Hydraulic Fracturing at Clair: Unlocking the Potential of Europe's Largest Reservoir

The Greater Clair area, Europe's largest oilfield, has two existing platforms, Clair Phase 1 and Clair Ridge, on production with future potential for a third platform targeting undeveloped Lower Clair Group to the South of Ph1. Clair Phase 1 was the initial development of Clair, targeting Lower Clair Group (LCG) reservoir consisting of a complex Devonian sandstone in six units. Most Phase 1 wells penetrated relatively good quality reservoir enhanced by natural fractures, while more recently Clair Ridge wells took a similar approach targeting natural fractures, however that strategy is continually being evaluated. In some areas however low matrix quality and lack of natural fractures were the dominant characteristics resulting in lower production rates. A brief comparison of the range of production outcomes will be presented, including potential downsides of reliance on natural fractures. Given the large oil volumes in areas of known poorer rock quality, alongside variable production results, a hydraulic fracturing trial was initiated in 2017. Well 206/08-A23 (A23) targeted previously under-developed, poor-quality Unit VI within the Phase 1 Graben area where natural fractures are absent. A pre-frac production test established baseline production of 900BOPD in December 2018. The A23 objectives included subsequent hydraulically fracturing the well to test this techniques ability to unlock production from tight, matrix dominated formation. Detailed analysis of core, log and limited vertical well fracturing data (from initial fracturing trials of 1980's vintage), yielded robust designs. Key challenges included overcoming very low KV/KH ratios with fracture heights exceeding 300ft. The resulting detailed designs provided consistent and predictable hydraulic fracturing execution in A23 in 2019, including placement of four planned 500klbs treatments combined with coil clean-outs after each stage to unload solids and fluids from the well. Initial fracture designs were conservative in terms of pad and proppant scheduling which, alongside learnings around operational logistics offshore West of Shetlands and completion design, offer significant optimisations for future hydraulic fractures. Post frac A23 became the highest non-natural fractured producer across Clair. Initially a six-fold production increase was observed with monitoring of transient production ongoing. Tracer analysis confirmed production contribution from all zones. Proving fracturing technology brings opportunities to unlock poorer Phase 1 and Ridge reservoir areas. Additionally, significant portions of the undeveloped Lower Clair Group to the South of Ph1 comprises lower permeability reservoir with higher viscosity oil and reduced natural fracture presence. Hydraulic fracturing is therefore a crucial completion technique for developing this lower quality reservoir and brings significant value enhancement to the project. Efficient delivery of numerous large fractures in a harsh offshore environment West of Shetlands presents significant challenges. The influence of how the A23 fracturing results and learnings are guiding future hydraulic fracturing concept are detailed, including optimising platform engineering design to facilitate efficient fracturing operations while maintaining the required productivity in this challenging scenario.

Numerical Simulation Study of Proppant Transport in Cross Fractures

Hydraulic fracturing technology is an important means to stimulate unconventional reservoirs, and the placement morphology of proppant in cross fractures is a key factor affecting the effect of hydraulic fracturing. It is very important to study the proppant transport law in cross fractures. In order to study the proppant transportation law in cross fractures, based on the CFD-DEM method, a proppant transport model in cross fractures was established. From the two aspects of the flow field in the fractures and the morphology of the proppant dune, the influence of the natural fracture approach angle, the fracturing fluid viscosity and injection rate on the proppant transport is studied. Based on the principle of hydropower similarity, the conductivity of proppant dune under different conditions is quantitatively studied. The results show that the natural fracture approach angle affects the distribution of proppant and fracturing fluid in natural fractures, and further affects the proppant placement morphology in hydraulic fractures and natural fractures. When the fracturing fluid viscosity is low and the displacement is small, the proppant forms a "high and narrow" dune at the entrance of the fracture. With the increase of the fracturing fluid viscosity and injection rate, the proppant settles to form a "short and wide" placement morphology. Compared with the natural fracture approach angle, the fracturing fluid viscosity and injection rate have a more significant impact on the conductivity of proppant dune. This paper investigated the proppant transportation in cross fractures, and quantitatively analyzes the conductivity of proppant dunes with different placement morphology. The results of this study can provide theoretical guidance for the design of hydraulic fracturing.

Integrated Hydraulic Fracturing Strategy Leads to Successful Execution of the First Highly Deviated Ultra-Deep Well in Tarim Oilfield

Well K1002 is the first highly deviated ultra-deep well in Tarim Oilfield of China, with the reservoir depth 7060m and the well deviation of 60° ∼ 77.6° in the fractured interval. Because of large deviation angle, high breakdown pressure and in-situ stress, poor effectiveness of natural fractures, large reservoir thickness, it is difficult and risky to implement hydraulic fracturing. In this paper, the fractured well was taken for a case study to illustrate the holistic optimization to guarantee the treatment success, a world-wide difficulty with high engineering risk. For figuring out a reasonable treatment design, comprehensive lab experiments and numerical simulation were conducted to analyze and benchmark the reservoir characteristics, rock mechanics and geological model. Systematic study on reducing breakdown pressure, development of natural fractures evaluation, multi-size combination of diverting agent, separated layer stimulation and fracture parameters optimization, treatment fluid formulation, proppant screening and operation program were carried out. Considering the wellbore trajectory and rock mechanics characteristics of well K1002, a breakdown pressure prediction model was established to optimize the perforation orientation. The best perforation orientation was 28° and 208°, the worst perforation orientation was 148° and 328°, and the breakdown pressure range was 168-175MPa with 60° phase angle. Combination with "imaging logging (0-3m) + far detection acoustic logging (0-30m) + geomechanics (0-300m)", the comprehensive evaluation and prediction of natural fractures in near wellbore area and far wellbore area were realized. Based on this, the stimulation technology of "mechanical layering + diverting agent" was optimized to connect the fracture development zone in near wellbore and far wellbore area. According to the Tight Packing Theory, the idea of "multi-size particles combination of diverting agent" was put forward. Through the experiment study, the combination of 1-5mm and 5-10mm particles was optimized, and the optimal chart of diverting agent size combination was made under different reservoir temperatures. For the fracturing job, totally 2562m3 KCL weighted fracturing fluid and 159.2m3 ceramic proppant of 40-70 mesh were pumped. The operation parameters were in reasonable agreement with the design. The initial test production was 10 times higher than before. The experience gained in this case study has some guiding significance for improving the success rate of hydraulic fracturing treatments in the highly deviated ultra-deep well and for effectively developing such fractured tight sandstone reservoirs, both theoretically and practically.

Integration of Geoscience and Engineering Concepts to Account for Natural Fractures in Fluid Flow within Shale Reservoirs

Unconventional shale reservoirs are characterized by low porosity and ultra-low permeability. Natural fractures are known to be present and considered a critical factor for the enhanced post-stimulation productivity. Accounting for natural fractures with existing techniques has not been widely adopted owing to their complexity or lack of validation. Ongoing research efforts are striving to understand how natural fractures can be accounted for and accurately modeled in fluid flow of the subject reservoirs. This study utilized Eagle Ford well data comprising reservoir properties, stimulation metrics, production, microseismicity and permeability measurements from a core plug. The methodology comprised use of production data to extract a linear flow regime parameter. This was coupled with fracture geometry, predicted from hydraulic fracture modeling and microseismicity, to estimate the system permeability. From interpreting microseismic events as slips on critically stressed natural fractures, explicit modeling incorporating a discrete fracture network (DFN) assumed activated natural fractures supplement conductive reservoir contact area. Thus, allowed the estimation of matrix permeability. For validation, the aforementioned was compared with core plug permeability measurements. Results from modeling of planar hydraulic fractures, with microseismicity as validation, predicted planar fracture geometry which when coupled with the linear flow parameter resulted in a system permeability. Incorporation of DFNs to account for activated natural fractures yielded matrix permeability in picodarcy range. A review of laboratory permeability measurements exhibited stress dependence with the value at the maximum experimental confining pressure of 4000 psi in the same range as the computed system permeability. However, the confining pressures used in the experiments were less than the in situ effective stress. Correction for representative stress yielded an ultra-low matrix permeability in the same range as the DFN-based picodarcy matrix permeability. Thus, supporting the adopted drainage architecture and often suggested role of natural fractures in shale reservoir fluid flow. This study presents a multi-discipline workflow to account for natural fractures, and contributes to understanding that will improve laboratory petrophysics and the overall reservoir characterization of the subject reservoirs. Given that the Eagle Ford is an analogue of emerging shales elsewhere, results from this study can be widely adopted.

Integration of Advanced Borehole Sonic and Resistivity Image Analysis for Fracture and Stress Characterisation - Implications to Carbon Sequestration Feasibility

Borehole resistivity images and dipole sonic data analysis helps a great deal to identify fractured zones and obtain reasonable estimates of the in-situ stress conditions of geologic formations. Especially when assessing geologic formations for carbon sequestration feasibility, borehole resistivity image and borehole sonic assisted analysis provides answers on presence of fractured zones and stress-state of these fractures. While in deeper formations open fractures would favour carbon storage, in shallower formations, on the other hand, storage integrity would be potentially compromised if these fractures get reactivated, thereby causing induced seismicity due to fluid injection. This paper discusses a methodology adopted to assess the carbon dioxide sequestration feasibility of a formation in the Newark Basin in the United States, using borehole resistivity image(FMI™ Schlumberger) and borehole sonic data (SonicScaner™ Schlumberger). The borehole image was interpreted for the presence of natural and drilling-induced fractures, and also to find the direction of the horizontal stress azimuth from the identified induced fractures. Cross-dipole sonic anisotropy analysis was done to evaluate the presence of intrinsic or stress-based anisotropy in the formation and also to obtain the horizontal stress azimuth. The open or closed nature of natural fractures was deduced from both FMI fracture filling electrical character and the Stoneley reflection wave attenuation from SonicScanner monopole low frequency waveform. The magnitudes of the maximum and minimum horizontal stresses obtained from a 1-Dimensional Mechanical Earth Model were calibrated with stress magnitudes derived from the ‘Integrated Stress Analysis’ approach which takes into account the shear wave radial variation profiles in zones with visible crossover indications of dipole flexural waves. This was followed by a fracture stability analysis in order to identify critically stressed fractures. The borehole resistivity image analysis revealed the presence of abundant natural fractures and microfaults throughout the interval which was also supported by the considerable sonic slowness anisotropy present in those intervals. Stoneley reflected wave attenuation confirmed the openness of some natural fractures identified in the resistivity image. The strike of the natural fractures and microfaults showed an almost NE-SW trend, albeit with considerable variability. The azimuth of maximum horizontal stress obtained in intervals with crossover of dipole flexural waves was also found to be NE-SW in the middle part of the interval, thus coinciding with the overall trend of natural fractures. This might indicate that the stresses in those intervals are also driven by the natural fracture network. However, towards the bottom of the interval, especially from 1255ft-1380ft, where there were indications of drilling induced fractures but no stress-based sonic anisotropy, it was found that that maximum horizontal stress azimuth rotated almost about 30 degrees in orientation to an ESE-WNW trend. The stress magnitudes obtained from the 1D-Mechanical Earth Model and Integrated Stress Analysis approach point to a normal fault stress regime in that interval. The fracture stability analysis indicated some critically stressed open fractures and microfaults, mostly towards the lower intervals of the well section. These critically stressed open fractures and microfaults present at these comparatively shallower depths of the basin point to risks associated with carbon dioxide(CO2) leakage and also to induced seismicity that might result from the injection of CO2 anywhere in or immediately below this interval.

Informed Decisions Guided by GeoMechanics to Improve Drilling Performance: A Case Study from Onshore Field, Abu Dhabi; UAE

ADNOC (Abu Dhabi National Oil Company) recently drilled some wells in Onshore Abu Dhabi (Field-A) and encountered consistent hole instability from Umm Er Radhuma (UER) to Simsima. Thus, a GeoMechanical review was proposed to investigate the root causes, if any, and recommend possible remedies for the upcoming drilling campaign. While detailed drilling event analysis allowed to investigate the correlation between the mud weight program and well trajectory, borehole image log analysis and geological understanding from nearby fields indicated the possible role of structural and lithological features on hole instability. Integration of drilling engineering data and regional geological knowledge helped to narrow down the possible causes of drilling challenges. Sedimentalogical review of Image logs have established some correlation between rock types and hole instability events. Drilling experience shows there is very narrow margin for loss and/or gain to occur. There is regional geological evidence of the presence of a wide range of vuggy structures, as well as natural fractures and/or faults. These features tend to make Simsima formation heterogeneous in terms of permeability and more prone to losses. Since most fractures are parallel to SHmax direction and well was drilled towards Shmin direction, there are greater chances of encountering faults and/or fractures, which would be critically-stressed and lead to loss and/or gain situations. Geomechanical parameters helped highlight the magnitudes and orientations of principal stresses. Observations of several tight hole and stuck pipe events while tripping from Radhuma and UERB shale to Simsima seem to indicate mud weight used was insufficient. Role of multiple failure mechanisms was identified, and relevant solutions were recommended as well as implemented to achieve the drilling success. The case study presented here emphasizes how different carbonate textures and the presence and orientation of natural fractures and/or faults within Simsima formation can impact hole instability with respect to wellbore trajectory. Proactive implementation of recommendations from this analysis on well planning and fluid design resulted in improvement of drilling performance and reduction of non-productive time in new wells.