EAGE/SPE Workshop on Integrated Geomechanics in Exploration and Production

Faults and fractures in hydrocarbon reservoirs are key to some major production issues including (1) varying productivity of different well sections due to intersection of preferential flow paths with the wellbore, (2) varying hydrocarbon column heights in different reservoir compartments due to differences in the sealing capacity of faults, and (3) water breakthrough along preferential flow paths in case of production assisted by water injection. Dynamic coupling of mechanical responses to flow and properties of faults and fracture networks should be incorporated in the geomechanical analysis of reservoir behaviour during injection and production. In particular, if local stress changes lead to fault reactivation. In this paper, a geomechanical production optimization workflow is presented that includes well-based models of local stress state and geomechanical reservoir properties, analytical or generic numerical models to perform sensitivity studies, and full field numerical models of the 3D spatial distribution of stress and deformation. The models determine fracture-controlled reservoir behaviour that can be used to perform geomechanical production optimization. It determines the optimum conditions for injection and depletion to achieve maximum hydrocarbon production with a minimum number of wells and a minimum number of stimulation operations, taking into account reactivation of faults and fractures.

In tight oil and gas reservoirs, the drainage area per well is relatively small in comparison with conventional reservoirs, so the drilling and stimulation of infill wells is a common practice to accelerate production. However, pressure changes due to production lead to anisotropic changes in the magnitude and orientation of the stresses across the reservoir, and this can affect the fracture geometry on the infill wells. For instance, depletion-induced stress changes have been associated with the development of asymmetric fractures, destructive well interference and production decline ( Mukherjee, et al., 2000 ; Ajani & Gajanan, 2012 ; Kurtoglu & Salman, 2015 ). Yet, one could argue that the impact of depletion-induced stress on the geometry of hydraulic fractures would depend on how much the stress field is modified by depletion and on the relative contribution of other variables such as the rock fabric, the in-situ stress anisotropy, the distance among wells and the production time among other variables. To fully plan and optimize the placement of infill wells, the interplay among these variables must be understood. In this paper we give a step in this direction and study, via numerical simulations, the potential scenarios in which asymmetric fractures can develop. The relative weight of two variables is considered: the depletion-induced stress and the rock fabric.

An oil company is currently preparing the Field Development Plan for a deepwater gas field, offshore Malaysia. A decline in field pressure of 2500psi over a period of 10 years is expected to give rise to large amounts of reservoir compaction, lateral deformations, and associated seabed subsidence, which will necessitate careful design considerations for planned production wells and seabed facilities. A series of fully coupled 3D analyses was carried out in order to predict an envelope of anticipated deformation, both in the reservoir and in the overburden to the sea floor.

Having established a representative field-wide stress condition throughout the production schedule, a 3D near-wellbore model was constructed to assess a preliminary casing string and completions design for a future appraisal well to be drilled to acquire further logs and cores. The operator would ideally like this well to become a “keeper” and side-track within the reservoir, thereby turning the appraisal well into a producer.

The results of both the field-wide and near-wellbore analyses with regard to reservoir compaction, seabed subsidence, and wellbore deformations throughout the anticipated life of the field highlighted the design considerations necessary for well integrity and subsea architecture.

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Historical trends show that most of the wellbore stability issues resulting from hole instabilities have been attributed to shaly formations. However, in this paper, a real experience has been described where severe formation instability issues were reported in a thick sequence of carbonates overlain by a well-known problematic shale unit and with detailed investigation, it was found that the root cause of all the wellbore instability was failure of weak carbonate zones which co-exist with very strong carbonate in alternating sequence. Comprehensive analysis of drilling data and geomechanical analysis from multiple wells across the field were integrated to understand the pattern of drilling problems and their relationship with rock mechanical properties of unstable formation intervals. Based on the geomechanical analysis and drilling experience, the recommended mud parameters and drilling practices were gradually applied in upcoming wells and visible improvement was noticed in drilling performance.

Tanggulangin oil and gas field is located in Northeast Java Basin, is one of the important operation area in East Java, was firstly explored through drilling operation in 2001, and has already produced significant oil and gas for PT.Lapindo Brantas. Production optimization through additional drilling campaign and more detailed geomechanical analysis is needed to increase the production and avoid undesirable cost. Wellbore stability became the most important aspect to be analysed as most of the wells in Tanggulangin encountered significant wellbore problems. Some of the problems were gas kick, stuck pipe, mud losses, sloughing shale, ballooning effect, and mud flowing, are very common in this overpressured area. We find several factors that influence wellbore stability in Tanggulangin field, they are: shallow gas potential, swelling clay (shown by smectite-illite content in the rock sample), accuracy of LOT measurement, mud management and soft sediment which shown by low rock strength value (5–10 MPa). Accurate of pore pressure prediction and LOT measurement will reduce wellbore stability risk.TGA-5 was drilled without any significant problem, ensure us that the drilling campaign in Tanggulangin can be improved effectively.

The paper assesses the economic and technical feasibility of producing not easily recoverable reserves in the northern part of the North Sea, specifically the Alness Formation. In the 1980’s, a test well was drilled in the Alness and was found to be uneconomic. The project was abandoned. To reassess the Alness, we developed an innovative method using the original 1980’s 2D seismic reflection, core, and well log data in a modern workflow. This method followed a sequential four-phase workflow spanning (1) Geomechanics and Petrophysics, (2) Geophysics, (3) Reservoir Simulation and, (4) Completion and Stimulation Engineering. We used the method to determine the feasibility of targeting a horizontal well in the Alness. It would be one of the first horizontals in this formation.

This study focused on the sandstones of Wajid Group in the outcrop in Wadi Al-Dawaser and Tathalith areas as an analogue of the groundwater aquifers and hydrocarbon reservoirs in Wajid and Rub’ Al-Khali Basins. Wajid Group in the outcrop divided into four formations from the bottom up, Dibsiyah, Sanamah, Khussyayan, and Juwayl. The geomechanical and sedimentological properties of studied sandstones have been determined, and the relationship between these properties has been defined. The geomechanical properties of the studied sandstones were measured in the field using the Schmidt rebound hammer and in laboratories by the uniaxial compression test. And, the sedimentological characteristics of studied sandstones also described in the field and laboratories(thin section analysis). The uniaxial compressive strength(UCS) and the static Young’s modulus of 81 sandstone samples were obtained. The result showed that Wajid Group can be divided into 27 mechanical units (Dibsiyah(18), Sanamah(2), Khussyayan(3) and Juwayl (4)). The geomechanical result revealed that the Dibsiyah and Khussyayan Formation display a similar geomechanical behavior, however, the Sanamah and Juwayl Formations are similar with mechanical properties values higher than Dibsiyah and Khussyayan Formations. Thus, this geomechanical similarity corresponding with similarity in depositional environments, where, the Dibsiyah and Khussyayan Formation deposited in fluvial to shallow marine environment, whereas, the Sanamah and Juwayl Formation deposited in glacial to the glacio-fluvial environments. the integrated results showed that the variation of the geomechanical behavior of studied sandstone mainly controlled by the percent of cemented materials. Thus, the increasing in the geomechanical values of studied sandstone is corresponding with increasing in cement materials percentage, and vice versa. The findings of this study will help to understand the geomechanical behavior of studied sandstone that hosting groundwater and hydrocarbon in Wajid and Rub’ Al-Khali basins. Moreover, the results of this study can be used to predict the relative geomechanical behavior of studied sandstone in the subsurface based on their sedimentological characteristics. thus, This study will help to enhance the groundwater and hydrocarbon exploration in Wajid and Rub’ Al-Khali Basins.

This paper presents and discusses field implications of a breakthrough geomechanics modeling software suite ELFEN for cost effective hydraulic fracture design and optimization. ELFEN is the first commercially available software suite that offer multiple unconventional geomechanics capabilities under one umbrella. These integrated breakthrough capabilities can accurately capture: (i) “true” 3D hydraulic fracture propagation with arbitrary/curving paths; (ii) near wellbore stress field and perforation architecture with implications to fracture tortuosity and breakdown; (iii) DFN stimulation integrated with induced seismicity and proppant transport; (iv) multi well interference and fracture-fracture interactions with stress shadows; (v) full cycle of fracture initiation, propagation, production and re-fracturing; (vi) multi-mode failure with tensile, shear and compaction localization; (vii) ductile-brittle transition through the utilization of advanced constitutive models; (viii) stress dependent permeability and fracture closure; (ix) fracture height growth in laminated/anisotropic rocks; (x) natural fracture evolution and characteristics.