The influence of pore pressure in assessing hydrocarbon prospectivity: a review

Transcription

1 The influence of pore pressure in assessing hydrocarbon prospectivity: a review Sam Green 1*, Stephen O Connor 1 and Alexander Edwards 1 discuss aspects of hydrocarbon prospectivity that are influenced by pore pressure. A ssessing the prospectivity of a basin or a play is a complex process that combines a multitude of geological, geomechanical and geophysical analyses with the aim to de-risk whether a particular basin/play should be explored further. However, it is possible to group the analyses under five simple terms: source, charge, reservoir, trap, and seal. In basic terms, if a basin/play can be demonstrated to have a source of hydrocarbons, a reservoir to accept the charge and a trap and seal to limit the migration of the hydrocarbons any further then the opportunity has been shown to be prospective for hydrocarbon exploration, i.e. de-risking has occurred. Typical elements of this de-risking process would include assessing the presence and quality of the source rock or building a structural and stratigraphic model from seismic amplitude data. Other components would be modelling porosity for instance. However, the particular focus of this paper is that many of the other components that need to be understood and modelled as part of the assessment of prospectivity are related to the pressure regime within a basin/acreage block in which a prospect is located. The focus of this paper is, therefore, to highlight and review those aspects of hydrocarbon prospectivity that pertain to reservoir quality, migration, maturation, prospect identification and hydrocarbon retention that are demonstrably influenced by pore pressure (Figure 1). It is important to note that whilst understanding the reservoir forms a key focus within such studies of prospectivity, the pore pressure within the bounding shales (relative to the reservoir) is also important to understand aside from the implications for well planning. Prospect identification One of the first instances of the importance of understanding pore pressure comes at the start of an exploration cycle where seismic is acquired and processed. A recent paper by Dutta et al. (2015) used a rock physics approach to guide the velocity model sub-salt in the Gulf of Mexico. The concept was to generate a range of plausible pressures based on a rock physics model, and then convert these pressures into a range of velocities. The set of velocities were then used to flatten the gathers. By constraining the gathers using this Figure 1 Flow chart summarising the key influences of pore pressure on the major elements of the petroleum system. 1 Ikon Science. * Corresponding author, sgreen@ikonscience.com 2016 EAGE 91

2 first break volume 34, May 2016 approach improves the image and allows for more detailed assessment of sub-surface features. Next, another key element is identifying direct hydrocarbon indicators (DHIs) from seismic amplitude data. Overpressure can change the nature of the seismic response at the sand/ shale interface thus making synthetic modelling problematic if pressure is assumed to be always hydrostatic, potentially changing AVO gradients and class. An example is presented in Selnes et al. (2014) from mid-norway where in the normally pressured part of the basin, a brine sand had a Class 2p AVO response and in the hydrocarbon case the sands had a Class 2 AVO response. Here the variation in AVO class allows for fluid type to be identified with confidence. However, if the reservoir is overpressured the hydrocarbons produce a Class 2p AVO response as the sand is cemented and the shale is overpressured (softer than normal). In this particular scenario, increased overpressure (as would be expected in deep clay-rich sections) leads to an inability to confidently identify the fluid type (Selnes et al., 2014). Reservoir quality Preserved porosity and overpressure in shales under-pins much of pressure prediction theory; where fluids from a compacting shale cannot escape, anomalously high porosity is preserved at depth and mechanical compaction is arrested. By way of contrast to shale porosity, the porosity of sand reservoirs is typically complicated by factors such as hydrocarbon charge timing and mineral precipitation and dissolution processes that reduce/enhance the porosity, as well as the ability of granular rocks to compact mechanically. Overpressure will reduce or arrest mechanical compaction, since it will either maintain or reduce the effective stress at grain boundaries and there are published studies of reservoir rocks that conclude that overpressure is an important contributor to porosity preservation (Loucks et al., 1984; Harris and Fowler, 1987; Scherer, 1987; Stricker and Jones, 2016). In the work by Scherer (1987) porosity was improved by 1.9% per 1000 psi of overpressure which could help to explain the presence of high porosity sands in deep, highly overpressured reservoirs such as the Jurassic Fulmar sand of the Central North Sea or the Eocene Wilcox play in the Gulf of Mexico. Stricker and Jones (2016) highlighted that early onset of overpressure within a sandstone was crucial as later overpressure development would have resulted in poorer reservoir quality. Owing to their porosity and permeability relative to any shale, fluids can percolate through, or out of, sands increasing the opportunity for cementation/dissolution through dissolution or precipitation of minerals within the reservoir fluid. Sealed, overpressured systems are likely to reduce in this fluid flux and thus preserve porosity (Stricker and Jones, 2016), although where local diffusion supplies the reactants, for example in quartz diagenesis, then the process cementation/ dissolution can still proceed but rather under closed conditions. Evidence for the direct influence of overpressure on quartz diagenesis is ambiguous; data from Mid-Norway suggest that quartz diagenesis is controlled by temperature alone, and can proceed irrespective of the pressure (Aase et al., 1996; Bjørkum, 1996; Walderhaug, 1996; Bjørkum and Nadeau, 1998). By contrast, data from Jurassic reservoirs in the Central North Sea show a dependence between volume and precipitation rate of quartz cement and the magnitude of overpressure (Osborne and Swarbrick, 1999; Nguyen et al., 2013). The model suggests a source of quartz from diffusion at grain contacts, the rate of which is controlled by effective stress magnitude. High magnitude overpressure (low effective stress) decreases the sources of quartz for subsequent re-precipitation; hence total cement and rate of cementation are lower than in reservoirs in which there is a higher effective stress. However, the effect of the overpressure may be coeval with early diagenetic cements aiding in the overall preservation of porosity (Nguyen et al., 2013; Grant et al., 2014). Therefore, the timing of overpressure with respect to the timing of cementation is critical because if overpressure occurs much later than cementation then there may be little or no porosity left to preserve. Furthermore, the timing of hydrocarbon charge has also been shown to be critical for porosity preservation. A recent study from the Kela-2 giant gas field in the Tarim Basin in north-western China highlights that understanding the palaeo-pressure and palaeo-hydrocarbon evolution of a reservoir can inform the present-day reservoir porosity (Guo et al., 2016). Key conclusions at Kela-2 are that the initial overpressuring associated with disequilibrium compaction in the shales, combined with initial charging of the reservoir with oil that was subsequently displaced by gas charge, lead to the preservation of anomalously high porosity through the retardation of compaction. Sandstone reservoirs with high porosity/permeability are associated with paleo-oil zones, whereas sandstones below the paleo-oil water contact have extremely low porosity and permeability. Thus, the porosity in sands may not reflect only pressure but also cementation, dissolution, timing of oil maturation and charge, as well as grain coating by depositional influences such as clay grain size/shape/surface area therefore linking pressure and reservoir quality directly is very problematic. Hydrocarbon maturation and phase Most studies of maturation are based on models that use only time and temperature, but there is a body of evidence from the literature from onshore plays of the United States (English et al., 2016), from the West of Shetlands (Carr and Scotchman, 2003) and from the South China Sea (Fang et al., 1995; Zou and Peng, 2001) that suggests that these models should also include an overpressure component. The most compelling field evidence for overpressureinduced retardation of maturation comes from the Yinggehai and Qiongdongnan Basins in the South China Sea where EAGE

3 Figure 2 Image showing the relationship between hydrocarbon migration from the source rock and pressure magnitude in the carrier beds relative to the source rock. When the carrier bed has an overpressure higher than the course rock then migration of hydrocarbons into the carrier beds is inhibited until the pressure differential is removed. organic maturation of overpressured source rocks is retarded relative to normally pressured source rocks of the same type under similar burial conditions (Fang et al., 1995; Zou and Peng, 2001). In the Zou and Peng (2001) analysis, overpressured conditions result in a lower vitrinite reflectance (VR) than would be expected in a normally pressured system. Zou & Peng (2001) link the lower VR values in overpressured zones to the inability of the organic material to expel hydrocarbons which consequently inhibits molecular reordering of the organic matter to higher VR configurations. As vitrinite reflectance is often used as an indicator of thermal maturity, its magnitude is important to maturation models (Carr, 1998; Zou and Peng, 2001; Carr and Scotchman, 2003). Lower temperatures are therefore assumed for these basin/plays when pressure is not incorporated into the maturation models which ultimately affects the predicted timing of hydrocarbon expulsion which has consequent implications for models of migration, charge and trapping; in some cases the diffrence can be significant. Hydrocarbon migration There are several ways in which petroleum can migrate out of a source rock. In a normally pressured system for instance, buoyancy forces may exceed the capillary entry pressure of the top seal. Alternatively, if the pore pressure within the source rock increases due to fluid expansion processes, i.e. gas generation, then this can result in hydraulic fracturing of the seal/overburden. Such hydraulic fracturing is evoked as an effective method of hydrocarbon leakage in petroleum basins (Grauls, 1997). Such processes have equal implications for unconventional plays as well as conventional sys- tems (English et al., 2016) as the uplift typically experienced in onshore plays can lead to dramatic overpressuring of the source rock due to gas expansion. Gas generation can create high internal pressures in source rocks which could drive migration downwards into adjacent carrier beds (Chi et al., 2010) as well as the more typical upwards flow, driven by buoyancy. In the examples quoted by Chi et al. (2010) from the Anticosti Basin (Eastern Canada) the overpressure in the source rock was greater than the buoyancy force and therefore downward migration was initiated. The variation in migration direction has implications for which parts of the basin to target for exploration. Once hydrocarbons have migrated into the carrier bed systems, overpressure can play a further role on their distribution. Variation in the magnitude of aquifer overpressure within a continuous carrier bed system will act to drive fluid flow from areas of high overpressure towards low overpressure; a process known as hydrodynamics, and resulting in hydrodynamic trapping and tilted fluid contacts in fields. One of the best studied hydrodynamic systems is the Palaeocene Andrew sand fan in the Central North Sea (e.g. Dennis et al., 1998, 2005). Hydrodynamic conditions affect prospectivity by a) depending on the trap geometry, the tilting of the HWC may increase or decrease the total volume of hydrocarbons, and b) the pressure drainage increases seal capacity allowing for longer hydrocarbon columns. Hydrocarbon retention The next logical step is to assess the seal capacity of a reservoir/seal pair. As a part of this process, pore pressure 2016 EAGE 93

4 first break volume 34, May 2016 assessment can have a major direct influence on de-risking prospects. Seal capacity analysis is typically divided into two areas; the quality of the seal, i.e. mineralogy, sorting, packing, net: gross, etc. (and therefore capillary entry pressures) and the mechanical or hydraulic capacity. Failure of the seal could, therefore, be hydraulic (fracturing) or through membrane leakage (no fracturing). In this paper, we focus on mechanical seal failure which is defined as the pressure difference between the minimum confining stress (which may be the overburden or the fracture pressure) of the seal and the pore pressure in the reservoir (e.g. Gaarenstroom et al., 1993; Bell, 1998; Hermanrud et al., 2005; Winefield et al., 2005). Seal capacity can be calculated as either the hydrocarbon seal capacity (HSC; minimum confining stress minus hydrocarbon buoyancy pressure) or the aquifer seal capacity (ASC; minimum confining stress minus aquifer pressure). Conventional industry practice would assess risk based on the HSC as the hydrocarbon buoyancy pressure is higher than the aquifer pressure (thus placing the seal closer to failure). However, laboratory studies have argued that due to the interfacial tension balancing the buoyancy forces, buoyancy pressure is not transferred on to the rock framework within the seal and therefore it is the aquifer pressure that controls hydraulic failure of the seal (Bjørkum et al., 1998). The applicability of using ASC to de-risk prospects is highlighted in the Jurassic of the UK Central North Sea where dry holes were shown to have low ASC and discoveries had high ASC (Swarbrick et al., 2010; O Connor et al., 2013). Furthermore, Swarbrick et al. (2010) also showed that the seal at top reservoir may not control hydrocarbon retention as the same aquifer overpressure was directly measured in the sands within and above the seal within some wells. The key conclusion of their study is that where vertical pressure cells can form it is the shallowest seal which exerts an influence on hydrocarbon retention. Hydrocarbon column length The implication from Bjørkum et al. (1998) is that buoyancy forces are not instrumental in fracturing top seal seals which has a potential impact on how hydrocarbon column length is Figure 3 Image demonstrating that lower aquifer overpressure (OP 1), therefore a higher aquifer seal capacity (ASC 1) will allow for a longer column height (CH 1) to be retained by a seal when compared to a more overpressured (OP 2) aquifer with a lower aquifer seal capacity (ASC 2) and therefore a consequently shorter column height (CH 2) EAGE

5 Figure 4 Workflow diagram summarizing the steps to create an effective stress map for an area of interest, i.e. a prospective basin or play. defined for a prospect. The conventional approach, as highlighted in Figure 3, is to calculate/estimate the aquifer pore pressure in the target reservoir and the minimum stress at the seal depth. Once a hydrocarbon fluid density has been estimated for the prospect, this gradient is projected downwards from the minimum stress at the top seal until it meets the aquifer gradient defined earlier. This defines the maximum theoretical column length a trap can retain. The relationship of overpressure, aquifer seal capacity and maximum column height is demonstrated in Figure 3. There are some interesting implications of the above discussion on whether buoyancy pressure is important or not in seal failure; Assuming the Bjørkum et al. (1998) model is valid, it can be inferred that it must be possible to retain a hydrocarbon column that is longer than that defined by the method above as the buoyancy force has no impact on seal capacity. There are no clear, published examples of such a discovery although there are traps considered to be actively leaking within the Central North Sea (Figure 4 in Winefield et al., 2005). The conventional column height assessment above is underpinned by the concept that as long as the aquifer pore pressure is lower magnitude than the minimum stress then a hydrocarbon column can be maintained and the column length is controlled solely by the hydrocarbon fluid density. In reality, failure of the top seal is likely once the aquifer pressure gets close to the minimum stress as observed in studies by many authors (Converse et al., 2000; Lupa et al., 2002; Winefield et al., 2005; Swarbrick et al., 2010; O Connor et al., 2013). A reason for this discrepancy is because LOTs measure the fracture strength of a wellbore but the magnitude of the test is higher than the minimum horizontal stress (Shmin) because of the hoop stress around a wellbore (e.g. Tamagawa and Pollard, 2008). Therefore, undrilled traps will fail at a stress lower than that defined from measured LOTs and requires a full Mechanical Earth Model (MEM) to accurately predict the failure stress. Derisking using Seal Capacity Magnitude It is possible to use knowledge of pore pressure and minimum stress to de-risk traps and, with the uncertainty highlighted, estimate column heights. A series of drilled wells with known results/pressures can be assessed using either ASC or HSC to produce a threshold for likely failure of the seal or preservation of hydrocarbons. An example from the Jurassic of the UK Central North Sea, and using ASC, demonstrates such a threshold in this key exploration area (Swarbrick et al., 2010). If 3D seismic data are available, then (a) crestal depths of a structure can be used in calculations of seal capacity rather then purely well depths which could be significantly down-dip of the weakest point of the structure (O Connor et al., 2013), and (b) a seal capacity map could be created based on a seismic surface. The process requires (a) that the overpressure is known at all points across the area of interest and (b) a distribution of the minimum stress; the minimum stress may be the fracture pressure (defined from LOT data) or the overburden (defined from wireline density data). In areas of high horizontal stress the fracture pressure may exceed the overburden hence the minimum stress is used. Once the above have been calculated, the aquifer seal capacity is computed as the minimum stress minus the aquifer pore pressure. The workflow is summarised in Figure 4 and an 2016 EAGE 95

6 first break volume 34, May 2016 Figure 5 An example of the aquifer seal capacity (ASC) mapped out for a key surface within an area of exploration within the Central North Sea. The colour scale represents the magnitude of the ASC value and the black lines are overpressure cell boundaries (either faults or stratigraphic barriers). Identified is the leak point for the overpressure cell (dark purple) as well a potential protected trap (pale pink) and a safe zone where the ASC is large (green). example is shown in Figure 5. There are other published examples of seal capacity mapping in the literature which were produced to aid in prospectivity, e.g. the Gulf of Mexico (Dutta, 1997). In the example in Figure 5, a number of features that are important for prospectivity can be identified; the leak point for the overpressure cell (purple bull s-eye), other areas of breached traps (other purple areas), potential protected traps and safe areas with large seal capacity (green). Clearly the areas with negative to low magnitudes of ASC would normally be avoided due to the excessive risk of hydraulic failure yet there are still opportunities within these zones, known as protected traps. A protected trap is a trap which may have a low ASC but is associated with a neighbouring trap which has an even lower ASC. The trap with the lowest ASC will always fail first and therefore it will protect the neighbouring structures from hydraulic failure by acting as the pressure release valve for the local system. Conclusions Based on the discussion above, it is clear that pore pressure plays an important role in many elements of derisking a prospective basin or play and accurately quantifying the pressure in the reservoir and the surrounding units is vital. Clearly pore pressure plays a critical role in assessing the likelihood of hydraulic failure of the top seal. Calculating the aquifer seal capacity and mapping it out across key surfaces can significantly aid in assessing areas of either likely failure of the seal or likely fluid retention. Pore pressure can have both positive and, potentially negative, implications when assessing hydrocarbon prospectivity. High pore pressure has been shown to help preserve porosity and to indicate the presence of higher quality seals but also to inhibit hydrocarbon maturation as well as migration from the source, reduce confidence in DHIs and increase the risk of hydraulic failure of the top seal. Lower pore pressure has been shown to aid in migration of hydrocarbons both out of the seal and along carrier beds towards up-dip traps as well as allowing longer hydrocarbon columns to form due to larger aquifer seal capacities but it also increases the chance of membrane failure. References Aase, N.E., Bjørkum, P.A. and Nadeau, P.H. [1996]. The effect of graincoating microquartz on preservation of reservoir porosity. AAPG Bulletin, 80 (10), Bell, J.S. [1998]. Offshore Canadian Overpressures and Implications for Hydrocarbon Exploration, In Overpressures in petroleum exploration. Bull. Centre Rech. Elf Explor. Prod. Mem., Bjørkum, P.A. and Nadeau, P.H. [1998]. Temperature controlled porosity/permeability reduction, fluid migration, and petroleum exploration in sedimentary basins. Australian Petroleum Production and Exploration Association, 38 (1), Bjørkum, P.A. Walderhaug, O. and Nadeau, P.H. [1998]. Physical constraints on hydrocarbon leakage and trapping revisited. Petroleum Geoscience, 4 (4), Bjørkum, P.A. [1996]. How important is pressure in causing dissolution of quartz in sandstones? Journal of Sedimentary Research, 66, Carr, A.D. and Scotchman, I.C. [2003]. Thermal history modelling in the southern Faroe Shetland Basin. Petroleum Geoscience, 9 (4), Carr, A.D. [1998]. Integrated maturation, hydrocarbon generation and diagenetic modelling in overpressured basins: Case study from the Central Graben, North Sea. Pau: Bull. Centre Rech. Elf Explor. Prod. Mem., Chi, G., Lavoie, D., Bertrand, R. and Lee, M.-K. [2010]. Downward hydrocarbon migration predicted from numerical modeling of fluid overpressure in the Paleozoic Anticosti Basin, eastern Canada. Geofluids, 10 (3), EAGE

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