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Barton, Colleen (Baker Hughes) | Izadi, Ghazal (Baker Hughes) | Tinnin, John (Baker Hughes) | Randazzo, Santi (Baker Hughes) | Ghadimipour, Amir (Baker Hughes) | Bouzida, Yasmina (Baker Hughes) | Leseur, Nicolas (Baker Hughes)
Abstract The Diyab Reservoir is an unconventional prospect in Abu Dhabi where previous exploration efforts revealed thin low permeability targets, unsuccessful stimulation, and poor well placement. This early field experience coupled with limited knowledge about local in situ stress and the impact of faults and subseismic fractures to affect hydrofracs led to a concentrated field data acquisition program together with a fully integrated 3D reservoir simulation approach to assess Producibility, Fracability and Geohazards in the Diyab. The fit-for-purpose field data acquisition program, 3D hydraulic fracture simulation, and reservoir flow modeling helped establish a baseline understanding of the relationship between 3D reservoir characterization and proppant transport. Seismic data was interpreted to understand structural components and natural fracture characterization. Elastic inversions were performed on this data using petrophysical models to populate high-resolution 3D geological and geomechanical models calibrated against log derived rock properties and in situ tests. A detailed analysis of core identified bitumen layers and thinly laminated mudstones that have the ability to undermine completions by causing horizontal hydraulic fracture growth and undesirable proppant migration. Physics-driven frac simulation of this fully integrated geomodel was performed to determine design completion and fracking strategies for the target reservoirs. Post frac analysis for three Diyab wells reveals that the ISIP varied significantly among the stages and the largest post frac pressure drops occurred at stages intersected by small-scale faults or natural fracture zones, particularly when they are well oriented for shear slip. Results of high-resolution 3D simulation of frac stages on earlier wells showed proppant distribution closely followed reservoir property distributions of low stress and similar Young’s Modulus values. Wells were landed in specific target reservoirs, however, the simulation demonstrated that proppant from some stages was inadvertently placed in overlying reservoirs. The natural fractures play a significant role in stage efficiency indicating the need to utilize non-geometric completion design. Simulating the role of natural fractures to create reservoir access indicated significant differences in propped height and length within naturally fractured stages. Dual permeability pre-frac reservoir modeling based on frac simulation results predicted cumulative gas rates for the new wells.
Izadi, Ghazal (Baker Hughes, a GE company) | Mahrooqi, Shabib (Petroleum Development Oman) | Shaibani, Mahmood (Petroleum Development Oman) | Dobroskok, Anastasia (Petroleum Development Oman) | Guises, Romain (Baker Hughes, a GE company) | Barton, Colleen (Baker Hughes, a GE company) | Ghadimipour, Amir (Baker Hughes, a GE company) | Randazzo, Santi (Baker Hughes, a GE company) | Bratovich, Matt (Baker Hughes, a GE company) | Tinnin, John (Baker Hughes, a GE company) | Walles, Frank (Baker Hughes, a GE company) | Khamatdinov, Rafael (Baker Hughes, a GE company) | Franquet, Javier (Baker Hughes, a GE company) | Perumalla, Satya (Baker Hughes, a GE company) | Freitag, Hans-Christian (Baker Hughes, a GE company)
Copyright 2020, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Dhahran, Saudi Arabia, 13 - 15 January 2020. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.
Izadi, Ghazal (Baker Hughes, a GE company) | Guises, Romain (Baker Hughes, a GE company) | Barton, Colleen (Baker Hughes, a GE company) | Randazzo, Santi (Baker Hughes, a GE company) | Mahrooqi, Shabib (Petroleum Development Oman) | Shaibani, Mahmood (Petroleum Development Oman) | Dobroskok, Anastasia (Petroleum Development Oman)
A fit-for-purpose integrated subsurface study was carried out in a tight gas field in Oman to evaluate the stimulation process in horizontal wells. The objective is to explore the role of vertically and laterally heterogeneous in situ stress for hydraulic fracture (HF) propagation, and to quantify its effect on hydraulic fracture stimulation efficiency using a 3D fully-coupled hydraulic fracturing simulator for complex geological conditions. The use of advanced simulation tools that realistically predict the evolution of stresses in 3D allows us to explore the parameter space required to optimally design stimulations for complex tight and unconventional field development [Izadi et al. 2017; Cruz et al. 2018; Izadi et al. 2018].
The goal of this study is to test scenarios that increase production through reservoir contact by use of various fracturing techniques that improve the Stimulated Rock Volume (SRV).
The modeling scenarios include an assessment of:
The impact of high vs. low
The impact of in situ stress magnitude in near wellbore conductivity
The impact of fluid properties and landing zone on proppant transport
The effect of laminations on proppant transport
The impact of HF/natural fracture interactions on SRV
This study illustrates that for complex reservoirs where spatial heterogeneities, preexisting natural fractures, or transitional stress states are present, advanced 3D modeling provides insight critical to optimize development strategy. Through parametric stimulation modeling design, mechanisms driving drilling, completion, stimulation and productions processes can be honed to optimize and better manage the primary risks to development in tight/unconventional reservoirs [
Izadi, Ghazal (Baker Hughes a GE company) | Barton, Colleen (Baker Hughes a GE company) | Cruz, Leonardo (Baker Hughes a GE company) | Franquet, Javier (Baker Hughes a GE company) | Hoeink, Tobias (Baker Hughes a GE company) | Laer, Pierre Van (ADNOC)
Abstract We use advanced modeling techniques to optimize wellbore landing, completion configuration, and stimulation treatments in a complex carbonate reservoir in the Middle East. The reservoir, where target formations are highly laminated, naturally fractured, and stresses are transitional as a function of depth, presents conditions for which a more sophisticated stimulation design approach is required. A meticulous analysis of wellbore image logs and detailed forward modeling of the geometry of the drilling induced tensile fractures revealed that in situ stresses rapidly transition between strike-slip and reverse faulting as a function of depth. The log-derived geomechanical model was calibrated against wellbore failure observations, laboratory measurements, and mini-frac test results. The stresses and rock properties were mapped to the 3D reservoir volume assuming a horizontally layered formation. Models of hydraulic fracture propagation in the presence of natural fractures and laminations under vertically heterogeneous stress conditions were investigated using a 3D simulator that couples geomechanics, fracture mechanics, fluid behavior, and proppant transport. Modeling results reveal hydraulic fracture propagation is profoundly influenced by the complex stresses and structures in this reservoir. Simulation results indicate that vertical hydraulic fracture propagation (height, growth) is controlled by stress contrasts, stress state, elastic, and strength variations between adjacent formations, and the frictional strength of weak bedding discontinuities that are ubiquitous in tight formations. Results also show limited height growth within a reverse-faulting zone where modeling predicts a tendency for the development of horizontal limbs ("T-shaped" fractures). Hydraulic fracture geometry is significantly different in the presence of weak bedding compared to bedding with sufficient strength to transmit crack tip stresses across the interfaces. Significant amounts of fluid and proppant can be diverted into created horizontal fractures in this reservoir. Increasing fluid viscosity improves the propped surface area and controls the height growth within the zone of interest. Capturing such subsurface complexities and using them to simulate hydraulic fracture propagation helps us to improve treatment designs, reduce operational costs, and ultimately improve hydrocarbon recovery. This study illustrates that for more complex reservoirs where spatial heterogeneities, preexisting natural fractures, or transitional stress states are present, using advanced 3D modeling is essential. Through parametric stimulation modeling, design parameters can be refined to achieve optimal solutions to better manage the controllable drilling, completion, stimulation, and production parameters that present the primary risks to development in tight/unconventional reservoirs.
Newby, Warren (Total SA) | Abbassi, Soumaya (Total SA) | Fialips, Claire (Total SA) | D.M. Gauthier, Bertrand (Total SA) | Padin, Anton (Total SA) | Pourpak, Hamid (Total SA) | Taubert, Samuel (Total SA)
Abstract The Upper Jurassic (Oxfordian to Late Kimmeridgian) Diyab Formation has served as the source rock for several world-class oil and gas fields in the Middle East. More recently it has become an emerging unconventional exploration target in United Arab Emirates (UAE), Saudi Arabia, Bahrain and its age-equivalent Najhma shale member in Kuwait. The Diyab is unique in comparison to other shale plays due to its significant carbonate mineralogy, low porosities, and high pore pressures. Average measured porosities in the Diyab are generally low and the highest porosity intervals are found to be directly linked to organic porosity created by thermal maturation. Despite low overall porosities, the high carbonate and very low clay content defines an extremely brittle target, conducive to hydraulic fracture stimulation. This coupled with a high-pressure gradient facilitates a new unconventional gas exploration target in the Middle East. However, these favorable reservoir conditions come along with some challenges, including complex geomechanical properties, a challenging stress regime and the uncertainty of whether the presence of natural fractures could enhance or hinder production after hydraulic fracture treatment. Only recently has the Diyab been studied in detail in the context of an unconventional reservoir. This paper presents an integrated approach allowing a multidisciplinary characterisation of this emerging unconventional carbonate reservoir in order to gain a better understanding on the plays’ productivity controls that will aid in designing and completing future wells, but already encouraging results have been observed to date.