This paper presents relationships for estimating horizontal stresses based on the assumptions that the in situ stress state in a petroleum basin is controlled by the bounding normal or thrust faults at a limit equilibrium and that the fault block is linear elastic and plane strain condition applies in the direction parallel to the strike of the fault. These relationships are an extension of an earlier study and include the effect of residual friction angles on the estimation of horizontal stresses at depth.
The result shows that re-orientation of the minimum principal stress is possible after faulting depending on the Poisson's ratio of the formation. Predictions based on the relationships are compared with the stress data obtained in normal and thrust fault conditions as well as with the change in the minimum horizontal stress induced by the pore pressure depletion. The results show that to match the field stress data, a relatively low residual friction angle (100 - 300) on the fault is required. This is further supported by the numerical modelling of the in situ stresses in the Cusiana field in Colombia, and is consistent with the residual friction angles measured in laboratory or back-calculated based on earthquake mechanism.
Sanding experiments were carried out on weak sandstones with uniaxial compressive strengths in the range of 2 MPa to 25 MPa. The sandstones were either reservoir rocks or those with appropriate physical and mechanical properties to be good model materials.
The experiments involved simulating a perforation or openhole well, by flowing fluid/gas down a hole in a cylindrical rock sample. No radial flow component was present. The flow velocity could be varied, while the sample was hydrostatically stressed to values up to 70 MPa. Deformation of the hole, and the initiation and subsequent flow of sand are viewed and monitored using a specially designed optical method.
Significant differences in behavior were seen for the different rock types. The weakest rock showed compactant behavior, whereas the stronger rocks showed a more brittle response with the formation of breakouts in sanding tests.
The data will be used in the future in the elastoplastic modeling of the perforation geometry.
Experiments of this type provide a simple route to direct observation of sanding in experimental perforations or openhole wells, and give new insight into the mechanisms of failure and the diversity of these mechanisms with different rock types.
The paper presents a discussion on the issues related to the interaction between geomechanics and reservoir simulation in deformable hydrocarbon reservoirs. Geomechanics is important in order to account for rock deformations due to pore pressure and temperature changes resulting from production and fluid injection. Rock deformation can affect the permeability and pore compressibility of the rock. In turn, the pore pressures will be vary due to changes in the pore volume. Geomechanics is also required in order to account for the effect of the non-pay rock surrounding the reservoir on the overall reservoir compressibility and the loads transmitted to the reservoir by the weight of the overburden rock.
The paper gives the formulation and finite element discretization of Biot's equations for multi-phase fluid flow in deformable porous media. Based on this formulation, it is argued that geomechanical response and multi-phase fluid flow are fully-coupled processes in that pore pressure changes affect rock mechanical response and vice-versa, and that the two processes occur simultaneously. By contrasting Biot's equations and its discretization to the corresponding multiphase fluid flow equations used in reservoir simulations, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can have impact on reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is pore compressibility. This parameter is not sufficient in representing aspects of rock behaviour such as stress path dependency and dilatancy, which require a full constitutive relation. Furthermore, the pore pressure changes due to the applied loads from the non-pay rock cannot be accounted for by simply adjusting the pore compressibility. Example problems are shown in order to illustrate the value of coupling geomechanics to reservoir simulators. Finally, the practical benefits of using coupled geomechanics and reservoir simulations are discussed.
Presented in this paper are the results and verification of field and wellbore scale large deformation, elasto-plastic, geomechanical finite element models of reservoir compaction and associated casing damage. The models were developed as part of a multidisciplinary team project to reduce the number of costly well failures in the diatomite reservoir of the South Belridge Field near Bakersfield, California. Reservoir compaction of high porosity diatomite rock induces localized shearing deformations on horizontal weak-rock layers and geologic unconformities. The localized shearing deformations result in casing damage or failure. Two-dimensional, field- scale finite element models were used to develop relationships between field operations, surface subsidence, and shear- induced casing damage. Pore pressures were computed for eighteen years of simulated production and water injection, using a three-dimensional reservoir simulator. The pore pressures were input to the two-dimensional geomechanical field scale model. Frictional contact surfaces were used to model localized shear deformations. To capture the complex casing-cement-rock interaction that governs casing damage and failure, three-dimensional models of a wellbore were constructed, including a frictional sliding surface to model localized shear deformation. Calculations were compared to field data for verification of the models.
Compressibility of deep fluids-filled cavern is discussed. Compressibility is measured both through statical and dynamical tests. Statical compressibility is influenced by cavern shape and cavern fluids nature. This parameter plays an important role for such applications as the determination of stored hydrocarbons volume, of volume lost during a blow-out, and of pressure build-up rate in a closed cavern. Dynamical compressibility is measured through the periods of waves triggered by pressure changes. Both tube waves and longer period waves associated to the existence of an interface between a liquid and a gas can be observed. They can provide additional information, for instance the existence of trapped gas in the well-head.
Ringstad, Cathrine (IKU Retroleum Research) | Lofthus, Ellen Benedikte (NTNU) | Sonstebo, Eyvind F. (IKU Petroleum Research) | Fjaer, Erling (IKU Petroleum Research) | Zausa, Fabrizio (ENI Spa - AGIP E&P Divison and Giin-Fa Fuh, Conoco Inc.) | Fuh, Giin-Fa (Conoco, Inc.)
Micro-indentation measurements have been performed in order to investigate the possibility of extracting rock mechanical properties from small rock samples. The tests were performed with a 1 mm flat indenter. Two parameters were determined when analyzing the indentation measurements: The Indentation Modulus (IM) and the Critical Transition Force (CTF). IM is the slope of the force-displacement curve, corrected for deformations in the load frame. CTF is defined as the force level where the material deforms without significant change in the applied force.
The rock samples were casted in a mounting material (Demotec 30), in order to stabilize the sample during testing, and simplify surface preparation. The upper and lower surfaces of the samples were made flat and plane parallel by grinding. 15 materials were tested, including sandstones, limestones and shale/clay materials with different strengths and stiffness.
The micro-indentation measurements showed that both IM and CTF were significantly affected when the experiments were performed on small samples with volumes ranging from 0.04 Cm3 to 0.7 cm3. Correlations combining the Uniaxial Compressive Strength (UCS), Young's Modulus (E) and porosity ( ) with IM and CTF have been made. For measurements performed on small rock samples (embedded in Demotec 30) the following correlation with Uniaxial Compressive Strength was found:
UCS = 0.149 CTFR2=0.90
The correlation is only valid for small samples embedded in a mounting material with the same indentation properties as Demotec 30. It is not recommended to use the micro- indentation measurements to predict porosity and Young's Modulus.
To determine factors controlling permeability variations within and adjacent to a fault-hosted geothermal reservoir at Dixie Valley, Nevada, we conducted borehole televiewer observations of wellbore failure (breakouts and cooling cracks) together with hydraulic fracturing stress measurements in six wells drilled into the Stillwater fault zone at depths of 2 to 3 km. Measurements in highly permeable wells penetrating the main geothermal reservoir indicate that the local orientation of the least horizontal principal stress, Shmin, is nearly optimal for normal faulting on the Stillwater fault. Hydraulic fracturing tests from these wells further show that the magnitude of Shmin is low enough to lead to frictional failure on the Stillwater and nearby subparallel faults, suggesting that fault slip is responsible for the high reservoir productivity. Similar measurements were conducted in two wells penetrating a relatively impermeable segment of the Stillwater fault zone, located 8 and 20 km southwest of the geothermal reservoir (wells 66-21 and 45-14, respectively). The orientation of Shmin in well 66-21 is near optimal for normal faulting on the nearby Stillwater fault, but the magnitude of Shmin is too high to result in incipient frictional failure. In contrast, although the magnitude of Shmin, in well 45-14 is low enough to lead to normal faulting on optimally oriented faults, the orientation of the Stillwater fault near this well is rotated by 40 from the optimal orientation for normal faulting. This misorientation, coupled with an apparent increase in the magnitude of the greatest horizontal principal stress in going from the producing to nonproducing wells, acts to inhibit frictional failure on the Stillwater fault zone in proximity to well 45-14. Taken together, data from the nonproducing and producing wells thus suggest that a necessary condition for high reservoir permeability is that the Stillwater fault zone be critically stressed for frictional failure in the current stress field.
A numerical thermo-poro-elasticity model which can model time-dependent changes in stresses and pore fluid pressure induced by thermal and fluid diffusion has been developed. The model results agree well with analytical solutions for the instantaneous fluid injection of a poro-elastic medium. The results of some simple numerical experiments show that the computed changes in effective stresses, strains and pore pressure satisfy the constitutive equations for the thermo-poroelastic medium used in the model.
The model results showed that difference in temperature between drilling fluid and formation can induce significant changes in pore fluid pressure and effective stresses around the wellbore wall. The extent of the effects vary significantly with thermal diffusivity of the formation. In general, cooling the formation tend to increase the stability of the wellbore while the reverse applies to heating of the formation. The results also show the importance of considering the geothermal gradient, and thermal and fluid transport properties of shales in wellbore stability analysis and development of recommendations to manage instability.
Monitoring acoustic emission behaviour during core restressing is a means of collecting stress history information, but this effect (the "kaiser" effect) for rocks can not he used alone for paleostress reconstruction. Therefore, an integrated approach including regional geological and geophysical information such as magnetic, gravitational, and image data has been implemented in combination with core measurements and imaging logs. This analysis leads to a prohable history of far-field loading, and allows greater confidence in the interpretation in that numerous independent sources seem to suggest that the interpretation is consistent. For details of local stress distributions, Kriging methods are used, based on knowledge of the ancient landforms and erosional geometry. Practical applications of paleostresses in the context of basin analysis seem feasible if fractures can be linked to hydrocarhon migration and accumulation. To demonstrate this, the method is applied in the Ordos Basin in North China to establish the relationships between far-field and local stresses, and to link the stress and fracture history to the migration and accumulation of the large gas field found in the central Ordos area.
The specific surface of particles' and the properties of the pore fluid control the sensitivity of shales to a given change in the host environment. In this study, dielectric permittivity measurements are suggested to assess the reactivity coefficient, which is a measure of the physico-chemical sensitivity of a clay-fluid system. The effects of specific surface and pore fluid properties on permittivity data are discussed using dielectric spectra of ideal systems and real shale cores. Normalized high-frequency real permittivity data and the percentage of free water (estimated using high- frequency imaginary permitivity spectra) are shown to decrease with the increase in the reactivity coefficient. Similarly, high low-frequency permittivity values normal to the bedding plane indicate systems with high reactivity coefficients. Vertical strains measured during osmotic consolidation tests confirm the previous trend. Finally, general guidelines are presented to help in identification of reactive systems using complex permiflivity measurements.