Abstract An accurate knowledge of porosity and permeability is crucial to accurate simulation of reservoir performance and enhanced reservoir management. Porosity and single-phase permeability of reservoir rocks is dependent on the stress experienced by the rock mass, which in the simplest case is given by the overburden stress minus the pore pressure. Hydrocarbon production decreases the pore pressure causing an increase in stress. This causes coupled changes in permeability and porosity, which have a significant effect on production rates. The stress and permeability changes are particularly large in the near wellbore region. The experimental programme was performed to examine the changes in two-phase permeability during deformation. This consisted of experiments where, starting from a given hydrostatic stress level, s 1 was increased until the rock failed and a shear fault was formed. In all experiments core flooding took place during the stress changes, either single-phase core flooding, oilflooding at S wi or waterflooding at S or . The experiments were performed on a water-wet sandstone. The deformation experiments were performed over a range of confining stress. Single phase, oilfloods and waterfloods, were performed at each stress. The stress strain behaviour, peak stress, residual sliding stress were independent of flooding type, but the variation of permeability was different depending on whether it was single or two phase flow. At low confining stress the single-phase experiments showed a smooth drop in permeability with strain, the oilflood showed first a decrease then a recovery then a steep drop at failure. The waterflood gave an intermediate behaviour between the other two. The results can be explained as an interplay between two mechanisms, compaction induced increase in tortuosity decreasing permeability and a dilatant increase in pore volume increasing permeability. At high confining stress the results showed the same effects except that the higher pressure inhibited dilatant cracking. This work has applications in determining the effect of the stress path on the permeability of the reservoir. The differences between the single and two-phase permeability are of great importance when the reservoir stress changes are likely to cause failure. The single-phase data greatly underestimates the actual permeability change. Introduction Changes in permeability in response to an applied stress have an influence on a wide range of processes from earthquake nucleation Byerlee (1993) to changes in oil production Bouteca et al (2000) . In the case of oil production the coupled interactions between geomechanics and fluid flow have a significant effect on production rates Chin et al (2000). The changes in permeability with stress are especially important in the near wellbore region where there is the potential for large stress changes. The changes in permeability with applied stress have been studied extensively since the early work of Fatt &Davis (1952) and Dobrynin (1962) , who studied the reduction in single-phase permeability at high confining pressure. They found a reduction in permeability with increasing effective stress. The changes in two phase permeability as a function of confining pressure have also been studied. Fatt (1953) Wilson (1956) and Ali et al (1987) all studied the effects of confining pressure on two phase permeability and came to differing conclusions on whether relative permeabilities were stress sensitive. Jones et al (2001) measured the stress sensitivity of relative permeabilities in a number of sandstones an found that they were in general sensitive to applied stress but the exact stress sensitivity was dependant on the type of sandstone.

Abstract There has been substantial recent progress in coupling geomechanical effects to reservoir response, thus dramatically improving representation of the consequences of rock response to pressure changes. New reserves have been identified from compaction. Injection geomechanics has gained an increase in interest due to its impact on the reservoir, faults and well hardware. Changes in transmissibility are now seriously implemented in reservoir engineering tools with more attention directed at the presence of compaction and dilatant bands around producers or injectors. Efforts are progressing to ensure adequate coupling between the local effects of the rock deformation near the wellbore, as well as along faults or bedding planes, and the evolving stresses and deformation in the reservoir. This paper attempts to discuss current gaps in understanding the intricacies and details of coupling farfield deformation to well completion. Examples are shown where reservoir compaction or dilatancy is explicitly coupled to near-wellbore behavior, with specific application for assessing well performance and survivability. The analyses can use reservoir simulations coupled with analytical predictions of stresses and deformations in individual simulator blocks. The predicted stresses and deformations form the boundary conditions for finite element modeling that can focus in on the details around the completion itself. This is in contrast to the current approaches that use explicit coupling of pressure and deformation in complete massive finite element representations, with refined gridding around the completion. The intimate details of coupling reservoir deformation to the completion require more intensive consideration. For example, "How can the cement sheath be represented?" or "What are some of the constitutive considerations in the near-wellbore region that impact integrity?" and "How is varying transmissibility related to well integrity?" These issues are considered. There are three goals: Start to recognize completion and production management practices that will improve completion longevity and optimize well productivity. Identify reasonable methodologies for representing the coupling between the completion and the reservoir, including yielded zones (dilatant and/or compactant), compaction bands with varying transmissibility, the cement sheath with or without a microannulus and the mud cake. Delineate approximate methods that will adequately forecast completion distress and permeability impairment without the necessity of expensive and time-consuming detailed finite element simulations. Introduction The industry has been experiencing a surge in activities related to the exploitation of reservoirs under complex conditions such as: Deepwater, under-saturated, abnormally pressured and unconsolidated sands where compaction drive can lead to subsidence and casing deformation in costly wells, especially subsea wells, and where future interventions are prohibitive and time consuming. Sand-production prone reservoir layers where sand exclusion imposes completion requirements that may impede achieving maximum well productivity. Depleted sand and carbonate zones where loss of circulation during infill drilling is undesirable and the presence of natural fractures may aggravate the situation. Horizontal, high angle and extended reach wells where well integrity during the well life is necessary. Environmental requirements that preclude emission of the associated produced streams (gas, water, drilling and completion wastes, etc.) and hence, may require provision for long-term subsurface injection of slurries.

Abstract This is a case study of a successful, field-wide implementation of horizontal, barefoot completions in a moderately competent formation - the Alpine Reservoir in Western North Slope, Alaska, Figure 1. A barefoot completion is a borehole without tubular liners and no cemented support - the least costly but riskiest completion strategy. (In this paper, barefoot and unsupported mean the same and are used interchangeably.) The Alpine experience provides a successful example where the benefits of unsupported boreholes outweigh the risks of borehole failure. To date, this aggressive yet simple completion technique has an aggregate length of more than 160,000 ft, all unsupported. Combined with good drilling practices, the success of barefoot horizontal wells in Alpine is also due to the following petrophysical and geomechanical factors: Consistent reservoir quality within the layer Absence of shale-breaks in the producing zone Moderate strength in normal fault geotectonic setting Low variability of strength Linearly elastic behavior Non-severe, slight weakening when water-saturated Good permeability retained under post-elastic strains Introduction In general, barefoot horizontal completions are implemented only in very competent, hard formations that pose little risk for wellbore collapse and/or sand production, such as dolomites, hard limestones, hard sandstones, and shale-free siltsones. The advantages of barefoot completions are: Low completion cost Simple and fast implementation Potentially lower completion skins if undamaged High productivity per unit length (producers) High injectivity (injection wells) Higher critical drawdown pressure for sanding However, the risks and disadvantages of unsupported, long, horizontal wells in Alpine are: Potential for collapse or sanding in weak zones Higher wellbore stresses compared to vertical wells Costly and limited options for zonal isolation Higher sensitivity to formation damage Limited options for stimulation Limited options for future remediation High friction factors for future coiled tubing workover There are very few reservoirs that are developed exclusively with barefoot horizontal wells, owing to the abovementioned risks. One recent example is described in Australia (Allard, 1998). The Alpine experience is the first reservoir in Alaska developed exclusively with barefoot horizontal wells.

Abstract Both horizontal and vertical rock stress magnitudes are substantially affected by pore pressure gradients generated by production from and water injection into low permeable chalk fields. This is confirmed by solid mechanics stress analyses and by observing fracture propagation in developed fields. Stress changes generated around horizontal injectors placed centrally between two parallel horizontal producers are considered in detail in this paper. It is shown that overburden and sideburden stresses may be altered and controlled to confine propagation of fracturing along the length of a central openhole horizontal injection well. It thereby becomes possible to establish a line drive development based on injection of water at fracturing conditions at reduced risk of premature water breakthrough (patent pending). 1. Introduction Mærsk Olie og Gas AS operates oil and gas fields in the Danish sector of the North Sea on behalf of DUC (Dansk Undergrunds Consortium). The Dan field, which came on production in 1972, was the first oil field to come on production. Experience has been gathered over three decades of production development of the tight chalk of (0.5–2.0 mD permeability range) Maastrichtian (Upper Cretaceous) and Danian (Lower Paleocene) age and has been associated with significant improvements to horizontal well and water injection technology. The conditions are favourable for displacing the oil by water because the injected water is less mobile than the oil. A means of providing sufficient leak-off area for water injection could be adoption of water injection at fracture propagation pressure. Induced water injection fractures in the Dan field can be large, some of more than 1,800 m (6,000 ft) of length have been created (Ovens et al. [1], Larsen et al. [2]). A few of these fractures intersect horizontal production wells resulting in water breakthrough, which has required isolation of production well partitions. To a large extent water injection fractures have been attempted aligned with the horizontal producers. Due to the low permeability of the chalk, a close well spacing is typically required. Traditionally, the fracture propagation direction has been assumed to be governed by a combination of local heterogeneities and the orientation of principal stresses as determined by the regional structural history. It shall be demonstrated here, that indeed orientation of stresses play a significant role in steering the fracture propagation. By controlling production and water injection induced stresses, an active steering of the fracture propagation direction may be achieved (patent pending). Based on Terzaghi's effective stress concept (Terzaghi [3]), the criterion for achieving (tensile) fracturing of the reservoir rock is that the effective rock stress becomes equal to the tensile strength of the rock. This criterion has been demonstrated experimentally (Jaeger [4]) and the theoretical basis has been treated by several authors amongst others Murrell (Murrell [5], see also comment by Jaeger and Cook [6] p. 225). Following a fracture mechanics approach Bruno and Nakagawa [7] derived the strain energy release rate (Griffith [8]) for fluid infiltrated porous rock. According to their analysis, the local pore pressure has an explicit, albeit minute, influence on the strain energy release rate for tensile fracturing. In response Detournay and Boone [9] argued against a direct contribution from the local pore pressure to the strain energy release rate (see also reply by Bruno [10]). Here, it is noted that the contribution from pore pressure is a result of the rock grain compressibility. For cases where the grain compressibility can be ignored (such as the present) the strain energy release rate can be derived directly from the compliance of the rock and the state of Terzaghi's effective stresses.

Abstract A novel numerical analysis is described, in which the steam-assisted gravity drainage (SAGD) recovery process in bituminous oil sand is studied. A geomechanical/reservoir simulator was modified to incorporate the absolute permeability increases resulting from the progressive shear dilation of oil sands. The objective was to obtain a realistic prediction of shear dilation, as the oil sands approached failure and beyond, and the concomitant increases in permeability. Changes in the in situ stresses that caused this dilation were due to the combined effects of reduced effective stress with high-pressure steam injection, and increased deviatoric stress with thermal expansion under lateral confinement. The resultant volumetric strains were used to modify the absolute permeability characteristics of the oil sands as the SAGD process progressed. The spatial and temporal growth of enhanced permeability zones resulted in an accelerated steam chamber growth. The relationship between volumetric strains and absolute permeability changes was obtained from existing laboratory data on quality specimens of non-bituminous Athabasca oil sands. The source sample was obtained from an outcropping of the McMurray Formation, thus avoiding most of the sample disturbance associated with unconsolidated core obtained conventionally. Under triaxial loading, the resultant volumetric strains increased absolute permeabilities by a factor of 4 to 6. The analysis is innovative in that the model used an effective stress approach, and used the volumetric strains to modify absolute permeabilities. Thus, the encroaching SAGD steam chamber was found to modify the stress regime, which in turn modified the permeabilities within the reservoir. Geomechanical enhancement of the SAGD process was found to be a significant beneficial effect, and would be increased by operating the SAGD process at higher injection pressures. Introduction Conventional reservoir simulations of thermal recovery processes in heavy oil and bituminous oil sands do not explicitly incorporate geomechanics. However, they implicitly include geomechanics since input permeabilities are air permeabilities obtained from core plugs. Due to the unconsolidated structure of these sands, core plugs are highly disturbed 1 . Porosities are typically 120% to 130% of the in situ porosities, as determined by petrophysical logging and other means. Specimens tested at overburden stress indicate that this disturbance results in permeabilities that are four times higher than in situ liquid permeabilities, on average. Fortuitously, these inflated permeabilities are comparable to those in situ , once the oil sand reservoirs have been disturbed. This is due to the shearing and dilation resulting from stresses altered by the recovery process itself. This is evident from history matches of SAGD projects, such as the UTF2, which used permeabilities obtained conventionally. Note that the limited number of operating SAGD projects have all been operated at relatively high injection pressures, relative to the reservoir depth, which result in low effective stresses. Therefore, while the implicit use of geomechanics, through the use of high absolute permeabilities, does work for the existing SAGD projects, this methodology cannot necessarily be extrapolated to other reservoirs with different operating conditions. Although history matches and predictions have been successfully conducted without geomechanics, these have been done without a complete accounting of the underlying physics. This is acceptable practice if simulating reservoirs and operating conditions comparable to those of current successful SAGD projects. However, a more rigorous approach was taken in this study, in which the geomechanics of the SAGD process were explicitly included in a combined geomechanics and reservoir simulation.