A new LWD ultrasonic imager for use in both water- and oil-based muds uses acoustic impedance contrast and ultrasonic amplitude measurements to obtain high-resolution structural, stratigraphic and borehole geometry information. Following extensive testing in the Middle East and the US, this paper presents results from the first European deployment of the new 4.75-in. high-resolution ultrasonic imaging tool.
An ultrasonic transducer, which operates at high frequency, scans the borehole at a high sampling rate to provide detailed measurements of amplitude and traveltime. A borehole caliper measurement is made, based on the time of arrival of the first reflection from the borehole wall. A second measurement detects formation features and tectonic stress indicators from the change in signal amplitude. The amplitude of the reflected wave is a function of the acoustic impedance of the medium. Resulting impedance maps have sufficient resolution to detect sinusoidal, non-sinusoidal and discontinuous features on the borehole wall.
Breakouts, drilling-induced fractures, and tensile zones were used for stress direction determination. Breakout identification was obtained both from amplitude images and oriented potato plot cross sections derived from traveltime measurements.
The orientation of natural fractures is parallel at the maximum stress direction, indicated by drilling-induced fractures and tensile zones. The World Stress Map confirms the maximum stress direction determination.
It was also possible to detect certain key-seat zones and investigate borehole conditions to prevent issues during the subsequent casing job.
The new LWD ultrasonic imaging technique represents an important alternative to density and water-based mud resistivity imaging, which has several limitations. Unlike the resistive imaging LWD tool that is very sensitive to standoff, the higher tolerance of the ultrasonic imaging tool enables the amplitude and traveltime ultrasonic images to contain fewer unwanted artifacts.
Ma, Joseph Ho Yin (Department of Civil and Environmental Engineering, National University of Singapore) | Qi, Qiaomu (Department of Civil and Environmental Engineering, National University of Singapore) | Qiu, Yu (Department of Civil and Environmental Engineering, National University of Singapore) | Li, Yunyue Elita (Key Laboratory of Groundwater Resources and Environment, Jilin University) | Cheng, Arthur (Department of Civil and Environmental Engineering, National University of Singapore)
The roughness of fracture surfaces controls both the flow and elastic properties. While the aperture opening and its height controls the flow and transport properties, the contacted area and the stress-free surface determine the elastic properties. An implicit, and potentially complicated relation exists connecting these two properties. In this paper, we demonstrate that, with a fracture in a granite core, the static compressibility of the fracture can be estimated from the steady state flow measurements. We establish an empirical relation between the compression displacement and the effective pressure, based on numerical simulations of fluid-flow through the digitized fracture surface. The resulting empirical relation shows reasonable agreement compared with those presented in earlier literatures.
Presentation Date: Tuesday, October 16, 2018
Start Time: 8:30:00 AM
Location: 202A (Anaheim Convention Center)
Presentation Type: Oral
ABSTRACT: The estimation of the in-situ stress state is required for the design and execution of deep engineering operations related to Enhanced Geothermal System (EGS). Borehole failures, often referred as borehole breakouts, which are controlled by local stress concentration around the wellbore, are recognized being a useful indicator to assess in-situ stress conditions. However, breakouts evolve with time and this may affect our ability to use them for quantifying the stress state. We use a unique data set from the deep geothermal well of Rittershoffen GRT-1 in order to verify the hypothesis concerning wellbore breakout geometrical evolution. In GRT-1 wellbore, imaging has been acquired 4 days, 348 days and 946 days after drilling completion. Thermal, hydraulic and chemical stimulations have been performed between the first and the second image acquisition. Using this data set, we were able to describe in-situ the breakout evolution with time. We show increase in the extension of breakouts along the well. Contrary to the common assumptions, we also show that breakout widen, but within the limit of the accuracy of our analysis they do not deepen. The consequences of the breakout evolution for stress characterization are significant and add up to other important uncertainties in such analyses like the estimation of strength parameters.
A large amount of energy is available at depth. This energy can be extracted by circulating fluids between boreholes through the hot rock mass, but this requires that sufficient permeability is present at depth. As permeability tends to decrease with depth (Manning and Ingebritsen 1999), it is necessary to target deep structures with locally higher permeability (e.g. fault zones) and/or to perform permeability enhancement operations. The later approach is referred as Enhanced Geothermal Systems (EGS). The principle underlying this technology consists of increasing the hydraulic performance of the reservoir through different types of stimulations so that commercially interesting flow rate can be achieved. The stimulations consist of high-pressure injection (hydraulic stimulation), cold water injection (thermal stimulation) or chemical injection (chemical stimulation). In the two first cases, the permeability increase is obtained by inducing a thermohydromechanical perturbation to the rock mass which reactivates existing structures or create new ones. The in-situ stress state is central to understand the response of the rock mass to injections and to design such operations.
ABSTRACT: Scour of rock in unlined rock spillway channels is a critical issue facing many of the world’s dams. From a modeling point of view this poses a challenging and interesting problem that combines rock mechanics and hydraulics of turbulent flow. We analyze this interaction between the blocky rock mass and water by directly modeling the solid and fluid phases—the individual polyhedral blocks are modeled using the Discrete Element Method (DEM) while the water is modeled using the Lattice Boltzmann Method (LBM). The LBM mesh is entirely independent of the DEM discretization, making it possible to refine the LBM mesh such that transient and varied fluid pressures acting of the rock surface are directly modeled. This provides the capability to investigate the effect of water pressure inside the fractured rock mass, along potential sliding planes, and can be extended to rock falls and slides into standing bodies of water such as lakes and reservoirs. Herein we present preliminary results to demonstrate the capabilities of the methodology.
Scour of rock is a very challenging and interesting problem that combines rock mechanics and hydraulics of turbulent flow. On a practical level, rock erosion is a critical issue facing many of the world’s dams at which excessive scour of the dam foundation or spillway can compromise the stability of the dam resulting in significant remediation costs, if not direct personal property damage or even loss of life. The most current example of this problem is Oroville Dam in Northern California—massive scour damage to both the service and emergency spillways during the flood events of February 2017 led to the evacuation of more the 188,000 people living downstream of the dam.
In order to effectively model rock scour, it is necessary to consider the interaction between the blocky rock mass and the water flowing over and through it. Simulations modeling this process can follow one of two approaches:
In the locally averaged approach, the number of solid particles is greater than the number of fluid cells, making this approach less computationally expensive. However, since the fluid-solid coupling is done on a volume- averaged basis, all particles within a local region will experience the same hydrodynamic forces. In certain applications this may be appropriate, but for rock scour this approach does not offer sufficient resolution.
ABSTRACT: In the framework of the In-situ Stimulation and Circulation (ISC) experiment Fiber-Bragg-Grating (FBG) and Brillouin strain sensing systems were installed to monitor deformation during six hydraulic shearing and six hydraulic fracturing experiments. Three boreholes were dedicated to strain monitoring. Both systems are installed in the same boreholes, offering a unique opportunity to compare these systems with respect to their applicability in hydraulic stimulation tests. A total of 60 FBG sensors with 1 m base length were installed across fractures, shear zones and intact rock. Along the entire borehole length, pre-stressed optical cables for Brillouin distributed strain (DBS) sensing were embedded in grout with two installation methods: a bare cable and a cable packed and fixed with glue every 0.65 m. The strain signals were compared as time series for a given borehole depth and as profiles along the borehole axis. The study reveals that the FBG system gives a high accuracy (0.04 μ-strain) and temporal resolution (>1s) with pointwise measurements. The bare DBS leg yield good quantitative strain data with poorer strain accuracy (>500 times poorer than FBG) and poorer temporal resolution (factor of >100). The packed DBS leg provide no meaningful information about the strain field
Deformation is the fundamental kinematic variable in rock mechanics. Commonly, it is expressed as strain, which is the non-rotational component of the deformation tensor (i.e., the spatial derivative of the displacement field) (Jaeger et al., 2007). Strain or deformation measurements are important for a broad range of applications: from lab-scale test (e.g., compressional tests), over structural engineering (e.g., bridges; Glisic et al., 2011) to geotechnical engineering (e.g., mining, tunneling; Valley et al., 2012) and to natural hazards (Moore et al., 2010). Conventionally, in-situ deformation measurements are executed using multi-point borehole extensiometers (MPBX) or inclinometers that present strong limitations in terms of sensitivity and spatial coverage(Madjdabadi et al., 2016). Fiber-optics-based strain monitoring systems are more and more used in geotechnical context, since they combine high resolution and long durability with insensitivity to electromagnetic noise and moisture (Madjdabadi et al., 2016).
Recovery of bypassed oil banked against nonconductive faults in heavily-faulted and stress-sensitive reservoirs such as the Wilmington and Kern River fields of California can raise concerns of fault destabilization. Here, we investigate the effects of well configuration and well flow rate on the changes in stress and mechanical stability of a fault during recovery of fault-banked oil. We use a computational framework of coupled flow, geomechanics and Coulomb failure to quantify the evolution of fault stresses for different configurations and flow rates of two wells located across the fault. In the case of two producers across the fault, we find that the fault stability is determined by the difference in flow rates of the two producers. A smaller difference in well rates result into a smaller difference in pressure across the fault, which leads to a smaller rate of destabilization. In case of an injector-producer pair placed across the fault, a smaller difference in the flow rates results into a larger destabilization of the fault. We conclude that the inevitability of producing or injecting close to a fault requires detailed geomechanical studies to evaluate the effects of existing and planned well locations and well rates on fault stability. Using our coupled simulation framework, we show that both well configuration and rates play important roles in determining the stability of a fault. Results from this study can be incorporated into geomechanical hazard analysis of fault-banked oil operations around California.
Numerous studies on unconventional shale well production data have shown that downhole pressure fluctuations can exceed 300 psig during a slugging period. Such pressure fluctuation will result in very high drawdown and could lead to near-wellbore formation damage when the rock failure criterion was met. An engineering workflow was developed to investigate the impact of multiphase slugging events on cemented casing plug and perforation (CCPP)and open hole sliding sleeves (OHSS) completions. Based on transient pressure analysis and geomechanical evaluation, safety operational envelope was generated to minimize the risk of formation damage due to slugging behavior.
In this study, a dynamic multiphase flow simulator was used to predict the pressure amplitude and frequency during the slugging events in both a CCPP and OHSS completion configuration. The results from the simulation were then incorporated into a geomechanical model to analyze and identify potential hydraulic fracture closure and formation damage concerns, which can compromise well performance.
The results from this study show that OHSS completion is more vulnerable to damage during the downhole slugging period than a CCPP completion. However, severe formation and fracture damage could occur during downhole slugging for CCPP well if the well is operated outside the safety operational envelope. Results from the two case studies led to the conclusion that it is crucial to consider the effect of downhole slugging on near-wellbore fracture and formation integrity to avoid permanent and irreversible damage.
Yang, Xiangtong (PetroChina) | Huang, Yongjie (Schlumberger) | Zhang, Yang (PetroChina) | Qiu, Kaibin (Schlumberger) | Fan, Wentong (PetroChina) | Pan, Yuanwei (Schlumberger) | Xu, Guowei (PetroChina) | Xian, Chenggang (Schlumberger)
Keshen is a high-pressure/high temperature (HP/HT) tight-sandstone gas reservoir with reservoir pressure over 110 MPa and temperature over 175°C. The sandstone is very hard, with unconfined compressive strength (UCS) greater than 100 MPa. Given the HP/HT nature and natural fracture system in the reservoir, with aid of stimulation, many wells produced at a very high rate with the mean value exceeding 500,000 m3/d. In the last few years, many production wells in this reservoir experienced severe sanding issues that contradicted the conventional understanding that sanding would not occur in such hard rock. The sanding wells exhibited large fluctuations of production rate and wellhead pressure, erosion of chocks and nozzles, and eventually major or even complete loss of production. A solution to address the sanding issues was urgently needed because the sanding issues had caused a major decline in production and resulted in significant economic loss.
Due to the unconventional nature of the sanding issues, the typical sanding prediction methods based on solely on evaluating rock failure were not adequate to reveal the underlying sanding mechanism and develop a viable operational solution to address the sanding issues. To this end, a new workflow was formulated and applied to this study. The workflow started with detailed data mining on the massive amount of drilling, completion, stimulation, and production data from this reservoir to investigate possible relationships of drilling practices, completion options, and production schedules to the occurrence and severity of sanding issues. The analysis revealed that downhole flow velocity and production drawdown were the two major controlling factors in the occurrence of sand production. Further geomechanics simulation and particle migration simulation with a multiphase dynamic flow simulator confirmed that the production drawdown would cause failure of the rock near the wellbore and the gas flow could transport the sand debris to the wellbore and lift it up to the surface. In addition, the fluctuation of production rate was caused by blockage due to accumulation in the wells and production tubing of sand particles that were flushed out after downhole pressure buildup.
Based on the analysis, the threshold of flow velocity and the threshold of drawdown were identified, and these thresholds can be used in the reservoir management to address the sanding issues.
The experience in Keshen shows that sanding is possible in HP/HT high-productivity sandstone gas reservoirs, even in extremely hard formation, which overturns some prior conceptions on sanding. The information shared from this paper could bring up the attention of those operating similar HP/HT tight sandstone reservoirs around the world.
This case study reports a comprehensive sanding study program for two offshore gas-condensate fields. The results from geomechanics laboratory testing and modeling of sand production were implemented into real-time monitoring of production wells using the Production Data Management System (PDMS). Sand detectors were also instrumented on all production wellheads and integrated into the real-time monitoring. The program will help define the envelopes of optimized production while ensuring safety of production facilities.
Comprehensive geomechanics laboratory testing was conducted on reservoir cores retrieved from exploration and production wells. In addition to unconfined compression tests and TWC tests, the testing included triaxial tests with acoustic velocities during hydrostatic confinement as well as deviatoric axial loading to determine formation rock strength and deformation behaviors. The laboratory results were then used to calibrate strength and elastic properties logs used in sand production modeling. Optimized production envelopes for each well could then be determined. Finally, the modeling results were integrated into PDMS so that downhole gauge pressure and sand detector readings could be monitored and managed real-time for all production wells.
The results revealed that many reservoirs in Hai Thach and Moc Tinh fields have relatively low strength and therefore moderate sanding potential. This study would help define the envelopes of optimized production while ensuring safety of production facilities. These envelopes included sanding prevention criteria in addition to criteria to optimize condensate production and minimize water production. Regarding sand production, downhole gauge pressure are monitored real-time and managed so that drawdowns are below sand production threshold at current reservoir pressures. The key functionality goal is real-time collaboration between onshore and offshore to establish reliable information for reservoir monitoring, improving modeling, and production losses mitigation, which significantly improves production through a proactive well management.
Fuller, J. (J2 Geomechanics Ltd.) | Cook, J. M. (Schlumberger Gould Research) | Subbiah, S. K. (Schlumberger Middle East S.A.) | De Groot, L. (ENGIE E&P Nederland B. V.) | Graven, H. (ENGIE E&P Nederland B. V.)
ABSTRACT: This paper considers the physics and solid and fluid mechanics relevant to sanding from weak or very weak sandstones, and then uses this understanding to suggest ways of designing screenless completions to take advantage of these aspects to avoid sand production. This is followed by a description of a scale-dependent approach to sand prediction. This takes grain size and production tunnel diameter into account within the conventional framework of in-situ stress, reservoir pressure and rock strength parameters. The influence of these factors on sand failure over the life-of-reservoir is treated. A brief discussion of the problem of predicting the rate of sand production is also included. The approach is demonstrated with a case study showing how wells in an old gas field, which were shut-in because of sand production, were recompleted using the sand failure prediction and design capabilities of the methodology presented to restore production, sand-free, to former rates.
1. IMPORTANCE OF SAND FAILURE
Sand failure can have a severe impact on the economics of an oil or gas field. Erosion of down-hole or surface components by sand can lead to loss of integrity and hydrocarbon leakage. Production rates from screenless completions may need to be reduced to limit solids either flowing to surface or filling the wells. Sand handling, either at surface or flushing from downhole, adds expense to lifting costs.
Sand failure and production can be a problem from the start of production if low sand strength or a high state of stress are not appreciated. Alternatively, early production may be sand-free, but as a reservoir depletes solids production can begin. Sand production either immediately or at some later stage in the life of the field may require costly intervention, management or retrofitting of exclusion devices (Andrews et al., 2005; Rawlins and Hewett, 2007). As the number of fields around the world with weak or depleted sand reservoirs increases, these experiences are likely to become more widespread. BP, for example, estimates that more than 60% of its production comes from sand-prone reservoirs (Liou, 2014). To manage the economics of a field and minimise capital expenditure, it is useful to know at the outset whether sand failure is a significant risk. This allows decisions to be made on the most effective completion strategy to manage sand failure for the life of the field.