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Insight: Innovative technology available to help maintain North Sea production.

Sunday, September 29, 2013

There is renewed commitment by the government and industry to the extraction of oil and gas from the UK Continental Shelf. (Webb, 2013). New tax allowances have encouraged investment such that it is expected to total an all-time record of £13.5 billion in 2013, almost 3 times that of 2009. However, this investment is to a background of decline in production of oil and gas from the UKCS of ~31% from 2010 to 2012 with a further decline of ~22% projected for 2013, principally due to unplanned shut-downs.

The UKCS has so far produced just over 41 billion boe, representing an average recovery factor of 40%. Increasing recovery factors further is a challenge, but the prize is ~1 billion barrels per 1% increase across the UKCS.

Amongst other initiatives involving Government and industry bodies, the Increased Oil Recovery (IOR) work group has prioritised ten areas, including low salinity waterfloods, chemical enhanced oil recovery (EOR) and low cost subsea developments. Key to implementing such new technologies as well as maintaining current recovery techniques is awareness of, and expertise in risk. The mission of PetroMall ( is to put science and engineering back into risk management processes. PetroMall is a social business platform, which brings together world-class expertise and E&P professionals so they can work together under the oversight of an experienced subject matter expert in real time to understand and address risks. Available to members of the PetroMall community are experts in a wide range of topics such as process safety, 21st century security, corporate governance, petroleum law, reservoir uncertainty, geomechanics, flow assurance and company culture. More information was given by Greg Coleman at the recent launch event at a Finding Petroleum meeting (Coleman, 2013). Below are just a couple of illustrations of where new technology is able to overcome risks to help maintain or increase North Sea production and in which there are experts available through the PetroMall platform:

1) Gas hydrate formation as a risk to flow assurance: to mitigate this one needs optimal gas hydrate inhibition systems. A novel device (HydraCHEK) based on measuring electrical conductivity and acoustic velocity has been developed by Hydrafact Ltd and Heriot-Watt University to determine the hydrate safety margin, reduce the risk of hydrates and optimise inhibitor injection rates. This device has been central in extending the life of the NUGGETS subsea gasfield in the northern North Sea by 3 years (to date), producing an extra 2.8 million boe of gas (valued at some £100 million) beyond the originally planned decommissioning date and increasing the recovery by 2% (Saha et al. 2013). Improvements in the economy and reliability of hydrate inhibition strategies (as well as minimising the impact on the environment) have also been effected in 2 Middle Eastern fields (e,g. Lavallie et al., 2009).

2) Geomechanical influence upon reservoir behaviour. IOR studies, as with much of reservoir management and field investment planning, are mainly guided by simulation. Although reservoir simulation has progressed enormously over recent years in terms of numerical efficiency, coping with heterogeneities, estimating uncertainties and history-matching, nevertheless the physics which its conventional form assumes for reservoir fluid flow has not essentially changed for 50 years or more. The risk that the physics is not adequate is associated with commercial risks such as reduced recoveries, increased water production or the requirement for more wells. This claim, involving generally unfamiliar material, requires justifying in some detail. It is based on three paths of recent discovery that have merged to lead to formulation of a common new mechanism which is predominantly not included in current conventional reservoir simulation, and therefore which presents a risk to development plans:

  1. Observations of splitting of shear seismic waves as they pass through a variety of formations (sandstone, limestone, crystalline) e.g. Crampin (1994), Horne & MacBeth (1994). Essentially the interpretation of the characteristics of the observed shear-wave splitting involves the presence of compliant, stress-aligned (micro-)cracks, which cause the shear-waves to split into two phases with different velocities and approximately orthogonal polarisations. The density of cracks interpreted from observed characteristics lie mainly in the range ~0.015 and ~0.045. This is close to the density at which fractures intersect and also encompasses the percolation threshold for interaction of the elastic stress fields around each fracture (see figure 1). Figure 2a shows the orientational distribution of the elastic stress field around a dilated crack: the strongest tensile stress is at about 30o to its strike, implying that this is the direction in which reinforcing interactions are greatest. The proximity of densities to interaction and intersection thresholds imply that reservoirs are commonly in a critical geomechanical state. Critical systems are dynamic interactive many-bodied systems (in our case of cracks) in which perturbations in one member influence all other members through the interactions, usually over an extensive volume; whereas below criticality, they perturb only locally.

  1. Field data on correlations in the fluctuations of flowrates at pairs of wells. Fluid flowrates out of producers or into injectors are rarely constant in time: fluctuations are often a significant proportion of the average. A series of projects has found that a geomechanical signal again appears in the correlations. An aggregation from over 500,000 injector-producer well pairs from 8 different field areas of flooding operations, shows that flowrate fluctuations correlate much more between well pairs separated along a direction sub-parallel to Shmax, whether raw data is used or detrended data. In the case of raw data the average correlations are in fact negative along the orthogonal axis (Shmin). The flowrate correlations are also long-range, in agreement with the concept of criticality, not decaying spatially as fast as one would expect from Darcy’s law. A further recent development along this line has found in 6 North Sea fields that rate correlations diffuse over time most strongly in spatial directions that are about 30o to Shmax (see figure 2b). So the concept is that crack dilations or compressions induced locally by rate changes at one well propagate via interacting (micro-)cracks with a pattern that follows the pattern for a single crack over large distances, giving rise to corresponding changes in permeability and therefore in rate at remote well locations.

  1. Field data on directionalities of breakthrough of injected fluids to producer wells indicate that, in aggregate, modern-day stress state is a determining factor: the directions ‘preferred’ by injected fluid are those close to the maximum horizontal principal stress axis (Shmax). This preference holds for ostensibly ‘unfractured’ reservoirs (see figure 2c) as well as for ‘fractured’ ones.

Furthermore, the different orientational trends of 2 and 3 can be rationalised. Calculation of the isobars around a central injector which is surrounded by aligned (micro-)cracks with variable dilations determined by the stress interactions allow the generic directionality of waterfloods to be assessed. This turns out to be a compromise between the strike-parallel conductivity of dilated cracks and their most prominent alignment at 30o to strike – which is precisely what has been observed for nominally “unfractured” reservoirs (figure 2c). The wide-ranging datasets imply that geomechanics is a common mechanism in many, if not most, reservoirs. But it is not taken into account in most reservoir models, implying that it is an extra risk that should be evaluated in most cases. What is the value associated with the risk? Potentially large. It has long been known (e.g. Caudle & Loneric, 1960; MacBeth & Pickup, 2002 ) that anisotropic permeabilities can have a large effect on recovery factors: arranging a favourable alignment of injectors and producers relative to permeability (and so stress state) axes makes a big difference to oil recovery to breakthrough (up to 10s of % points in an idealised situation); and some difference up to high water-cuts. To this potential additional recovery can be added the saving in cost of treatment for produced injection fluid, and even savings in well numbers in some circumstances. In some cases permeability anisotropy is obviously manifest; in many more it is likely to be a more subtle characteristic, but nevertheless still commercially important.

So here are some pointers towards utilising these findings in the effort to mitigate the risk of geomechanical influence:

· Take stress state orientation into account when planning well configurations for waterfloods or EOR. The theory and field data are mutually supportive of a generic orientational pattern (relative to Shmax) of water breakthrough and permeability changes around injection points (figure 3). Figure 4 is a field example that provides specific support for these trends: large differences have been observed in oil and water production for producers according to the orientation of their offset from nearby injectors relative to the local stress state.

· To provide improved detail of the potential influence of geomechanics within the context of the specific structural and stratigraphic heterogeneities associated with a particular reservoir, coupling reservoir simulation models with geomechanics is certainly possible, but presents further practical difficulties for day-to-day reservoir engineering. Supplementary analysis that enables the implications of geomechanical effects for poroperm properties to be fed into conventional reservoir simulation is an easier first option.

· The technique of analysing correlations in flowrates can be used to complement geomechanical information in mature fields: such analysis enables a form of tomogram of the reservoir between wells. Principal components and rate diffusivity axes extracted from the correlations can highlight the dynamic faults and fracture corridors that are prominent in passing signals between wells (see figure 5 for an example).

· Stress fields and pressure are coupled variables: therefore one should expect stress states to change significantly during the life of a field. Such geomechanical changes can then change permeability pathways. Changing patterns of flowrate correlation over time have been observed in one North Sea field as reservoir pressures dropped drastically and then recovered during water injection.

· Analysis of flowrate correlation, using readily available production data, requires no field data acquisition. As well as being useful in its own right it can also provide a useful screening tool to assist decisions on whether further studies or field data acquisition is appropriate; e.g. measurement of mechanical properties of reservoir rock, coupled or uncoupled geomechanical modelling, passive seismic (microseismic) and shear-wave surveys. Conversely, different geomechanical changes compared with conventional assumptions (principally perhaps long-range versus local influences) imply potentially different interpretations of 4D seismic.

· Optimisation of short-term production might be effected outside of reservoir simulation. For example an initial analysis could examine principal modes of rate fluctuations to assess whether those that are associated with high oil production and low water production might be encouraged in field operations.

“The tendency for extensional fracturing and normal faulting associated with abrupt changes in pore pressure may have implications for changing reservoir properties during production. One can speculate that steep gradients in pore pressure due to lateral variations in permeability might generate substantial changes in horizontal stress that favor extensional fracturing and normal faulting in the lower-permeability medium”. That quotation is consistent with the above concepts, but the words were written by Segall & Fitzgerald in 1998. The UKCS hydrocarbon industry does not have much further time for such leisurely uptake of new technology!

To contact Kes Heffer, please click here or on the link at the beginning of this Review.

Read more:


Caudle, BH & Lonaric, IG (1960) ‘Oil Recovery in Five-Spot Pilot Floods’, Trans AIME v219, 132-136. Results reproduced in ‘The Reservoir Engineering Aspects of Waterflooding’ ed. FF Craig, SPE Monograph vol. 3 (1971) Figs 5.14 & 5.15

Coleman, G. (2013) Why are there still major incidents in the E&P industry? presentation at the Finding Petroleum event of 18 Sept video and pdf available at

Crampin, S., 1994, The fracture criticality of crustal rock, Geophys. J. Int., 107, 185-189.

Heffer, K.J. publications available at

Horne, S.A. & MacBeth, C.D. 1994. Inversion for seismic anisotropy using genetic algorithms, Geophysical Prospecting. 42 (8) 953-974

Lavallie, O., Al Ansari, A., O’Neil, S., Chazelas, O., Glenat, P. & Tohidi, B. 2009, Successful Field Application of an Inhibitor Concentration Detection System in Optimising the Kinetic Hydrate Inhibitor (KHI) Injection Rates and Reducing the Risks Associated with Hydrate Blockage, IPTC 13765, presented at the International Petroleum Technology Conference, Doha, 7-9 December.

MacBeth, C. & Pickup, G., 2002, Estimation of directional permeability in fractured reservoirs – concepts and applications, SEG 72nd Annual Meeting, Salt Lake City, Utah, October 6-11.

Pollard, D.D. & Segall, P. 1987. Theoretical displacements and stresses near fractures in rock with applications to faults, joints, veins, dykes, and solution surfaces. In: B.K. Atkinson (ed) Fracture Mechanics of Rock, 277-349, Academic, San Diego, California.

Saha, P., Parsa, A. & Abolarin, J., 2013, NUGGETS Gas Field – Pushing the Operational Barriers, SPE 166596, SPE Offshore Europe, Aberdeen, 3-6 Sept.

Segall, P &. Fitzgerald , S. D. (1998) A note on induced stress changes in hydrocarbon and geothermal reservoirs, Tectonophysics, 289, 117–128

Webb, M. (2013) Oil & Gas UK publication

Figure 1. Frequencies of measurement of crack density from shear-wave splitting surveys (from Crampin, 1994),compared with theoretical estimates of percolation thresholds for interacting stress fields and intersecting cracks (i.e. the densities at which overlapping stress fields from individual cracks or the cracks themselves, respectively, form throughgoing paths)

Figure 2. (a) The stress field around a dilated crack (after Pollard & Segall, 1987). This is the xx component of the stress tensor where x is the normal direction to the crack. (b) Aggregated orientational distribution, relative to the most common local measurements of direction of Shmax (rotated to 0 degrees), of the major axes of flowrate diffusivities derived from rate correlations observed in 6 North Sea fields (from Heffer, 2012). c) Pattern of theoretical dilations of microcracks (all aligned with Shmax) around a central injector (green), and observed pattern of most preferred directionalities relative to Shmax in 47 waterfloods of nominally “unfractured” reservoirs (blue) (note that flooding will have progressed in other directions in any one case, but not to the extent of the most preferred direction)

Figure 3. Generic trends of waterflooding derived from theory and field observations. Note that local details and heterogeneities of geology will modify this idealised pattern in specific cases.

Figure 4. Field example of oil and water production according to orientation of producer from nearest injector relative to stress state.

Figure 5. An example from a carbonate reservoir showing how the trends in a composite of the 4 most important principal components (or modes) of the dynamic rate correlations (in black) agree well with independent observations of structural lineaments, porosity and fracture trends from log and core static data.

Author: Kes Heffer
Company: Petromall

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