Unconventional Resource Estimates in the UK
In March 2016, a small UK independent oil company announced the results of flow tests from their Horse Hill-1 discovery well, 60 km south of London, sparking a fierce backlash against the vision of an American-style frack-fest across the rural idyll of the Weald (see GEO ExPro Vol. 13, No. 5 & GEO ExPro Vol. 12, No. 3). While stressing that no rocks had been fracked in the making of the oil flows, the press release outlined very promising oil rates from Jurassic strata: 323 bopd from an established Portland sandstone play and also 1,365 bopd from two Kimmeridgian intervals characterized as ‘tight’ reservoirs. The latter grabbed media headlines, as it was revealed that up to 124 Bbo could lie beneath the commuter belt of southern England. Press reports emphasized that this is an ‘in-place’ resource estimate of all the oil zones encountered and would need confirmation from future drilling results across the 3,266 km2 evaluation area. Even so, how can such an enormous volume be justified by one well, when the latest government estimate (2017, UK Oil and Gas Resources as at end 2016, ogauthority. co.uk) attributes ‘only’ 43.5 Bboe produced to date from the whole of the UK North Sea?
Understanding Conventional Resources First
When I started work as a seismic interpreter in the mid-1980s, there was only conventional oil and gas and it was vital that we learned how to assess for the ingredients and requirements for an economic oil or gas field, as understood then. A prerequisite is the presence of a source rock, often a black shale with a high organic content, which is gently heated as it is buried by sediments, transforming the plant or animal matter to hydrocarbons. Crucially, these escape the source rock and migrate across the strata, reaching porous layers, after which their buoyancy conveys them upwards, unless trapped by an impermeable layer. An anticline or a tilted fault block can form such a trap, filling until the fluids spill from a leak point into the next structure or onwards up-dip.
The direct result is that such oil and gas fields are discrete structures, with oil migration focused towards structural highs or fault blocks. For sure, exploration successes are usually grouped along structural trends that are close to and above the mature source ‘kitchen’, but otherwise, each is individually assessed. The in-place hydrocarbon volume of an undrilled prospect or discovery is essentially a simple calculation of structure volume, reduced by multiplication to reflect the proportion of net sand thickness and its porosity, accounting for water content and the compression factor related to its depth. Finally, the all-important recovery factor is applied to provide the reserves figure – those hydrocarbons that can be produced.
The Mighty Brent Oil Field
If we view an oil field distribution map, using the East Shetland Platform of the northern North Sea as an example (right), we can see the trend of faults reflected by the blobs approximating the field outlines, indicating where Jurassic sands of the Brent Group, segmented by tilted fault blocks, are overlain by sealing shales. Take the mighty Brent Field, the oil giant whose discovery in 1971 set in motion the exploitation of a vast new hydrocarbon province ( GEO ExPro Vol. 14, No. 2). During 40 years of production the field has produced almost 2 Bbo and 6 Tcfg, approximately half and three quarters respectively of the original estimated hydrocarbons in place. Today, this vast hydrocarbon factory is being decommissioned and the first of the giant platforms has arrived on Teeside, north-east England.
Estimating Producible Hydrocarbon Reserves
Only now, near the end of Brent’s life, we can be confident of exactly how much oil will be produced – but as geologists we are required to estimate the producible reserves throughout a field’s life.
According to the Society of Petroleum Engineers (SPE), the industry declared arbiter of such assessments, to be classified as reserves, hydrocarbons must be discovered, recoverable, commercial and remaining.
Proven reserves (1P) are often considered to be only those associated with the forecasted production (decline curves) from wells already on stream.
Probable reserves (proven plus probable, hence 2P) could include new drilling or well interventions already approved and financed
Possible reserves (3P) include those assessed volumes for which there is not yet a development plan.
During the life of a field, reserves initially classified as 2P and 3P are developed and re-categorized as 1P before being produced. Other discovered but undeveloped hydrocarbons are considered contingent while undrilled structures are indicated as prospective.
However, P also stands for probability and the market is often confused between 1P, 2P, 3P versus P90, P50, P10. This confusion arises from the exploration practice of assessing the range of volumes associated with an undrilled prospect. When minimum, most likely and maximum reservoir parameters were multiplied, it was realized that the minimum volume could be minutely small while the result of combining maximum values correspondingly huge. In a bid to rationalize results, Monte Carlo simulation is used, in which thousands of realizations sampled from the range of prospect parameters are plotted and the resulting probability curve has a ‘most likely’ or ‘P50’ result. The low case is associated with ‘P90’, for which there is a 90% chance that the actual reserves are higher. The range between P90 to P10 is routinely used to describe the range of possible reserves from the outcome of a successful exploration well.
Confusion might arise with this usage in the production world. Even a proven oil reserve can have a low, most likely and high case depending on pessimistic or optimistic forecasts of production decline and could be referred to as P90, P50 or P10 cases.
Producing from Tight Reservoirs
The Brent Field is an example of how a good reservoir with 20–25% porosity can be a prolific producer. Of course, some reservoirs disappoint; the oil may be there, but stored in smaller pores of low porosity sandstones which are poorly connected, inhibiting the flow of hydrocarbons, quantified by rock core measurements as permeability. Such reservoirs are dubbed ‘tight’; a good reservoir would have permeabilities of tens to hundreds of millidarcys, a tight one would be a single millidarcy or less.
Tight reservoirs have long been stimulated by hydraulic fracking, when water is pumped down the well at pressures high enough to fracture the reservoir by expanding and extending existing natural fractures, improving the permeability by the resulting network of interconnected flow paths. Outcomes can be further improved if the injection fluid is charged with proppant, like sand, which props open the cracks even after the pressure is relaxed. Such an operation can easily require 1.3 million litres of water, plus a hundred tonnes of proppant, propelled downhole at pressures of 10,000 psi or greater.
For many years fracking was limited by drilling technology to vertical or slanted wells, but since the turn of the century, the impact of this operation has been transformed by its deployment in horizontal wells. The ability to drill and frack multiple intervals along the target strata has enabled the development of hydrocarbons from previously unpromising reservoirs.
Shale Source Rock Reservoirs
Although I had worked on numerous tight reservoirs through my career, never did I think that the source rock itself could become prospective. It seemed that, while highly organic shales could source oil, they are also the archetypal seal beds, being minutely grained and impermeable. But it has turned out that the right sort of shale, preferably brittle or riddled with fissures, can be exploited commercially when stimulated by hydraulic fracking.
The hydrocarbons in such rocks are either stored within the micro-porosity or chemically bonded (‘adsorbed’) to the organic constituent of the source rock. In either case, they remain in-situ and do not flow, even when their confining pressure is liberated by the drill bit. Cue hydraulic fracking, which releases the hydrocarbons from along horizontal boreholes, and we have the basis of the unconventional shale resources.
To determine the amount of oil and gas in place for the prospective shale beds, we must estimate the proportions of free (but tightly held) and adsorbed hydrocarbons. The former is derived from bulk density on wireline logs and the latter by assessing the total organic content, preferably calibrated to measurements from rock core. Crucially, when estimating the volume potential for a shale play, the hydrocarbons are attached to the reservoir and not constrained to structural highs. Play areas are defined by mapping the distribution and thickness of the objective shales and outlining where they are both mature for hydrocarbon generation and have the required brittle property. The mapped area of each prospective interval is continuous across the fairway (in contrast to conventional oil fields) and characterized by barrels stored per unit area.
So, in the case of the Horse Hill-1 tight reservoirs, the prospective areas and parameters of the various target shales and tight limestones were mapped and aggregated beneath the Weald. The reported result gives an average of 38 MMb/km2 across an area of 3,266 km2 – hence 124 Bbo in place. It is by its nature a widespread resource and awaiting confirmation drilling, but the volumes certainly catch the headlines, particularly if fracking is to be employed.
Recovery Rate & Fracking Shale Reservoirs
The oil industry of the USA has been transformed by shale and fracking; oil production has been boosted by over 4 MMbopd and unconventional plays are contributing half the gas currently produced by the country. The technology, however, requires intense operations; horizontal wells are sequentially fracked in 6 to 12 sections and 6 to 8 wells are typically drilled from each well pad, with some provinces drilling a thousand or more such wells a year. Individual well flows tend to decline quite rapidly, so continued new drilling is required to keep production rates at a plateau. And all this effort typically recovers 3–6% of oil or 15–25% of gas originally in place, much less than conventional reservoirs.
But how would reserves be assigned for such a widespread resource? The use of decline curves is still preferred to define proven reserves but they require careful calibration, as many producing wells experience a precipitous fall in flow before a stable, low rate is established. In 2011 the SPE updated their guidance for reserve estimates, suggesting that probable reserves for shale gas could include 2 or 3 drill locations beyond current production, as long as they lay within a contiguous and appraised region. Likewise, possible reserves could extend the probable area in a similar manner.
The Future of Unconventional Resources
If I were to speculate that just the tight Kimmeridgian limestones that flowed in Horse Hill-1 were the primary interest, development of the cited 20 Bb in place across the region might recover a billion. An optimistic view of the average cumulative production per well of a million barrels would require 1,000 wells to be drilled from over a hundred well pads. While the drilling operation is time-limited compared to production, the public perception around water usage, gas leakage and induced earthquakes will provide fertile ground for a ferocious opposition, even before discussions against the continued development of fossil fuels. Today’s estimates of what oil might be produced could only be considered as ‘technically recoverable’, as the economic and political factors will dominate any development plan.
Now that the Brent Delta platform is on view in Teeside, we can get a sense of the scale of development it took to produce the North Sea resources that were comfortably out of sight. The trouble with onshore developments is that they are always in someone’s backyard; the scale required to develop shale plays in the UK will take some hiding.
- UK Oil and Gas plc website
- UK Oil and Gas Authority; SPE 2011: Guidelines for Application of the Petroleum Resources Management System.