3D geomechanical model considering the viscoelastic plasticity of the rock mass is introduced into Flac3D to numerically study the influence of internal gas pressure, cavern upper shape and well spacing on the stability of an SSTW salt cavern for Pingdingshan UGS. A set of assessment indices is summarized for the stability of gas storage. The results show that the minimum internal gas pressure is no less than 14 MPa, and the cavern should not be operated under constant low gas pressure for a long time. The cavern with an upper height of 70 m is recommended for Pingdingshan gas storage based on the safety evaluation and maximum volume. The well spacing has a limited influence on the stability of the salt cavern in view of the volume shrinkage and safety factor. Among the values of 10 m, 20 m and 30 m, the well spacing of 20 m is recommended for Pingdingshan gas storage. In addition, when the cavern groups are constructed, the pillar width on the short axis should be larger than that on the long axis due to its greater deformation in this direction. This study provides a design reference for the construction of salt cavern gas storage in ultra-deep formations with the technology of SSTW.

Multidisciplinary Analysis of Hydraulic Stimulation and Production Effects within the Niobrara and Codell Reservoirs, Wattenberg Field, Colorado: Part 2 — Analysis of Hydraulic Fracturing and Production

Enhanced hydrocarbon recovery is essential for continued economic development of unconventional reservoirs. Our study focuses on dynamic characterization of the Niobrara and Codell Formations in Wattenberg Field through the development and analysis of a full integrated reservoir model. We demonstrate the effectiveness of hydraulic fracturing and production with two seismic monitor surveys, surface microseismic, completion data, and production data. The two monitor surveys were recorded after stimulation, and again after two years of production. Identification of reservoir deformation due to hydraulic fracturing and production improves reservoir models by mapping non-stimulated and non-producing zones. Monitoring these time-variant changes improves the prediction capability of reservoir models, which in turn leads to improved well and stage placement. We quantify dynamic reservoir changes with time-lapse P-wave seismic data utilizing pre-stack inversion, and velocity-independent layer stripping for velocity and attenuation changes within the Niobrara and Codell reservoirs. A 3D geomechanical model and production data are history matched, and a simulation is run for two years of production. Results are integrated with time-lapse seismic data to illustrate the effects of hydraulic fracturing and production. Our analyses illustrate that chalk facies have significantly higher hydraulic fracture efficiency and production performance than marl facies. Additionally, structural and hydraulic complexity associated with faults generate spatial variability in a well’s total production.