Peter Schutjens

An introduction to reservoir geomechanics

Production of hydrocarbons leads to changes in reservoir pore pressure, resulting in changes in the stress acting on the reservoir and surrounding rocks. A decrease in pore pressure due to depletion leads to an increase in stress carried by the load-bearing rock frame of the reservoir, and may be accompanied by microscale deformation mechanisms such as cement breakage at grain contacts, grain sliding and rotation, Hertzian cracking at point contacts, plastic deformation of clay and mica grains, and opening and closing of microcracks (Schutjens et al., 2004). The increasing stress acting on the rock framework may also lead to compaction of the reservoir, and may result in problems such as surface subsidence, casing deformation, reactivation of faults or bedding-parallel slip. Evidence for stress changes in and around reservoirs undergoing depletion is provided by seismic events resulting from production (Segall, 1989; Grasso, 1992), and by time shifts observed using time-lapse seismic (Hatchell et al., 200...

Monitoring primary depletion reservoirs using amplitudes and time shifts from high-repeat seismic surveys

In the high-porosity, poorly consolidated turbidites of the deepwater Gulf of Mexico, production-induced compaction is the main production-drive mechanism when aquifer support is weak and prior to pressure support by secondary recovery water injection. Time-lapse (4D) seismic monitoring of this class of reservoirs has provided several new learning opportunities. The time-lapse amplitude response of these fields can be complicated due to saturation changes (water replacing oil) inside the reservoir, rock compaction causing density and velocity changes inside the reservoir, stress relief and associated deformation of the rock outside the reservoir, and changes in reservoir fluid pressures due to pore-pressure decrease. Methods that rely on time-lapse amplitude changes with offset to discriminate pressure and saturation changes can help separate and thus simplify the interpretation of some of these effects (Tura and Lumley, 1999; Landro, 2001).

Production-Induced Stress Change in and Above a Reservoir Pierced by Two Salt Domes: A Geomechanical Model and Its Applications

Production decreases the pore fluid pressure and increases the effective stress acting on the load-bearing grain-framework that makes up the reservoir. As a result, the reservoir deforms and compacts, and because it is connected to the rocks around it, there will be deformations and displacements in these rocks too. Well known effects are surface subsidence, wells damaged by shear, and timeshifts in 4D-seismic. Less well known is how the changes in the stress field itself should be taken into account in operations, e.g. to design infill wells and to plan production stimulation by hydraulic fracturing or waterflooding of the reservoir. We present a geomechanical model for the initial stress field and production-induced stress changes in and around a steeplydipping hydrocarbon reservoir penetrated by two large salt-domes. The model integrates 3D seismic and geological understanding, geomechanical data from wells and analogues, and depletion patterns from fluid-flow (dynamic) simulation. Our model results confirm published models of principal stress orientation in rocks pierced by salt domes. The depleted-model results show stress changes up to several MPa in magnitude compared to the pre-production stress state, but only limited changes in the stress orientations. The model highlights the influence of structural dip and time-dependent salt-sediment interaction on stress changes. We then describe the application of the model in wellbore stress analysis for infill wells and in a water-injection scheme that has (we think) been severely impacted by injection-induced fractures propagating into the reservoir towards the producer wells. We explain how the latter application uses a 3D flow simulation model coupled to a dynamic fracture propagation model. The geomechanical model provides key input: stress magnitude and orientation. Results are validated against more conventional analysis of real-time pressure data. In both applications, the integration of geomechanics in 3D static and dynamic models improved insight in the rock response to drilling and waterflooding, thus helping to optimise production. Introduction The Pierce field is characterized by two salt diapirs that are penetrating the reservoir formation, leading to two connected accumulations (North Pierce and South Pierce, see Figure 1). Seismic control is relatively poor due to the steep dips and shadow zones from the salt diapirs, and only major geological features such as large faults are well localized (at least mid to down dip). The field consists of two main reservoir units: Forties consolidated sandstone (described here) and the Chalk (undeveloped, and not treated in this paper). Geologically, the Forties consist of turbiditic sand-shale sequences, with considerable intra-reservoir structural complexity. Some data of the field are given in Table 1. It should be noted that due to the steep dips and a stepped/tilted contact, the total hydrocarbon column height is nearly 1600 m, while the average stratigraphic thickness is only approximately 100 m. It increases to approximately 230 meters in the saddle between the diapirs and in the main channel axis to the west of both diapirs. The pinching-out of the Forties towards the salt suggests that the salt diapir had pushed up two hills at the sea floor at the time of the Forties sediment deposition. Since 1999 the field has been developed under depletion drive with gas re-injection (one gas injector per accumulation). Since the aquifer strength was unknown at the time of the Field Development Plan, the producers were positioned roughly in the middle of the oil column. Then from the production and pressure data it became clear that the aquifer is weak. Therefore, in 2004, water injection was introduced in South Pierce with the dual objective to give additional pressure support and better sweep downdip of

The influence of stress path on compressibility and permeability of an overpressurised reservoir sandstone: Some experimental data

Abstract Laboratory experiments were performed to measure how the compressibility and permeability of an overpressurised quartz/feldspar-rich reservoir sandstone depend on the stress path induced by a production-induced decrease in hydrocarbon pressure. Two stress paths were followed in the experiments: one involved a uniaxial compaction with strain only along the cylindrical axis of the sample (i.e. no radial strain), and the other involved a simultaneous axial and radial compaction due to an isotropic increase in effective stress. The experimental results demonstrate a strong influence of compaction mode (i.e. stress path) on compressibility. Firstly, at a given effective axial stress, the uniaxial compressibility is a factor of between 2 and 10 higher than the axial compressibility observed during an isotropic increase in effective stress. Secondly, at around 60 MPa effective axial stress, the uniaxial compressibility shows a marked non-linear increase with increasing effective stress ( compaction weakening ). In contrast, the axial compressibility obtained in experiments with an isotropic increase in effective stress is much lower and increases roughly linearly with effective axial stress. Microstructural analysis revealed that the compaction weakening is probably due to intergranular fracturing and transgranular fracturing, particularly of quartz grains near partly hydrolysed feldspars. The horizontal permeability decreased by 5% to 10% of the initial permeability with every 10-MPa decrease of the reservoir fluid pressure, independent of stress path. This result agrees with data in the literature on isostatic compaction/permeability experiments, but it disagrees with the data of Rhett and Teufel (1992), who observed a permeability increase during uniaxial compaction of reservoir sandstones. A possible explanation for this discrepancy is that Rhett and Teufel probably measured the permeability parallel to the long dimension of preferentially oriented stress-induced microcracks, whereas in the present study the permeability was measured in a direction orthogonal to the long dimension of most microcracks.

On the stress change in overburden resulting from reservoir compaction Observations from two computer models and implications for 4D seismic

Production-induced depletion of hydrocarbon reservoirs leads to deformation, compaction, displacements, and stress change in the reservoir as well as in the surrounding rock. Such stress changes affect the acoustic-wave velocity and bulk density. This has two implications. It changes the contrast in acoustic impedance between reservoir and overburden, resulting in seismic amplitude changes at the top of the compacting reservoir. Secondly, it changes the traveltime of seismic reflection waves, leading to arrival-time delays (time shifts) of seismic data gathered in the repeat survey compared to data gathered in the base survey (Hatchell et al, 2004; Kenter et al, 2004; Stammeijer et al, 2004). Maps of time shifts can then indicate the areal distribution of reservoir compaction, and thus reveal the areal distribution of depletion. This could help to locate bypassed oil in undrained compartments, identify drilling targets and sidetracks, and avoid expensive infill wells. These interesting geophysical applica...

Production-Induced Compaction of the Brent Field: An Experimental Approach

The most attractive option to increase hydrocarbon recovery from the Brent and Statfjord reservoirs (Brent field, North Sea) is a gradual decrease of the reservoir fluid pressure. To provide laboratory data upon which estimates of the resulting reservoir compaction and surface subsidence could be made, the authors performed uniaxial compaction experiments at room temperature and in-situ stress conditions. Experimental observations suggest that the reloading of core samples to in-situ stress conditions closed coring-induced microcracks. Most Brent samples (porosity 6% to 30%) showed a compressibility that was constant with increasing effective stress (i.e., linear compaction) and increased with porosity. There was 30% to 75% strain recovery during unloading and an average permanent shortening of about 0.7%. Some high-porosity (25% to 30%) Brent samples showed a relatively high uniaxial compressibility that increased with stress (nonlinear compaction). Nearly all the statfjord samples showed nonlinear compaction. These inelastic brittle mechanisms, which occur together with elastic deformation of the load-bearing grain framework, seem dominant in high-porosity (Statfjord-type) sandstones and should be incorporated into predictive models of production-induced compaction of quartz-rich reservoir rock.

Geomechanical Technology for Seal Integrity Analysis: The Three-Step Approach

A clear understanding of the subsurface pore pressure and the presence of geological seals are significant considerations when designing safe wells and optimal production strategies for oil and gas resources. This paper highlights geomechanical techniques and tools which have been developed to assure injection operations for largescale EOR projects in South-East Asia. A key concern is if depletion or injection will lead to reservoir or seal failure by tensile fracturing or shear faulting. If so, will these fractures and faults “grow” upwards and provide a pathway for fluids to escape to the seafloor? First, a 1D-model is made of the total stresses and pore fluid pressures and how these change as a function of depth and depletion/injection. This empirical approach helps to highlight the zones of relatively low minimum effective stress where there is greater risk of rock deformation which will impact operations. Where more detail and refinement is required in terms of the identified risks, we analytically describe the reservoir and overburden deformation with the theory of poro-elasticity, Mohr-Coulomb-type shear faulting, and tensile fracturing. Analytical geomechanics aims at a mechanistic understanding using simplified geology and simplified pore pressure patterns, but with realistic mechanical rock properties. The third step delivers greater detail of the technical complexity using a 3D finite-element simulator. These numerical techniques can simulate the effects of complex structural geology or intra-reservoir compartmentalization, inhomogeneous depletion, and spatial variation in rock mechanical properties. It makes sense to start simple and gradually bring in more complexity whilst adjusting geomechanics support accordingly. We demonstrate the above three-step approach with examples from projects in the South China Sea, offshore Malaysia, which illustrate the multi-disciplinary aspect of geomechanics and its impact on safety, efficiency (costs), and the technical reputation of our company and industry.

Introduction to this special section: Geomechanics

Geomechanics is the discipline dealing with the prediction and management of rock deformation and failure. Geomechanical problems resulting from the change of stress in the rock induced by drilling and production make many hydrocarbon production projects challenging. Examples of geomechanical problems include wellbore stability and fracturing of the formation during drilling that may lead to financial loss due to losses, kicks, stuck pipe, extra casing strings, and sidetracks. Other problems are due to reservoir stress changes occurring during production such as reservoir compaction, surface subsidence, formation fracturing, casing deformation and failure, sanding, reactivation of faults, and bedding parallel slip.

An evaluation of pore pressure diffusion into a shale overburden and sideburden induced by production-related changes in reservoir fluid pressure

It is commonplace in the simulation of reservoir fluid flow induced by hydrocarbon production to regard shales as barriers to flow. Whilst this appears correct for fluid exchange, this is not the case for the fluid pressure component of this process. Indeed, the authors observe that pore pressure reduction due to reservoir depletion can propagate significant distances into the shale overburden or sideburden over the production time scale. Shales may deplete their pore pressures by more than 10% of that experienced in the reservoir sand for distances of tens of metres to kilometres into the shale, depending on the production history, duration and the specific shale properties. An important factor controlling these results is heterogeneity of the shale sediments, and the pressure diffusion process can be considerably enhanced by the presence of silt laminations and streaks. These results suggest a possible risk to drillers when advancing towards the top of a depleting reservoir or when drilling a well alongside an already depleted reservoir. Our analyses conclude that pore pressure diffusion should be considered as a factor in geomechanical and fluid flow reservoir modelling, and in mud weight determination during infill drilling.

Monitoring Primary-Depletion Reservoirs With Seismic Amplitudes and Time Shifts

In the high-porosity, poorly consolidated turbidites of the deepwater Gulf of Mexico (GOM), production-induced compaction can be the drive mechanism when aquifer support is weak and before pressure support by secondary-recovery water injection begins. Time-lapse (4D) seismic-monitoring time shifts occur in areas of depletion and in the overburden, and they indicate compartmentalization in the reservoir. Compartmentalization information can help place new production and injection wells better, as well as new sidetracks for optimized field development.