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Abstract Shales encountered in the overburden above hydrocarbon reservoirs often pose challenges to the stability of boreholes.Consequently, there is a keen interest in borehole stability prediction, which is complicated by the laminated structure of shale that arises as a consequence of the depositional environment. A combined experimental/numerical investigation is being undertaken to address how the directional properties of shale impact borehole stability in weak shale formations.Within this paper an advanced finite element procedure for simulation of progressive damage of orthotropic pressure-sensitive materials is presented, which includes bifurcation and post-bifurcation analysis.This constitutive model is based on critical state theory and is specifically designed to represent the characteristic deformation of weak shale formations. It includes orthotropic elasticity and an orthotropic pressure-dependent yield surface that is curved in the p-q plane, and which intercepts the hydrostatic axis in both tension and compression. A regularization procedure is also presented that ensures mesh invariance and correctly reproduces the dependence of strength on the size of the test specimen. Calibration of the model parameters is also discussed and the model is validated by comparison with the results of uniaxial and triaxial compression tests for Pierre I Shale performed at different bedding plane orientations. Introduction Despite significant advances in prediction in recent years, wellbore instability can still occur in shales during drilling. While instability in homogeneous shales can largely be avoided by using an adequate mud weight, attention is now focusing on predicting instability in shales with a more pronounced ‘fabric’ or fissile character. This anisotropy in mechanical and strength properties is usually neglected in conventional analyses. However, shales usually possess a laminated structure as a consequence of the depositional environment, and therefore exhibit a directional variation in elastic properties, yield strength and post-yield behaviour. Conventional approaches - assuming transverse isotropic elastic properties with isotropic failure surfaces - are typically unable to properly reproduce the complex yield and deformation behaviour of these materials.This deficiency is most pronounced in highly laminated and fissile shales, which are the most likely to cause drilling problems. The low permeability of shale may also complicate the stability assessment by necessitating a coupled poroelastic formulation. Extensive research has been carried out on the formulation of appropriate failure criteria for orthotropic and transversely isotropic materials, see [4] for a recent review. Early work focused on empirical failure criteria that account for the continuous variation of compressive strength with orientation for transversely isotropic rock [5,6]. Subsequently Tsai and Wu [7] and Pariseau [8] extended Hill's criterion [9] for orthotropic metal plasticity to pressure sensitive materials, and Ong and Roegiers [10] employed these theories in horizontal wellbore stability predictions. Nova [11] proposed a generalised failure condition that describes failure of transversely isotropic rocks in compression and Nova and Zaninetti [12] established a failure criterion in tension based on similar concepts. Cazacu and Critescu [13] show that an anisotropic Mises-Schleicher (AMS) criterion can accurately fit the failure strength for transversely isotropic rocks, including the directional character of transversely isotropic materials under general loading conditions, and the dependence on the intermediate principal stress.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Abstract A model has been developed for sand production prediction in gas wells. The model is based on linear poroelasticity and brittle plasticity with a critical equivalent plastic strain as sand production initiation condition. It included effect of residual strength in the plastic zone surrounding the cavity. The model has been applied to sand formations in a gas well in offshore North West Australia. The calculated drawdown pressure is higher than that based on linear poroelasticity but lower than the predictions based on the plasticity model without including the residual strength effect previously developed. Introduction Approximately 70% of the world oil and gas reserves are found in poorly/weakly consolidated reservoirs. Sand production has been a major concern to the industry for decades, and has become more critical today as more aggressive production schedules are implemented and productions are increased in offshore environment where tolerance to sand production is very low. Sand influx into the wellbore may lead to various problems such as erosion of valves and pipelines, plugging of production liner and sand deposits in the separators. In addition to the economic loss due to production limitations, sudden deposition of produced sands on the production equipment in high pressure gas wells presents a major safety risk. Sand production is a natural consequence of fluid flow into a wellbore from the reservoir and the process may be divided into three stages - the loss of mechanical integrity and the rocks surrounding an openhole or perforation (cavity), separation of solid particles from the rocks due to hydrodynamic force and transportation of the particles to the surface by reservoir fluids. A sand formation at depth exists at an equilibrium state of in-situ stress, pore pressure and temperature. Creation of a cavity and depletion of the reservoir cause redistribution of the stresses and pore pressure around the cavity. When the drilling and production-induced redistribution of the stress and pore pressure exceeds the strength of the sand around the cavity, the rock surrounding the cavity may become highly plastic and loss of mechanical integrity may take place. It is generally accepted that compressive and tensile failures are two main mechanisms responsible for the loss of mechanical integrity of the formation rock. The compressive failure is induced when the effective compressive stress exceeds the formation's compressive strength at the cavity. This may be caused by high in-situ stress and/or fluid flow (pore pressure gradient). Tensile failure is induced when the tensile stress due to fluid flow exceeds the tensile strength of the formation, which could be close to zero for unconsolidated sands or approximately one order lower than the compressive strength for consolidated formation. Tensile failure can only be induced by fluid flow. Accurate prediction of sand production initiation condition and the likely rate and amount of produced sand is the key to combat sand production problems. This information may be used to assist completion engineers in deciding either if and when sand control measures are required or the sand production can be managed. A number of sand production prediction models have been developed. Majority of the models were developed for oil wells, and were based on comparison between formation rock strength and the effective stress state around a cavity. It is assumed that sand production takes place when the effective stress state exceeds the formation strength. However, whether sand particle will be separated from the apparently failed formation, therefore sand production will depend on the stress state in the failed/plastic rock material and the magnitude of the hydrodynamic force due to fluid flow. A calculation on the effect of hydrodynamic force on a simplified configuration by Charlez showed that hydrodynamic effects can only play a major role in a highly plasified cohesionless zone where the hoop stress drops to a low value.
- North America > United States (0.68)
- Oceania > Australia > Western Australia (0.34)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.68)
- Well Completion > Sand Control (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Solids (scale, sand, etc.) (1.00)
Abstract Microseismic monitoring has been used to image the growth behaviour of hydraulic fractures in the Barnett Shale, Texas. The Barnett is a naturally fractured shale reservoir, which causes significant variability and complexity in fracture growth during well stimulation operations. Over the past two years, several Barnett treatments have been successfully imaged using microseismicity recorded in realtime during the stimulations. In this paper, we provide examples illustrating how realtime microseismic monitoring can be used to map the complexity and variability of slurry interaction with pre-existing fracture sets during the treatment. In one example, the dynamic spatial and temporal behaviour in microseismicity during a staged treatment procedure was used to vary the hydraulic fracture geometry. The observations described in this paper suggest that realtime microseismic recording and analysis can be used to map hydraulic fracture variability in naturally fractured reservoirs, evaluate the influence of pre-existing fractures on stimulations, and change stimulation procedures in response to observed hydraulic fracture variability. Introduction The efficiency of hydraulic fractures largely determines the economics of reservoirs. Having a reliable method to directly measure hydraulic fracture geometry / orientation and to assess the quality of the created fractures as permeable pathways, allows field engineers to improve completion designs and development strategies for effective drainage of these reservoirs. Typically, however, field engineers have to rely on engineering parameters, such as surface pressure, proppant concentration, for real-time control of the stimulation. History matches of numerical model simulations, post-frac radio-tracer tests and production results are used to assess the success or failure of hydraulic fracture based stimulations. Techniques such as surface and downhole tilt-meters have been used to obtain information on fracture orientation and length, but these do not provide adequate images of the fracture volume, particularly in real-time when field engineers can still invoke changes to stimulation procedures. In recent years, a significant effort has made to investigate the possibility of using microseismic monitoring methods to record microearthquakes originating as a result of hydraulic fracture stimulations. In this paper, we describe how microseismic monitoring, including event location and event timing has enhanced our understanding of the hydraulic fracture process, particularly as related to stimulations in the Barnett Shale, Texas, a naturally fractured reservoir in the Fort Worth Basin, comprising of Lower and Upper Barnett shale units varying in thickness between 300' and 1000'. This study provides direct microseismic measurements of fracture dimensions and orientation, and the relationship to ensuing production. Acquisition and Processing of Realtime Microseismicity For each treatment, an offsetting production well was selected to act as the observation well. These wells were approximately orthogonal to the expected frac-ture orientation and within 2000' of the treatment well. A 12 level triaxial geophone array, along with downhole digitization and telemetry, was temporarily placed in the observation wells. Sensor spacing ranged from 50' for the lower levels to 100' for the upper four levels. Sensor orientations were obtained using perforation shots in the treatment wells. Figure 1 shows an example of the recorded signals along with the automated P- and S-wave arrival times. Event locations were auto-matically determined based on arrival times and azimuths (orientation to the event source), as shown in Figure 2. As described in Maxwell et al., a data visualization package was used to display the event locations in realtime. As new events were processed, a quality check was made on the automatic data by verifying the arrival times and hodograms prior to sending the data to a visualization computer at the frac van, where petroleum engineers could view interactive 4d maps of the fracture geometry.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.76)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Abstract This paper highlights the development of a coupled poroelastic geomechanical and fluid flow model which incorporates field and lab data with the objective to constrain the full in-situ stress tensor and rock strength in order to predict the stability of open hole horizontal completions during reservoir depletion. Results of a four-year comprehensive testing and monitoring program conducted to assess the extent of hole instability during shut-in and flowing periods indicated that there was no immediate hole collapse. However, the study revealed the need to assess the long-term impact of reservoir depletion and pressure drawdown on wellbore stability. The results of this study indicate that the in situ stress state can be characterized by a normal faulting environment with low differential stresses in which the maximum principal stress is approximately equal to the overburden. Furthermore, a detailed analysis of wellbore stability during production supports openhole completion for horizontal wells under the condition that reservoir depletion is limited to a maximum pressure drop of 1,500 psi. This finding is independent of well azimuth. Pressure drops exceeding 1,500 psi in the reservoir are likely to cause considerable wellbore instabilities. These results were achieved under the assumption of moderate to more pronounced amounts of drawdown (500–1000 psi) in the near wellbore region. The study also highlighted that laboratory-derived rock strength values from triaxial tests, are low and are not consistent with the drilling and production experiences to date in the field. Rather, the formation appears to behave in a plastic manner that strengthens the wellbore. Introduction Hole stability concerns in the Shu'aiba reservoir, Shaybah Field, Saudi Arabia, first surfaced during the drilling and logging of two development vertical evaluation/production wells where a logging tool was stuck in one well due to tight hole, and indications of tight hole were encountered while drilling another well. The two incidents signaled the need to investigate hole stability in the Shu'aiba reservoir. A review of all the vertical delineation wells drilled in the 1960's for problems associated with hole fill and/or collapse during drilling and production found no conclusive evidence for stability problems. Cores taken in the mud-rich, high porosity rock of the Shu'aiba formation have been described as having a "toothpaste-like" texture and behavior. Preliminary laboratory rock mechanics studies indicated that the Shu'aiba carbonates are mechanically weak with the majority of the rocks tested yielding very low strength values (less than 2000 psi) when compared to samples from other carbonate reservoirs. In light of the gathered field and geomechanics data, a comprehensive hole stability monitoring program was formulated and initiated with the objective to investigate the extent and implications of hole stability on field development and deliverability. Results of which are summarized in SPE 565081 indicating, at least in the short term, no impact of production on wellbore stability. Furthermore, a long term study, which is the focus of this paper, was initiated to constrain the full in situ stress tensor (i.e., orientation and magnitude), reservoir pore pressure, and rock strength in order to build a geomechanical model of the Shaybah Field and predict the stability of openhole horizontal wells during reservoir depletion. To achieve these goals, a broad suite of available data from wells drilled in Shaybah Field were utilized such as electrical FMI image data, four-arm caliper logs, minifracs, wireline logs (e.g., density, neutron, and sonic logs), and pore pressure information obtained by direct measurement were studied. This data - sufficient to constrain the full stress tensor and pore pressure - was then augmented by information on uniaxial compressive strength derived from laboratory measurements and log data to build the full geomechanical model, which was then used as a basis to predict wellbore stability during reservoir depletion.
- North America (0.94)
- Asia > Middle East > Saudi Arabia > Eastern Province > Rub' al Khali Governorate (0.66)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Fault > Dip-Slip Fault (0.34)
- Asia > Middle East > Saudi Arabia > Eastern Province > Rub' al Khali Governorate > Rub' al Khali Basin > Shaybah Field (0.99)
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Wasia Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Nahr Umr Formation (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract This paper presents a forward model for subsidence prediction and an inversion model to calculate the reservoir behaviour from subsidence data. The forward model employs combinations of analytic solutions to the elasticity equations, which approximate the boundary conditions. There are only few free parameters and consequently the calculation times are limited. Still, the model is applicable to a multi-layer subsurface with elasticity parameters changing per layer. The inverse problem is usually ill-conditioned or ill-posed and has therefore been regularized by introducing a priori data about the pressure field or by imposing a certain amount of smoothness. The strength of the regularization parameters are best determined using the model resolution of the inversion and synthetic cases. These also can be used to optimize the experimental design. Inversion of a synthetic case with a "wrong" forward model shows the importance of obtaining reliable subsurface elasticity data. Without such data, the quality of the inversion can be highly compromised. Introduction The production of hydrocarbons reduces the pressure in the reservoir. As this pressure change affects the in-situ stress field through poro-elastic coupling, the reservoir may compact and surface subsidence or seabottom subsidence can result. Classical examples are the Groningen gas field in the Northern part of the Netherlands [1,2], and the Ekofisk oil field in chalk in the Norwegian sector of the North Sea [3]. The connexion between compaction at the reservoir level and the surface subsidence calls for modelling. Forward modelling is required when the amount of compaction is known, or when it can be predicted to an acceptable confidence level, and when the present or expected subsidence must be estimated. Inverse modelling is required when the subsidence pattern has been measured and knowledge or confirmation is sought about the subsurface processes. The latter can be the distribution of the pressure drop over the reservoir. It can also be the behaviour of an aquifer driving the reservoir to production. For accurate predictions it is often necessary to first perform an inversion and then apply the forward model for the future. Various authors have already touched upon the above modelling requirements. Geertsma [4] was the first to apply an analytic, linear forward model based on the nucleus of strain concept [5,6] to subsidence phenomena. Many others have used or expanded his formulae, or presented alternatives [7,8]. A different approach is to use numerical codes, as Finite Elements [9–12]. Here the full coupling between the flow in the porous medium and the geomechanics can be simulated, with due account of the subsurface heterogeneity [13]. The inverse modelling has attracted less attention, although there have already been a number of useful contributions [14–18]. Most of them used a linear forward model as the Geertsma formula and a linear inversion technique, although Vasco also used Green functions obtained from Finite Element simulations. In all cases, regularization of the inverse problem was required because the problem was ill-conditioned or even ill-posed. This regularization was achieved using additional a priori information. The present paper will first discuss the multi-layer linear elastic model which the author briefly presented earlier [19], being a more sophisticated model than the single-layer to three-layer analytical models available to date, but without the computational efforts required for finite-element calculations. The limited computational requirements made the method suitable for inversion, which is the second main issue in this paper. An inverse model is presented targeted at obtaining information about the subsurface from the subsidence levelling data. A method to assess the quality of the inversion process, independent of the actual data, has been used to optimize the regularization of the inverse modelling process and to determine an optimal subsidence measuring campaign.
- Europe > Netherlands > North Sea (0.48)
- Europe > Norway > North Sea > Central North Sea (0.34)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > Ameland Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract For a borehole of the Gullfaks field in the northern North Sea 60 days borehole pressure data of two successive registrations (hereafter parts I, II) were analyzed. From correlation with theoretical ocean tides a loading efficiency ? of 0.35–0.40 and of 0.16–0.19 were obtained for parts I and II, respectively. No influence of air pressure or earth tides could be resolved. Assuming an undrained Poisson ratio ?uranging between 0.30 and 0.36 and assuming that the vertical loading results in an areal strain ea of the same magnitude as the vertical strain eV a Skempton ratio B of about 0.45 for part I and of about 0.20 for part II were derived. B values are somewhat higher assuming smaller ea. The notably different values for ? and thus, B can be explained by a significant change in reservoir properties, which was induced by several injections in the borehole in the time between the two registrations. Introduction Variations of crustal strain are known to result in pore pressure changes (Bodvarsson, Wakita, Rojstaczer, Kümpel). These may be observed as fluid level changes in open wells or as pressure variations in wells shut-in. While on-shore earth tidal strain and air pressure variations are major natural forces, off-shore ocean tide loading is of significant influence. Comparison of pore pressure fluctuations and forcing functions enables to derive the loading efficiency (pressure change per loading) and the strain sensitivity and consequently, to constrain some effective, in-situ petrohydraulic parameters of the hydraulically connected section. This analysis has been applied in a number of continental wells (e.g. Van der Kamp &Gale, Rojstaczer &Agnew, Beavans et al., Schulze et al.) but only in a few oceanic boreholes (e.g. Furnes et al., Netland et al, Wang &Davis). Here, this technique is used to analyze two consecutive pressure registration of an offshore borehole in the Gullfaks field in the North Sea. The in-situ Skempton ratio was derived for both time intervals. The two values differ significantly and indicate a change in reservoir properties resulting from activities in the borehole. Theory Fluid level changes due to earth tidal strain have been observed for more than 100 years (Klonne). Often, the deformed rock is modeled as a homogeneous porous body with a poroelastic rheology. In this paper we use the approaches of Van der Kamp &Gale and Rojstaczer &Agnew as presented in Schulze et al.. Assuming static confined conditions, the reaction of a poroelastic aquifer due to strain changes and extensive loading can be described with the three parameters Skempton ratio B, undrained Poisson ratio ?u and undrained compressibility cu. (For a detailed overview on the theory and parameters of poroelasticity see Kümpel or Wang). B measures the change in pore pressure P per unit change in confining pressure Pc under undrained conditionsEquation 1 where c is the drained compressibility, cs the grain compressibility, cn the pore compressibility, cfl the pore fluid compressibility and n the porosity. Often it is assumed that cn=cs, which is true, if the porosity does not change for equal changes in Pc and P.
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract A technique for extrapolating core-measured rock mechanical properties from a cored well to an uncored well is presented. The process uses electrofacies and square wave techniques to develop rock mechanical property logs for the uncored wells. Data from the North LaBarge Shallow Unit (NLBSU) is used to develop the process. The NLBSU wells require hydraulic fracturing to generate economic production rates. The NLBSU produces from Cretaceous-age Mesaverde sandstone that is composed of thinly bedded sand and shale layers. The reservoir heterogeneity caused by these layers complicates hydraulic fracture growth characteristics. Improvements in hydraulic fracture simulation are needed to accurately predict these growth characteristics. This includes improvements in input data, such as rock mechanical properties, for the simulations. The described methodology uses electrofacies developed from core and FMI in one well and extrapolates the electrofacies to other wells via an AO10 induction log curve (depth of investigation 10 in (25 cm)). Induction logs are run in almost every well in the field and provide a universal extrapolation medium without incurring additional costs. The process uses acoustic velocity measurements for rock mechanical values, but any accepted measurement technique can be used. Only two major facies are present in the NLBSU and the presented technique only addresses the two facies. However, the methodology can be expanded to include more facies if cutoff values can be established. The process described in this paper is being used to improve hydraulic fracture modeling in the NLBSU. It can be used in other fields which need improved modeling also. Additionally, it can be used for any computer simulation program that requires rock mechanical property input including reservoir simulation and wellbore stability programs. Introduction Computer simulation programs are available for various applications in the oil and gas industry including hydraulic fracture modeling and reservoir simulation. Unfortunately, as helpful as some of these simulation programs are, the output information provided is only as good as the input data supplied. In 1998 at the SPE/ISRM Eurock conference, Kenter and Currie even described the need for good simulation input data as the "major challenge for the coming decade." Not only is the acquisition of high-quality data an issue, but the cost of obtaining such data is also a concern. Whether physical properties are measured in the laboratory or in the field, there are associated costs. These costs are generally tied directly to the heterogeneity of a reservoir - the more heterogeneous the reservoir, the more data sets are acquired, the higher the cost. This paper provides a methodology for extrapolating rock mechanical properties from a cored well to an uncored well through the use of electrofacies. This process allows detailed data acquired at one well to be extrapolated to other wells in the same reservoir. The extrapolation process uses common electrical logs that are run in the majority of field wells. By using this extrapolation technique, the cost for measuring the initial rock mechanical properties is spread between several wells. Additionally, comprehensive hydraulic fracture simulation can be performed for all wells in the field, not just the well on which the rock mechanical properties were initially measured.
- North America > United States > Wyoming (0.95)
- Europe (0.93)
- North America > United States > Texas > Dawson County (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.88)
- North America > United States > Wyoming > La Barge Field > Madison Formation (0.99)
- North America > United States > Wyoming > Green River Basin (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- (2 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Wellbore Design > Rock properties (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (2 more...)
Abstract A Mohr-Coulomb failure criterion is applied to estimate fluid pressures that may cause fault reactivation during the depletion of hydrocarbon reservoirs. The estimates incorporate the decline in total minimum horizontal stress that accompanies fluid pressure depletion in hydrocarbon reservoirs. Such pore pressure/stress coupling must be incorporated in predictions of depletion-induced failure because it significantly influences the fluid pressures at which faulting occurs. A new algorithm for failure incorporating the coupled decrease in pore pressure and stress is derived to calculate the fluid pressures that can cause slip on normal faults during ongoing production. The algorithm is applied to the Ekofisk reservoir, Norway, using various friction coefficients for chalk and incorporating the observation that the minimum horizontal stress decreased at 80% the rate of pore pressure depletion in the field. A friction coefficient of 0.6 yields realistic results when modelling the depletion period 1975 to 1990. A fluid pressure decrease from the initial 45 MPa to 38 MPa is required to activate optimally oriented faults with dip angles of approximately 60°. This fluid pressure level (38 MPa) was attained in 1978–1980 and marks the onset of significant subsidence in the Ekofisk field. Ongoing fluid pressure depletion from 38 MPa to the present level of approximately 25 MPa is sufficient for sliding on faults with dip angles of 48° to 73°. Preexisting fractures in the Ekofisk reservoir fall in this range, as they exhibit predominantly steep dip angles (65°). Slip events recorded during seismic monitoring that was conducted in 1994, are likely to represent the reactivation of such steeply dipping faults and possibly the formation of new fractures. The modelling technique presented for predicting induced reservoir and fault failure is an essential requirement for the long-term planning of hydrocarbon field depletion. Introduction The production of hydrocarbons from reservoir rocks can induce brittle failure in reservoirs and their immediate vicinity. Induced failure in reservoirs may increase existing fracture permeability and may thus be beneficial for hydrocarbon recovery. However, the withdrawal of pore fluid and thus the depletion of pore fluid pressures can also cause well bore casing failure and hence reduce the stability of the well bore. In fact, the reactivation of preexisting faults can shear off wells and damage surface constructions such as oil, gas and water pipelines. The risk of damage can be managed by predicting pore fluid pressures at which brittle failure is likely to occur. Hydrocarbon withdrawal over decades of production in oil fields can cause fluid pressure depletion that is in turn associated with a decrease of the minimum horizontal stress. Such pore pressure/stress coupling, that was observed in the Ekofisk field, Norwegian North Sea, is shown in Fig. 1. Some of the effects of pore pressure/stress coupling on reservoir integrity in normal fault stress regimes have been outlined by Hillis. A decrease in the minimum horizontal stress, which is the minimum principal stress in a normal fault stress regime, leads to an increase in the differential stress (s1 - s3). Unlike the total horizontal stress in the earth's crust that is strongly controlled by the elastic properties of rocks, the total vertical stress is given by the weight of the overburden load. The vertical stress, which is the maximum principal stress in a normal fault regime, is thus largely unaffected by pore pressure depletion. Although fluid pressure depletion without changes in (s1 - s3) decreases the likelihood of induced failure, the increase in (s1 - s3) that is associated with depletion promotes failure in a normal fault stress regime (Fig. 2). Thus, predictions of induced failure require identification of the stress and fluid pressure path of a hydrocarbon field during production, as well as knowledge of the rock and fault strengths.
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 044 > Block 1/9 > Tommeliten Field > Zechstein Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 044 > Block 1/9 > Tommeliten Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 044 > Block 1/9 > Tommeliten Field > Smith Bank Formation (0.99)
- (7 more...)
Abstract To help design the completion of an Indonesian development well, we have carried outcross-dipole dispersion analyses over a depth interval of approximately 500 ft. Dispersion analyses provide estimates of radial extent of formation damage and indicators of stress- and bedding-induced anisotropies. Most of these sections of this vertical well exhibit sand and shale lithology with shear slowness anisotropy ranging from 5 to 10%. Above the angular unconformity in the deeper section of the well, a clean sand interval (Sand A) shows evidence of cross-dipole dispersion crossovers. Crossing dipole dispersions are indicators of stress-induced anisotropy dominating the sonic data. We have developed a new technique for estimating the maximum horizontal SH, and minimum horizontal Sh stress magnitudes using multi-frequency inversion of wideband cross-dipole dispersions. At the mid-point of sand A, we estimate the overburden stress SV=-2278 psi; the maximum horizontal stress SH=-1843; and minimum horizontal stress Sh=-1698. The fast shear direction is NW5 in this depth interval. Radial profiling of formation shear velocity indicates varying degrees of mechanical alteration extending from one to two borehole diameters in the entire depth. A second clean sand interval B, 300 ft above sand A, shows dipole shear anisotropy on the order of 10%. However, cross-dipole dispersions appear to merge together at high frequencies instead of showing a cross-over. Radial profiling of shear velocity in the two orthogonal directions confirms mechanical damage extending to about 2x the borehole diameter. The near-wellbore region in this interval appears to have deformed (material creep) in an attempt to reduce shear stresses and attain hydrostatic equilibrium. Using the same stress sensitivity coefficients as estimated in the lower sand A, the differential stress (SH-Sh) is estimated to be about 20% larger in the upper interval, than the corresponding value in the lower interval. The fast-shear direction varies abruptly across the angular unconformity, changing from NW5 to NW75. Below the unconformity, this section exhibits beds with dips ranging from 10° to 30°. Cross-dipole dispersions show significant anisotropy and are non-intersecting at higher frequencies. Non-intersecting dispersions indicate bedding-induced anisotropy dominating the cross-dipole data. We have inverted borehole sonic velocities for four combinations of the TI-shale anisotropy, which can be combined with walk away VSPs to obtain all the shale anisotropy constants. These constants are needed in generating synthetic AVO gathers in anisotropic shale formations. Quantitative estimates of the radial extent of near-wellbore damage in this well suggest that perforations should penetrate deeper than twice the borehole diameter to avoid potential permeability impairment caused by near-wellbore mechanical damage. Introduction Optimal completions of wells require both identification and estimation of the radial extent of near-wellbore mechanical alteration that might cause near-wellbore permeability impairment. The near-wellbore mechanical damage characterized by radial profiling of formation shear can be correlated with the skin effect and reservoir productivity index. In addition, a detailed characterization of formation stresses is of help in maintaining wellbore stability and reservoir management. Estimates of formation stresses help us manage reservoirs that are prone to subsidence caused by a significant reduction in pore pressure and an associated increase in the effective stress that exceeds the in-situ rock strength. In addition, the magnitude and orientation of the in-situ stresses in a given field have a significant influence on permeability distribution that help in a proper planning of wellbore trajectories and injection schemes for water or steam flooding.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Stratigraphy > Lithostratigraphy (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.92)
- Geophysics > Seismic Surveying > Seismic Processing (0.74)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract The Pore Pressure is a critical point of any drilling project, once it influences the definition of the mud weight, casing setting depths, casing design, riser safety margin (RSM), etc. During the design stage of offshore and shallow water wells, safety factors (ranging normally from 0.5 to 1.0 ppg) are introduced to compensate the lack of accuracy in pore pressure evaluation. However, this may impose a limit in deepwater drilling operations. In such environment, as the water depth increases, the formations tend to show lower fracture gradients, which makes the difference between the pore pressure and the fracture gradient curves quite small, complicating the project. In this work the methods employed by Petrobras to evaluate the formation pressure are reviewed. Next, a procedure, employing statistical analysis, to evaluate the uncertainty in the pore pressure determination in the offshore portion of Campos Basin - Brazil, is presented. For that, a DST (drill stem test) and RFT (repeat formation test) database collected along the years in this area is employed. As a result, the safety factor applied over the Pore Pressure could be reduced, simplifying deepwater well projects. Introduction The Campos basin is currently the most productive of the Brazilian petroleum areas. This basin extends roughly from 15 km (9.3 mi) in land up to 3,400 m (11,155 ft) of water depth, coverings an area of about 100,000 km (2.47 10 acres) along the southeastern Brazil passive margin. To date, more than 30 oil fields have been discovered, including the giant fields of Marlin, Albacora and Roncador in about 2,000 m (6,562 ft) of water. As a consequence there is increasing interest in exploration in still greater water depths in this area . The offshore exploratory drilling is usually a high-cost and high-risk activity. One of the most significant sources of risk during drilling is associated with the unforeseen occurrence of formation pressure. Such situations can result in: stuck pipes, formation damage, well instability, kicks and eventually a blowout. Therefore, one of the most important objectives of the formation pressure evaluation is to drill a well safely and economically, without causing formations instabilities (collapse or fracture), without allowing inflow of formation fluids (water, oil or gas) and without causing damage to the reservoirs. In other words, the optimization of the drilling project depends on the correct evaluation of the geopressures. This evaluation is more critical in well design for deepwater wells. In this scenario, with the increase of the water depth, the formation tends to show lower fracture gradient (FG) due to having been compacted under low overburden gradient. Uncertainty in the PP evaluation is usually compensated by introducing a safety factor. Such factors range normally from 0.5 to 1.0 ppg, according with the uncertainty associated with the determination. That, however, imposes limits during the well design phase. The available margin for the mud weight, which must stay between FG and PP, can be very narrow complicating deepwater well projects, as it is schematically represented in Figure 1. In the next section, some important definitions related to the formation pressure evaluation will be given.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.30)
- Well Drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)