Fracturing Height Growth Restriction Technique Successfully Extended into Horizontal Wells in Ostracod Formation

The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and because of the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves. The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. After the success of a trial campaign in vertical wells, the technique was adjusted for the horizontal wellbores. The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod’s potential. Three horizontal wells were drilled and simulated, each with four stages of adjusted HGC technique to verify if this aggressive method was applicable to challenging sand admittance in case of transverse fractures. This rare implementation of HGC mixtures in horizontal wells showed operational success and proof of fracture containment based on pressure signatures and production monitoring. The applied HGC technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world’s largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near a water formation with insufficient or uncertain stress barriers.

ANALYSIS OF THE TRAFFIC LOAD–INDUCED STRESSES OF EMBANKMENT

This article represents traffic loads on the road structure distribution and evaluation of the vertical and horizontal stresses formation in the soil embankment. This evaluation allows to predict the depth and intensity of the propagation of additional stresses resulting from traffic loads. The calculations were performed in accordance with four normative documents applied in Lithuania, which define the loads on the road structure. The obtained results showed that the area to which the load is distributed has the greatest influence on the intensity of stresses and the distance of propagation. The maximum horizontal stress in the embankment was found to be no more than 70 kPa and the maximum stress propagation depth did not exceed 0.9 m. The results can be applied to a triaxial test apparatus to restore horizontal stresses in the embankment. It is recommended to select a lateral pressure from 20 kPa to 70 kPa for tests provided with triaxial test device. The mechanical properties of the soil determined with triaxial test device and recommended lateral pressure would be representative of the test results obtained in the field of embankment.

Experimental Research of Compound Monitoring on Multiple Temporary Blocking Refracturing for Long-Section Horizontal Wells

As an important energy replacement block in China, the tight conglomerate oilfields in the Mahu area are difficult to develop and are characterized by strong heterogeneity, large horizontal stress differences, and undeveloped natural fractures. However, new development processes including temporary blocking diversion and large section-multiple clusters have been implemented on the oilfields in the past few years. In 2020, two adjacent horizontal wells in the MD well area experienced a poor fracturing development effect compared with the earlier wells in this area. Analysis suggests that the main reasons are water sensitivity of the reservoir, insufficient fracturing scale, and/or interference from the adjacent old wells. To ameliorate the problem, this study presents an experimental study of multiple temporary plugging and refracturing technology in long horizontal well sections, in combination with electromagnetic and microseismic monitoring. Results from the study show a great difference between the two monitoring techniques, which is attributed to their different detection principles. Interestingly, the combination of the two approaches provides a greater performance than either approach alone. As the fracturing fluid flow diversion is based on temporary plugging diversion and electromagnetic monitoring of fracturing fluid is advantageous in temporary plugging diversion monitoring, both approaches require further research and development to address complex situations such as multiple temporary plugging and refracturing in long intervals of adjacent older wells.

Analysis of the Causes of the Collapse of a Deep-Buried Large Cross-Section of Loess Tunnel and Evaluation of Treatment Measures

To address the problem of the collapse of the roof of the Bailuyuan tunnel during construction, the causes of collapse were analyzed, targeted treatment measures were proposed, and the effects of the treatment measures were evaluated through on-site monitoring and three-dimensional numerical simulations. The results showed that the particular characteristics of loess and the synergy of groundwater were the internal causes of the tunnel’s collapse as well as, to a certain extent, atmospheric precipitation. Therefore, the combination of multiple factors contributed to the tunnel’s collapse. Untimely monitoring and measurement, as well as the low initial support parameters, reflect a lack of human understanding of the collapse. Based on the analysis of the causes of the collapse, comprehensive treatment measures for inside and outside the tunnel are proposed, which are shown to be effective and to be capable of preventing the occurrence of further collapses. After the collapse treatment, the measured maximum settlement of the tunnel vault was 65.1 mm, the maximum horizontal convergence was 25 mm, the maximum surrounding rock pressure was 0.56 MPa, and the maximum stress on the steel arch frame was 54.34 MPa. Compared with the original design plan, the vertical stress, horizontal stress, and shear stress of the surrounding rock obtained from numerical simulation after the collapse treatment were greatly reduced, the reduction rate at the vault reached 50%, and the safety factors of the initial support positions after treatment met the specification requirements. The research results can provide engineering guidance for the design and construction of large-section tunnels crossing deep-loess strata, and they are of important engineering significance.

Dike Propagation During Global Contraction: Making Sense of Conflicting Stress Histories on Mercury

Thrust fault-related landforms, smooth plains units, and impact craters and basins have all been observed on the surface of Mercury. While tectonic landforms point to a long-lived history of global cooling and contraction, smooth plains units have been inferred to represent more punctuated periods of effusive volcanism. The timings of these processes are inferred through impact cratering records to have overlapped, yet the stress regimes implied by the processes are contradictory. Effusive volcanism on Mercury is believed to have produced flood basalts through dikes, the propagation of which is dependent on being able to open and fill vertical tensile cracks when horizontal stresses are small. On the contrary, thrust faults propagate when at least one horizontal stress is very large relative to the vertical compressive stress. We made sense of conflicting stress regimes through modeling with frictional faulting theory and Earth analogue work. Frictional faulting theory equations predict that the minimum and maximum principal stresses have a predictable relationship when thrust faulting is observed. The Griffith Criterion and Kirsch equations similarly predict a relationship between these stresses when tensile fractures are observed. Together, both sets of equations limit the range of stresses possible when dikes and thrusts are observed and permitted us to calculate deviatoric stresses for regions of Earth and Mercury. Deviatoric stress was applied to test a physical model for dike propagation distance in the horizontally compressive stress regime of the Columbia River Flood Basalt Province, an Earth analogue for Borealis Planitia, the northern smooth plains, of Mercury. By confirming that dike propagation distances from sources observed in the province can be generated with the physical model, we confidently apply the model to confirm that dikes on Mercury can propagate in a horizontally compressive stress regime and calculate the depth to the source for the plains materials. Results imply that dikes could travel from ∼89 km depth to bring material from deep within the lithosphere to the surface, and that Mercury’s lithosphere is mechanically layered, with only the uppermost layer being weak.

Utilizing Microseismic to Monitor Fracture Geometry in a Horizontal Well in a Tight Sandstone Formation

This paper presents the use of real-time microseismic (MS) monitoring to understand hydraulic fracturing of a horizontal well drilled in the minimum stress direction within a high-temperature high-pressure (HTHP) tight sandstone formation. The well achieved a reservoir contact of more than 3,500 ft. Careful planning of the monitoring well and treatment well setup enabled capture of high quality MS events resulting in useful information on the regional maximum horizontal stress and offers an understanding of the fracture geometry with respect to clusters and stage spacing in relation to fracture propagation and growth. The maximum horizontal stress based on MS events was found to be different from the expected value with fracture azimuth off by more than 25 degree among the stages. Transverse fracture propagation was observed with overlapping MS events across stages. Upward fracture height growth was dominant in tighter stages. MS fracture length and height in excess of 500 ft and 100 ft, respectively, were created for most of the stages resulting in stimulated volumes that are high. Bigger fracture jobs yielded longer fracture length and were more confined in height growth. MS events fracture lengths and heights were found to be on average 1.36 and 1.30 times, respectively, to those of pressure-match.

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.

Estimating SHmax azimuth with P sources and vertical geophones: Use P-P reflection amplitudes or use SV-P reflection times?

We compared two methods for extracting the azimuth of maximum horizontal stress (SHmax) from 3D land-based seismic data generated by a P source and recorded with vertical geophones. In the first method, we used the direct-SV mode that is produced by all land-based P sources. P sources generate SV illumination that radiates in all azimuth directions from a source station and creates SV-P reflections that are recorded by vertical geophones. Unless stratigraphy has steep dip, SV-P raypaths recorded by vertical geophones are the reverse of P-SV raypaths recorded by horizontal geophones. Thus, SV-P data provide the same S-wave sensitivity to stress fields as popular P-SV data do. In the second method, we retrieved P-P reflections and then performed an amplitude-versus-incident-angle (AVA) analysis of the amplitude-gradient behavior of P-P reflection wavelets. We did this analysis in narrow azimuth corridors to determine the gradient of reflection-wavelet amplitudes as a function of azimuth. This P-P AVA amplitude-gradient method has been of great interest in the reflection seismology community since it was introduced in the late 1990s. Each of these methods, AVA analysis of the gradient of P-P reflection amplitudes and azimuth-dependent arrival times of SV-P reflections can be used to determine the azimuth of SHmax stress. We compare the results of the two methods with ground truth measurements of SHmax azimuth at a CO2 sequestration site in the Michigan Basin. SHmax azimuths were determined from P-P and SV-P data at three major boundaries at depths of approximately 3500 ft (1067 m), 5500 ft (1676 m), and 7500 ft (2286 m). Two estimates of SHmax azimuth (one using SV-P data and one using P-P data) were made at each stacking bin inside a 24 mi2 (62 km2) image space. The result was approximately 98,000 estimates of SHmax azimuth across each of these three boundaries for each of these two prediction strategies. Histogram displays of PP AVA gradient estimates had peaks at correct azimuths of SHmax at all three depths, but the spread of the distributions widened with depth and split into two peaks at the deepest boundary. In contrast, each histogram of SHmax azimuth predicted by azimuth-dependent SV-P traveltimes had a single, definitive peak that was positioned at the correct SHmax azimuth at all three boundary depths.

Proactive Decision-Making Through Real-Time Geomechanical Support Leveraging Drilling a Long Horizontal Section Through a Tight Unconventional Reservoir of an Oil and Gas Field: Middle East

This paper discusses the Integrated Role of Geomechanics and Drilling Fluids Design for drilling a well oriented towards the minimum horizontal stress direction in a depleted, yet highly stressed and complex clastic reservoir. There are multiple challenges related to such a well that need to be addressed during the planning phase. In this case, the well needs to be drilled towards the minimum horizontal stress direction (Shmin) to benefit multi-stage hydraulic fracturing. At the same time, the most prominent challenge is that this well orientation is more prone to wellbore failure and requires a maximum mud weight, due to the present strike slip stress environment. Well planning challenges in such an environment include (a) the determination of formation characteristics and rock properties, (b) the anticipation of higher formation collapse pressure during the course of drilling the lateral section within the reservoir, (c) the determination of the upper bound mud weight to prevent lost circulation due to a low fracture gradient against depleted sections, or due to the presence of pre-existing natural fractures, d) mitigating the higher risk of differential sticking against depleted porous layers, and determining appropriate bridging in the drilling fluids, (e) recognizing the prolonged exposure time of the formation due to the length of the lateral and the lower rate of penetration against the tight highly dense formations. For successful drilling, and to mitigate the above risks, the first step is to prepare a predrill GeoMechanical model along with adequate fluid design and drillers action plans to be considered during drilling. Offset well petrophysical logs and core data are considered for the preparation of the predrill GeoMechanical model, along with the drilling experiences in the offset locations. Based on the above, a predrill GeoMechanical model is prepared, a risk matrix is being established, and a representative mud weight window is recommended (Wellbore Stability Analysis). In most cases, the offset well locations considered are vertical- or inclined-, or lateral wells of different trajectory azimuth than the target well location and the predrill GeoMechanical model can incorporate such variations easily; however, any Geology uncertainty, leading to a different rock property- and stress set-up (or even different pore pressure than expected), at the actual well location will be part of the uncertainty of the predrill GeoMechanical model and Wellbore Stability Analysis. This is where the real time monitoring is playing out its full potential: giving an updated model and wellbore stability analysis during drilling. While drilling the lateral section, the wellbore condition is being monitored using LWD (logging while drilling) tools, e.g. Gamma Ray, Density, Neutron, Acoustic Caliper, Azimuthal density image and ECD (equivalent circulating density). While gamma ray helps in determining the lithology, density logs help to understand the formation hardness, and they can be used to generate a calibrated pseudo acoustic log. Based on this pseudo acoustic log, the rock strength and other rock mechanical properties of the pre- GeoMechanical model can be updated as soon as they become available. This gives insight into the model differences and helps to understand model variations and adjust Wellbore Stability recommendations accordingly. While the neutron log helps to determine the zones of high porosity, and thus potential risk zones for differential sticking, the azimuthal density image clearly indicates the breakout zones caused by the shear failure of the wellbore. The presence of wellbore failure (breakout) is further confirmed by acoustic caliper data, and accordingly wellbore stability related recommendations are communicated to the operator, for an increase in the specific gravity of the mud, and thus, to balance the wellbore. From a mud rheology perspective, high performance OBM (oil-based mud) parameters are maintained consistent with the formation properties, to minimize fluid loss, optimize wellbore strengthening characteristics and minimize at the same time solids concentrations in order to avoid excessive ECD (equivalent circulating density) which may open pre-existing natural fractures resulting in downhole losses and in consequence might lead to differential sticking. In the case study presented herein, the proactive implementation of GeoMechanics and its Wellbore Stability application as well as the integration of drilling fluids services, resulted in the smooth and successful drilling of the lateral section, and also in the delivery of an in gauge hole necessary for multi-stage fracturing (MSF) completion optimization.

Real-Time Wellbore Stability and Hole Quality Evaluation Using LWD Azimuthal Photoelectric Measurements

Horizontal and high-inclination deep wells are routinely drilled to enhance hydrocarbon recovery. To sustain production rates, these wells are generally designed to be drilled in the direction of minimum horizontal stress in strike slip stress regime to facilitate transverse fracture growth during fracturing operations. These wells can also cause wellbore instability challenges due to high stress concentration due to compressional or strike-slip stress regimes. Hence, apart from pre-drill wellbore stability analysis for an optimum mud weight design, it is important to continuously monitor wellbore instability indicators during drilling. With the advancements of logging-while-drilling (LWD) techniques, it is now possible to better assess wellbore stability during drilling and, if required, to take timely decisions and adjust mud weight to help mitigate drilling problems. The workflow for safely drilling deep horizontal wells starts with analyzing the subsurface stress regime using data from offset wells. Through a series of steps, data is integrated to develop a geomechanics model to select an optimum drilling-fluid density to maintain wellbore stability while minimizing the risks of differential sticking and mud losses. Due to potential lateral subsurface heterogeneity, continuous monitoring of drilling events and LWD measurements is required, to update and calibrate the pre-well model. LWD measurements have long been used primarily for petrophysical analysis and well placement in real time. The use of azimuthal measurements for real-time wellbore stability evaluation applications is a more recent innovation. Shallow formation density readings using azimuthal LWD measurements provide a 360° coverage of wellbore geometry, which can be effectively used to identify magnitude and orientation of borehole breakout at the wellbore wall. Conventional LWD tools also provide auxiliary azimuthal measurements, such as photoelectric (Pe) measurement, derived from the near detector of typical LWD density sensors. The Pe measurement, with a very shallow depth of investigation (DOI), is more sensitive to small changes in borehole shape compared with other measurements from the same sensor, particularly where a high contrast exists between drilling mud and formation Pe values. Having azimuthal measurements of both Pe and formation density while drilling facilitates better control on assess wellbore stability assessment in real time and make decisions on changes in mud density or drilling parameters to keep wellbore stable and avoid drilling problems. Time dependency of borehole breakout can also be evaluated using time-lapse data to enhance analysis and reduce uncertainty. Analyzing LWD density and Pe azimuthal data in real time has guided real-time decisions to optimize drilling fluid density while drilling. The fluid density indicated by the initial geo-mechanical analysis has been significantly adjusted, enabling safe drilling of deep horizontal wells by minimizing wellbore breakouts. Breakouts identified by LWD density and photoelectric measurements has been further verified using wireline six-arm caliper logs after drilling. Contrary to routinely used density image, this paper presents use of Pe image for evaluating wellbore stability and quality in real time, thereby improving drilling safety and completion of deep horizontal wells drilled in the minimum horizontal stress direction.